Initial Public Offering (IPO): Pre-Effective Amendment to Registration Statement (General Form) — Form S-1 Filing Table of Contents
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REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
ATLAS RESOURCES PUBLIC #16-2007 PROGRAM
(Exact name of Registrant as Specified in its Charter)
Delaware
(State or other jurisdiction of incorporation or organization)
1311
(Primary Standard Industrial Classification Code Number)
Not Applicable
(IRS Employer Identification Number)
311 Rouser Road Moon Township, Pennsylvania15108
(412) 262-2830
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)
Jack L. Hollander, Senior Vice President – Direct Participation Programs
Atlas Resources, LLC
311 Rouser Road, Moon Township, Pennsylvania15108
(412) 262-2830
(Name, address, including zip code, and telephone
number, including area code, of agent for service)
With a Copy to: Wallace W. Kunzman, Jr., Esq.
Kunzman & Bollinger, Inc.
5100 N. Brookline
Suite 600 Oklahoma City, Oklahoma73112
As soon as practicable after this Registration Statement becomes effective.
(Approximate Date of Commencement of Proposed Sale to the Public)
If any of the securities being registered on this form are to be offered on a delayed or
continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:
þ
If this Form is filed to register additional securities for an offering pursuant to Rule
462(b) under the Securities Act, please check the following box and list the Securities Act
registration statement number of the earlier effective registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to rule 462(c) under the
Securities Act, check the following box and list the Securities Act registration statement number
of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to rule 462(d) under the
Securities Act, check the following box and list the Securities Act registration statement number
of the earlier effective registration statement for the same offering. o
CALCULATION OF REGISTRATION FEE
C:
Proposed
Proposed
Title of Each
Unit
Dollar
Maximum
Maximum
Amount of
Class of Securities
Amounts
Amounts to be
Offering
Aggregate Offering
Registration
to be Registered
to be Registered
Registered
Price per Unit
Price
Fee
C:C:
Investor General Partner Units (1)
19,900
$199,000,000
$10,000
$199,000,000
$21,293.00
Converted Limited Partner Units (2)
19,900
- 0 -
- 0 -
- 0 -
- 0 -
Limited Partner Units (3)
100
$1,000,000
$10,000
$1,000,000
$107.00
TOTAL
20,000
$200,000,000
$200,000,000
$21,400.00
C:
(1)
“Investor General Partner Units” means the investor general partner interests offered to
participants in the program.
(2)
“Converted Limited Partner Units” means up to 19,900 limited partner units into which the
investor general partner units automatically will be converted by the managing general partner
with no additional price paid by the investor.
(3)
“Limited Partner Units” means up to 100 initial limited partner interests offered to
participants in the program.
The Registrant hereby amends this Registration Statement on such dates as may be necessary to
delay its effective date until the Registrant shall file a further amendment which specifically
states that this Registration Statement shall thereafter become effective in accordance with
Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.
The managing general partner’s officers, directors,
promoters and affiliated persons have not acquired any
units during the past five years. Also, no units will
be issued in this offering to the managing general
partner except units subscribed for by the managing
general partner, which it does not anticipate.
Discounted units, if any, are described in “Plan of
Distribution.”
Item 7.
Selling Security Holders
The program does not have any selling security holders.
Market Price of and Dividends on the Registrant’s
Common Equity and Related Stockholder Matters
The partnerships composing the program have no markets
in which their units are being traded and they have not
yet conducted activities or paid any dividends.
(e)
Financial Statements
Financial Information Concerning the Managing General
Partner and Atlas Resources Public #16-2007(A) L.P.
(f)
Selected Financial Data
All of the partnerships composing the program have been
formed, but the partnerships have not conducted any
activities. Thus, the program does not have this
information for the partnerships.
(g)
Supplementary Financial Information
All of the partnerships composing the program have been
formed, but the partnerships have not conducted any
activities. Thus, the program does not have this
information for the partnerships.
The information in this prospectus is not complete and may be changed. We may not sell these
securities until the registration statement filed with the Securities and Exchange Commission is
effective. This prospectus is not an offer to sell these securities and it is not soliciting an
offer to buy these securities in any state where the offer or sale is not permitted.
PRELIMINARY PROSPECTUS DATED FEBRUARY___, 2007
ATLAS RESOURCES PUBLIC #16-2007 PROGRAM
Up to 19,900 Investor General Partner Units, which will be automatically
converted to Limited Partner Units after drilling is completed in the respective
partnership, and up to 100 Limited Partner Units, which are collectively referred to
as the “Units,” (1) at $10,000 per Unit
$2 Million (200 Units) Minimum Aggregate Subscriptions
$200 Million (20,000 Units) Maximum Aggregate Subscriptions
(1)
You may elect to buy either investor general partner units in the partnership
then being offered that will be automatically converted to limited partner units after
the partnership’s drilling is completed, or limited partner units. The type of unit you
buy will not change your share of your partnership’s costs, revenues and cash
distributions, however, there are material differences in the federal income tax
effects and liability between investor general partner units and limited partner units
as discussed in “Summary of the Offering – Description of Units.”
Atlas Resources Public #16-2007 Program is a series of up to two limited partnerships which will
drill primarily natural gas development wells. See “Terms of the Offering – Subscription to a
Partnership,” beginning on page 50, for a detailed description of the offering of these limited
partnerships. The limited partnerships will be managed by Atlas Resources, LLC of Pittsburgh,
Pennsylvania.
If you invest in a partnership, you will not have any interest in the other partnership unless
you also make a separate investment in the other partnership.
The units will be offered on a “best efforts”“minimum-maximum” basis. This means the
broker/dealers must sell at least 200 units and receive subscription proceeds of at least $2
million in order for a partnership to close, and they must use only their best efforts to sell
the remaining units in the partnership.
Subscription proceeds for each partnership will be held in an interest bearing escrow account until
$2 million has been received. The offering of Atlas Resources Public #16-2007(A) L.P. and Atlas
Resources Public #16-2007(B) L.P. will not extend beyond December 31, 2007. If the minimum
subscription proceeds are not received by a partnership’s offering termination date, then your
subscription will be promptly returned to you from the escrow account with interest and without
deduction for any fees.
The Offering: In addition to the information in the table below for not less than 95% of the units
(19,000 units), up to 5% of the units (1,000 units), in the aggregate, may be sold at $9,000 per
unit to the managing general partner, its officers, directors and affiliates, and investors who buy
units through the officers and directors of the managing general partner; or at $9,300 per unit to
registered investment advisors and their clients, and selling agents and their registered
representatives and principals. These discounted prices reflect certain fees, sales commissions
and reimbursements which will not be paid for these sales. (See “Plan of Distribution.”) To the
extent that units are sold at discounted prices, a partnership’s subscription proceeds will be
reduced.
Total
Total
Per Unit
Minimum
Maximum (2)
Public Price
$
10,000
$
2,000,000
$
200,000,000
Dealer-manager fee, sales commissions and bona fide due diligence reimbursements (1)
$
1,000
$
200,000
$
20,000,000
Proceeds to partnership
$
10,000
$
2,000,000
$
200,000,000
(1)
These fees, sales commissions and reimbursements will be paid by the managing general partner
as a part of its capital contribution and not from subscription proceeds.
•
A partnership’s drilling operations involve the possibility of a total or partial loss of your investment
that may be substantial because a partnership may drill wells that are productive, but do not produce
enough revenue to return the investment made, and from time to time dry holes.
•
A partnership’s revenues are directly related to its ability to market the natural gas produced from the
wells it drills and natural gas and oil prices, which are volatile and uncertain. If natural gas and oil prices
decrease, then your investment
return will decrease.
•
Unlimited joint and several liability for partnership obligations if you choose to invest as an investor
general partner until you are converted to a limited partner.
•
Lack of liquidity or a market for the units, which makes it extremely difficult for you to sell your units.
•
Lack of conflict of interest resolution procedures.
•
Total reliance on the managing general partner and its affiliates.
•
Authorization of substantial fees to the managing general partner and its affiliates.
•
You and the managing general partner will share in costs disproportionately to your sharing of revenues.
•
Possible allocation of taxable income to you in excess of your cash distributions from your partnership.
•
No guaranty of cash distributions every month.
These securities are speculative and are subject to certain risks. You should purchase these
securities only if you can afford a complete loss of your investment. (See “Risk Factors,” Page
14.)
Neither the SEC nor any state securities commission has approved or disapproved of these
securities or determined if this prospectus is truthful or complete. Any representation to the
contrary is a criminal offense.
Information Regarding Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.
Exhibit (A)
Form of Amended and Restated Certificate and Agreement of
Limited Partnership for Atlas Resources Public #16-2007(A)
L.P. [Form of Amended and Restated Certificate and Agreement
of Limited Partnership for Atlas Resources Public
#16-2007(B) L.P.]
Exhibit (I-A)
Form of Managing General Partner Signature Page
Exhibit (I-B)
Form of Subscription Agreement
Exhibit (II)
Form of Drilling and Operating Agreement for Atlas Resources
Public #16-2007(A) L.P. [Atlas Resources Public #16-2007(B)
L.P.]
Exhibit (B)
Special Suitability Requirements and Disclosures to Investors
It is the obligation of persons selling the units to make every reasonable effort to assure that
the units are suitable for you based on your investment objectives and financial situation,
regardless of your income or net worth. However, you should invest in a partnership only if you
are willing to assume the risk of a speculative, illiquid, and long-term investment. Also,
subscriptions to a partnership will not be accepted from IRAs, Keogh plans and qualified retirement
plans, because the partnership’s income would be characterized as unrelated business taxable
income, which is subject to federal income tax.
The decision to accept or reject your subscription will be made by the managing general partner, in
its sole discretion, and is final. The managing general partner will not accept your subscription
until it has reviewed your apparent qualifications, and the suitability determination must be
maintained by the managing general partner during the partnership’s term and for at least six years
thereafter.
Pennsylvania Investors: Because the minimum closing amount is less than 10% of the maximum closing
amount allowed to a partnership in this offering, you are cautioned to carefully evaluate the
partnership’s ability to fully accomplish its stated objectives and inquire as to the current
dollar volume of partnership subscriptions. In addition, subscription proceeds received by a
partnership from Pennsylvania investors will be placed into a short-term escrow (120 days or less)
until subscriptions for at least 5% of the maximum offering proceeds have been received by a
partnership, which for Atlas Resources Public #16-2007(A) L.P. means that subscriptions for at
least $6.7 million have been received by the partnership from investors, including Pennsylvania
investors. If the appropriate minimum has not been met at the end of each escrow period, the
partnership must notify the Pennsylvania investors in writing by certified mail or any other means
whereby a receipt of delivery is obtained within 10 calendar days after the end of each escrow
period that they have a right to have their investment returned to them. If an investor requests
the return of such funds within 10 calendar days after receipt of notification, the issuer must
return such funds within 15 calendar days after receipt of the investor’s request.
General Suitability Requirements for Purchasers of Limited Partner Units
If you are a resident of any of the following states or jurisdictions:
then limited partner units may be sold to you if you meet either of the following requirements:
•
a minimum net worth of $225,000, exclusive of home, home furnishings, and automobiles; or
•
a minimum net worth of $60,000, exclusive of home, home furnishings, and
automobiles, and had during the last tax year or estimate that you will have during the
current tax year “taxable income” as defined in Section 63 of the Internal Revenue Code
of at least $60,000, without regard to an investment in the partnership.
In addition, if you are a resident of Pennsylvania, then you must not make an investment in a
partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings and
automobiles. Finally, if you are a resident of Kansas, it is recommended by the Office of the
Kansas Securities Commissioner that Kansas investors should limit their investment in the program
and substantially similar programs to no more than 10% of their liquid net worth. Liquid net worth
is that portion of your net worth (total assets minus total liabilities) that is comprised of cash,
cash equivalents and readily marketable securities. Readily marketable securities may include
investments in an IRA or other retirement plan that can be liquidated within a short time, less any
income tax penalties that may apply for early distribution.
However, if you are a resident of the states set forth below, then different suitability
requirements apply to you.
Special Suitability Requirements for Purchasers of Limited Partner Units
•
If you are a resident of Alaska and you subscribe for limited
partner units, then you must meet either of the following special
suitability requirements:
•
a net worth of not less than $65,000, exclusive of your
principal automobile, principal residence and home furnishings, and
an annual gross income of not less than $65,000; or
•
a net worth of not less than $150,000, exclusive of your
principal automobile, principal residence, and home furnishings.
•
If you are a resident of California or New Jersey and you subscribe for limited
partner units, then you must meet any one of the following special suitability
requirements:
•
a net worth of not less than $250,000, exclusive of home, home furnishings,
and automobiles, and expect to have gross income in the current tax year of
$65,000 or more; or
•
a net worth of not less than $500,000, exclusive of home, home furnishings,
and automobiles; or
•
a net worth of not less than $1 million; or
•
expected gross income in the current tax year of not less than $200,000.
•
If you are a resident of Kentucky and you subscribe for limited partner units, then
you must meet either of the following special suitability requirements:
•
a net worth of not less than $250,000, exclusive of home, home furnishings,
and automobiles; or
•
a net worth of not less than $70,000, exclusive of home, home furnishings,
and automobiles, and annual income of $70,000 or more without regard to an
investment in the partnership.
Additionally, if you are a resident of Kentucky, then you must not make an investment
in a partnership which is in excess of 10% of your liquid net worth.
•
If you are a resident of Michigan or North Carolina and you subscribe for limited
partner units, then you must meet either of the following special suitability
requirements:
a net worth of not less than $225,000, exclusive of home, home furnishings,
and automobiles; or
•
a net worth of not less than $60,000, exclusive of home, home furnishings,
and automobiles, and estimated current tax year taxable income as defined in
Section 63 of the Internal Revenue Code of $60,000 or more without regard to an
investment in the partnership.
Additionally, if you are a resident of Michigan, then you must not make an investment
in a partnership which is in excess of 10% of your net worth, exclusive of home, home
furnishings and automobiles.
•
If you are a resident of New Hampshire and you subscribe for limited partner units,
then you must meet either of the following special suitability requirements:
•
a net worth of not less than $250,000, exclusive of home, home
furnishings, and automobiles; or
•
a net worth of not less than $125,000, exclusive of home, home
furnishings, and automobiles and $50,000 of taxable income.
•
If you are a resident of Ohio, Iowa or Massachusetts and you subscribe for limited
partner units, then you must meet, without regard to your investment in a partnership,
either of the following special suitability requirements:
•
a net worth of not less than $330,000, exclusive of home, home furnishings,
and automobiles; or
•
a net worth of not less than $85,000, exclusive of home, home furnishings,
and automobiles, and an annual gross income during the current tax year of at
least $85,000.
Additionally, if you are a resident of Ohio you must not make an investment in a
partnership which would, after including your previous investments in prior Atlas
Resources programs, if any, and any other similar natural gas and oil drilling
programs, exceed 10% of your net worth, exclusive of home, home furnishings and
automobiles.
General Suitability Requirements for Purchasers of Investor General Partner Units
If you are a resident of any of the following states or jurisdictions:
•
Colorado,
•
Connecticut,
•
Delaware,
•
District of Columbia,
•
Florida,
•
Georgia,
•
Hawaii,
•
Idaho,
•
Illinois,
•
Louisiana,
•
Maryland,
•
Montana,
•
Nebraska,
•
Nevada,
•
New York,
•
North Dakota,
•
Rhode Island,
•
South Carolina,
•
Utah,
•
Virginia,
•
West Virginia,
•
Wisconsin, or
•
Wyoming,
then investor general partner units may be sold to you if you meet either of the following
requirements:
a minimum net worth of $225,000, exclusive of home, home furnishings, and
automobiles; or
•
a minimum net worth of $60,000, exclusive of home, home furnishings, and
automobiles, and had during the last tax year or estimate that you will have during the
current tax year “taxable income” as defined in Section 63 of the Internal Revenue Code
of at least $60,000, without regard to an investment in the partnership.
However, if you are a resident of the states set forth below, then different suitability
requirements apply to you if you purchase investor general partner units.
Special Suitability Requirements for Purchasers of Investor General Partner Units
•
If you are a resident of any of the following states:
•
Alabama,
•
Arizona,
•
Arkansas,
•
Indiana,
•
Maine,
•
Minnesota,
•
North Carolina,
•
Oklahoma,
•
Pennsylvania,
•
Tennessee,
•
Texas, or
•
Washington
and you subscribe for investor general partner units, then you must meet any
one of the following special suitability requirements:
•
an individual or joint net worth with your spouse of $225,000 or more,
without regard to the investment in the partnership, exclusive of home, home
furnishings, and automobiles, and a combined gross income of $100,000 or more
for the current year and for the two previous years; or
•
an individual or joint net worth with your spouse in excess of $1 million,
inclusive of home, home furnishings, and automobiles; or
•
an individual or joint net worth with your spouse in excess of $500,000,
exclusive of home, home furnishings, and automobiles; or
•
a combined “gross income” as defined in Internal Revenue Code Section 61 in
excess of $200,000 in the current year and the two previous years.
•
In addition, if you are a resident of Pennsylvania, then you must not make an
investment in a partnership which is in excess of 10% of your net worth,
exclusive of home, home furnishings, and automobiles.
•
If you are a resident of Alaska and you subscribe for
investor general partner units, then you must meet either of the
following special suitability requirements:
•
a net worth of not less than $65,000, exclusive of your
principal automobile, principal residence and home furnishings, and
an annual gross income of not less than $65,000; or
•
a net worth of not less than $150,000, exclusive of your
principal automobile, principal residence and home furnishings.
•
If you are a resident of any of the following states:
•
Kansas,
•
Michigan,
•
Mississippi,
•
Missouri,
•
New Mexico,
•
Oregon,
•
South Dakota, or
•
Vermont
and you subscribe for investor general partner units, then you must meet any
one of the following special suitability requirements:
an individual or joint net worth with your spouse of $225,000 or more,
without regard to the investment in the partnership, exclusive of home, home
furnishings, and automobiles, and a combined “taxable income” of $60,000 or more
for the previous year and expect to have a combined “taxable income” of $60,000
or more for the current year and for the succeeding year; or
•
an individual or joint net worth with your spouse in excess of $1 million,
inclusive of home, home furnishings, and automobiles; or
•
an individual or joint net worth with your spouse in excess of $500,000,
exclusive of home, home furnishings, and automobiles; or
•
a combined “gross income” as defined in Internal Revenue Code Section 61 in
excess of $200,000 in the current year and the two previous years.
•
In addition, if you are a resident of Michigan, then you must not make an
investment in a partnership which is in excess of 10% of your net worth,
exclusive of home, home furnishings, and automobiles.
•
Finally, if you are a resident of Kansas, it is recommended by the Office of
the Kansas Securities Commissioner that Kansas investors should limit their
investment in the program and substantially similar programs to no more than 10%
of their liquid net worth. Liquid net worth is that portion of your net worth
(total assets minus total liabilities) that is comprised of cash, cash
equivalents and readily marketable securities. Readily marketable securities
may include investments in an IRA or other retirement plan that can be
liquidated within a short time, less any income tax penalties that may apply for
early distribution.
•
If you are a resident of California or New Jersey and you subscribe for
investor general partner units, then you must meet any one of the following special
suitability requirements:
•
an individual or joint net worth with your spouse of not less than $250,000,
exclusive of home, home furnishings, and automobiles, and expect to have
gross income in the current tax year of $120,000 or more; or
•
an individual or joint net worth with your spouse of not less than $500,000,
exclusive of home, home furnishings, and automobiles; or
•
an individual or joint net worth with your spouse of not less than $1 million; or
•
a combined expected gross income in the current tax year of not less than $200,000.
•
If you are a resident of Kentucky and you subscribe for investor general partner
units, then you must meet either of the following special suitability requirements:
•
a net worth of not less than $250,000, exclusive of home, home furnishings,
and automobiles; or
•
a net worth of not less than $70,000, exclusive of home, home furnishings,
and automobiles, and annual income of $70,000 or more without regard to an
investment in the partnership.
Additionally, if you are a resident of Kentucky, then you must not make an investment
in a partnership which is in excess of 10% of your liquid net worth.
If you are a resident of New Hampshire and you subscribe for investor general
partner units, then you must meet either of the following special suitability
requirements:
•
a net worth of not less than $250,000, exclusive of home, home
furnishings, and automobiles; or
•
a net worth of not less than $125,000, exclusive of home, home
furnishings, and automobiles, and $50,000 of taxable income.
•
If you are a resident of Ohio, Iowa or Massachusetts and you subscribe for investor
general partner units, then you must meet, without regard to your investment in a
partnership, either of the following special suitability requirements:
•
an individual or joint net worth with your spouse of not less than $750,000,
exclusive of home, home furnishings, and automobiles; or
•
an individual or joint net worth with your spouse of not less than $330,000,
exclusive of home, home furnishings, and automobiles, and an annual gross
income of at least $150,000 for the current year and the two previous years.
Additionally, if you are a resident of Ohio, then you must not make an investment in
a partnership which would, after including your previous investments in prior Atlas
Resources programs, if any, and any other similar natural gas and oil drilling
programs, exceed 10% of your net worth, exclusive of home, home furnishings and
automobiles. Additionally, if you are a resident of Iowa, then you must not make an
investment in a partnership which is in excess of 10% of your net worth, exclusive of
home, home furnishings, and automobiles.
Fiduciary Accounts
If there is a sale of a unit to a fiduciary account, then all of the suitability standards set
forth above must be met by the beneficiary, the fiduciary account, or the donor or grantor who
directly or indirectly supplies the funds to purchase the units if the donor or grantor is the
fiduciary.
Generally, you are required to execute your own subscription agreement, and the managing general
partner will not accept any subscription agreement that has been executed by someone other than
you. The only exception is if you have given someone else the legal power of attorney to sign on
your behalf and you meet all of the conditions in this prospectus.
This is a summary and does not include all of the information that may be important to you.
You should read this entire prospectus and the attached exhibits and appendix before you decide to
invest in a partnership. Throughout this prospectus when there is a reference to you it is a
reference to you as a potential investor or participant in a partnership.
Business of the Partnerships and the Managing General Partner
Atlas Resources Public #16-2007 Program, which is sometimes referred to in this prospectus as the
“program,” consists of up to two Delaware limited partnerships. These limited partnerships are
sometimes referred to in this prospectus in the singular as a “partnership” or in the plural as the
“partnerships.” Units in the two partnerships will be offered and sold in a series beginning with
the offering of units in the first partnership, Atlas Resources Public #16-2007(A) L.P. See “Terms
of the Offering” for a discussion of the terms and conditions involved in making an investment in a
partnership. Each partnership has a maximum 50 year term, although the
managing general partner intends to terminate each partnership when
all of its wells become uneconomical for the partnership to continue
to operate, which may be 30 to 40 years or longer.
Each partnership in the program will be a separate business entity from the other partnership. A
limited partnership agreement will govern the rights and obligations of the partners of each
partnership. A form of the limited partnership agreement is attached to this prospectus as Exhibit
(A). For a summary of the material provisions of the limited partnership agreement which are not
covered elsewhere in this prospectus see “Summary of Partnership Agreement.” You will be a partner
only in the partnership in which you invest. You will have no interest in the business, assets or
tax benefits of the other partnership unless you also invest in the other partnership. Thus, your
investment return will depend solely on the operations and success or lack of success of the
partnership in which you invest.
The offering proceeds of each partnership will be used to drill primarily natural gas development
wells in the Appalachian Basin. The wells to be drilled by each partnership will be located
primarily in western Pennsylvania and north central Tennessee as described in “Proposed
Activities.” A development well means a well drilled within the proved area of a natural gas or
oil reservoir to the depth of a stratigraphic horizon known to be productive. Currently, the
partnerships do not hold any interests in any properties or prospects on which the wells will be
drilled by each partnership.
The managing general partner of each partnership is Atlas Resources, LLC, a Pennsylvania limited
liability company, which was originally formed as a corporation in 1979 and then changed to a
limited liability company in March, 2006. The managing general partner is sometimes referred to in
this prospectus as “Atlas Resources.” As set forth in “Prior Activities,” the managing general
partner has sponsored and serves as managing general partner of 38 private drilling partnerships
and 16 public drilling partnerships. Atlas Resources also will serve as each partnership’s general
drilling contractor and operator and it will supervise the drilling, completing and operating of
the wells to be drilled by each partnership. As discussed in “Compensation,” the managing general
partner and its affiliates will receive substantial fees and profits in connection with this
offering.
The address and telephone number of the partnerships and the managing general partner are 311
Rouser Road, Moon Township, Pennsylvania15108, (412) 262-2830.
Risk Factors
This offering involves numerous risks, including risks related to each partnership’s oil and gas
operations, risks related to an investment in a partnership, and tax risks. You should carefully
consider a number of significant risk factors inherent in and affecting the business of a
partnership and this offering, including the following.
•
The drilling operations of the partnership in which you invest involve the
possibility of a total or partial loss of your investment that may be substantial
because each partnership may drill wells that are productive, but do not produce enough
revenue to return the investment made, and from time to time dry holes.
Each partnership’s revenues are directly related to its ability to market
the natural gas produced from the wells it drills and natural gas and oil prices, which
are volatile and uncertain. If natural gas and oil prices decrease then your
investment return will decrease.
•
Unlimited joint and several liability for partnership obligations if you
choose to invest as an investor general partner until you are converted to a limited
partner.
•
Lack of liquidity or a market for the units makes it extremely difficult
for you to sell your units and necessitates a long-term investment commitment from you.
•
Total reliance on the managing general partner and its affiliates to
manage each partnership and its business.
•
Authorization of substantial fees to the managing general partner and its
affiliates.
•
Possible allocation of taxable income to you and the other investors in
excess of your respective cash distributions from a partnership.
•
Each partnership must receive minimum subscription proceeds of $2 million
to close this offering, and the subscription proceeds of all partnerships, in the
aggregate, may not exceed $200 million. There are no other requirements regarding the
size of a partnership, and the subscription proceeds of one partnership may be
substantially more or less than the subscription proceeds of the other partnership. If
only the minimum subscription proceeds are received by a partnership, its ability to
spread the risks of drilling will be greatly reduced as described in “Compensation -
Drilling Contracts.”
•
There are certain conflicts of interest between the managing general
partner and you and the other investors, and a lack of procedures to resolve the
conflicts.
•
You and the other investors and the managing general partner will share in
a partnership’s costs disproportionately to the sharing of its revenues.
•
Currently, the partnerships do not hold any interests in any properties or
prospects on which the wells will be drilled. Although the managing general partner
has absolute discretion in determining which properties or prospects will be drilled by
a partnership, the managing general partner intends that Atlas Resources Public
#16-2007(A) L.P. will drill the prospects described in “Appendix A — Information
Regarding Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.”
These prospects represent a portion of the wells to be drilled if the nonbinding
targeted maximum subscription proceeds described in “Terms of the Offering -
Subscription to a Partnership” are received. If there are material adverse events with
respect to any of the currently proposed prospects before drilling begins on the
prospect, the managing general partner will substitute a new prospect. The managing
general partner also anticipates that it will designate a portion of the prospects in
Atlas Resources Public #16-2007(B) L.P. by a supplement or an amendment to the
registration statement of which this prospectus is a part.
•
In each partnership the managing general partner will subordinate a
portion of its share of the partnership’s net production revenues to increase the
partnership’s distributions to you and the other investors if you and the partnership’s
other investors do not receive cash distributions equal to a minimum of 10% of capital,
based on a subscription price of $10,000 per unit, regardless of the actual
subscription price you paid for your units, in each of the first five 12-month periods
beginning with the partnership’s first cash distribution from operations. This
subordination, however, is not a guaranty by the managing general partner of your
distributions from that partnership. If the wells in
that partnership produce small volumes of natural gas and oil and/or natural gas and
oil prices decrease, then even with subordination your cash flow from the partnership
may not return the intended distributions during the subordination period or, over
the term of the partnership, all of your investment.
•
In each partnership monthly cash distributions to its investors may be
deferred if revenues are used for partnership operations or reserves.
The time period for the offer and sale of the first partnership’s units will begin on the date of
this prospectus. Each partnership will offer a minimum of 200 units, which is $2 million, and the
partnerships, in the aggregate, will offer a maximum of 20,000 units which is $200 million. The
maximum subscription proceeds for each partnership will be the lesser of:
•
the amount of $200 million; or
•
$200 million less the amount of subscriptions sold in the preceding partnership.
The targeted subscription proceeds for Atlas Resources Public #16-2007(A) L.P. are $100 million,
although it may raise the entire $200 million and not offer and sell any units in the second
partnership, and its closing date is June 30, 2007, which may be extended until December 31, 2007.
The targeted subscription proceeds of Atlas Resources Public #16-2007(B) L.P. are $100 million and
its closing date is December 31, 2007, as set forth in a table in “Terms of the Offering -
Subscription to a Partnership.”
Units are offered at a subscription price of $10,000 per unit, provided that up to 5% of the units
in each partnership in this offering may be sold to certain investors at discounted prices as
described in “Plan of Distribution.” All subscriptions must be paid 100% in cash at the time of
subscribing. Your minimum subscription in a partnership is one unit ($10,000). Larger fractional
subscriptions will be accepted in $1,000 increments, beginning, for example, with $11,000, $12,000,
etc.
You may elect to purchase units as either an investor general partner or a limited partner as
described in “- Description of Units,” below. Under the partnership agreement no investor,
including investor general partners, may participate in the management of a partnership or its
business. The managing general partner will have exclusive management authority for the
partnerships.
Each partnership has been formed as a limited partnership under the Delaware Revised Uniform
Limited Partnership Act. Subscription proceeds for each partnership will be held in a separate
interest bearing escrow account at National City Bank of Cleveland, Ohio until receipt of the
minimum subscription proceeds, excluding any subscriptions by the managing general partner or its
affiliates. On receipt of the minimum subscription proceeds, the managing general partner on
behalf of a partnership may break escrow, transfer the escrowed subscription proceeds to a
partnership account, and begin the partnership’s activities, including drilling. After breaking
escrow, additional subscription proceeds may be paid directly to a partnership account for that
partnership and will continue to earn interest until the final closing date of the offering of
units in that partnership. (See “Terms of the Offering.”) If subscription proceeds of $2 million
are not received by the offering termination date for your partnership, which is June 30, 2007,
extendible to December 31, 2007 for Atlas Resources Public #16-2007(A) L.P., and December 31, 2007
for Atlas Resources Public #16-2007(B) L.P., then your subscription amount will be promptly
returned to you from the escrow account with interest and without deduction for any fees.
Pennsylvania Investors: Because the minimum closing amount is less than 10% of the maximum closing
amount allowed to a partnership in this offering, you are cautioned to carefully evaluate the
partnership’s ability to fully accomplish its stated objectives and inquire as to the current
dollar volume of partnership subscriptions. In addition, subscription proceeds received by a
partnership from Pennsylvania investors will be placed into a short-term escrow (120 days or less)
until subscriptions for at least 5% of the maximum offering proceeds have been received by a
partnership, which for Atlas Resources Public #16-2007(A) L.P. means that subscriptions for at
least $6.7 million have been received by the partnership from investors, including Pennsylvania
investors. If the appropriate minimum has not been met at the end of each escrow period, the
partnership must notify the Pennsylvania investors in writing by certified mail or any other means
whereby a receipt of delivery is obtained within 10 calendar days after the end of each escrow
period that they have a right to have their investment returned to them. If an investor requests
the return of such funds within 10 calendar days after receipt of notification, the issuer must
return such funds within 15 calendar days after receipt of the investor’s request.
Description of Units
On subscribing for units in the partnership being offered at the time, you may elect to buy either:
•
investor general partner units; or
•
limited partner units.
The partnerships will not issue certificates for their units, but your ownership of your unit(s)
will be recorded on the partnership’s books and records. Also, the type of unit you buy will not
affect the allocation of your partnership’s costs, revenues, and cash distributions among you and
its other investors. There are, however, material differences in the federal income tax effects
and liability associated with each type of unit.
Investor General Partner Units.
•
Tax Effect. If you invest in a partnership as an investor general partner, then
your share of the partnership’s deduction for intangible drilling costs will not be
subject to the passive activity limitations on losses. For example, if you pay $10,000
for a unit, then generally you may deduct not less than 90% of your subscription
amount, $9,000 per unit, in the year in which you invest, which includes your deduction
for intangible drilling costs for all of the wells to be drilled by the partnership.
(See “Federal Income Tax Consequences — Limitations on Passive Activity Losses and
Credits.”)
•
Intangible drilling costs generally means those costs of drilling and
completing a well that are currently deductible, as compared to lease costs
which must be recovered through the depletion allowance and costs for equipment
in the well which must be recovered through depreciation deductions. For
example, intangible drilling costs include all expenditures made for any well
before production in commercial quantities for wages, fuel, repairs, hauling,
supplies and other costs and expenses incident to and necessary for drilling the
well and preparing the well for production of natural gas or oil. Intangible
drilling costs also include the expense of plugging and abandoning any well
before a completion attempt, and the costs (other than equipment costs and lease
acquisition costs) to re-enter and deepen an existing well, complete the well to
deeper reservoirs, or plug and abandon the well if it is nonproductive from the
targeted deeper reservoirs.
•
Liability. If you invest in a partnership as an investor general partner, then you
will have unlimited liability regarding the partnership’s activities. This means that
if:
•
the partnership’s insurance proceeds from any source;
•
the managing general partner’s indemnification of you and the other investor
general partners; and
were not sufficient to satisfy a partnership liability for which you and the other
investor general partners were also liable solely because of your status as general
partners of the partnership, then the managing general partner would require you and
the other investor general partners to make additional capital contributions to the
partnership to satisfy the liability. In addition, you and the other investor
general partners will have joint and several liability, which means generally that a
person with a claim against the partnership may sue all or any one or more of the
partnership’s general partners, including you, for the entire amount of the
liability. You will be able to determine if your units are subject to assessibility
based on whether you buy investor general partner units, which are subject to
assessibility, or limited partner units, which are not subject to assessibility.
(See “Actions To Be Taken By Managing General Partner To Reduce Risks of Additional
Payments by Investor General Partners” and “Proposed Activities — Insurance.”)
Although past performance is no guarantee of future results, the investor general partners
in the managing general partner’s prior partnerships have not had to make any additional
capital contributions to their partnerships because of their status as investor general
partners. (See “Prior Activities.”)
Your investor general partner units in a partnership will be automatically converted by the
managing general partner to limited partner units after all of that partnership’s wells have
been drilled and completed. In this regard, a well is deemed to be completed when
production equipment is installed on a well, even though the well may not yet be connected
to a pipeline for production of natural gas. The conversion will not create any tax
liability to you or the other investors.
Once your units are converted, you will have the lesser liability of a limited partner under
Delaware law for partnership obligations and liabilities arising after the conversion.
However, you will continue to have the responsibilities of a general partner for partnership
liabilities and obligations incurred before the effective date of the conversion. For
example, you might become liable for partnership liabilities in excess of your subscription
amount during the time the partnership is engaged in drilling activities and for
environmental claims that arose during drilling activities, but were not discovered until
after the conversion.
Limited Partner Units.
•
Tax Effect. If you invest in a partnership as a limited partner, then your use of
your share of the partnership’s deduction for intangible drilling costs will be limited
to offsetting your net passive income from “passive” trade or business activities.
Passive trade or business activities generally include the partnership and other
limited partner investments, but passive income does not include salaries, dividends or
interest. This means that you will not be able to deduct your share of the
partnership’s intangible drilling costs in the year in which you invest unless you have
net passive income from investments other than the partnership. However, any portion
of your share of the partnership’s deduction for intangible drilling costs that you
cannot use in the year in which you invest, because you do not have sufficient net
passive income in that year, may be carried forward indefinitely until you can use it
to offset your net passive income from the partnership or your other passive
activities, if any, in subsequent tax years. (See “Federal Income Tax Consequences -
Limitations on Passive Activity Losses and Credits.”)
•
Liability. If you invest in a partnership as a limited partner, then you will have
limited liability for the partnership’s liabilities and obligations. This means that
you will not be liable for any partnership liabilities or obligations beyond the amount
of your initial investment in the partnership and your share of the partnership’s
undistributed net profits, subject to certain exceptions set forth in “Summary of
Partnership Agreement — Liability of Limited Partners.”
Use of Proceeds
Each partnership must receive minimum subscription proceeds of $2 million to close, and the
subscription proceeds of both partnerships, in the aggregate, may not exceed $200 million. The
subscription proceeds of one partnership may be
substantially more or less than the subscription proceeds of the other partnerships and the
managing general partner has the discretion to accept subscriptions for up to and including the
entire amount in Atlas Resources Public #16-2007(A) L.P. and not offer and sell any units in Atlas
Resources Public #16-2007(B) L.P. In each partnership, regardless of whether the partnership
receives the minimum or the maximum subscription proceeds from you and the other investors:
•
90% of the subscription proceeds will be used to pay 100% of the intangible drilling
costs, as defined above in “- Description of Units,” of drilling and completing the
partnership’s wells; and
•
10% of the subscription proceeds will be used to pay a portion of the equipment
costs of drilling and completing the partnership’s wells.
The managing general partner will contribute all of the leases to each partnership covering the
acreage on which that partnership’s wells will be drilled and pay all of the equipment costs of
drilling and completing the partnership’s wells that exceed 10% of the partnership’s subscription
proceeds. Thus, the managing general partner will pay the majority of each partnership’s equipment
costs. The managing general partner also will be charged with 100% of the organization and
offering costs for each partnership. A portion of these contributions to each partnership will be
in the form of payments to itself, its affiliates and third-parties and the remainder will be in
the form of services related to organizing this offering. The managing general partner will
receive a credit towards its required capital contribution to each partnership for these payments
and services as discussed in “Participation in Costs and Revenues.” (See “Capitalization and
Source of Funds and Use of Proceeds” and “Federal Income Tax Consequences — Intangible Drilling
Costs.”)
Five Year-50% Subordination, Participation in Costs and Revenues, and Distributions
Each partnership will be a separate business entity from the other partnerships, and you will be a
partner only in the partnership in which you invest. You will have no interest in the business,
assets or tax benefits of the other partnership unless you also invest in the other partnership.
Thus, your investment return will depend solely on the operations and success or lack of success of
the particular partnership in which you invest. Each partnership is structured to provide you and
its other investors with cash distributions equal to a minimum of 10% of capital, based on a
subscription price of $10,000 per unit, regardless of the actual subscription price you paid for
your units, in each of the first five 12-month periods beginning with the partnership’s first cash
distribution from operations. To help achieve this investment feature of a 10% return of capital
in each of the first five 12-month periods, the managing general partner will subordinate up to 50%
of its share of partnership net production revenues, which will be up to between 16% and 20% of
total partnership net production revenues, depending on the amount of the managing general
partner’s capital contribution to that partnership, during this subordination period. (See
“Participation in Costs and Revenues — Subordination of Portion of Managing General Partner’s Net
Revenue Share.”)
Each partnership’s 60-month subordination period will begin with the partnership’s first cash
distribution from operations to you and its other investors. The estimated maximum time from the
closing for a partnership to begin distributions is eight months from the closing as discussed in
“Investment Objectives.” Subordination distributions will be determined by debiting or crediting
current period partnership revenues to the managing general partner as may be necessary to provide
the distributions to you and the other investors. At any time during the subordination period, but
not after, the managing general partner is entitled to an additional share of partnership revenues
to recoup previous subordination distributions to the extent your cash distributions from the
partnership exceed the 10% return of capital described above. The specific formula for determining
subordination distributions is set forth in Section 5.01(b)(4)(a) of the partnership agreement.
The following table sets forth how the partnership’s costs and revenues will be charged and
credited between the managing general partner and you and the other investors for each partnership
after deducting from the partnership’s gross revenues the landowner royalties and any other lease
burdens.
Operating costs, administrative costs, direct costs, and all other costs
(3
)
(3
)
Partnership Revenues
Interest income
(4
)
(4
)
Equipment proceeds
(2
)
(2
)
All other revenues including production revenues
(5)(6
)
(5)(6
)
(1)
Ninety percent of the subscription proceeds of you and the other investors in the partnership
in which you subscribe will be used to pay 100% of the intangible drilling costs incurred by
that partnership in drilling and completing its wells.
(2)
Ten percent of the subscription proceeds of you and the other investors in the partnership in
which you subscribe will be used to pay a portion of the equipment costs incurred by that
partnership in drilling and completing its wells. All equipment costs in excess of 10% of the
partnership’s subscription proceeds will be paid by the managing general partner. Thus, the
managing general partner will pay a majority of each partnership’s equipment costs. Equipment
proceeds, if any, will be credited in the same percentage in which the equipment costs were
charged. Thus, the managing general partner will receive a majority of any equipment
proceeds.
(3)
These costs will be charged to the parties in the same ratio as the related production
revenues are being credited. These costs also include the plugging and abandonment costs of
the wells after their economic reserves have been produced and depleted as described in
“Participation in Costs and Revenues.”
(4)
Interest earned on your subscription proceeds until they are paid to the managing general
partner for use in the drilling activities of the partnership in which you subscribed before
the final closing of the partnership to which you subscribed will be credited to your account
and paid to you not later than the partnership’s first cash distribution from operations.
After the subscription proceeds from the closing are invested in the partnership’s natural gas
and oil operations, any interest income from temporary investments will be allocated pro rata
to the investors providing the subscription proceeds. All other interest income, including
interest earned on the deposit of operating revenues, will be credited as natural gas and oil
production revenues are credited.
(5)
The managing general partner and you and the other investors in a partnership will share in
all of that partnership’s other revenues in the same percentage as their respective capital
contributions bears to the partnership’s total capital contributions, except that the managing
general partner will receive an additional 7% of the partnership revenues. However, the
managing general partner’s total revenue share may not exceed 40% of partnership revenues.
(6)
The actual allocation of partnership revenues between the managing general partner and you
and the other investors will vary from the allocation described in (5) above if a portion of
the managing general partner’s share of partnership net production revenues is subordinated as
described above.
The managing general partner will review each partnership’s accounts at least monthly to determine
whether cash distributions are appropriate and the amount to be distributed, if any. The
partnership in which you invest will distribute funds to you and its other investors that the
managing general partner does not believe are necessary for the partnership to retain. (See
“Participation in Costs and Revenues.”)
Compensation
As discussed in “Compensation,” the managing general partner and its affiliates will receive
substantial fees and profits in connection with this offering. The items of compensation paid to
the managing general partner and its affiliates from each partnership are as follows:
The managing general partner will receive a share of each partnership’s revenues.
The managing general partner’s revenue share will be in the same percentage as its
capital contribution bears to that partnership’s total capital contributions plus an
additional 7% of partnership revenues. However, the managing general partner’s revenue
share may not exceed a total of 40% of partnership revenues, regardless of the amount
of the managing general partner’s capital contribution, and a portion of the managing
general partner’s revenue share will be subject to the its subordination obligation.
•
The managing general partner will receive a credit to its capital account in an
amount equal to the cost of the leases contributed to a partnership by the managing
general partner, or the fair market value of the leases if the managing general partner
has reason to believe that cost is materially more than the fair market value.
•
Each partnership will enter into the drilling and operating agreement with the
managing general partner to drill and complete the partnership’s wells at competitive
rates as described in “Compensation — Drilling Contracts.”
•
When a partnership’s wells begin producing natural gas or oil in commercial
quantities, the managing general partner, as operator of the wells, will receive:
•
reimbursement at actual cost for all direct expenses incurred by it on behalf
of the partnership; and
•
well supervision fees for operating and maintaining the wells during
producing operations at a competitive rate.
•
The managing general partner will receive gathering fees at competitive rates for
its services in gathering and transporting a partnership’s natural gas production.
•
Subject to certain exceptions described in “Plan of Distribution,” Anthem
Securities, Inc., the dealer-manager and an affiliate of the managing general partner,
which is sometimes referred to in this prospectus as “Anthem Securities,” will receive
on each unit sold to an investor a 2.5% dealer-manager fee, a 7% sales commission and
up to a .5% reimbursement of the selling agents’ bona fide due diligence expenses.
•
The managing general partner or an affiliate will have the right to charge a
competitive rate of interest on any loan it may make to or on behalf of a partnership.
If the managing general partner provides equipment, supplies, and other services to a
partnership, then it may do so at competitive industry rates.
•
The managing general partner and its affiliates will receive a nonaccountable, fixed
payment reimbursement for their administrative costs, which has been determined by the
managing general partner to be $75 per well per month. The managing general partner
may not increase this fee during the term of the partnership.
An investment in a partnership involves a high degree of risk and is suitable only if you have
substantial financial means and no need of liquidity in your investment.
Risks Related To The Partnerships’ Oil and Gas Operations
No Guarantee of Return of Investment or Rate of Return on Investment Because of Speculative Nature
of Drilling Natural Gas and Oil Wells. Natural gas and oil exploration is an inherently
speculative activity. Before the drilling of a well the managing general partner cannot predict
with absolute certainty:
•
the volume of natural gas and oil recoverable from the well; or
•
the time it will take to recover the natural gas and oil.
You may not recover any or all of your investment in a partnership, or if you do recover your
investment in a partnership you may not receive a rate of return on your investment that is
competitive with other types of investment. You will be able to recover your investment only
through distributions of the partnership’s net proceeds from the sale of its natural gas and oil
from productive wells. The quantity of natural gas and oil in a well, which is referred to as its
reserves, decreases over time as the natural gas and oil is produced until the well is no longer
economical to operate. All of these distributions to you will be considered a return of capital
until you have received 100% of your investment. This means that you are not receiving a return on
your investment in a partnership, excluding tax benefits, until your total cash distributions from
the partnership exceed 100% of your investment. (See “Prior Activities.”)
Because Some Wells May Not Return Their Drilling and Completion Costs, It May Take Many Years to
Return Your Investment in Cash, If Ever. Even if a well is completed in a partnership and produces
natural gas and oil in commercial quantities, it may not produce enough natural gas and oil to pay
for the costs of drilling and completing the well, even if tax benefits are considered. For
example, the managing general partner has formed 54 partnerships since 1985 as set forth in “Prior
Activities,” however, 38 of the 54 partnerships have not yet returned to the investor 100% of his
capital contributions without taking tax savings into account. Thus, it may take many years to
return your investment in cash, if ever. The partnerships’ primary drilling areas are located in
the most active drilling areas in the Appalachian Basin. As a result, many of the leases which
will be drilled by a partnership are in areas that have already been partially depleted or drained
by earlier offset drilling. This may reduce a partnership’s ability to find economically
recoverable quantities of natural gas in those areas. (See “Prior Activities.”)
Nonproductive Wells May be Drilled Even Though the Partnerships’ Operations are Primarily Limited
to Development Drilling. Each partnership may drill some development wells that are nonproductive,
which is referred to as a “dry hole,” and must be plugged and abandoned. If one or more of a
partnership’s wells are nonproductive, then the partnership’s productive wells may not produce
enough revenues to offset the loss of investment in the nonproductive wells. (See “Prior
Activities.”)
Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and
Oil. The prices at which a partnership’s natural gas and oil will be sold are uncertain and, as
discussed in “- Adverse Events in Marketing a Partnership’s Natural Gas Could Reduce Partnership
Distributions,” the partnerships are not guaranteed a specific natural gas price for the sale of
their natural gas production. Changes in natural gas and oil prices will have a significant impact
on a partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may
not only decrease a partnership’s revenues, but also may reduce the amount of natural gas and oil
that a partnership can produce economically. Historically, natural gas and oil prices have been
volatile and it is likely that they will continue to be volatile in the future. Prices for natural
gas and oil will depend on supply and demand factors largely beyond the control of the partnerships
and prices may fluctuate widely in response to:
•
relatively minor changes in the supply of and demand for natural gas or oil;
a variety of additional factors that are beyond a partnership’s control, as
described in “Competition, Markets and Regulations — Competition and Markets.”
These factors make it extremely difficult to predict natural gas and oil price movements with any
certainty.
If natural gas and oil prices decrease in the future, then your partnership distributions will
decrease accordingly. Also, natural gas and oil prices may decrease during the first years of
production from your partnership’s wells which is when the wells typically achieve their greatest
level of production. This would have a greater adverse effect on your partnership distributions
than price decreases in later years when the wells have a lower level of production. Also, your
return level will decrease during the term of the partnership, even if there are rising natural gas
prices, because of declining production volumes from the wells over time. See “Appendix A -
Information Regarding Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.” for
a discussion of flush production and “Proposed Activities — Sale of Natural Gas and Oil
Production.” Further, as discussed in “Federal Income Tax Consequences — Depletion Allowance,” the
managing general partner has represented that most, if not all, of the natural gas and oil
production from your partnership’s productive wells will be marginal production under the Internal
Revenue Code and could qualify for potentially higher rates of percentage depletion. Thus, the
partnership will be more sensitive to price declines than if its wells produced at a higher average
rate of production that did not qualify for the potentially higher rate of percentage depletion.
Adverse Events in Marketing a Partnership’s Natural Gas Could Reduce Partnership Distributions. In
addition to the risk of decreased natural gas and oil prices described above, certain material
adverse events in marketing a partnership’s natural gas could reduce a partnership’s distributions
to you and its other investors. These risks are set forth below.
•
Competition from other natural gas producers and marketers in the Appalachian Basin,
as well as competition from alternative energy sources, may make it more difficult to
market each partnership’s natural gas.
•
The majority of each partnership’s natural gas production and that of the managing
general partner will be sold to a limited number of different natural gas purchasers as
described in “Proposed Activities — Sale of Natural Gas and Oil Production.” As set
forth in “Appendix A — Information Regarding Currently Proposed Prospects for Atlas
Resources Public #16-2007(A) L.P.,” the managing general partner has identified three
primary areas where it intends to drill each partnership’s wells. The managing general
partner anticipates that each partnership’s natural gas production in each of the three
primary areas initially will be sold to a different purchaser or purchasers in each
area. Each partnership will depend on a limited number of natural gas purchasers. If
a partnership loses a natural gas purchaser in a given area, the partnership may be
unable to locate a new natural gas purchaser in the area that will buy the
partnership’s natural gas on as favorable terms as the initial purchaser.
Although one of the partnership’s natural gas purchasers has a 10-year agreement,
which began on April 1, 1999, to buy all of the managing general partner’s and its
affiliates’ natural gas production, there are various exceptions to its obligation to
buy the natural gas. The most significant exception for each partnership includes
natural gas produced from the Fayette County, Pennsylvania area, which is where the
managing general partner anticipates that the majority of each partnership’s
prospects will be situated. The majority of the natural gas produced from the
Fayette County area by each partnership initially will be sold to four different
purchasers under natural gas contracts described in “Proposed Activities — Sale of
Natural Gas and Oil Production.” Of the remaining two primary areas, there will be a
different natural gas purchaser in each area and natural gas produced from only one
of those areas will be sold under the 10-year agreement referred to above.
Also, all of these natural gas purchase contracts provide that the price paid by the
natural gas purchaser may be adjusted upward or downward in accordance with the spot
market price and market conditions as described in “Proposed Activities — Sale of
Natural Gas and Oil Production.” Thus, the partnerships will not be guaranteed a
specific natural gas price, other than through hedging. To limit exposure to
changing natural gas prices, Atlas America and/or Atlas Energy Resources, LLC use
financial and physical hedges for their natural gas production, including the
partnerships and the managing general partner’s other
partnerships. Physical hedges are not deemed hedging for accounting purposes because
they require firm delivery of natural gas and are considered normal sales of natural
gas. These arrangements are limited to smaller quantities than those projected to be
available at any delivery point. In addition, Atlas America and/or Atlas Energy
Resources, LLC may enter into financial hedges, which may include purchases of
regulated NYMEX futures and options contracts and non-regulated over-the-counter
futures contracts with qualified counterparties. The futures contracts are
commitments to purchase or sell natural gas at future dates and generally cover
one-month periods for up to 36 months in the future.
The percentages of natural gas that are hedged through either financial hedges or
physical hedges, or are not hedged at all, will change from time to time in the
discretion of Atlas America and/or Atlas Energy Resources, LLC. It is difficult to
project what portion of these hedges will be allocated to each partnership by the
managing general partner because of uncertainty about the quantity, timing, and
delivery locations of natural gas that may be produced by a partnership.
By removing the price volatility from a portion, which may be substantial, of the
natural gas production from the partnerships, the managing general partner and its
affiliates will reduce, but not eliminate, the potential effects of changing natural
gas prices on a portion, which may be substantial, of the cash flow from the
partnerships for the periods covered by the hedges. Furthermore, while intended to
help reduce the effects of volatile natural gas prices, such transactions, depending
on the hedging instrument used, may limit the potential gains for the partnerships if
natural gas prices were to rise substantially over the price established by the
hedge. Under circumstances in which, among other things, production is substantially
less than expected, the counterparties to the futures contracts fail to perform under
the contracts or a sudden, unexpected event materially impacts natural gas prices,
the partnerships may be exposed to the risk of financial loss. See “Proposed
Activities — Sale of Natural Gas and Oil Production — Natural Gas Contracts.”
All of the natural gas contracts, including those described above, are between the
natural gas purchaser and either Atlas America, Atlas Energy Resources, LLC or an
affiliate. Either Atlas America, Atlas Energy Resources, LLC or an affiliate will
receive the sales proceeds from the natural gas purchasers and then distribute the
sales proceeds to each partnership based on the volume of natural gas produced by
each partnership. Until the sales proceeds are distributed to the partnerships, they
will be subject to the claims of Atlas America’s, Atlas Energy Resources, LLC’s, or
their affiliates’ creditors.
•
There is a credit risk associated with a natural gas purchaser’s ability to pay.
Each partnership may not be paid, or may experience delays in receiving payment, for
its natural gas that has already been delivered to the purchaser. In accordance with
industry practice, a partnership typically will deliver natural gas to a purchaser for
a period of up to 60 to 90 days before it receives payment. Thus, it is possible that
the partnership may not be paid for natural gas that already has been delivered if the
natural gas purchaser fails to pay for any reason, including bankruptcy. This ongoing
credit risk also may delay or interrupt the sale of the partnership’s natural gas or
the partnership’s negotiation of different terms and arrangements for selling its
natural gas to other purchasers. Finally, this credit risk may reduce the price
benefit derived by the partnerships from the managing general partner’s natural gas
hedging arrangements as described in “Proposed Activities — Sale of Natural Gas and Oil
Production — Natural Gas Contracts,” since from time to time the managing general
partner has implemented a portion of its natural gas hedges through the natural gas
purchasers.
•
A partnership’s net revenues will decrease the farther its natural gas is
transported for sale because of increased transportation costs.
•
Production from wells drilled in certain areas, such as wells drilled in the
Crawford County, Pennsylvania area and, to a lesser extent, the Fayette County,
Pennsylvania and Anderson, Campbell, Morgan, Scott and Roane Counties, Tennessee area,
may be delayed until construction of the necessary gathering lines and production
facilities is completed. (See “Proposed Activities — Sale of Natural Gas and Oil
Production — Gathering of Natural Gas.”)
The managing general partner anticipates that it will use the gathering system owned
by Atlas Pipeline Partners for the majority of a partnership’s natural gas as described
in “Proposed Activities — Sale of Natural Gas and Oil Production — Gathering of Natural
Gas.” Atlas Pipeline Partners GP, LLC, a wholly-owned subsidiary of Atlas Pipeline
Holdings, L.P., an affiliate of Atlas America, Inc., which is sometimes referred to in
this prospectus as “Atlas America” and is the indirect parent company of the managing
general partner, controls and manages the gathering system for Atlas Pipeline Partners.
(See “Management — Organizational Diagram and Security Ownership of Beneficial
Owners.”) However, Atlas Pipeline Holdings, L.P., as a public company, may be more
susceptible to a change of control from Atlas America’s affiliates to independent
third-parties.
Also, certain of the managing general partner’s affiliates, including Atlas America,
are obligated through their agreement with Atlas Pipeline Partners to pay the
difference between the amount a partnership pays for gathering fees to the managing
general partner as set forth in “Compensation — Gathering Fees,” and the greater of
$.35 per mcf or 16% of the gross sales price for the natural gas. This creates a
conflict of interest between the managing general partner and a partnership because
the managing general partner has an economic incentive to increase the amount of
gathering fees paid by a partnership so as to reduce the amount of gathering fees
paid by Atlas America to Atlas Pipeline Partners, but any increase cannot exceed a
competitive rate. Further, if Atlas Pipeline Partners GP, LLC were removed as
general partner of Atlas Pipeline Partners without cause and without its consent,
this could create further pressure to increase the amount of gathering fees required
to be paid by the partnerships for natural gas transported through Atlas Pipeline
Partners’ gathering system since Atlas Pipeline Partners GP, LLC would no longer
receive revenues from Atlas Pipeline Partners, but Atlas America and its affiliates
would be obligated to pay the difference between the amount in the master natural gas
gathering agreement and the amount paid by a partnership other than with respect to
new wells drilled, if any, by the partnership after the removal of Atlas Pipeline
Partners GP, LLC as general partner of Atlas Pipeline Partners. Thus, the managing
general partner and its affiliates would have an incentive to increase the gathering
fees charged to a partnership. Any increase in the gathering fees that your
partnership pays, which cannot exceed competitive rates, would reduce your cash
distributions from the partnership.
Possible Leasehold Defects. There may be defects in a partnership’s title to its leases. Although
the managing general partner will obtain a favorable formal title opinion for the leases before
each well is drilled, it will not obtain a division order title opinion after the well is
completed. Thus, a partnership may experience losses from title defects which arose during
drilling that would have been disclosed by a division order title opinion, such as liens arising
during drilling operations or transfers of interests in the leases after drilling begins. Also,
the managing general partner may use its own judgment in waiving title requirements for a
partnership’s leases and it will not be liable for any failure of title of leases transferred to a
partnership. (See “Proposed Activities — Title to Properties.”)
Transfer of the Leases Will Not Be Made Until Well is Completed. Because the leases will not be
transferred from the managing general partner to a partnership until after the wells are drilled
and completed, the transfer could be set aside by a creditor of the managing general partner, or
the trustee in the event of the voluntary or involuntary bankruptcy of the managing general
partner, if it were determined that the managing general partner received less than a reasonably
equivalent value for the leases. In this event, the leases and the wells would revert to the
creditors or trustee, and the partnership would either recover nothing or only the amount it paid
for the leases and the cost of drilling the wells. Assigning the leases to a partnership after the
wells are drilled and completed, however, will not affect the availability of the tax deductions
for intangible drilling costs since the partnership will have an economic interest in the wells
under the drilling and operating agreement before the wells are drilled. (See “Proposed Activities
- Title to Properties.”)
Participation with Third-Parties in Drilling Wells May Require the Partnerships to Pay Additional
Costs. Third-parties will participate with each partnership in drilling some of the well and
additional financial risks exist when the costs of drilling, equipping, completing, and operating
wells is shared by more than one person. If a partnership pays its share of the costs, but another
interest owner does not pay its share of the costs, then the partnership would have to pay the
costs of the defaulting party. In this event, the partnership would receive the defaulting party’s
revenues from the well, if any, under penalty arrangements set forth in the operating agreement,
which may, or may not, cover all of the additional costs paid by the partnership.
If the managing general partner is not the actual operator of the well for all of the working
interest owners of the well, then there is a risk that the managing general partner cannot
supervise the third-party operator closely enough. For example, decisions related to the following
would be made by the third-party operator and may not be in the best interests of the partnerships
and you and the other investors:
•
how the well is operated;
•
expenditures related to the well; and
•
possibly the marketing of the natural gas and oil production from the well.
Further, the third-party operator may have financial difficulties and fail to pay for materials or
services on the wells it drills or operates, which would cause the partnership to incur extra costs
in discharging materialmen’s and workmen’s liens. The managing general partner may not be the
operator of the well for all of the working interest owners of the well if the partnership owns
less than a 50% working interest in the well, or if the managing general partner acquired the
working interest in the well from a third-party under arrangements that required the third-party to
be named operator as one of the terms of the acquisition.
Risks Related to an Investment In a Partnership
If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner.
If you elect to invest in a partnership as an investor general partner for the tax benefits instead
of as a limited partner, then under Delaware law you will have unlimited liability for your
partnership’s activities until you are converted to limited partner status, subject to certain
exceptions described in “Actions To Be Taken by Managing General Partner To Reduce Risks of
Additional Payments By Investor General Partners — Conversion of Investor General Partner Units to
Limited Partner Units.” This could result in you being required to make payments, in addition to
your original investment, in amounts that are impossible to predict because of their uncertain
nature. Under the terms of the partnership agreement, if you are an investor general partner you
agree to pay only your proportionate share, as among all of your partnership’s investor general
partners, of your partnership’s obligations and liabilities. This agreement, however, does not
eliminate your liability to third-parties if another investor general partner does not pay his
proportionate share of your partnership’s obligations and liabilities.
Also, each partnership will own less than 100% of the working interest in some of its wells. If a
court holds you and the other third-party working interest owners of the well liable for the
development and operation of a well and the third-party working interest owners do not pay their
proportionate share of the costs and liabilities associated with the well, then the partnership and
you and the other investor general partners also would be liable for those costs and liabilities.
As an investor general partner you may become subject to the following:
•
contract liability, which is not covered by insurance;
•
liability for pollution, abuses of the environment, and other environmental damages
as discussed in “Competition, Markets and Regulation — Environmental Regulation,
including but not limited to the release of toxic gas, spills or uncontrollable flows
of natural gas, oil or well fluids, including underground or surface contamination,
against which the managing general partner cannot insure because coverage is not
available or against which it may elect not to insure because of high premium costs or
other reasons; and
•
liability for drilling hazards that result in property damage, personal injury, or
death to third-parties in amounts greater than the insurance coverage. The drilling
hazards include, but are not limited to, well blowouts, fires, craterings and
explosions.
If your partnership’s insurance proceeds and assets, the managing general partner’s indemnification
of you and the other investor general partners, and the liability coverage provided by major
subcontractors were not sufficient to satisfy the liability, then the managing general partner
would call for additional funds from you and the other investor general partners to satisfy the
liability. See “Actions To Be Taken By Managing General Partner To Reduce Risks of
Additional Payments by Investor General Partners,” including the managing general partner’s current
insurance coverage of $10 million for pollution liability, which may not be adequate.
Additionally, any of the drilling hazards may result in the loss of the well and the
associated revenues. Finally, an investor general partner may have liability if his partnership
does not properly plug and abandon a well. See “Participation in Costs and Revenues — Operating
Costs, Direct Costs, Administrative Costs and All Other Costs” relating to the costs associated
with plugging and abandoning wells.
The Managing General Partner May Not Meet Its Capital Contributions, Indemnification and Purchase
Obligations If Its Liquid Net Worth Is Not Sufficient. The managing general partner has made
commitments to you and the other investors in each partnership regarding the following:
•
the payment of organization and offering costs and the majority of equipment costs;
•
indemnification of the investor general partners for liabilities in excess of their
pro rata share of partnership assets and insurance proceeds, which commitment the
managing general partner has made in 51 of the partnerships it has sponsored; and
•
purchasing units presented by an investor, although this feature may be suspended by
the managing general partner if it determines, in its sole discretion, that it does not
have the necessary cash flow or cannot borrow funds for this purpose on reasonable
terms.
A significant financial reversal for the managing general partner could adversely affect its
ability to honor these obligations.
The managing general partner’s net worth is based primarily on the estimated value of its producing
natural gas properties and is not available in cash without borrowings or a sale of the properties.
Also, if natural gas prices decrease, then the estimated value of the properties and the managing
general partner’s net worth will be reduced. Further, price decreases will reduce the managing
general partner’s revenues, and may make some reserves uneconomic to produce. This would reduce
the managing general partner’s reserves and cash flow, and could cause the lenders of the managing
general partner and its affiliates to reduce the borrowing base for the managing general partner
and its affiliates. Also, because the majority of the managing general partner’s proved reserves
are currently natural gas reserves, the managing general partner’s net worth is more susceptible to
movements in natural gas prices than in oil prices.
The managing general partner’s net worth may not be sufficient, either currently or in the future,
to meet its financial commitments under the partnership agreement. These risks are increased
because the managing general partner has made similar financial commitments in most of its other
partnerships and will make this same commitment in future partnerships. See “Financial Information
Concerning the Managing General Partner and Atlas Resources Public #16-2007(A) L.P.”
An Investment in a Partnership Must be for the Long-Term Because the Units Are Illiquid and Not
Readily Transferable. If you invest in a partnership, then you must assume the risks of an
illiquid investment. The transferability of the units is limited by the securities laws, the tax
laws, and the partnership agreement. The units generally cannot be liquidated since there is not a
readily available market for the sale of the units. Further, the partnerships do not intend to
list the units on any exchange. (See “Transferability of Units — Restrictions on Transfer Imposed
by the Securities Laws, the Tax Laws and the Partnership Agreement.”)
Also, a sale of your units could create adverse tax and economic consequences for you. The sale or
exchange of all or part of your units held for more than 12 months generally will result in a
recognition of long-term capital gain or loss. However, previous deductions for depreciation,
depletion and intangible drilling costs may be recaptured as ordinary income rather than capital
gain regardless of how long you have owned your units. If you have held your units for 12 months
or less, then the gain or loss generally will be short-term gain or loss. Also, your pro rata
share of a partnership’s liabilities, if any, as of the date of the sale or exchange of your units
must be included in the amount realized by you. Thus, the gain recognized by you may result in a
tax liability greater than the cash proceeds, if any, received by you from the sale or other
disposition of your units, if permitted under the partnership agreement. (See “Federal Income Tax
Consequences — Disposition of Units” and “Presentment Feature.”)
Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum
Subscription Proceeds are Received and Fewer Wells are Drilled. Each partnership must receive
minimum subscription proceeds of $2 million to close the offering, and the subscription proceeds of
the partnerships, in the aggregate, may not exceed $200 million. There are no other requirements
regarding the size of a partnership other than the nonbinding targeted maximum
amounts described in “Terms of the Offering — Subscription to a Partnership.” Thus, the
subscription proceeds of one partnership may be substantially more or less than the subscription
proceeds of another partnership. A partnership with a smaller amount of subscription proceeds will
drill fewer wells which decreases the partnership’s ability to spread the risks of drilling. For
example, the managing general partner anticipates that a partnership will drill approximately seven
net wells if the minimum subscriptions of $2 million are received, which is compared with
approximately 710 net wells if subscription proceeds of $200 million are received by a partnership.
A gross well is a well in which a partnership owns a working interest. This is compared with a
net well which is the sum of the fractional working interests owned in the gross wells. For
example, a 50% working interest owned in three wells is three gross wells, but 1.5 net wells.
On the other hand, to the extent more than the minimum subscription proceeds are received by a
partnership and the number of wells drilled increases, the partnership’s overall investment return
may decrease if the managing general partner is unable to find enough suitable wells to be drilled.
(See “Proposed Activities — Acquisition of Leases.”) Also, to the extent a partnership’s
subscription proceeds and number of wells it drills increase, greater demands will be placed on the
managing general partner’s management capabilities.
In addition, the cost of drilling and completing a well is often uncertain and there may be cost
overruns in drilling and completing the wells because the wells will not be drilled and completed
on a turnkey basis for a fixed price, that would shift certain risks of loss to the managing
general partner as drilling contractor. The majority of the equipment costs of each partnership’s
wells will be paid by the managing general partner. However, all of the intangible drilling costs
of a partnership’s wells will be charged to you and the other investors in that partnership. If a
partnership incurs a cost overrun for the intangible drilling costs of a well or wells, then the
managing general partner anticipates that it would use the partnership’s subscription proceeds, if
available, to pay the cost overrun or advance the necessary funds to the partnership. Using
subscription proceeds to pay cost overruns charged to you and the other investors under the
partnership agreement will result in a partnership drilling fewer wells.
Increases in the Costs of the Wells May Adversely Affect Your Return. The increase in natural gas
and oil prices over the last several years has increased the demand for drilling rigs and other
related equipment, and the costs of drilling and completing natural gas and oil wells also have
increased. Because each partnership’s wells will be drilled on a modified cost plus basis as
described in “Compensation — Drilling Contracts,” these increased costs will increase the cost to
drill and complete each partnership’s wells. As compared with 2005, the managing general partner
estimates that its drilling and completion costs increased by approximately 26% in 2006 and may
continue to increase in the future. This means that fewer wells will be drilled by a partnership
in 2007 than it would have drilled if the drilling and completion costs of the wells had not
increased since 2005. On the other hand, if the price of natural gas and oil decreases before a
partnership’s wells are drilled, the drilling and completion costs of the wells to be drilled by
the partnerships would, in all likelihood, not be affected since the managing general partner
believes that, in the short term, drilling and completion costs are not likely to be reduced by a
drop in natural gas and oil prices. Also, the reduced availability of drilling rigs and other
related equipment may make it more difficult to drill a partnership’s wells in a timely manner or
to comply with the prepaid intangible drilling costs rules discussed in “Federal Income Tax
Consequences — Drilling Contracts.”
The Partnerships Do Not Own Any Prospects, the Managing General Partner Has Complete Discretion to
Select Which Prospects Are Acquired By a Partnership, and The Possible Lack of Information for a
Majority of the Prospects Decreases Your Ability to Evaluate the Feasibility of a Partnership. The
partnerships do not currently hold any interests in any prospects on which the wells will be
drilled, and the managing general partner has absolute discretion in determining which prospects
will be acquired to be drilled. The managing general partner has identified in “Proposed
Activities” the general areas where each partnership will drill wells and the managing general
partner intends that Atlas Resources Public #16-2007(A) L.P. will drill the prospects described in
“Appendix A — Information Regarding Currently Proposed Prospects for Atlas Resources Public
#16-2007(A) L.P.” These prospects represent the wells currently proposed to be drilled if a
portion of the targeted nonbinding amount of subscription proceeds is received by Atlas Resources
Public #16-2007(A) L.P. as described in “Terms of the Offering — Subscription to a Partnership.”
If there are material adverse events with respect to any of the currently proposed prospects, the
managing general partner will substitute a new prospect. The managing general partner also
anticipates that it will designate a portion of the prospects in Atlas Resources Public #16-2007(B)
L.P., if units are offered in that partnership, by a supplement or an amendment to the
registration statement of which this prospectus is a part. With respect to the identified
prospects to be drilled by a partnership, the managing general partner has the right on behalf of
the partnership to:
•
substitute prospects;
•
take a lesser working interest in the prospects;
•
drill in other areas; or
•
do any combination of the foregoing.
Thus, you do not have any geological or production information to evaluate any additional and/or
substituted prospects and wells. Also, if the subscription proceeds received by a partnership are
insufficient to drill all of the identified prospects, then the managing general partner will
choose those prospects which it believes are most suitable for the partnership. You must rely
entirely on the managing general partner to select the prospects and wells for a partnership.
In addition, the partnerships do not have the right of first refusal in the selection of prospects
from the inventory of the managing general partner and its affiliates, and they may sell their
prospects to other partnerships, companies, joint ventures, or other persons at any time.
Drilling Prospects in One Area May Increase Risk. If multiple wells are drilled in one area at
approximately the same time, then there is a greater risk that two or more of the wells will be
marginal or nonproductive since the managing general partner will not be using the drilling results
of one or more of those wells to decide whether or not to continue drilling prospects in that area
or to substitute other prospects in other areas. This is contrasted with the situation in which a
partnership drills one well in an area, and then assesses the drilling results before it decides to
drill a second well in the same area or to substitute a different prospect in another area.
This risk is further increased with respect to wells for which the drilling and completing costs
are prepaid in one year, and the drilling of the wells must begin within the first 90 days of the
immediately following year under the tax laws associated with deducting the intangible drilling
costs of the prepaid wells in the year in which the prepayment is made, rather than the year in
which the wells are drilled. For example, if the partnership prepays in 2007 the costs of drilling
one or more wells to be drilled in 2008, potential bad weather conditions during the first 90 days
of 2008 could delay beginning the drilling of one or more of the prepaid wells beyond the 90 day
time limit under the tax laws. This would have a greater adverse effect on the partnership’s
deduction for prepaid intangible drilling costs if the managing general partner is required to
begin drilling many wells at the same time, rather than only a few wells. Also, “frost laws”
prohibit drilling rigs and other heavy equipment from using certain roads during the winter, which
may delay beginning the drilling of the prepaid wells within the 90 day time limit in 2007 under
the tax laws. In addition, there could be shortages of drilling rigs, equipment, supplies and
personnel during this time period, or unexpected operational events and drilling conditions. (See
“Federal Income Tax Consequences — Drilling Contracts” regarding prepaid wells and the 90 day time
constraint.)
Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the
Feasibility of a Partnership’s Drilling Program. Production information from wells previously
drilled in the area surrounding the location where a new well is proposed to be drilled is an
important indicator in evaluating the economic potential of the well proposed to be drilled.
However, generally, there will be a lack of production information from surrounding wells for the
majority of the wells to be drilled by a partnership, which results in greater uncertainty to you
and the other investors. This lack of production information results primarily from the managing
general partner, as operator, proposing wells to be drilled in a partnership that are adjacent to
wells it has previously drilled as operator in prior partnerships that have not yet been completed,
have not yet been put on-line to sell production, or have been producing for only a short period of
time so there is little or no production information available. If the managing general partner
was not the operator of a previously drilled well, then the production information is not available
if the well was drilled within the last five years since the Pennsylvania Department of
Environmental Resources keeps production data confidential for the first five years from the time a
well starts producing.
The Partnerships In This Program and Other Partnerships Sponsored by the Managing General Partner
May Compete With Each Other for Prospects, Equipment, Subcontractors, and Personnel. One or more
partnerships in this program and
other partnerships sponsored by the managing general partner may have unexpended capital funds at
the same time. Thus, these partnerships may compete for suitable prospects, equipment,
subcontractors, and the managing general partner’s personnel. For example, a partnership
previously organized by the managing general partner may still be acquiring prospects to drill when
the partnerships in this program are attempting to acquire their prospects. This may make it more
difficult for the partnerships to complete their prospect acquisition and drilling activities and
may make each partnership less profitable.
Managing General Partner’s Subordination is Not a Guarantee of the Return of Any of Your
Investment. If your cash distributions from the partnership in which you invest are less than a
10% return of capital for each of the first five 12-month periods beginning with the partnership’s
first cash distribution from operations, then the managing general partner has agreed to
subordinate a portion of its share of the partnership’s net production revenues. However, if the
wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease,
then even with subordination you may not receive the 10% return of capital for each of the first
five years as described above, or a return of your capital during the term of the partnership.
Also, at any time during the subordination period the managing general partner is entitled to an
additional share of partnership revenues to recoup previous subordination distributions to the
extent your cash distributions from the partnership exceed the 10% return of capital described
above. (See “Participation in Costs and Revenues — Subordination of Portion of Managing General
Partner’s Net Revenue Share.”)
Borrowings by the Managing General Partner Could Reduce Funds Available for Its Subordination
Obligation. With respect to each partnership, the managing general partner has or will pledge
either its partnership interest and/or an undivided interest in the partnership’s assets equal to
or less than its revenue interest, which will range from 32% to 40%, depending on the amount of its
capital contribution, to secure borrowings for its and its affiliates’ general purposes. (See
“Participation in Costs and Revenues” and “Conflicts of Interest — Conflicts Regarding Managing
General Partner Withdrawing or Assigning an Interest.”) Under agreements previously entered into
as described in “Management’s Discussion and Analysis of Financial Condition, Results of
Operations, Liquidity and Capital Resources,” the managing general partner’s lenders have required
a first lien on the managing general partner’s interest in the natural gas and oil properties and
other assets of each partnership, and the lenders will have priority over the managing general
partner’s subordination obligation under the partnership agreement for each partnership. Thus, if
there was a default by the managing general partner to the lenders under this pledge arrangement,
or if there was a default by an affiliate of the managing general partner under this pledge
arrangement or another loan secured by this pledge arrangement, the amount of each partnership’s
net production revenues available to the managing general partner for its subordination obligation
to you and the other investors would be reduced or eliminated. Also, under certain circumstances,
if the managing general partner made a subordination distribution to you and the other investors
after a default to its lenders, then the lenders may be able to recoup that subordination
distribution from you and the other investors.
Compensation and Fees to the Managing General Partner Regardless of Success of a Partnership’s
Activities Will Reduce Cash Distributions. The managing general partner and its affiliates will
profit from their services in drilling, completing, and operating each partnership’s wells, and
will receive the other fees and reimbursement of direct costs described in “Compensation,”
regardless of the success of the partnership’s wells. These fees and direct costs will reduce the
amount of cash distributions to you and the other investors. The amount of the fees is subject to
the complete discretion of the managing general partner, other than the fees must not exceed
competitive fees charged by unaffiliated third-parties in the same geographic area engaged in
similar businesses and they must comply with any other restrictions set forth in “Compensation.”
With respect to direct costs, the managing general partner has sole discretion on behalf of each
partnership to select the provider of the services or goods and the provider’s compensation as
discussed in “Compensation.”
The Intended Monthly Distributions to Investors May be Reduced or Delayed. Cash distributions to
you and the other investors may not be paid each month. Distributions may be reduced or deferred,
in the discretion of the managing general partner, to the extent a partnership’s revenues are used
for any of the following:
•
compensation and fees to the managing general partner as described above in “-
Compensation and Fees to the Managing General Partner Regardless of Success of a
Partnership’s Activities Will Reduce Cash Distributions”;
remedial work to improve a well’s producing capability;
•
direct costs and general and administrative expenses of the partnership;
•
reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or
•
indemnification of the managing general partner and its affiliates by the
partnership for losses or liabilities incurred in connection with the partnership’s
activities. (See “Participation in Costs and Revenues — Distributions.”)
There Are Conflicts of Interest Between the Managing General Partner and the Investors. There are
conflicts of interest between you and the other investors and the managing general partner and its
affiliates. These conflicts of interest, which are not otherwise discussed in this “Risk Factors”
section, include the following:
•
the managing general partner has determined the compensation and reimbursement that
it and its affiliates will receive in connection with the partnerships without any
unaffiliated third-party dealing at arms’ length on behalf of you and the other
investors;
•
the managing general partner must monitor and enforce, on behalf of the
partnerships, its own compliance with the drilling and operating agreement and the
partnership agreement and the compliance of it and its affiliate, Atlas Pipeline
Partners, with the gas gathering agreement;
•
because the managing general partner will receive a percentage of revenues greater
than the percentage of costs that it pays, there may be a conflict of interest
concerning which wells will be drilled based on each wells’ risk and profit potential;
•
the allocation of all intangible drilling costs to you and the other investors and
the majority of the equipment costs to the managing general partner may create a
conflict of interest concerning whether to complete a well;
•
if the managing general partner, as tax matters partner, represents a partnership
before the IRS, potential conflicts include, for example, whether or not to expend
partnership funds to contest a proposed adjustment by the IRS, if any, to the amount of
your deduction for intangible drilling costs, or the credit to the managing general
partner’s capital account for contributing the leases to the partnership;
•
which wells will be drilled by the managing general partner’s and its affiliates’
other affiliated partnerships or third-party programs in which they serve as
driller/operator and which wells will be drilled by the partnerships in this program,
and the terms on which the partnerships’ leases will be acquired;
•
the managing general partner will have complete discretion in determining the terms
on which it or its affiliated limited partnerships may purchase producing wells from
each partnership;
•
the managing general partner and its officers, directors, and affiliates may
purchase units at a reduced price, which would dilute the voting rights of you and the
other investors on certain matters;
•
the same legal counsel represents the managing general partner and each partnership;
•
Atlas Pipeline Partners, an affiliate of the managing general partner, has the right
to determine the order of priority for constructing gathering lines for each
partnership’s wells;
•
Atlas Pipeline Partners, an affiliate of the managing general partner, will benefit
from the partnerships drilling wells that will connect to its gathering system; and
as discussed in “Proposed Activities,” the managing general partner has a drilling
commitment with Knox Energy for the drilling of 300 wells, which creates a conflict of
interest in deciding whether the managing general partner will select wells for each
partnership to drill in the areas that will help the managing general partner satisfy
this drilling commitment.
Other than certain guidelines set forth in “Conflicts of Interest,” the managing general partner
has no established procedures to resolve a conflict of interest. Also, the partnerships do not
have an independent investment committee. Thus, certain matters, including conflicts of interest
between a partnership and the managing general partner and its affiliates such as those described
above or set forth in “Conflicts of Interest,” may not be resolved as favorably to you and the
other investors in your partnership as they would be if there was an independent investment
committee.
The Presentment Obligation May Not Be Funded and the Presentment Price May Not Reflect Full Value.
Subject to certain conditions, beginning with the fifth calendar year after the offering of units
in your partnership closes you may present your units to the managing general partner for purchase.
However, the managing general partner may determine, in its sole discretion, that it does not have
the necessary cash flow or cannot borrow funds for this purpose on reasonable terms. In either
event the managing general partner may suspend the presentment feature. This risk is increased
because the managing general partner has and will incur similar presentment obligations in other
partnerships.
Further, the presentment price for your units may not reflect the full value of a partnership’s
property or your units because of the difficulty in accurately estimating natural gas and oil
reserves. Reservoir engineering is a subjective process of estimating underground accumulations of
natural gas and oil that cannot be measured in an exact way, and the accuracy of the reserve
estimate is a function of the quality of the available data and of engineering and geological
interpretation and judgment. Also, the reserves and future net revenues are based on various
assumptions as to natural gas and oil prices, taxes, development expenses, capital expenses,
operating expenses and availability of funds. Any significant variance in these assumptions could
materially affect the estimated quantity of the reserves. As a result, the managing general
partner’s estimates are inherently imprecise and may not correspond to realizable value. Thus, the
presentment price paid for your units and the amount of any partnership distributions received by
you before the presentment may be less than the subscription amount you paid for your units.
However, because the presentment price is a contractual price it is not reduced by discounts such
as minority interests and lack of marketability that generally are used to value partnership
interests for tax and other purposes. (See “Presentment Feature.”)
Finally, see “- An Investment in a Partnership Must be for the Long-Term Because the Units Are
Illiquid and Not Readily Transferable,” above, concerning the tax effects on you of presenting your
units for purchase.
The Managing General Partner May Not Devote the Necessary Time to the Partnerships Because Its
Management Obligations Are Not Exclusive. The partnerships do not have any employees and must rely
on the managing general partner and its affiliates for the management of it and its business, and
they may not devote the necessary time to the partnerships, which is in the managing general
partner’s discretion. Also, the managing general partner depends on its indirect parent companies,
Atlas America and Atlas Energy Resources, LLC, and their affiliates, for management and
administrative functions and financing for capital expenditures as discussed in “Management -
Transactions with Management and Affiliates.” The managing general partner and its affiliates will
be engaged in other oil and gas activities, including other partnerships and unrelated business
ventures for their own account or for the account of others, during the term of each partnership.
Thus, the competition for time and services of the managing general partner and its affiliates
could result in insufficient attention to the management and operation of the partnerships.
Prepaying Subscription Proceeds to the Managing General Partner May Expose the Subscription
Proceeds to Claims of the Managing General Partner’s Creditors. Under the drilling and operating
agreement, each partnership will be required to immediately pay the managing general partner the
investors’ share of the entire estimated price for drilling and completing the partnership’s wells.
Thus, these funds could be subject to claims of the managing general partner’s creditors. (See
“Financial Information Concerning the Managing General Partner and Atlas Resources Public
#16-2007(A) L.P.”)
Lack of Independent Underwriter May Reduce Due Diligence Investigation of the Partnerships and the
Managing General Partner. There has not been an extensive in-depth “due diligence” investigation
of the existing and proposed business activities of the partnerships and the managing general
partner that would be provided by independent underwriters. Anthem Securities, which is affiliated
with the managing general partner, serves as dealer-manager and will receive
reimbursement of bona fide due diligence expenses for certain due diligence investigations
conducted by the selling agents which it will reallow to the selling agents. However, Anthem
Securities’ due diligence examination concerning the partnerships cannot be considered to be
independent, nor as comprehensive as an investigation that would have been conducted by an
independent broker/dealer. (See “Conflicts of Interest.”)
A Lengthy Offering Period May Result in Delays in the Investment of Your Subscription and Any Cash
Distributions From the Partnership to You. Because the offering period for a particular
partnership can extend for many months, it is likely that there will be a delay in the investment
of your subscription proceeds. This may create a delay in the partnership’s cash distributions to
you which will be paid only after a portion of the partnership’s wells have been drilled, completed
and placed on-line for the delivery and sale of natural gas and/or oil, and payment has been
received from the purchaser of the natural gas and/or oil. Also, distributions of a partnership’s
net production revenues will be made only after payment of the managing general partner’s fees and
expenses and only if there is sufficient cash available in the managing general partner’s
discretion. See “Terms of the Offering” for a discussion of the procedures involved in the
offering of the units and the formation of a partnership.
The Partnerships are Subject to Comprehensive Federal, State and Local Laws and Regulations That
Could Increase the Cost and Alter the Manner or Feasibility of the Partnerships Doing Business.
The partnerships’ operations are regulated extensively at the federal, state and local levels.
Environmental and other governmental laws and regulations have increased the costs to plan, design,
drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations,
the partnerships could also be liable for personal injuries, property damage and other damages. In
addition, failure to comply with these laws and regulations may result in the suspension or
termination of a partnership’s operations and subject a partnership to administrative, civil and
criminal penalties.
Part of the regulatory environment in which the partnerships will operate includes, in some cases,
legal requirements for obtaining environmental assessments, environmental impact studies and/or
plans of development before beginning drilling and production activities. In addition, the
partnerships’ activities are subject to regulations regarding conservation practices and protection
of correlative rights. Further, the natural gas and oil regulatory environment could change in
ways that might substantially increase the financial and managerial costs of compliance with these
laws and regulations and, thus, reduce the partnerships’ profitability. Furthermore, the
partnerships may be put at a competitive disadvantage to larger companies in the oil and gas
industry who can spread these additional regulatory compliance costs over a greater number of
wells. See “Competition, Markets and Regulation” for a more detailed description of the laws and
regulations that affect the partnerships.
Your Interests May Be Diluted. The equity interests of you and the other investors in a
partnership may be diluted. You and the other investors will share in a partnership’s production
revenues from all of its wells in proportion to your respective number of units, based on $10,000
per unit, regardless of:
•
when you subscribe;
•
which wells are drilled with your subscription proceeds; or
•
the actual subscription price you paid for your units as described below.
Although subscription proceeds received by a partnership in different closings may be used to pay
the costs of drilling different wells depending on when the subscriptions are received, 90% of the
subscription proceeds of you and the other investors in your partnership will be used to pay
intangible drilling costs regardless of when you subscribe. However, the revenues from all of the
wells drilled in the partnership will be commingled regardless of when you subscribe and regardless
of which wells were drilled with the subscription proceeds in your closing and the results of those
wells.
Also, some investors, including the managing general partner and its officers and directors as
described in “Plan of Distribution,” may buy up to 5% of the total units in each partnership at
discounted prices because the dealer-manager fee, the sales commission and the reimbursement for
bona fide due diligence expenses will not be paid for those sales. These discounted subscription
prices will reduce the amount of the subscription proceeds available to a partnership to drill
wells. (See “- Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less
than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled.”) In addition,
all of the investors in each partnership will share in the
partnership’s production revenues with the managing general partner, based on the number of units
purchased by each investor, rather than the purchase price paid by the investor for his units.
Thus, investors who pay discounted prices for their units will receive higher returns on their
investments in a partnership as compared to investors who pay the entire $10,000 per unit.
Tax Risks
Your Deduction for Intangible Drilling Costs May Be Limited for Purposes of the Alternative Minimum
Tax. You will be allocated a share of your partnership’s deduction for intangible drilling costs
in 2007 in an amount equal to 90% of the subscription price you pay for your units. Under current
tax law, however, your alternative minimum taxable income in 2007 cannot be reduced by more than
40% by your deduction for intangible drilling costs. (See “Federal Income Tax Consequences -
Alternative Minimum Tax.”)
Limited Partners Need Passive Income to Use Their Deduction for Intangible Drilling Costs. If you
invest in a partnership as a limited partner (except as discussed below), your share of the
partnership’s deduction for intangible drilling costs in 2007 will be a passive loss that cannot be
used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends
and interest income. Thus, you may not have enough passive income from the partnership or net
passive income from your other passive activities, if any, in 2007, to offset a portion or all of
your passive deduction for intangible drilling costs in 2007. However, any unused passive loss
from intangible drilling costs may be carried forward indefinitely by you to offset your passive
income in subsequent taxable years. Also, except as described below, the passive activity
limitations on your share of the partnership’s deduction for intangible drilling costs in 2007 do
not apply to you if you invest in the partnership as a limited partner and you are a C corporation
which:
•
is not a personal service corporation or a closely held corporation;
•
is a personal service corporation in which employee-owners hold 10% (by value) or
less of the stock, but is not a closely held corporation; or
•
is a closely held corporation (i.e., five or fewer individuals own more than
50% (by value) of the stock), but is not a personal service corporation in which
employee-owners own more than 10% (by value) of the stock, in which case you may use
your passive losses to offset your net active income (calculated without regard to your
passive activity income and losses or portfolio income and losses).
(See “Federal Income Tax Consequences — Limitations on Passive Activity Losses and Credits.”)
You May Owe Taxes in Excess of Your Cash Distributions from Your Partnership. You may become
subject to income tax liability for your share of your partnership’s income in any taxable year in
an amount that is greater than the cash and any marginal well production credits you receive from
the partnership in which you invest in that taxable year. For example:
•
if the partnership borrows money, your share of partnership revenues used to pay
principal on the loan will be included in your income from the partnership and will not
be deductible;
•
income from sales of natural gas and oil may be included in your income from the
partnership in one tax year, although payment is not actually received by the
partnership and, thus, cannot be distributed to you, until the next tax year;
•
if there is a deficit in your capital account, the partnership may allocate income
or gain to you even though you do not receive a corresponding distribution of
partnership revenues;
•
the partnership’s revenues may be expended by the managing general partner for
nondeductible costs or retained in the partnership to establish a reserve for future
estimated costs, including a reserve for the estimated costs of eventually plugging and
abandoning the wells, which will increase your share of the partnership’s income
without a corresponding cash distribution to you; and
•
the taxable disposition of the partnership’s property or your units may result in
income tax liability to you in excess of the cash you receive from the transaction.
Investment Interest Deductions of Investor General Partners May Be Limited. If you invest in a
partnership as an investor general partner, your share of the partnership’s deduction for
intangible drilling costs will reduce your investment income and may reduce the amount of your
deductible investment interest expense, if any.
Your Tax Benefits from an Investment in a Partnership Are Not Contractually Protected. An
investment in a partnership does not give you any contractual protection against the possibility
that part or all of the intended tax benefits of your investment will be disallowed by the IRS. No
one provides any insurance, tax indemnity or similar agreement for the tax treatment of your
investment in a partnership. You have no right to rescind your investment in a partnership or to
receive a refund of any of your investment in the partnership if a portion or all of the intended
tax consequences of your investment in the partnership are ultimately disallowed by the IRS or the
courts. Also, none of the fees paid by the partnerships to the managing general partner, its
affiliates or independent third-parties (including special counsel which issued the tax opinion
letter) are refundable or contingent on whether the intended tax consequences of your investment in
a partnership are ultimately sustained if challenged by the IRS.
An IRS Audit of Your Partnership May Result in an IRS Audit of Your Personal Federal Income Tax
Returns. The IRS may audit each partnership’s annual federal information income tax returns,
particularly since each partnership’s investors will receive a deduction equal to not less than 90%
of their investment amount in 2007, which includes their respective deductions for intangible
drilling costs. If the partnership in which you invest is audited, the IRS also may audit your
personal federal income tax returns, including prior years’ returns and items which are unrelated
to the partnership. (See “Federal Income Tax Consequences — Penalties and Interest.”)
Each Partnership’s Deductions May be Challenged by the IRS. If the IRS audits a partnership, it
may challenge the amount of the partnership’s deductions and the taxable year in which the
deductions were claimed, including the deductions for intangible drilling costs and depreciation.
Any adjustments made by the IRS to the federal information income tax returns of the partnership in
which you invest could lead to adjustments on your personal federal income tax returns and could
reduce the amount of your deductions from the partnership in 2007 and subsequent tax years. The
IRS also could seek to recharacterize a portion of the partnership’s intangible drilling costs for
drilling and completing its wells as some other type of expense, such as lease costs or equipment
costs, which would reduce or defer your share of the partnership’s deductions for those costs.
(See “Federal Income Tax Consequences — Business Expenses,”“- Depreciation and Cost Recovery
Deductions,” and “- Drilling Contracts.”)
In addition, depending primarily on when its subscription proceeds are received, it is possible
that each partnership may prepay in 2007 most or all of its intangible drilling costs for wells the
drilling of which will not begin until 2008. In that event, you will not receive a deduction in
2007 for your share of the partnership’s prepaid intangible drilling costs for those wells unless
the drilling of the prepaid wells begins on or before the 90th day following the close
of the partnership’s taxable year in which the prepayment was made. Under the drilling and
operating agreement, the drilling of all of each partnership’s prepaid wells, if any, will be
required to begin within that 90 day time period. However, the drilling of any partnership well
may be delayed due to circumstances beyond the control of the managing general partner, acting as
general drilling contractor, without liability to the managing general partner. If for any reason
the drilling of a prepaid partnership well does not begin within the required 90 day time period in
2008, your deduction for prepaid intangible drilling costs for that well must be claimed for your
2008 tax year, instead of your 2007 tax year. Also, there is a greater risk that the IRS will
attempt to defer from 2007 to 2008 your share of the partnership’s deduction for intangible
drilling costs for drilling and completing any prepaid partnership wells if there are other
additional working interest owners of a prepaid well, because those other working interest owners
will not be required to prepay their share of the costs of drilling and completing the wells. (See
“Federal Income Tax Consequences — Drilling Contracts.”)
Changes in the Law May Reduce Your Tax Benefits From an Investment in a Partnership. Your tax
benefits from an investment in a partnership may be affected by changes in the tax laws. For
example, the top four federal income tax brackets for individuals were reduced in 2003, including
reducing the top bracket to 35% from 38.6%, until December 31, 2010. The lower federal income tax
rates will reduce to some degree the amount of taxes you save by virtue of your share of the
partnership’s deductions for intangible drilling costs, depletion, and depreciation, and its
marginal well production credits, if any. However, the federal income tax rates described above
could be changed again, even before January 1, 2011, and other changes in the tax laws could be
made which would affect your tax benefits from an investment in a partnership.
It May Be Many Years Before You Receive Any Marginal Well Production Credits, If Ever. There is a
federal income tax credit for the sale of qualified marginal natural gas and oil production.
Although the managing general partner anticipates that each partnership’s natural gas and oil
production will be qualified production for purposes of this tax credit, the managing general
partner further anticipates any natural gas and oil production sold by Atlas Resources Public
#16-2007(A) L.P. or Atlas Resources Public #16-2007(B) L.P. in 2007 will be sold at prices above
the applicable reference prices for 2006 at which the marginal well production credit would be
reduced to zero. In addition, depending primarily on market prices for natural gas and oil, which
are volatile, you may not receive any marginal well production credits from either partnership in
which you invest for many years, if ever. (See “Federal Income Tax Consequences — Marginal Well
Production Credits.”)
ADDITIONAL INFORMATION
The program and the partnerships composing the program currently are not required to file
reports with the SEC. However, a registration statement on Form S-1 has been filed on behalf of
the program with the SEC. Certain portions of the registration statement have been deleted from
this prospectus under SEC rules and regulations. You are urged to refer to the registration
statement, as amended, and its exhibits for further information concerning the provisions of
certain documents referred to in this prospectus.
You may read and copy any materials filed as a part of the registration statement, including the
tax opinion included as Exhibit 8, at the SEC’s Public Reference Room at 100 F Street, N.E.,
Washington, D.C. 20549. The SEC maintains an internet world wide web site that contains
registration statements, reports, proxy statements, and other information about issuers who file
electronically with the SEC, including the program. The address of that site is
http://www.sec.gov. Also, you may obtain information on the operation of the Public Reference Room
by calling the SEC at 1-800-SEC-0330. In addition, a copy of the tax opinion may be obtained by
you or your advisors from the managing general partner at no cost. The delivery of this prospectus
does not imply that its information is correct as of any time after its date.
FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS
Statements, other than statements of historical facts, included in this prospectus and its
exhibits address activities, events or developments that the managing general partner and the
partnerships anticipate will or may occur in the future. For example, the words “believes,”“anticipates,”“will” and “expects” are intended to identify forward-looking statements. These
forward-looking statements include such things as:
•
investment objectives;
•
references to future success in a partnership’s drilling and marketing activities;
•
business strategy;
•
estimated future capital expenditures;
•
competitive strengths and goals; and
•
other similar matters.
These statements are based on certain assumptions and analyses made by the partnerships and the
managing general partner in light of their experience and their perception of historical trends,
current conditions, and expected future developments. However, whether actual results will conform
with these expectations is subject to a number of risks and uncertainties, many of which are beyond
the control of the partnerships and the managing general partner, including, but not limited to:
•
general economic, market, or business conditions;
•
changes in laws or regulations;
•
the risk that the wells are productive, but do not produce enough revenue to return the investment made;
uncertainties concerning the price of natural gas and oil, which may decrease.
Thus, all of the forward-looking statements made in this prospectus and its exhibits are qualified
by these cautionary statements. There can be no assurance that actual results will conform with
the managing general partner’s and the partnerships’ expectations.
INVESTMENT OBJECTIVES
Each partnership’s principal investment objectives are to invest its subscription proceeds in
natural gas development wells which will:
•
Provide monthly cash distributions to you from the partnership in which you invest
until the wells are depleted, with a minimum annual return of capital of 10% during the
first five years beginning with your partnership’s first revenue distribution and based
on $10,000 per unit for all units sold regardless of the actual subscription price you
paid for your units. These distributions of a 10% return of capital during the first
five years are not guaranteed, but are subject to the managing general partner’s
subordination obligation. The managing general partner anticipates that investors in a
partnership will begin to receive monthly cash distributions approximately eight months
after the offering period for the partnership ends and it may take up to 12 months
before all of the wells in that partnership have been drilled and completed and are
on-line for the sale of their natural gas or oil production. However, if all or the
majority of the units are sold in Atlas Resources Public #16-2007(A) L.P., then it may
take longer for all of the wells to be drilled, completed and placed online to sell
production in that partnership. This will delay conversion of the investor general
partner units to limited partner units since the managing general partner will not
convert the investor general partner units to limited partner units in a partnership
until after all of the partnership’s wells have been drilled and completed. In this
regard, a well is deemed to be completed when production equipment is installed on a
well, even though the well may not yet be connected to a pipeline for production of
natural gas. Also, see “Participation in Costs and Revenues — Subordination of Portion
of Managing General Partner’s Net Revenue Share” for a discussion of the subordination
feature. The partnerships currently do not hold any interests in any prospects on
which the wells will be drilled.
•
Obtain tax deductions from the partnership in which you invest, in the year that you
invest, from intangible drilling costs to offset a portion of your taxable income from
sources other than the partnership, subject to the passive activity limitations on
losses if you invest as a limited partner. For example, if you pay $10,000 for a unit
your investment will produce an income tax deduction for intangible drilling costs of
$9,000 per unit, 90%, in the year you invest against:
•
ordinary income, or capital gain in some situations, if you invest as an
investor general partner in a partnership; or
•
net passive income from your other passive activity investments, if any, and
passive income from the partnership in the year you invest, if any, if you
invest as a limited partner in a partnership.
In 2003, the top four tax brackets for individual taxpayers were reduced from 38.6%
to 35%, 35% to 33%, 30% to 28%, and 27% to 25%. These changes are scheduled to
expire December 31, 2010. If you are in either the 35% or 33% tax bracket, you will
save approximately $3,150 or $2,970, respectively, per $10,000 unit, in federal
income taxes in the year that you invest. Most states also allow this type of a
deduction against the state income tax. If the partnership in which you invest
begins selling natural gas and oil production from its wells in the year in which you
invest, however, then you may be allocated a share of partnership income in that year
that will be offset by a portion of your intangible drilling cost deduction and your
share of the other partnership deductions discussed below.
Offset a portion of any gross production income generated by your partnership with
tax deductions from percentage depletion, which is anticipated by the managing general
partner to be 15% in 2007. The percentage depletion rate may fluctuate from year to
year depending on the price of oil, but under current tax law it will not be less than
the statutory rate of 15% nor more than 25%.
•
Obtain tax deductions of the remaining 10% of your investment over a seven-year cost
recovery period, beginning in the year the wells are drilled, completed and placed in
service for the production of natural gas or oil in the partnership in which you
invest. For example, if you pay $10,000 for a unit, you will receive additional income
tax deductions over the cost recovery period totaling $1,000 per unit for depreciation
of your partnership’s equipment costs for its productive wells.
•
If you are self-employed and invest in a partnership as an investor general partner,
then you may use your share of the partnership’s deduction for intangible drilling
costs to offset a portion of your net earnings from self-employment in the year you
invest. Also, if wells in the partnership are drilled and completed and placed in
service in the year you invest, you will begin receiving the depreciation deductions
discussed above which, to the extent they exceed your share of your partnership’s
income, if any, in the year in which you invest, also will reduce your net earnings
from self-employment in the year you invest, and in your subsequent tax years during
the seven-year cost recovery period.
Attainment of these investment objectives by a partnership will depend on many factors, including
the ability of the managing general partner to select suitable wells that will be productive and
produce enough revenue to return the investment made. The success of each partnership depends
largely on future economic conditions, especially the future price of natural gas, which is
volatile and may decrease. Also, the extent to which each partnership attains the foregoing
investment objectives will be different, because each partnership is a separate business entity
which:
•
generally will drill different wells;
•
will likely receive a different amount of subscription proceeds, as intended by the
managing general partner, which generally will be the primary factor in determining the
number of wells that can be drilled by each partnership; and
•
may drill wells situated in different geographical areas, where the wells will be
drilled to different formations, reservoirs or depths, which will affect the cost of
the wells and, thus, will also affect the number of wells that can be drilled by each
partnership.
There can be no guarantee that the foregoing objectives will be attained.
ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS
OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS
You may choose to invest in a partnership as an investor general partner so that you can
receive an immediate tax deduction against any type of income. To help reduce the risk that you
and other investor general partners could be required to make additional payments to the
partnership, the managing general partner will take the actions set forth below.
•
Insurance. The managing general partner will obtain and maintain
insurance coverage in amounts and for purposes which would be carried by a reasonable,
prudent general contractor and operator in accordance with industry standards. Each
partnership will be included as an insured under these general, umbrella, and excess
liability policies. In addition, the managing general partner requires all of its
subcontractors to certify that they have acceptable insurance coverage for worker’s
compensation and general, auto, and excess liability coverage. Major subcontractors
are required to carry general and auto liability insurance with a minimum of $1 million
combined single limit for bodily injury and property damage in any one occurrence or
accident. In the event of a loss caused by a major subcontractor, the managing general
partner or partnership may attempt to draw on the insurance policy of the particular
subcontractor before the insurance of the managing general partner or that of the
partnership, but currently would be unable to do so since none of its major
subcontractors have insurance which would allow this. Also, even if a major
subcontractor’s insurance was initially available, the managing general partner or a
partnership may choose to draw on its own insurance coverage before that of the major
subcontractor so that its insurance carrier will control the payment of claims.
The managing general partner’s current insurance coverage satisfies the following
specifications:
•
worker’s compensation insurance in full compliance with the laws of the
Commonwealth of Pennsylvania and any other applicable state laws where the wells
will be drilled;
•
commercial general liability covering bodily injury and property damage third
party liability, including products/completed operations, blow out, cratering,
and explosion with limits of $1 million per occurrence/$2 million general
aggregate; and $1 million products/completed operations aggregate;
•
underground resources and equipment property damages liability to others with
a limit of $1 million;
•
automobile liability with a $1 million combined single limit;
•
employer’s liability with a $500,000 policy limit;
•
pollution liability resulting from a “pollution incident,” which is defined
as the discharge, dispersal, seepage, migration, release or escape of one or
more pollutants directly from a well site, with a limit of $1 million for bodily
injury and property damage and a limit of $100,000 for clean-up for
third-parties; however, coverage does not apply to pollution damage to the well
site itself or the property of the insured;
•
commercial umbrella liability composed of:
•
primary umbrella limit of $25 million over general
liability, automobile liability, and employer’s liability and a $10
million sublimit for pollution liability; and
•
excess liability providing excess limits of $24 million over
the $25 million provided in the commercial umbrella, which is for general
liability only.
Because the managing general partner is driller and operator of wells for other
partnerships, the insurance available to each partnership could be substantially less
if insurance claims are made in the other partnerships.
This insurance has deductibles, which would first have to be paid by a partnership, of:
•
$2,500 per occurrence for bodily injury and property damage; and
•
$10,000 per pollution incident for pollution damage.
The insurance also has terms, including exclusions, that are standard for the natural
gas and oil industry. On request the managing general partner will provide you or
your representative a copy of its insurance policies. The managing general partner
will use its best efforts to maintain insurance coverage that meets its current
coverage, but it may be unsuccessful if the coverage becomes unavailable or too
expensive.
If you are an investor general partner and there is going to be a material adverse
change in your partnership’s insurance coverage, which the managing general partner
does not anticipate, then the
managing general partner will notify you at least 30 days before the effective date
of the change. You will then have the right to convert your units into limited
partner units before the change in insurance coverage by giving written notice to the
managing general partner.
•
Conversion of Investor General Partner Units to Limited Partner Units. Your
investor general partner units will be automatically converted by the managing general
partner to limited partner units after all of the wells in your partnership have been
drilled and completed. In this regard, a well is deemed to be completed when
production equipment is installed on a well, even though the well may not yet be
connected to a pipeline for production of natural gas. In each partnership, the
managing general partner anticipates that all of the wells will be drilled and
completed no more than 12 months after a partnership closes, and the conversion will
occur before the end of the succeeding tax year. However, if all or the majority of
the units are sold in Atlas Resources Public #16-2007(A) L.P., then it may take longer
for all of the wells to be drilled and completed in that partnership than if fewer
units were sold in that partnership and there were fewer wells drilled and completed.
This will delay conversion of the investor general partner units to limited partner
units since the managing general partner will not convert the investor general partner
units to limited partner units in a partnership until after all of the partnership’s
wells have been drilled and completed.
Once your units are converted, which is a nontaxable event, you will have the lesser
liability of a limited partner in your partnership under Delaware law for obligations
and liabilities arising after the conversion. However, you will continue to have the
responsibilities of a general partner for partnership liabilities and obligations
incurred before the effective date of the conversion. For example, you might become
liable for partnership liabilities in excess of your subscription amount during the
time the partnership is engaged in drilling activities and for environmental claims
that arose during drilling activities, but were not discovered until after the
conversion.
•
Nonrecourse Debt. The partnerships do not anticipate that they will borrow funds.
However, if borrowings are required, then the partnerships will be permitted to borrow
funds only from the managing general partner or its affiliates and without recourse
against non-partnership assets. Thus, if there is a default under this loan
arrangement you cannot be required to contribute funds to the partnership. Any
borrowings by a partnership will be repaid from that partnership’s revenues.
The amount that may be borrowed at any one time by a partnership may not exceed an
amount equal to 5% of the investors’ subscription proceeds in the partnership.
However, because you do not bear the risk of repaying these borrowings with
non-partnership assets, the borrowings will not increase the extent to which you are
allowed to deduct your individual share of partnership losses. (See “Federal Income
Tax Consequences — Tax Basis of Units” and “- ‘At Risk’ Limitation on Losses.”)
•
Indemnification. The managing general partner will indemnify you from any liability
incurred in connection with your partnership that is in excess of your interest in the
partnership’s:
•
undistributed net assets; and
•
insurance proceeds, if any, from all potential sources.
The managing general partner’s indemnification obligation, however, will not
eliminate your potential liability if the managing general partner’s assets are
insufficient to satisfy its indemnification obligation. There can be no assurance
that the managing general partner’s assets, including its liquid assets, will be
sufficient to satisfy its indemnification obligation. The managing general partner
has agreed to this indemnification obligation in 51 of its prior partnerships.
CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS
Source of Funds
Each partnership must receive minimum subscription proceeds of $2 million to close, and the
subscription proceeds of both partnerships, in the aggregate, may not exceed $200 million. There
are no other requirements regarding the size of a partnership, and the subscription proceeds of one
partnership may be substantially more or less than the subscription proceeds of the other
partnership. See the targeted maximum subscription amounts for each partnership set forth in
“Terms of the Offering – Subscription to a Partnership.” Also, the managing general partner has
the discretion to accept subscriptions for any amount up to and including the entire amount in
Atlas Resources Public #16-2007(A) L.P. and not offer and sell any units in the other partnership.
(See “Terms of the Offering – Subscription to a Partnership.”)
On completion of the offering of units in a partnership, the partnership’s source of funds will be
as follows assuming each unit is sold for $10,000:
•
the subscription proceeds of you and the other investors, which will be:
•
$2 million if 200 units are sold; and
•
$200 million if 20,000 units are sold; and
•
the managing general partner’s capital contribution, which must be at least 25% of
all capital contributions and includes its credit for organization and offering costs
and contributing the leases, which will be:
•
not less than approximately $781,233 if 200 units are sold; and
•
not less than approximately $78,810,820 if 20,000 units are sold.
Thus, the total amount available to a partnership will be not less than approximately $2,781,233 if
200 units are sold ranging to not less than approximately $278,810,820 if 20,000 units are sold.
The managing general partner has made the largest single capital contribution in each of its prior
partnerships and no individual investor has contributed more, although the total investor
contributions in each partnership have exceeded the managing general partner’s contribution. The
managing general partner also expects to make the largest single capital contribution in each of
the partnerships.
Use of Proceeds
The subscription proceeds received from you and the other investors will be used by the partnership
in which you invest as follows:
•
90% of the subscription proceeds will be used to pay 100% of the intangible drilling
costs of drilling and completing the partnership’s wells; and
•
10% of the subscription proceeds will be used to pay a portion of the equipment
costs of drilling and completing the partnership’s wells.
The managing general partner will contribute all of the leases to each partnership covering the
acreage on which the partnership’s wells will be drilled, and pay all of the equipment costs of
drilling and completing the partnership’s wells that exceed 10% of the partnership’s subscription
proceeds. Thus, the managing general partner will pay the majority of each partnership’s equipment
costs. The managing general partner also will be charged with 100% of the organization and
offering costs for each partnership. A portion of these contributions to each partnership will be
in the form of payments to itself, its affiliates and third-parties and the remainder will be in
the form of services related to organizing this offering. The managing general partner will
receive a credit towards its required capital contribution to each partnership for these payments
and services as discussed in “Participation in Costs and Revenues.”
The following tables present information concerning each partnership’s use of the proceeds provided
by both you and the other investors and the managing general partner. The tables are based in part
on the managing general partner’s estimate of its capital contribution to a partnership based on
the applicable number of units sold as shown in the table. The managing general partner’s
estimated capital contribution shown in the tables includes its credit for organization and
offering costs and contributing the leases, and exceeds in each case its required capital
contribution of not less than 25% of all capital contributions to a partnership. Anthem
Securities, an affiliate of the managing general partner, will be the dealer-manager of each
offering and it will receive the dealer-manager fee, the sales commissions and the up to .5%
reimbursement for bona fide due diligence expenses. A portion of these payments and
reimbursements, including all of the up to .5% reimbursement for bona fide due diligence expenses,
will be reallowed by the dealer-manager to the broker/dealers, which are referred to as selling
agents, as discussed in “Plan of Distribution.” Subject to the above, a partnership’s
organizational costs will be paid to the managing general partner, its affiliates and various
third-parties, and the intangible drilling costs and tangible costs of drilling and completing a
partnership’s wells will be paid to the managing general partner as general drilling contractor and
operator under the drilling and operating agreement.
The tables are presented based on:
•
the sale of 200 units ($2 million), which is the minimum number of units for each partnership; and
•
the sale of 20,000 units, which is the maximum number of units, in the aggregate,
for all the partnerships in the program.
Substantially all of the proceeds available to each partnership will be expended for the following
purposes and in the following manner:
INVESTOR CAPITAL
200
20,000 UNITS
NATURE OF PAYMENT
UNITS SOLD
% (1)
SOLD
% (1)
Organization and Offering Expenses
Dealer-manager fee, sales
commissions and up to .5%
reimbursement for bona fide due
diligence expenses
- 0 -
- 0 -
- 0 -
- 0 -
Organization costs
- 0 -
- 0 -
- 0 -
- 0 -
Amount Available for Investment:
Intangible drilling costs (2)
$
1,800,000
90
%
$
180,000,000
90
%
Equipment costs (2)
$
200,000
10
%
$
20,000,000
10
%
Leases
- 0 -
- 0 -
- 0 -
- 0 -
Total Investor Capital
$
2,000,000
100
%
$
200,000,000
100
%
(1)
The percentage is based on the investors’ total subscription proceeds, and excludes the
managing general partner’s estimate of its capital contributions in the “– Managing General
Partner Capital” table below.
(2)
Ninety percent of the subscription proceeds provided by you and the other investors to each
partnership will be used to pay 100% of the partnership’s intangible drilling costs. Ten
percent of the subscription proceeds provided by you and the other investors to each
partnership will be used to pay a portion of the partnership’s equipment costs. (See
“Participation in Costs and Revenues.”) The managing general partner will pay all of the
remaining equipment costs of each partnership. In this regard, the managing general partner’s
share of each partnership’s equipment costs as set forth in the “– Managing General Partner
Capital” and the “– Total Partnership Capital” tables below is based on the managing general
partner’s estimate of the average cost of drilling and completing wells in each partnership’s
primary areas as discussed in “Compensation – Drilling Contracts.”
Dealer-manager fee, sales commissions
and up to .5% reimbursement for bona
fide due diligence expenses (2)
$
200,000
25.60
%
$
20,000,000
26.65
%
Organization costs (2)
$
100,000
12.80
%
$
10,000,000
11.42
%
Amount Available for Investment:
Intangible drilling costs
- 0 -
- 0 -
- 0 -
- 0 -
Equipment costs (3)
$
402,063
51.47
%
$
40,780,720
51.74
%
Leases (4)
$
79,170
10.13
%
$
8,030,100
10.19
%
Total Managing General Partner Capital
$
781,233
100
%
$
78,810,820
100
%
(1)
The percentage is based on the managing general partner’s estimate of its capital
contributions, and excludes the investors’ total subscription proceeds set forth in the “–
Investor Capital” table above.
(2)
As discussed in “Participation in Costs and Revenues,” if these fees, sales commissions,
reimbursements and organization costs exceed 15% of the investors’ total subscription proceeds
in a partnership, then the excess will be charged to the managing general partner, but will
not be included as part of its capital contribution.
(3)
The managing general partner’s share of equipment costs is described in “Compensation –
Drilling Contracts” and “Participation in Costs and Revenues.” However, these costs will vary
depending on the actual equipment costs of drilling and completing the wells. Also, see
footnote (2) to the “– Investor Capital” table above.
(4)
Instead of contributing cash for the leases, the managing general partner will assign to each
partnership the leases covering the acreage on which the partnership’s wells will be drilled.
Generally, as described in “Compensation – Lease Costs,” the managing general partner’s lease
costs are approximately $11,310 per prospect. For purposes of this table, the managing
general partner’s lease costs have been quantified using this amount based on its estimate of
the number of net wells that will be drilled with the amount of subscription proceeds
available as set forth in the table. The actual number of net wells drilled by the
partnerships is likely to vary from the managing general partner’s estimate, based primarily
on where the wells are drilled and the actual costs of drilling and completing the wells.
Also, the managing general partner’s lease costs on a prospect may be significantly higher
than the above-referenced amount, and its credit for the leases contributed will equal its
cost, unless it has a reason to believe that cost is materially more than fair market value of
the property, in which case its credit for its lease contribution must not exceed fair market
value.
Dealer-manager fee, sales
commissions and up to .5%
reimbursement for bona fide due
diligence expenses (2)
$
200,000
7.19
%
$
20,000,000
7.17
%
Organization costs (2)
$
100,000
3.59
%
$
10,000,000
3.59
%
Amount Available for Investment:
Intangible drilling costs (3)
$
1,800,000
64.72
%
$
180,000,000
64.56
%
Equipment costs (3)
$
602,063
21.65
%
$
60,780,720
21.80
%
Leases (4)
$
79,170
2.85
%
$
8,030,100
2.88
%
Total Partnership Capital
$
2,781,233
100
%
$
278,810,820
100
%
(1)
The percentage is based on investors’ total subscription proceeds in the “– Investor Capital
Table” above, and the managing general partner’s estimate of its capital contributions in the
“– Managing General Partner Capital” table above.
(2)
As discussed in “Participation in Costs and Revenues,” if these fees, sales commissions,
reimbursements and organization costs exceed 15% of the investors’ total subscription
proceeds in a partnership, then the excess will be charged to the managing general partner,
but will not be included as part of its capital contribution.
(3)
The managing general partner’s share of equipment costs is described in “Compensation –
Drilling Contracts” and “Participation in Costs and Revenues.” Although these costs will
vary depending on the actual equipment costs of drilling and completing the wells, 90% of the
subscription proceeds provided by you and the other investors will be used to pay intangible
drilling costs and 10% will be used to pay equipment costs. Also, see footnote (2) to the “–
Investor Capital” table, above.
(4)
Instead of contributing cash for the leases, the managing general partner will assign to
each partnership the leases covering the acreage on which that partnership’s wells will be
drilled as set forth in footnote (4) to the “– Managing General Partner Capital” table above.
COMPENSATION
The items of compensation to be paid to the managing general partner and its affiliates from
each partnership are set forth below. Most of these items of compensation depend on how many wells
a partnership drills and how much of the working interest in each of the wells is owned by the
partnership. In this regard, the managing general partner estimates that approximately eight gross
wells, which will be approximately seven net wells, will be drilled if the minimum required
subscription proceeds of $2 million are received by a partnership, and approximately 777 gross
wells, which will be approximately 710 net wells, will be drilled, in the aggregate, if
subscription proceeds of $200 million are received by a partnership or the partnerships. Also,
following the narrative discussion for all items of compensation is a tabular presentation based on
the narrative discussion.
A gross well is a well in which a partnership owns a working interest. This is compared with a net
well, which is the sum of the fractional working interests owned in the gross wells. For example,
a 50% working interest owned in three wells is three gross wells, but 1.5 net wells. However, the
managing general partner’s estimated number of wells to be drilled by a partnership or the
partnerships is subject to risks that can cause the actual number of wells drilled by a partnership
or the partnerships to vary from the managing general partner’s estimate. (See “Risk Factors –
Risks Related to an Investment in a Partnership – The Partnerships Do Not Own Any Prospects, the
Managing General Partner Has Complete Discretion to Select Which Prospects are Acquired By a
Partnership, and The Possible Lack of Information for a Majority of the Prospects Decreases Your
Ability to Evaluate the Feasibility of a Partnership.”)
Subject to certain exceptions described in “Plan of Distribution,” Anthem Securities, the
dealer-manager and an affiliate of the managing general partner, will receive on each unit sold to
an investor:
•
a 2.5% dealer-manager fee;
•
a 7% sales commission; and
•
an up to .5% reimbursement of the selling agents’ bona fide due diligence expenses.
Assuming the above amounts are paid for all units sold, the dealer-manager will receive:
•
$200,000 if subscription proceeds of $2 million are received by a partnership; and
•
$20 million if subscription proceeds of $200 million are received by the partnerships.
All of the reimbursement of the selling agents’ bona fide due diligence expenses, and generally all
of the sales commissions, will be reallowed to the selling agents. A portion of the 2.5%
dealer-manager fee will be reallowed to the wholesalers who are associated with the managing
general partner and registered through Anthem Securities for subscriptions obtained through their
efforts. Also, a portion of the dealer-manager fee may be reallowed to the selling agents as
described in “Plan of Distribution.” The dealer-manager will retain any of the compensation which
is not reallowed. See “Management” for the ownership of Anthem Securities.
Natural Gas and Oil Revenues
Subject to the managing general partner’s subordination obligation, the investors and the managing
general partner will share in each partnership’s revenues in the same percentages as their
respective capital contributions bear to the total partnership capital contributions for that
partnership except that the managing general partner will receive an additional 7% of that
partnership’s revenues. However, the managing general partner’s total revenue share may not exceed
40% of that partnership’s revenues regardless of the amount of its capital contribution.
For example, if the managing general partner contributes the minimum of 25% of a partnership’s
total capital contributions and the investors contribute 75% of the partnership’s total capital
contributions, then the managing general partner will receive 32% of the partnership’s revenues and
the investors will receive 68% of the partnership’s revenues as shown by the bar chart set forth
below.
On the other hand, if the managing general partner contributes 35% of a partnership’s total capital
contributions and the investors contribute 65% of the partnership’s total capital contributions,
then the managing general partner will receive 40%
of the partnership’s revenues, not 42%, because
its revenue share cannot exceed 40% of the partnership’s revenues, and the investors will receive
60% of the partnership’s revenues as shown by the bar chart set forth below.
As noted above, up to 50% of the managing general partner’s revenue share from each partnership is
subject to its subordination obligation as described in “Participation in Costs and Revenues –
Subordination of Portion of Managing General Partner’s Net Revenue Share” and the accompanying
tables. For example, if the managing general partner’s revenue share is 35% of the partnership’s
revenues, then up to 17.5% of the managing general partner’s partnership net production revenues
could be used for its subordination obligation.
Lease Costs
Under the partnership agreement the managing general partner will contribute to each partnership
all the undeveloped leases necessary to cover each of the partnership’s prospects. The managing
general partner will receive a credit to its capital account equal to:
•
the cost of the leases; or
•
the fair market value of the leases if the managing general partner has reason to
believe that cost is materially more than the fair market value.
In the primary drilling areas, the managing general partner’s lease costs are approximately $11,310
per prospect assuming a partnership acquires 100% of the working interest in the prospect. The
cost of the leases includes a portion of the managing general partner’s reasonable, necessary and
actual expenses for geological, engineering, drafting, accounting, legal and other like services
allocated to the leases in conformity with generally accepted accounting principles and industry
standards. Also, the managing general partner has averaged the cost of all of its leases to arrive
at the average lease cost of $11,310 per prospect, which the managing general partner believes is
less than fair market value. Notwithstanding, from time to time, the managing general partner’s
lease costs on a prospect may be significantly higher than this amount, and in that event the
managing general partner’s credit to its capital contribution to the partnership and its capital
account under the partnership agreement will be the greater amount.
The managing general partner’s credit for its lease costs for a prospect will be proportionally
reduced to the extent a partnership acquires less than 100% of the working interest in the
prospect. In this regard, a working interest generally means an interest in the lease under which
the owner of the working interest must pay some portion of the cost of development, operation, or
maintenance of the well. Assuming all the leases are situated in the primary areas, the managing
general partner estimates that its total credit for lease costs will be:
•
$79,170 if subscription proceeds of $2 million are received, which is seven net
wells times $11,310 per prospect; and
$8,030,100 if subscription proceeds of $200 million are received, which is 710 net
wells times $11,310 per prospect.
Drilling a partnership’s wells also may provide the managing general partner with offset prospects
to be drilled by allowing it to determine at the partnership’s expense the value of adjacent
acreage in which the partnership would not have any interest. Further, the managing general
partner may drill wells on leases that are scheduled to expire in order to prevent the expiration
of the lease.
Drilling Contracts
Each partnership will enter into the drilling and operating agreement with the managing general
partner to drill and complete each partnership’s wells for an amount equal to the sum of the
following items: (i) the cost of permits, supplies, materials, equipment, and all other items used
in the drilling and completion of a well provided by third-parties, or if the foregoing items are
provided by affiliates of the managing general partner, then those items will be charged at
competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the
managing general partner’s affiliates, which will be charged at competitive rates; (iv) an
administration and oversight fee of $15,000 per well, which will be charged to you and the other
investors as part of each well’s intangible drilling costs and the portion of equipment costs paid
by you and the other investors; and (v) a mark-up in an amount equal to 15% of the sum of (i),
(ii), (iii) and (iv), above, for the managing general partner’s services as general drilling
contractor. Notwithstanding, if the managing general partner drills a well for a partnership that
it determines is not an average well in the area because of the well’s depth, complexity associated
with either drilling or completing the well or as otherwise determined by the managing general
partner, the administration and oversight fee of $15,000 per well described in §4.02(d)(1)(iv) of
the partnership agreement may be increased to a competitive rate as determined by the managing
general partner.
The managing general partner has determined that this is a competitive rate based on:
•
information it has concerning drilling rates of third-party operators in the Appalachian Basin;
•
the estimated costs of non-affiliated persons to drill and equip wells in the
Appalachian Basin as reported for 2004 in a survey prepared by the Independent
Petroleum Association of America; and
•
information it has concerning increases in drilling costs in the area since 2004.
If this rate subsequently exceeds competitive rates available from non-affiliated persons in the
area engaged in the business of rendering or providing comparable services or equipment, then the
rate will be adjusted to the competitive rate. Additionally, the 15% mark-up will not be increased
by the managing general partner during the term of the partnership.
The managing general partner expects to subcontract some of the actual drilling and completion of
each partnership’s wells to third-parties selected by it as well as to its affiliates. The
managing general partner may not benefit by interpositioning itself between the partnership and the
actual provider of drilling contractor services, and may not profit by drilling in contravention of
its fiduciary obligations to the partnership. However, the managing general partner’s affiliates
may charge a competitive rate if they meet the requirements described in “Conflicts of Interest –
Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.”
The cost of each partnership well includes all of the ordinary costs of drilling, testing and
completing the well. This includes the cost of the following items with respect to each natural
gas well, which will be the classification of the majority of the wells:
•
multiple completions, which generally means treating separately all potentially
productive geological formations in an attempt to enhance the natural gas production
from the well;
•
installing gathering lines of up to 2,500 feet per well to connect the well’s
natural gas production to a pipeline; and
•
the necessary surface facilities for producing natural gas from the well.
The amount paid to the managing general partner for drilling and completing a partnership well will
be proportionately reduced to the extent the partnership acquires less than 100% of the working
interest in the prospect. In addition, the amount of compensation that the managing general
partner could earn as a result of these arrangements depends on many other factors as well,
including the following:
•
where the wells are drilled and their depths;
•
the method used to complete the well; and
•
the number of wells drilled.
Assuming the maximum subscription proceeds of $200 million are received, the managing general
partner anticipates that the partnerships’ weighted average cost of drilling and completing
approximately 710 net wells and 777 gross wells, excluding lease costs, will be approximately
$339,128 per net well, which includes the administration and oversight fee of $15,000 per well
(included as part of the intangible drilling costs and the portion of the equipment costs of the
well charged to the investors) and the 15% mark-up per well paid to the managing general partner
for its services as general drilling contractor. This estimate also was based on the managing
general partner’s estimate of:
•
the number of wells that will be drilled in each area by the partnerships;
•
the percentage of working interest that the partnerships will acquire in the prospects in each area; and
•
the estimated drilling and completion costs of the wells to be drilled by the
partnerships, which are different for wells in each area, primarily because of
different depths of the wells and different completion methods.
Thus, the managing general partner’s estimated weighted average cost of drilling and completing one
net well as set forth above, in all likelihood, will vary from the actual average cost of the wells
in each of the primary areas and for a partnership’s wells as a whole.
Based on the assumptions and the estimated weighted average cost for one net well as set forth
above, the managing general partner expects that its 15% mark-up will be approximately $42,254 per
net well with respect to the intangible drilling costs and the portion of equipment costs paid by
you and the other investors. The actual compensation received by the managing
general partner as a result of each partnership’s drilling operations will vary from these
estimates, and the managing general partner anticipates that the partnerships will acquire less
than 100% of the working interest in some of their respective prospects.
Subject to the foregoing, the managing general partner estimates that its administration and
oversight fee of $15,000 and its 15% mark-up of approximately $42,254 for one net well, which
totals $57,254 per net well, will be:
•
$400,778 if subscription proceeds of $2 million are received, which is seven net
wells times $57,254; and
•
$40,650,340 if subscription proceeds of $200 million are received, which is 710 net
wells times $57,254.
Additionally, affiliates of the managing general partner will provide subcontracting services,
equipment and materials in drilling, completing or operating the partnership’s wells for which they
will receive competitive rates, because they meet the requirements described in “Conflicts of
Interest – Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.”
Thus, the total compensation paid to the managing general partner and its affiliates per net well
will be greater than the estimated amount to be paid to the managing general partner as described
above to the extent compensation is paid by the partnerships to the managing general partner’s
affiliates for services, equipment or supplies they provide to the partnerships.
The managing general partner’s estimated weighted average cost of $339,128 for one net well to be
drilled by a partnership as discussed above consists of:
•
intangible drilling costs of approximately $253,521 (75%); and
The managing general partner further anticipates that a partnership’s cost of drilling and
completing any given well in the primary areas as described in “Proposed Activities,” excluding
lease costs, may be considerably more or less than the average weighted cost of approximately
$339,128 to drill and complete one net well, excluding lease costs, depending primarily on the area
where the well is situated, the partnership’s percentage ownership of the working interest in the
well and unanticipated cost overruns.
Per Well Charges
Under the drilling and operating agreement the managing general partner, as operator of the wells,
will receive the following compensation from each partnership when the wells begin producing
natural gas or oil:
•
reimbursement at actual cost for all direct expenses incurred on behalf of the
partnership; and
•
well supervision fees at a competitive rate for operating and maintaining the wells
during producing operations.
Currently the competitive rate for well supervision fees is $362 per well per month in the primary
and secondary areas discussed in “Proposed Activities.” The well supervision fees will be
proportionately reduced to the extent the partnership acquires less than 100% of the working
interest in the well. Also, the managing general partner’s well supervision fees may be adjusted
annually beginning with the first calendar year after a partnership closes for inflation since
January 1, 2007. If the managing general partner’s well supervision fee would exceed a competitive
rate in the area where the well is situated, then the rate will be adjusted to the competitive
rate. Conversely, if in the future the managing general partner’s well supervision fee set forth
above would be less than a competitive rate in the area where the well is situated, then regardless
of the inflation adjustment, the rate may be increased automatically to the competitive rate from
time to time by the managing general partner, as operator, as determined in its sole discretion.
The managing general partner may not benefit by interpositioning itself between the partnership and
the actual provider of operator services. In no event will any consideration received for operator
services be duplicative of any consideration or reimbursement received under the partnership
agreement.
The well supervision fee covers all normal and regularly recurring operating expenses for the
production, delivery, and sale of natural gas and oil, such as:
•
well tending, routine maintenance, and adjustment;
•
reading meters, recording production, pumping, maintaining appropriate books and records; and
•
preparing reports to the partnership and to government agencies.
The well supervision fees do not include costs and expenses related to:
•
the purchase of equipment, materials, or third-party services;
•
brine disposal; and
•
rebuilding of access roads.
These costs will be charged to a partnership at the invoice cost of the materials purchased or the
third-party services performed.
The managing general partner estimates that it will receive well supervision fees for a
partnership’s first 12 months of operation after all of the wells have been placed in production
of:
•
$30,408 if subscription proceeds of $2 million are received, which is seven net
wells at $362 per well per month; and
$3,084,240 if subscription proceeds of $200 million are received, which is 710 net
wells at $362 per well per month.
Gathering Fees
Under the partnership agreement the managing general partner will be responsible for gathering and
transporting the natural gas produced by the partnerships to interstate pipeline systems, local
distribution companies, and/or end-users in the area (the “gathering services”). The managing
general partner anticipates that it will use the gathering system owned by Atlas Pipeline Partners
for the majority of the partnerships’ natural gas production as described in “Proposed Activities –
Sale of Natural Gas and Oil Production – Gathering of Natural Gas.” The managing general partner’s
affiliate, Atlas America, Inc., which is sometimes referred to in this prospectus as “Atlas
America,” or another affiliate controls and manages the gathering system for Atlas Pipeline
Partners. (See “Management – Organizational Diagram and Security Ownership of Beneficial Owners.”)
Also, Atlas America and the managing general partner’s affiliates, Resource Energy, LLC, sometimes
referred to in this prospectus as “Resource Energy,” and Viking Resources LLC, sometimes referred
to in this prospectus as “Viking Resources,” which are sometimes referred to collectively in this
prospectus as the “Atlas Entities,” which do not include the partnerships, have an agreement with
Atlas Pipeline Partners under which generally all of the gas produced by their affiliated
partnerships, which does include the partnerships, will be gathered and transported through the
gathering system owned by Atlas Pipeline Partners, and that the Atlas Entities must pay the greater
of $.35 per mcf or 16% of the gross sales price for each mcf transported by these affiliated
partnerships through Atlas Pipeline Partners’ gathering system. Gross sales price means the price
that is actually received, adjusted to take into account proceeds received or payments made
pursuant to hedging arrangements. Subject to the agreement with Atlas Pipeline Partners described
above, in providing the gathering services the managing general partner may use gathering systems
owned by Atlas Pipeline Partners, independent third-parties and/or affiliates of Atlas America
other than Atlas Pipeline Partners.
Each partnership will pay a gathering fee directly to the managing general partner at competitive
rates for the gathering services. The gathering fee paid by the partnership to the managing
general partner may be increased from time-to-time by the managing general partner, in its sole
discretion, but may not be increased beyond competitive rates as determined by the managing general
partner. Currently, the managing general partner has determined that the competitive rate in each
of its primary and secondary areas where it drills its wells as described in “Proposed Activities”
is an amount equal to 13% of the gross sales price received by each partnership for its natural
gas.
The payment of a competitive fee to the managing general partner for its gathering services will be
subject to the following conditions:
•
If the gathering system owned by Atlas Pipeline Partners is used by a partnership,
then the managing general partner will apply the gathering fee it receives from the
partnership towards the payments owed by the Atlas Entities under their agreement with
Atlas Pipeline Partners.
•
If a third-party gathering system is used by a partnership, the managing general
partner will pay all of the gathering fee it receives from the partnership to the
third-party gathering the natural gas. The managing general partner may not retain the
excess of any gathering fees it receives from the partnership over the payments it
makes to third-party gas gatherers. If the third-party’s gathering system charges more
than an amount equal to 13% of the gross sales price, then the managing general
partner’s gathering fee charged to a partnership will be the actual transportation and
compression fees charged by the third-party gathering system with respect to the
partnership’s natural gas in the area.
•
If both a third-party gathering system and the Atlas Pipeline Partners gathering
system (or a gas gathering system owned by an affiliate of Atlas America other than
Atlas Pipeline Partners) are used by a partnership, then the managing general partner
will receive an amount equal to 13% of the gross sales price plus the amount charged by
the third-party gathering system. For purposes of illustration, but not limitation,
certain wells drilled by a partnership in the Upper Devonian Sandstone Reservoirs in
the McKean County, Pennsylvania secondary area will deliver natural gas produced in
this area into a gathering system, a segment of which will be provided by Atlas
Pipeline Partners and a segment of which will be provided by a third-party. In this
area, the managing general partner’s competitive gathering fee will include the
third-party’s fee of $.35 per mcf for transportation and compression, including any
increase in the fee by the
third-party gatherer from time-to-time, all of which it will
then pay to the third-party gatherer, and the managing general partner will also
receive a gathering fee equal to 13% of the gross sales price.
Finally, in connection with the Knox project in the Mississippian and Devonian Shale Reservoirs in
the Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee area, as discussed in “Proposed
Activities – Primary Areas of Operations – Mississippian Carbonate and Devonian Shale Reservoirs in
Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee,” a partnership will deliver
natural gas into a gathering system provided by Knox Energy, which is referred to as the Coalfield
Pipeline. The Coalfield Pipeline will receive gathering fees of $.55 per mcf plus fees for
compression, which it may increase from time-to-time. If the Coalfield Pipeline does not have
sufficient capacity to compress and transport the natural gas produced from a partnership’s wells
as determined by Atlas America, then Atlas America or an affiliate other than Atlas Pipeline
Partners may construct an additional gathering system and/or enhancements to the Coalfield
Pipeline. On completion of the construction, Atlas America will transfer its ownership in the
additional gathering system and/or enhancements to the owners of the Coalfield Pipeline, which will
then pay Atlas America an amount equal to $.12 per mcf of natural gas transported through the newly
constructed and/or enhanced gathering system. If the events described above occur, Coalfield
Pipeline will pay this amount to Atlas America from the gathering and compression fees it charges
to a partnership. The managing general partner’s gathering fee in this area also will be 13% of
the gross sales price of the partnership’s natural gas, but will be increased to include the amount
of the Coalfield Pipeline fees, if greater, all of which the managing general partner will then pay
to the Coalfield Pipeline.
The actual amount of gathering fees to be paid by a partnership to the managing general partner
cannot be quantified, because the volume of natural gas that will be produced and transported from
the partnership’s wells cannot be predicted.
Interest and Other Compensation
The managing general partner or an affiliate will have the right to charge a competitive rate of
interest on any loan it may make to or on behalf of a partnership. If the managing general partner
provides equipment, supplies, and other services to a partnership, then it may do so at competitive
industry rates. The managing general partner will determine competitive industry rates for
equipment, supplies and other services by conducting a survey of the interest and/or fees charged
by unaffiliated third-parties in the same geographic area engaged in similar businesses. If
possible, the managing general partner will contact at least two unaffiliated third-parties,
however, the managing general partner will have sole discretion in determining the amount to be
charged a partnership.
Estimate of Administrative Costs and Direct Costs to be Borne by the Partnerships
The managing general partner and its affiliates will receive from each partnership a
nonaccountable, fixed payment reimbursement for their administrative costs, which has been
determined by the managing general partner to be $75 per well per month. This payment per well is
subject to the following:
•
it will not be increased in amount during the term of the partnership;
•
it will be proportionately reduced to the extent the partnership acquires less than
100% of the working interest in the well;
•
it will be the entire payment to reimburse the managing general partner for the
partnership’s administrative costs; and
•
it will not be received for plugged or abandoned wells.
The managing general partner estimates that the nonaccountable, fixed payment reimbursement for
administrative costs allocable to a partnership’s first 12 months of operation after all of its
wells have been placed into production will not exceed approximately:
•
$6,300 if subscription proceeds of $2 million are received, which is seven net wells
at $75 per well per month; and
•
$639,000 if subscription proceeds of $200 million are received, which is 710 net
wells at $75 per well per month.
Direct costs will be determined by the managing general partner, in its sole discretion, including
the provider of the services or goods and the amount of the provider’s compensation. Direct costs
will be billed directly to and paid by each partnership to the extent practicable. The anticipated
direct costs set forth below for a partnership’s first 12 months of operation after all of its
wells have been placed into production may vary from the estimates shown for numerous reasons that
cannot accurately be predicted. These reasons include:
•
the number of the partnership’s investors;
•
the number of wells drilled by the partnership;
•
the partnership’s degree of success in its activities;
•
the extent of any production problems encountered by the partnership;
•
inflation; and
•
various other factors involving the administration of the partnership.
Minimum
Maximum
Subscriptions
Subscriptions
of $2 million
of $200 million (1)
Direct Costs
External Legal
$
6,000
$
24,000
Accounting Fees for Audit and Tax Preparation
25,000
150,000
Independent Engineering Reports
1,500
40,000
TOTAL
$
32,500
$
214,000
(1)
This assumes two partnerships are formed as described below in “Terms of the Offering –
Subscription to a Partnership” and the targeted nonbinding subscriptions of each partnership
are received.
Set forth below is a tabular presentation of the narrative discussion of the compensation set forth
above. In all cases, the tabular presentation is subject to the discussion set forth above.
Offering Stage
Entity receiving
compensation
Type and method of compensation
Estimated amount
Anthem Securities,
Inc.
Dealer-Manager Fees. Subject to
certain exceptions described in “Plan
of Distribution,” Anthem Securities,
the dealer-manager and an affiliate of
the managing general partner, will
receive on each unit sold to an
investor:
• a 2.5% dealer-manager fee;
• a 7% sales commission; and
• an up to .5% reimbursement of
the selling agents’ bona fide due
diligence expenses.
Assuming these
amounts are paid
for all units sold,
the dealer-manager
will receive:
• $200,000 if
subscription
proceeds of $2
million are
received by a
partnership; and
• $20 million
if subscription
proceeds of $200
million are
received by the
partnerships.
Lease Costs. Under the partnership
agreement the managing general partner
will contribute to each partnership
all the undeveloped leases necessary
to cover each of the partnership’s
prospects. The managing general
partner will receive a credit to its
capital account equal to:
• the cost of the leases; or
• the fair market value of the
leases if the managing general partner
has reason to believe that cost is
materially more than the fair market
value.
Drilling Contracts. Each partnership
will enter into the drilling and
operating agreement with the managing
general partner to drill and complete
each partnership’s wells for an amount
equal to the sum of the following
items: (i) the cost of permits,
supplies, materials, equipment, and
all other items used in the drilling
and completion of a well provided by
third-parties, or if the foregoing
items are provided by affiliates of
the managing general partner, then
those items will be charged at
competitive rates; (ii) fees for
third-party services; (iii) fees for
services provided by the managing
general partner’s affiliates, which
will be charged at competitive rates;
(iv) an administration and oversight
fee of $15,000 per well, which will be
charged to you and the other investors
as part of each well’s intangible
drilling costs and the portion of
equipment costs paid by you and the
other investors; and (v) a mark-up in
an amount equal to 15% of the sum of
(i), (ii), (iii) and (iv), above, for
the managing general partner’s
services as general drilling
contractor. Additionally, if the
managing general partner drills a well
for the partnership that it determines
is not an average well in the area
because of the well’s depth,
complexity associated with either
drilling or completing the well or as
otherwise determined by the managing
general partner, the administration
and oversight fee of $15,000 per well
described in §4.02(d)(1)(iv) of the
partnership agreement may be increased
to a competitive rate as determined by
the managing general partner.
Based on the
assumptions and the
estimated average
lease costs
described in
“Compensation -
Lease Costs,” the
managing general
partner estimates
that its total
credit for lease
costs will be:
• $79,170 if
subscription
proceeds of $2
million are
received, which is
seven net wells
times $11,310 per
prospect; and
• $8,030,100
if subscription
proceeds of $200
million are
received, which is
710 net wells times
$11,310 per
prospect.
Based on the
assumptions and the
estimated weighted
average cost for
one net well as set
forth in “-
Drilling Contracts”
above, the managing
general partner
expects that its
15% mark-up will be
approximately
$42,254 per net
well with respect
to the intangible
drilling costs and
the portion of
equipment costs
paid by you and the
other investors.
Subject to the
foregoing, the
managing general
partner estimates
that its
administration and
oversight fee of
$15,000 and its 15%
mark-up of
approximately
$42,254 for one net
well, which totals
$57,254 per net
well, will be:
• $400,778 if
subscription
proceeds of $2
million are
received, which is
seven net wells
times $57,254; and
• $40,650,340
if subscription
proceeds of $200
million are
received, which is
710 net wells times
$57,254.
Additionally,
affiliates of the
general partner
will provide
subcontracting
services, equipment
and materials in
drilling,
completing or
operating the
partnership’s wells
for which they will
receive competitive
rates, because they
meet the
requirements
described in
“Conflicts of
Interest -
Conflicts
Regarding Transactions with the Managing
General Partner and its Affiliates.”
Thus, the total
compensation paid to the managing
general partner and its affiliates per
net well will be greater than the estimated amount to
be paid to the managing general partner as
described above to the extent compensation is
paid by the partnerships to the managing general
partner’s affiliates for services, equipment
or supplies they provide to the partnerships.
Operational Stage
Entity receiving
compensation
Type and method of compensation
Estimated amount
Managing general
partner and its
affiliates
Natural Gas and Oil Revenues.
Subject to the managing
general partner’s
subordination obligation, the
investors and the managing
general partner will share in
each partnership’s revenues in
the same percentages as their
respective capital
contributions bear to the
total capital contributions to
that partnership, except that
the managing general partner
will receive an additional 7%
of that partnership’s
revenues. However, the
managing general partner’s
total revenue share may not
exceed 40% of that
partnership’s revenues
regardless of the amount of
its capital contribution.
For example, if the managing general partner
contributes the minimum of 25% of the
partnership’s total capital contributions and
the investors contribute 75% of the
partnership’s total capital contributions,
then the managing general partner will
receive 32% of the partnership’s revenues and
the investors will receive 68% of the
partnership’s revenues. On the other hand,
if the managing general partner contributes
35% of the partnership’s total capital
contributions and the investors contribute
65% of the partnership’s total capital
contributions, then the managing general
partner will receive 40% of the partnership’s
revenues, not 42%, because its revenue share
cannot exceed 40% of the partnership’s
revenues, and the investors will receive 60%
of the partnership’s revenues.
Managing general
partner and its
affiliates
Per Well Charges. Under the
drilling and operating
agreement the managing general
partner, as operator of the
wells, will receive from each
partnership when the wells
begin producing natural gas or
oil reimbursement at actual
cost for all direct expenses
incurred on behalf of the
partnership and well
supervision fees at a
competitive rate for operating
and maintaining the wells
during producing operations.
Based on the assumptions and the estimated
well supervision fees described in “- Per
Well Charges,” above, the managing general
partner estimates that it will receive well
supervision fees for a partnership’s first 12
months of operation after all of the wells
have been placed in production of:
• $30,408 if subscription proceeds of
$2 million are received, which is seven net
wells at $362 per well per month; and
• $3,084,240 if subscription proceeds
of $200 million are received, which is 710
net wells at $362 per well per month.
Managing general
partner and its
affiliates
Managing general
partner and its
affiliates
Gathering Fees. Under the
partnership agreement the
managing general partner will
be responsible for gathering
and transporting the natural
gas produced by the
partnerships to interstate
pipeline systems, local
distribution companies, and/or
end-users in the area (the
“gathering services”). The
managing general partner
anticipates that it will use
the gathering system owned by
Atlas Pipeline Partners for
the majority of the
partnerships’ natural gas
production. Each partnership
will pay a gathering fee
directly to the managing
general partner at competitive
rates for the gathering
services. The gathering fee
paid by the partnership to the
managing general partner may
be increased from time-to-time
by the managing general
partner, in its sole
discretion, but may not be
increased beyond competitive
rates as determined by the
managing general partner.
Currently, the managing
general partner has determined
that the competitive rate in
each of its primary and
secondary areas where it
drills its wells as described
in “Proposed Activities” is an
amount equal to 13% of the
gross sales price received by
each partnership for its
natural gas. Gross sales
price means the price that is
actually received, adjusted to
take into account proceeds
received or payments made
pursuant to hedging
arrangements.
The payment of a competitive
fee to the managing general
partner for its gathering
services will be subject to
the conditions described in “-
Gathering Fees,” above.
Interest and Other
Compensation. The managing
general partner or an
affiliate will have the right
to charge a competitive rate
of interest on any loan it may
make to or on behalf of a
partnership. If the managing
general partner provides
equipment, supplies, and other
services to a partnership,
then it may do so at
competitive industry rates.
The actual amount of gathering fees to be
paid by a partnership to the managing general
partner cannot be quantified, because the
volume of natural gas that will be produced
and transported from each partnership’s wells
cannot be predicted.
The actual amount of interest and other
compensation is not determinable at this
time.
partner and
its affiliates will receive
from each partnership a
nonaccountable, fixed payment
reimbursement for their
administrative costs, which
has been determined by the
managing general partner to be
$75 per well per month.
“- Estimate of Administrative and Direct
Costs to be Borne by the Partnerships,”
above, the managing general partner estimates
that the nonaccountable, fixed payment
reimbursement for administrative costs
allocable to a partnership’s first 12 months
of operation after all of its wells have been
placed into production will not exceed
approximately:
• $6,300 if subscription proceeds of $2
million are received, which is seven net
wells at $75 per well per month; and
• $639,000 if subscription proceeds of
$200 million are received, which is 710 net
wells at $75 per well per month.
Managing general
partner and its
affiliates and
various
third-parties
Direct Costs. Direct costs
will be determined by the
managing general partner, in
its sole discretion, including
the provider of the services
or goods and the amount of the
provider’s compensation.
Direct costs will be billed
directly to and paid by each
partnership to the extent
practicable.
Assuming the two partnerships are formed as
described below in “Terms of the Offering -
Subscription to a Partnership” and the
targeted nonbinding subscriptions of each
partnership are received, the managing
general partner estimates that the maximum
amount of direct costs to be borne by the
partnerships, in the aggregate, will be
$214,000, which is composed of:
• $24,000 for external legal costs;
• $150,000 for accounting fees for
audit and tax preparation; and
Atlas Resources Public #16-2007 Program was formed to offer for sale an aggregate of $200 million
of units in a series of up to two limited partnerships, each of which has been formed under the
Delaware Revised Uniform Limited Partnership Act.
The targeted subscriptions for each partnership are set forth below. These targeted amounts are
not mandatory, and the managing general partner may determine the final subscription amount for
each partnership in its sole discretion. The maximum subscription of any partnership, however,
must be the lesser of:
$200 million less the total subscription proceeds received by any prior partnership in the program.
Also, set forth below are the targeted ending dates for each partnership, which are not binding
except that the units in each partnership may not be offered beyond that partnership’s offering
termination date as set forth below. The managing general partner may close the offering of units
in a partnership at any time before that partnership’s offering termination date once the
partnership is in receipt of the minimum required subscriptions, and the managing general partner
may withdraw the offering of units in any partnership at any time.
Required
Targeted
Targeted
Offering
Partnership
Minimum
Subscription
Ending
Termination
Name
Subscription
Proceeds
Date (1)(2)
Date (1)(2)
Atlas Resources Public #16-2007(A)
$2 million
$100 million
06/30/07
12/31/07
Atlas Resources Public #16-2007(B)
$2 million
$100 million
12/31/07
12/31/07
(1)
The units in the above partnerships will be offered and sold only during 2007.
(2)
Units in Atlas Resources Public #16-2007(B) L.P. will not be offered until the offering
of units in Atlas Resources Public #16-2007(A) L.P. has terminated.
Units are offered at a subscription price of $10,000 per unit, subject to certain exceptions
described in “Plan of Distribution,” and must be paid 100% in cash at the time of subscribing. The
subscription price of the units has been arbitrarily determined by the managing general partner
because the partnerships do not have any prior operations, assets, earnings, liabilities or present
value. Your minimum subscription is one unit ($10,000). Larger fractional subscriptions will be
accepted in $1,000 increments, beginning with $11,000, $12,000, etc.
You may elect to purchase units in a partnership as either an investor general partner or a limited
partner. However, even though you may elect to subscribe as an investor general partner the
managing general partner will have exclusive management authority for each partnership. Each
partnership will be a separate business entity from the other partnership. Thus, as an investor,
you will be a partner only in the partnership in which you invest. You will have no interest in
the business, distributions, assets or tax benefits of the other partnership unless you also invest
in the other partnership. Your investment return will depend solely on the operations and success
or lack of success of the particular partnership in which you invest.
Partnership Closings and Escrow
You and the other investors should make your checks for units payable to “National City Bank of
Cleveland, Ohio, Escrow Agent, Atlas Resources Public #16-2007(A) L.P.” or “National City Bank of
Cleveland, Ohio, Escrow Agent, Atlas Resources Public #16-2007(B) L.P.,” depending on which
partnership is then being offered at the time you
subscribe for units, and give your check to your broker/dealer for submission to the dealer-manager
and escrow agent. Subscription proceeds for each partnership will be held in a separate interest
bearing escrow account at National City Bank of Cleveland, Ohio, 200 Public Square, 5th
Floor, Cleveland, Ohio44114, until each partnership has received subscription proceeds of at least
$2 million, excluding the subscription price discounts described in “Plan of Distribution” and
excluding any subscriptions by the managing general partner or its affiliates. However, on receipt
of the minimum subscription proceeds and written instructions to the escrow agent from the managing
general partner and the dealer-manager, the managing general partner on behalf of a partnership may
break escrow and transfer the escrowed subscription proceeds to a partnership account, enter into
the drilling and operating agreement with itself or an affiliate as operator, and begin drilling
operations for the partnership.
Pennsylvania Investors: Because the minimum closing amount is less than 10% of the maximum closing
amount allowed to a partnership in this offering, you are cautioned to carefully evaluate the
partnership’s ability to fully accomplish its stated objectives and inquire as to the current
dollar volume of partnership subscriptions. In addition, subscription proceeds received by a
partnership from Pennsylvania investors will be placed into a short-term escrow (120 days or less)
until subscriptions for at least 5% of the maximum offering proceeds have been received by a
partnership, which for Atlas Resources Public #16-2007(A) L.P. means that subscriptions for at
least $6.7 million have been received by the partnership from investors, including Pennsylvania
investors. If the appropriate minimum has not been met at the end of each escrow
period, the
partnership must notify the Pennsylvania investors in writing by certified mail or any other means
whereby a receipt of delivery is obtained within 10 calendar days after the end of each escrow
period that they have a right to have their investment returned to them. If an investor requests
the return of such funds within 10 calendar days after receipt of notification, the issuer must
return such funds within 15 calendar days after receipt of the investor’s request.
If the minimum subscription proceeds are not received by the offering termination date of a
partnership, then the subscription proceeds deposited in the escrow account will be promptly
returned to you and the other subscribers in that partnership with interest and without deduction
for any fees. In this regard, the latest offering termination date for each partnership is
December 31, 2007. Although the managing general partner and its affiliates may buy up to 5% of
the total units sold in this offering, currently they do not anticipate purchasing any units. If
they do buy units, then those units will not be applied towards the minimum subscription proceeds
required for a partnership to break escrow and begin operations. Also, any units purchased by the
managing general partner and its affiliates must be purchased for investment purposes only, and not
with a view toward redistribution.
You will receive interest on your subscription proceeds from the time they are deposited in the
escrow account, or the partnership account if you subscribe after the minimum subscription proceeds
have been received and escrow has been broken, until your subscription proceeds are paid by the
partnership to the managing general partner for use in the partnership’s drilling activities. All
interest distributions will be made in the ratio that the number of units held by each investor
multiplied by the number of days the investor’s subscription proceeds were held in the escrow
account, or a partnership account after the minimum number of units have been received, bears to
the sum of that calculation for all investors whose subscription proceeds are paid the managing
general partner at the same time.
During each partnership’s escrow period its subscription proceeds will be invested only in
institutional investments comprised of, or secured by, securities of the United States government.
After the funds are transferred to a partnership account and before their use in partnership
operations, they may be temporarily invested in income producing short-term, highly liquid
investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills. If
the managing general partner determines that a partnership may be deemed to be an investment
company under the Investment Company Act of 1940, then the investment activity will cease.
Subscription proceeds will not be commingled with the funds of the managing general partner or its
affiliates, nor will subscription proceeds be subject to their creditors’ claims, before they are
paid to the managing general partner under the drilling and operating agreement.
Acceptance of Subscriptions
Your execution of the subscription agreement constitutes your offer to buy units in the partnership
then being offered and to hold the offer open until either:
•
your subscription is accepted or rejected by the managing general partner; or
•
you withdraw your offer.
To rescind or withdraw your subscription agreement, you must give written notice to the managing
general partner before your subscription agreement is accepted by the managing general partner.
Also, the managing general partner will:
•
not complete a sale of units to you until at least five business days after the date
you receive a final prospectus; and
•
send you a confirmation of purchase.
Subject to the foregoing, your subscription agreement will be accepted or rejected by the
partnership within 30 days of its receipt. The managing general partner’s acceptance of your
subscription is discretionary, and the managing general partner may reject your subscription for
any reason without incurring any liability to you for this decision. If your subscription is
rejected, then all of your funds will be promptly returned to you together with any interest earned
on your subscription proceeds and without deduction for any fees.
When you will be admitted to a partnership depends on whether your subscription is accepted before
or after a partnership breaks escrow. If your subscription is accepted:
•
before breaking escrow, then you will be admitted to the partnership to which you
subscribed not later than 15 days after the release from escrow of the investors’
subscription proceeds to that partnership; or
•
after breaking escrow, then you will be admitted to the partnership to which you
subscribed not later than the last day of the calendar month in which your subscription
was accepted by that partnership.
Your execution of the subscription agreement and the managing general partner’s acceptance also constitutes your:
•
execution of the partnership agreement and agreement to be bound by its terms as a partner; and
•
grant of a special power of attorney to the managing general partner to file amended
certificates of limited partnership and governmental reports, and perform certain other
actions on behalf of you and the other investors as partners of a partnership.
PRIOR ACTIVITIES
The following tables reflect certain historical data with respect to the private drilling
partnerships and the public drilling partnerships that the managing general partner has sponsored.
The tables also reflect certain historical data with respect to 1999 Viking Resources LP, a private
drilling program that raised $4,555,210, and is the only drilling program sponsored by Viking
Resources after it was acquired by Resource America, Inc. in August 1999. Information concerning
this program and other programs sponsored by Viking Resources before it was acquired by Resource
America will be provided to you on written request to the managing general partner. The tables
also do not include information concerning wells acquired by Atlas Resources through merger or
other form of acquisition, and this information also will be available to you on written request to
the managing general partner.
Although past performance is no guarantee of future results, the investor general partners in the
managing general partner’s prior partnerships have not had to make additional capital contributions
to their partnerships because of their status as investor general partners.
It should not be assumed that you and the other investors in a partnership will experience returns,
if any, comparable to those experienced by investors in the prior drilling partnerships for several
reasons, including, but not limited to, differences in:
•
partnership terms;
•
property locations;
•
partnership size; and
•
economic considerations.
The results of the prior drilling partnerships should be viewed only as a measure of the level of
activity and experience of the managing general partner with respect to drilling
partnerships.
Table 1 sets forth certain sales information of previous development drilling partnerships
sponsored by the managing general partner and its affiliates.
Table 2 reflects the drilling activity of previous development drilling partnerships sponsored by
the managing general partner and its affiliates. All the wells were development wells. You should
not assume that the past performance of prior partnerships is indicative of the future results of
the partnerships.
TABLE 2
WELL STATISTICS — DEVELOPMENT WELLS
AS OF JANUARY 15, 2007
GROSS WELLS (1)
NET WELLS (2)
Partnership
Oil
Gas
Dry (3)
Oil
Gas
Dry (3)
1.
Atlas L.P. 1 - 1985
0
6
1
0
2.83
0.50
2.
A.E. Partners Limited (1986)
0
8
0
0
3.50
0.00
3.
A.E. Partners Limited 1987
0
9
0
0
4.10
0.00
4.
A.E. Partners Limited 1988
0
9
0
0
3.80
0.00
5.
A.E. Partners Limited 1989
0
10
0
0
3.30
0.00
6.
A.E. Partners Limited-1990
0
12
0
0
5.00
0.00
7.
Atlas-Energy Partners 1990 L.P.(Series 10)
0
12
0
0
11.50
0.00
8.
Atlas-Energy Partners 1991 L.P.(Series 11)
0
14
0
0
4.30
0.00
9.
A.E. Partners Limited-1991
0
12
0
0
4.95
0.00
10.
Atlas-Energy for the Nineties-1 LP (Series 12)
0
14
0
0
12.50
0.00
11.
Atlas JV 92 Limited Partnership
0
52
0
0
24.44
0.00
12.
A.E. Partners Limited-1992
0
7
0
0
3.50
0.00
13.
A.E. Nineties-Public #1 Ltd.
0
14
0
0
14.00
0.00
14.
A.E. Nineties-1993 Ltd.
0
20
1
0
19.40
1.00
15.
A.E. Partners Limited-1993
0
8
0
0
4.00
0.00
16.
A.E. Nineties-Public #2 Ltd.
0
16
0
0
15.31
0.00
17.
A.E. Nineties-Series 14 Ltd.
0
53
2
0
53.00
2.00
18.
A.E. Partners Limited-1994
0
12
0
0
5.00
0.00
19.
A.E. Nineties-Public #3 Ltd.
0
26
1
0
25.50
1.00
20.
A.E. Nineties-Series 15 Ltd.
0
61
1
0
55.50
1.00
21.
A.E. Partners Limited-1995
0
6
0
0
3.00
0.00
22.
A.E. Nineties-Public #4 Ltd.
0
32
0
0
30.50
0.00
23.
A.E. Nineties-Seriess 16 Ltd.
0
51
6
0
40.50
4.50
24.
A.E. Partners Limited-1996
0
13
0
0
4.84
0.00
25.
A.E. Nineties-Public #5 Ltd.
0
36
0
0
35.91
0.00
26.
A.E. Nineties-Series 17 Ltd.
0
47
5
0
42.00
3.50
27.
A.E. Nineties-Public #6 Ltd.
0
55
0
0
44.45
0.00
28.
A.E. Partners Limited-1997
0
6
0
0
2.81
0.00
29.
A.E. Nineties-Series 18 Ltd.
0
63
0
0
58.00
0.00
30.
A.E. Nineties-Public #7 Ltd.
0
64
0
0
57.50
0.00
31.
A.E. Partners Limited-1998
0
19
0
0
9.50
0.00
32.
A.E. Nineties-Series 19 Ltd.
0
82
4
0
75.75
4.00
33.
A.E. Nineties-Public #8 Ltd.
0
58
0
0
54.66
0.00
34.
A.E. Partners Limited-1999
0
5
0
0
2.50
0.00
35.
1999 Viking Resources LP
0
23
2
0
23.00
2.00
36.
Atlas America Series 20 Ltd.
0
106
1
0
100.25
1.00
37.
Atlas America Public #9 Ltd.
0
83
2
0
78.75
2.00
38.
Atlas America Series 21-A Ltd.
0
68
0
0
62.50
0.00
39.
Atlas America Series 21-B Ltd.
0
89
2
0
84.05
1.00
40.
Atlas America Public #10 Ltd.
0
107
3
0
103.15
3.00
41.
Atlas America Series 22-2002 Ltd.
0
51
1
0
49.55
1.00
42.
Atlas America Series 23-2002 Ltd.
0
47
1
0
47.00
1.00
43.
Atlas America Public #11-2002 LP
0
167
0
0
160.50
0.00
44.
Atlas America Series 24-2003(A) Ltd., LP
0
76
0
0
69.50
0.00
45.
Atlas America Series 24-2003(B) Ltd., LP
0
121
1
0
113.00
1.00
46.
Atlas America Public #12-2003 LP
0
221
6
0
214.25
1.00
47.
Atlas America Series 25-2004(A) LP
0
137
4
0
130.80
4.00
48.
Atlas America Series 25-2004(B) LP
0
171
4
0
153.40
4.00
49.
Atlas America Public #14-2004 LP
0
256
11
0
233.55
11.00
50.
Atlas America Public #14-2005(A) LP
0
338
5
0
315.49
5.00
51.
Atlas America Series 26-2005 LP
0
142
2
0
132.31
2.00
52.
Atlas America Public #15-2005(A) LP
0
187
1
0
181.50
1.00
53.
Atlas America Public #15-2006(B) LP (4)
0
243
1
0
228.18
1.00
54.
Atlas America Series 27-2006 LP (5)
0
53
0
0
48.88
0.00
0
3598
68
0
3266.96
58.50
(1)
A “gross well” is one in which a leasehold interest is owned.
(2)
A “net well” equals the actual leasehold interest owned in one gross well divided by one
hundred. For example, a 50% leasehold interest in a well is one gross well, but a .50 net well.
(3)
For purposes of this Table only, a “Dry Hole” means a well which is plugged and abandoned
with or without a completion attempt because the operator has determined that it will not be
productive of gas and/or oil in commercial quantities.
(4)
This partnership closed August 31, 2006, and as of the date of this table this is the number of
wells drilled. The total tentative gross well count is 638.
(5)
This partnership closed December 29, 2006, and as of the date of this table this is the number
of wells drilled. The toal tentative gross well count is 273 gross partnership wells.
Table 3 provides information concerning the operating results of previous development drilling
partnerships sponsored by the managing general partner and its affiliates. You should not assume
that the past performance of prior partnerships is indicative of the future results of the
partnerships.
TABLE 3
INVESTOR OPERATING RESULTS — INCLUDING EXPENSES
AS OF JANUARY 15, 2007
Table 3 provides information concerning the operating results of previous development drilling
partnerships sponsored by the managing general partner and its affiliates. You should not assume
that the past performance of prior partnerships is indicative of the future results of the
partnerships.
TABLE 3
INVESTOR OPERATING RESULTS — INCLUDING EXPENSES
AS OF JANUARY 15, 2007
All cash distributions were from the sale of gas. The following partnerships also include
revenue from the sale of properties: A.E. Nineties-16 ($4,776), A.E. Nineties-19 ($1,607), Atlas
America Series 20 ($6,662), Atlas America Series 22 ($34), Atlas America Series 24-2003(A)
($9,066), Atlas America Series 24-2003(B) ($12,582), Atlas America Series 25-2004(A) ($595), Atlas
America Series 25-2004(B) ($3,813), A.E. Nineties-Public #1 ($2,452), A.E. Nineties-Public #2
($3,292), A.E. Nineties-Public #3 ($2,491), A.E. Nineties-Public #5 ($8,639), A.E. Nineties-Public
#7 ($2,206), Atlas America Public #11-2002 ($2,789), Atlas America Public #12-2003 ($1,568), and
Atlas America Public #14-2004 ($920).
(2)
A portion of the cash distributions was used to drill three reinvestment wells at a cost of
$307,434 in accordance with the terms of the offering.
(3)
This column reflects total cash distributions beginning with the first production from the
program as a percentage of the total amount invested in the program and includes the return of the
investors’ capital.
(4)
As of the date of this table there is not twelve months of production and/or not all of the
wells are drilled or on-line to sell production.
(5)
Operating costs consist of gathering fees, water hauling fees, meter reading fees, repairs and
maintenance, insurance and severance tax.
(6)
Current reserve information is not available for these partnerships. The most current reserve
report is dated 1/1/06. Also, reserve information for Public #15-2005(A) which closed at 12/31/05
is incomplete since not all of its wells were drilled at 1/1/06.
(7)
The information presented in this column has been prepared in conformity with SEC guidelines
by making the standardized estimates of future net cash flow from proved reserves using natural gas
and oil prices in effect as of the date of the estimates, which was a weighted average price of
$10.08 per mcf for the natural gas, and which are held constant throughout the life of the
properties. The information presented for future net cash flows based on estimated proved reserves
was prepared by an independent petroleum consultant, Wright & Company, Inc., as noted below with
respect to the managing general partner’s prior public partnerships and three Regulation D
offerings which were registered under Section 12(g) of the Securities Exchange Act of 1934:
Atlas-Energy for the Nineties-Public #1 Ltd., Atlas-Energy for the Nineties-Public #2 Ltd.,
Atlas-Energy
for the Nineties-Public #3 Ltd., Atlas-Energy for the Nineties-Public #4 Ltd., Atlas-Energy for the
Nineties-Public #5 Ltd., Atlas-Energy for the Nineties-Public #6 Ltd., Atlas-Energy for the
Nineties-Public #7 Ltd., Atlas-Energy for the Nineties-Public #8 Ltd., Atlas America Public #9
Ltd., Atlas America Public #10 Ltd., Atlas America Public #11-2002 Ltd., Atlas America Public
#12-2003 Limited Partnership, Atlas America Series 25-2004(A) L.P., Atlas America Series 25-2004(B)
L.P., Atlas America Public #14-2004 L.P., Atlas America Public #14-2005(A) L.P., Atlas America
Series 26-2005 L.P., and Atlas America Public #15-2005(A) L.P. The future net cash flows based on
the reserve information for the other
partnerships were not prepared or reviewed by Wright & Company, Inc., but instead the reserve
information was prepared by the managing
general partner’s reservoir engineer. You should understand that reserve estimates are imprecise
and may change. There are inherent uncertainties in interpreting the engineering data and the
projection of future rates of production. Also, prices received from the sale of natural gas and
oil may be different from those estimates in preparing the reports, and the amounts and timing of
future operating and development costs may also differ from those used. The cash flow information
based on estimated proved reserves shown for a partnership does not include this information for
the managing general partner.
(8)
This column represents a partnership’s estimate of future net cash flows from its proved
reserves using natural gas sales prices in effect as of the dates of the estimates which are held
constant throughout the life of the partnership’s properties. As natural gas prices change, these
estimates will change. The information in this column has not been discounted.
(9)
This column represents a partnership’s estimate of future net cash flows from its proved
reserves using natural gas sales prices in effect as of the dates of the estimates which are held
constant throughout the life of the partnership’s properties. As natural gas prices change, these
estimates will change. The present value of estimated future net cash flows is calculated by
discounting estimated future net cash flows by 10% annually in accordance with SEC guidelines. You
should not construe the estimated PV-10 values as representative of the fair market value of a
partnership’s properties.
Table 3A provides information concerning the operating results of previous development drilling
partnerships sponsored by the managing general partner and its affiliates.
TABLE 3A
MANAGING GENERAL PARTNER
OPERATING RESULTS — INCLUDING EXPENSES
AS OF JANUARY 15, 2007
Table 3A provides information concerning the operating results of previous development drilling
partnerships sponsored by the managing general partner and its affiliates.
TABLE
3A
MANAGING GENERAL PARTNER
OPERATING RESULTS — INCLUDING EXPENSES
AS OF JANUARY 15, 2007
Latest Quarterly Cash
Managing General
Total Costs
Cash
Distribution As of
Partnership
Partner Capital
Operating (3)
Admin.
Direct
Distributions (1)
Cash Return
Date of Table
46.
Atlas America Public #12-2003 LP
17,285,400
1,127,923
149,285
83,191
8,763,362
51
%
564,838
47.
Atlas America Series 25-2004(A) LP
12,086,800
937,516
75,214
73,397
7,378,172
61
%
732,626
48.
Atlas America Series 25-2004(B) LP
15,238,800
855,017
77,086
77,112
5,106,226
34
%
521,963
49.
Atlas America Public #14-2004 LP
23,677,700
1,165,877
95,573
83,595
6,404,439
27
%
778,470
50.
Atlas America Public #14-2005(A) LP (2)
26,374,800
974,428
67,617
48,475
5,562,827
21
%
1,730,448
51.
Atlas America Public 26-2005 LP (2)
13,647,700
(4)
420,189
27,995
67,014
2,032,573
15
%
1,018,933
52.
Atlas America Public #15-2005(A) LP (2)
21,412,609
(4)
416,897
28,901
40763
2,130,276
10
%
1,286,477
53.
Atlas America Public #15-2006(B) LP (2)
55,159,085
(4)
0
0
0
0
0
%
0
54.
Atlas America Series 27-2006 L.P. (2)
(5)
(4)
0
0
0
0
0
%
0
(1)
All cash distributions were from the sale of gas. The following partnerships also include
revenue from the sale of properties: A.E Nineties-JV92 ($2,680) A.E. for the Nineties-1993 LTD
($8,837), A.E. Nineties-14 ($7,964), A.E. Nineties-15 ($4,776), A.E. Nineties-19 ($2,472), Atlas
America Series 20 ($8,562), Atlas America Series 22 ($66), Atlas America Series 24-2003(A)
($17,598), Atlas America Series 24-2003(B) ($24,424), Atlas America Series 25-2004(A) ($1,445),
Atlas America Series 25-2004(B) ($10,500), A.E. Nineties-Public #1 ($25), A.E. Nineties-Public #2
($33), A.E. Nineties-Public #3 ($25), A.E. Nineties-Public #5 ($1,406), A.E. Nineties-Public #7
($2,296), Atlas America Public #9 ($4,446), Atlas America Public #11 ($5,696), Atlas America Public
#12-2003 ($3,582), and Atlas America Public #14-2004 ($2,374).
(2)
As of the date of this table there is not twelve months of production and/or not all wells are
drilled or on-line to sell production.
(3)
Operating costs consist of gathering fees, water hauling fees, meter reading fees, repairs and
maintenance, insurance and severance tax.
(4)
The Managing General Partners capital contribution is an estimate based on current drilling
information.
(5)
This partnership closed December 29,2006 and as of the date of this table the Managing General
Partner’s capital contribution is not available.
Table 4 sets forth the managing general partner’s estimate of the federal tax savings to investors
in the managing general partner’s prior development drilling partnerships, based on the maximum
marginal tax rate in each year, the share of tax deductions as a percentage of their subscriptions,
and the aggregate cash distributions. You are urged to consult with your own tax advisors
concerning your specific tax situation and should not assume that the past performance of prior
partnerships is indicative of the future results of the partnerships.
TABLE 4
SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
AS OF JANUARY 15, 2007
Table 4 sets forth the managing general partner’s estimate of the federal tax savings to investors
in the managing general partner’s prior development drilling partnerships, based on the maximum
marginal tax rate in each year, the share of tax deductions as a percentage of their subscriptions,
and the aggregate cash distributions. You are urged to consult with your own tax advisors
concerning your specific tax situation and should not assume that the past performance of prior
partnerships is indicative of the future results of the partnerships.
TABLE 4
SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
AS OF JANUARY 15, 2007
Total
Cumulative
1st Year
Eff
Estimated Federal Tax Savings From (1):
Cash Distribution
Cash Dist.
Percent of Cash
Investor
Tax
Tax
1st Year I.D.C.
Depletion
Section 29
As of
And Tax
Dist. And Tax
Partnership
Capital
Deduct. (2)
Rate
Deduct. (3)
Allowance (3)
Depreciation (3)
Tax Credit (4)
Total
Date of Table (5) (6)
Savings (5) (6)
Savings to Date (5)(6)(7)
50.
Atlas America Public #14-2005(A) LP (8)
69,674,900
91.0
%
35.0
%
22,107,994
101,748
276,015
N/A
22,485,757
10,326,253
32,812,010
47
%
51.
Atlas America Series 26-2005 LP (8)
34,886,465
91.0
%
35.0
%
10,989,458
0
21,461
N/A
11,010,919
3,273,021
14,283,940
41
%
52.
Atlas America Public #15-2005(A) LP (8)
52,245,720
91.0
%
35.0
%
16,457,402
0
0
N/A
16,457,402
3,775,674
20,233,076
39
%
53.
Atlas America Public #15-2006(B) LP (8)
147,513,130
91.0
%
35.0
%
0
0
0
N/A
0
0
0
0
%
54.
Atlas America Series 27-2007 L.P. (8)
70,882,965
91.0
%
35.0
%
0
0
0
N/A
0
0
0
0
%
1.
These columns reflect the savings in taxes which would have been paid by an investor, assuming
full use of deductions available to the investor through the 2005 tax year.
2.
Atlas Resources anticipates that approximately 90% of an investor general partner’s
subscription to a partnership will be deductible in the year in which he invests.
3.
The I.D.C. Deductions, Depletion Allowance and MACRS depreciation deductions have been reduced
to credit equivalents.
4.
The Section 29 tax credit is not available with respect to wells drilled after December 31,1992. N/A means not applicable.
5.
These distributions were all from production revenues. The following partnerships also include
revenue from the sale of properties: A.E. Nineties-16 ($4,776), A.E. Nineties-19 ($1,607), Atlas
America Series 20 ($6,662), Atlas America Series 22 ($34), Atlas America Series 24-2003(A)
($9,066), Atlas America Series 24-2003(B) ($12,582), Atlas America Series 25-2004(A) ($595), Atlas
America Series 25-2004(B) ($3,813), A.E. Nineties-Public #1 ($2,453), A.E. Nineties-Public #2
($3,292), A.E. Nineties-Public #3 ($2,491), A.E. Nineties-Public #5 ($8,639), A.E. Nineties-Public
#7 ($2,206), Atlas America Public #11-2002 ($2,789), Atlas America Public #12-2003 ($1,568), and
Atlas America Public #14-2004 ($920).
6.
This column reflects total cash distributions beginning with the first production from the
program and includes the return of investor’s capital.
7.
These percentages are calculated by dividing the entry for each partnership in the “Total Cash
Dist. And Tax Savings” column by that partnership’s entry in the “Investor Capital” column.
8.
As of the date of this table there is not twelve months of production and/or not all wells are
drilled or on-line to sell production.
Table 5 sets forth payments made to the managing general partners and its affiliates from its
previous partnerships.
TABLE 5
SUMMARY OF PAYMENTS TO THE MANAGING GENERAL PARTNER AND AFFILIATES
FROM PRIOR PARTNERSHIPS (1)
AS OF JANUARY 15, 2007
Cumulative
Leasehold
Reimbursement
Cumulative
Drilling and
Cumulative
of General and
Investor
Gathering
Completion
Operator’s
Administrative
Partnership
Capital
Fees (1)
Costs (2)
Charges
Overhead
1.
Atlas L.P. 1 - 1985
$
600,000
0
$
600,000
$
304,924
$
60,984
2.
A.E. Partners Limited (1986)
631,250
0
631,250
243,653
101,071
3.
A.E. Partners Limited 1987
721,000
0
721,000
269,193
90,976
4.
A.E. Partners Limited 1988
617,050
0
617,050
235,580
90,860
5.
A.E. Partners Limited 1989
550,000
0
550,000
214,528
90,170
6.
A.E. Partners Limited-1990
887,500
0
887,500
350,887
108,050
7.
Atlas-Energy Partners 1990 L.P.(Series 10)
2,200,000
0
2,200,000
63,856
104,159
8.
Atlas-Energy Partners 1991 L.P.(Series 11)
750,000
0
761,802
(3)
24,714
166,221
9.
A.E. Partners Limited-1991
868,750
0
867,500
322,769
139,679
10.
Atlas-Energy for the Nineties-1 LP
(Series 12)
2,212,500
0
2,272,017
(3)
52,804
149,555
11.
Atlas JV 92 Limited Partnership
4,004,813
0
4,157,700
139,972
283,589
12.
A.E. Partners Limited-1992
600,000
0
600,000
184,462
69,263
13.
A.E. Nineties-Public #1 Ltd.
2,988,960
0
3,026,348
(3)
102,335
163,463
14.
A.E. Nineties-1993 Ltd.
3,753,937
0
3,480,656
(3)
79,531
181,148
15.
A.E. Partners Limited-1993
700,000
0
689,940
244,538
51,338
16.
A.E. Nineties-Public #2 Ltd.
3,323,920
0
3,324,668
(3)
76,021
140,230
17.
A.E. Nineties-Series 14 Ltd.
9,940,045
0
9,512,015
(3)
337,177
519,719
18.
A.E. Partners Limited-1994
892,500
0
892,500
267,905
64,968
19.
A.E. Nineties-Public #3 Ltd.
5,800,990
0
5,800,990
168,490
249,492
20.
A.E. Nineties-Series 15 Ltd.
10,954,715
0
9,859,244
(3)
410,313
511,489
21.
A.E. Partners Limited-1995
600,000
0
600,000
154,032
26,733
22.
A.E. Nineties-Public #4 Ltd.
6,991,350
0
6,991,350
247,735
285,816
23.
A.E. Nineties-Seriess 16 Ltd.
10,955,465
0
10,955,465
330,504
354,848
24.
A.E. Partners Limited-1996
800,000
0
800,000
225,401
35,666
25.
A.E. Nineties-Public #5 Ltd.
7,992,240
0
7,992,240
214,267
278,338
26.
A.E. Nineties-Series 17 Ltd.
8,813,488
0
8,813,488
310,054
295,911
27.
A.E. Nineties-Public #6 Ltd.
9,901,025
0
9,901,025
320,555
333,881
28.
A.E. Partners Limited-1997
506,250
0
506,250
132,275
21,087
29.
A.E. Nineties-Series 18 Ltd.
11,391,673
0
11,391,673
430,867
399,592
30.
A.E. Nineties-Public #7 Ltd.
11,988,350
0
11,988,350
428,918
351,771
31.
A.E. Partners Limited-1998
1,740,000
0
1,740,000
415,169
39,350
32.
A.E. Nineties-Series 19 Ltd.
15,720,450
0
15,720,450
534,525
452,888
33.
A.E. Nineties-Public #8 Ltd.
11,088,975
0
11,088,975
327,391
299,230
34.
A.E. Partners Limited-1999
450,000
0
450,000
86,360
6,928
35.
1999 Viking Resources LP
4,555,210
0
4,555,210
2,031,844
0
36.
Atlas America Series 20 Ltd.
18,809,150
0
18,809,150
741,332
490,900
37.
Atlas America Public #9 Ltd.
14,905,465
1,085,618
14,905,465
2,089,954
356,925
38.
Atlas America Series 21-A Ltd.
12,510,713
769,440
12,510,713
1,581,369
285,435
39.
Atlas America Series 21-B Ltd.
17,411,825
1,003,736
17,411,825
1,953,253
343,969
40.
Atlas America Public #10 Ltd.
21,281,170
1,398,449
21,281,170
2,092,936
409,111
41.
Atlas America Series 22-2002 Ltd.
10,156,375
654,936
10,156,375
931,150
180,184
42.
Atlas America Series 23-2002 Ltd.
9,644,550
607,052
9,644,550
818,591
166,800
43.
Atlas America Public #11-2002 LP
31,178,145
1,557,353
31,178,145
2,692,690
482,613
44.
Atlas America Series 24-2003(A) Ltd., LP
14,363,955
582,573
14,363,955
1,044,269
189,806
45.
Atlas America Series 24-2003(B) Ltd., LP
20,542,850
992,652
20,542,850
1,670,469
268,650
46.
Atlas America Public #12-2003 LP
40,170,300
1,603,869
40,170,308
2,269,772
436,538
47.
Atlas America Series 25-2004(A) LP
27,601,053
1,387,681
27,601,053
1,292,547
214,898
48.
Atlas America Series 25-2004(B) LP
31,531,035
92,671
31,531,035
2,336,563
220,245
49.
Atlas America Public #14-2004 LP
52,506,570
1,234,908
52,506,570
2,100,505
273,066
50.
Atlas America Public #14-2005(A) LP
69,674,900
1,705,047
69,674,900
1,074,320
193,191
51.
Atlas America Series 26-2005 LP
34,886,465
558,030
34,886,465
538,782
73,074
52.
Atlas America Public #15-2005(A) LP
52,245,720
688,408
52,245,720
467,391
80,124
53.
Atlas America Public #15-2006(B) LP
147,513,130
0
147,513,130
0
0
54.
Atlas America Series 27-2006 LP
70,882,965
0
70,882,965
0
0
(1)
The amount of gathering fees paid to the managing general partner and its affiliates from 2001
to the date of this table are shown for those partnerships which began operations on or after
December 31, 2000. The books and records of the earlier partnerships do not separately allocate
all of the gathering fees paid by them. Additional information concerning the gathering fees paid
by those partnerships will be provided to you on written request to the managing general partner.
(2)
Excluding the managing general partner’s capital contributions.
(3)
Includes additional drilling costs paid with production revenues.
The partnerships will have no officers, directors or employees. Instead, Atlas Resources, LLC, a
Pennsylvania limited liability company, which was originally formed as a corporation in 1979 and
then changed to a limited liability company on March 28, 2006, will serve as the managing general
partner of each partnership. However, see “- Transactions with Management and Affiliates,” below,
regarding the managing general partner’s dependence on its indirect parent companies, Atlas America
and Atlas Energy Resources, LLC and their affiliates, for facilities, management and administrative
functions and financing for capital expenditures. The managing general partner and its affiliates
operate more than 5,100 natural gas and oil wells located in the Appalachian Basin in the states of
Ohio, Pennsylvania, New York and Tennessee.
In addition, Atlas America (ATLS) transferred to Atlas Energy Resources, LLC (ATN), a newly-formed,
limited liability company subsidiary of Atlas America, substantially all of its natural gas and oil
exploration and production assets in December 2006 pursuant to the completion of an initial public
offering of 6,325,000 of its Class B limited liability company interests. At the conclusion of the
offering, pursuant to the contribution, conveyance and assumption agreement among Atlas America,
Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC, Atlas America contributed to
Atlas Energy Resources, LLC all of the stock of its natural gas and oil development and production
subsidiaries as well as the development and production assets owned by it. As consideration for
this contribution, on December 18, 2006 Atlas Energy Resources, LLC distributed to Atlas America
$121,730,000 net proceeds of the offering, 30,301,746 of common units, 748,456 Class A units, and
the management incentive interests. Atlas Energy Resources, LLC redeemed 948,750 of the common
units from Atlas America in connection with the exercise of the underwriters’ over-allotment option
on December 18, 2006. Also pursuant to the contribution agreement, Atlas America contributed to
its subsidiary, Atlas Energy Management, Inc. (“Atlas Management”), the 748,456 Class A units and
the management incentive interests. Atlas America retained approximately 81% of the limited
liability company interests of Atlas Energy Resources, LLC, which will continue to provide Atlas
America control over Atlas Energy Resources, LLC and its assets and business. This prospectus does
not constitute an offer to sell or a solicitation of an offer to buy any such securities.
Atlas America will indemnify Atlas Energy Resources, LLC until December 18, 2007 against certain
potential environmental liabilities associated with the operation of the assets and occurring
before December 18, 2006 and against claims for covered environmental liabilities made before
December 18, 2010. The obligation of the indemnitors will not exceed $25 million, and they will
not have any indemnification obligation until Atlas Energy Resources, LLC’s losses exceed $500,000
in the aggregate, and then only to the extent such aggregate losses exceed $500,000. Additionally,
Atlas America will indemnify Atlas Energy Resources, LLC for losses attributable to title defects
to the oil and gas property interests until December 18, 2009, and indefinitely for losses
attributable to retained liabilities and income taxes attributable to pre-closing operations and
the formation transactions. Atlas Energy Resources, LLC will indemnify Atlas America for all
losses attributable to the post-closing operations of the assets contributed to it, to the extent
not subject to Atlas America’s indemnification obligations.
In addition, Atlas Energy Resources, LLC became a party to an existing master natural gas gathering
agreement between Atlas America and Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating
Partnership, L.P. (collectively, “Atlas Pipeline”) pursuant to which Atlas Pipeline will gather
substantially all of the natural gas from wells operated by Atlas Energy Resources, LLC. The
gathering fees payable to Atlas Pipeline under the master natural gas gathering agreement are
generally greater than the gathering fees paid by the partnerships or the managing general
partner’s other partnerships for gathering. Pursuant to the contribution agreement, Atlas America
will assume Atlas Energy Resources, LLC’s obligation to pay these gathering fees to Atlas Pipeline;
Atlas Energy Resources, LLC will pay Atlas America the gathering fees it receives from the
partnerships and the managing general partner’s other partnership and fees associated with
production to its interest.
Further, Atlas America and Atlas Energy Resources, LLC entered into an Omnibus Agreement, which
provides that if a business opportunity with respect to an investment in or acquisition of a
domestic natural gas or oil production or development business is presented to Atlas Energy
Resources, LLC or Atlas America or its affiliates, Atlas Energy Resources, LLC will have the first
right to pursue the business opportunity as follows:
•
If the opportunity is a control investment, that is, majority control of the voting
securities of an entity, Atlas Energy Resources, LLC will have the first right of
refusal.
If the opportunity is a non-control investment, that is, less than majority control
of the voting securities of an entity, Atlas America and its affiliates will not be
restricted in their ability to pursue the opportunity and will not have an obligation
to present the opportunity to Atlas Energy Resources, LLC.
•
Notwithstanding the foregoing, if the opportunity involves an investment in natural
gas or oil wells or other natural gas or oil rights, even a non-control investment,
Atlas Energy Resources, LLC will have the right of first refusal.
The omnibus agreement will remain in effect so long as Atlas America or one of its affiliates has
the power, directly or indirectly, to direct Atlas Energy Resources, LLC’s management and policies.
Since 1985 the managing general partner has sponsored 16 public and 38 private partnerships to
conduct natural gas drilling and development activities in Pennsylvania, Ohio, New York and
Tennessee as set forth in “Prior Activities.” In these partnerships the managing general partner
and its affiliates acted as the operator and the general drilling contractor and were responsible
for drilling, completing, and operating the wells. Atlas Resources has a 97% completion rate for
wells drilled by its development partnerships.
In September 1998, Atlas Energy Group, Inc., the former parent company of the managing general
partner, merged into Atlas America, Inc., a Delaware holding company, which was a subsidiary of
Resource America, Inc., a publicly-traded company, which is sometimes referred to in this
prospectus as Resource America. In May 2004 Resource America conducted a public offering of a
portion of its common stock (the “shares”) in Atlas America. Two million six hundred forty-five
thousand shares were registered and sold at a price of at $15.50 per share resulting in gross
proceeds of $41 million. Further, in May 2004, in connection with the Atlas America offering, the
following officers and key employees of the managing general partner and Atlas America set forth in
“- Officers, Directors and Other Key Personnel,” below, resigned their positions with Resource
America and all of its subsidiaries that are not also subsidiaries of Atlas America: Mr. Freddie M.
Kotek, Mr. Frank P. Carolas, Mr. Jeffrey C. Simmons, Ms. Nancy J. McGurk, Mr. Michael L. Staines,
and Ms. Marci Bleichmar.
After the public offering, Resource America continued to own approximately 80.2% of Atlas America’s
common stock until it distributed all of its remaining 10.7 million shares of common stock in Atlas
America to its common stockholders on June 30, 2005. The distribution was in the form of a
spin-off by means of a tax free dividend of approximately 0.6 shares of Atlas America to Resource
America common stockholders for each share of Resource America common stock owned. As a result of
the spin-off, Resource America no longer determines the outcome of corporate actions requiring the
approval of Atlas America’s stockholders, such as the election and removal of directors, mergers or
other business combinations involving Atlas America, future issuances of Atlas America’s common
stock or other securities and amendments to Atlas America’s certificate of incorporation and
bylaws. Resource America’s rights following the distribution are defined by agreements between
Resource America and Atlas America.
Atlas America and Atlas Energy Resources, LLC are headquartered at 311 Rouser Road, Moon Township,
Pennsylvania15108, near the Pittsburgh International Airport, which is also the managing general
partner’s primary office.
Officers, Directors and Other Key Personnel of Managing General Partner
The officers and directors of the managing general partner will serve until their successors are
elected. The officers, directors, and key personnel of the managing general partner are as
follows:
Senior Vice President — Direct Participation Programs
Nancy J. McGurk
50
Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Michael L. Staines
57
Senior Vice President, Secretary and a Director
Michael G. Hartzell
51
Vice President — Land Administration
Donald R. Laughlin
58
Vice President — Drilling and Production
Marci F. Bleichmar
36
Vice President of Marketing
Sherwood S. Lutz
55
Senior Geologist/Manager of Geology
Michael W. Brecko
48
Director of Energy Sales
Karen A. Black
46
Vice President — Partnership Administration
Justin T. Atkinson
33
Director of Due Diligence
Winifred C. Loncar
65
Director of Investor Services
With respect to the biographical information set forth below, the approximate amount of an
individual’s professional time devoted to the business and affairs of the managing general partner,
Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc. have been aggregated.
Freddie M. Kotek. President and Chief Executive Officer since January 2002 and Chairman of the
Board of Directors since September 2001. Mr. Kotek has been Executive Vice President of Atlas
America since February 2004, and served as a director from September 2001 until February 2004 and
served as Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice
President of Resource America and President of Resource Leasing, Inc. (a wholly-owned subsidiary of
Resource America) from 1995 until May 2004 when he resigned from Resource America and all of its
subsidiaries which are not subsidiaries of Atlas America. Mr. Kotek was President of Resource
Properties from September 2000 to October 2001 and its Executive Vice President from 1993 to August
1999. Mr. Kotek received a Bachelor of Arts degree from Rutgers College in 1977 with high honors
in Economics. He also received a Master in Business Administration degree from the Harvard
Graduate School of Business Administration in 1981. Mr. Kotek will devote approximately 95% of his
professional time to the business and affairs of the managing general partner, Atlas America, Atlas
Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his professional time
to the business and affairs of the managing general partner’s other affiliates.
Frank P. Carolas. Executive Vice President — Land and Geology and a Director since January 2001.
Mr. Carolas has been an Executive Vice President of Atlas America since January 2001 and served as
a Director of Atlas America from January 2002 until February 2004. Mr. Carolas has been a Senior
Vice President of Atlas Energy Management, Inc. since 2006. Mr. Carolas was a Vice President of
Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr.
Carolas served as Vice President of Land and Geology for the managing general partner from July
1999 until December 2000 and for Atlas America from 1998 until December 2000. Before that Mr.
Carolas served as Vice President of Atlas Energy Group, Inc. from 1997 until 1998, which was the
former parent company of the managing general partner. Mr. Carolas is a certified petroleum
geologist and has been with the managing general partner and its affiliates since 1981. He
received a Bachelor of Science degree in Geology from Pennsylvania State University in 1981 and is
an active member of the American Association of Petroleum Geologists. Mr. Carolas devotes
approximately 100% of his professional time to the business and affairs of the managing general
partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Jeffrey C. Simmons. Executive Vice President — Operations and a Director since January, 2001. Mr.
Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director
of Atlas America from January 2002 until February 2004. Mr. Simmons has been a Senior Vice
President of Atlas Energy Management, Inc. since 2006. Mr. Simmons was a Vice President of
Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr.
Simmons served as Vice President of Operations for the managing general partner from July 1999
until December 2000 and for Atlas America from 1998 until December 2000. Mr. Simmons joined
Resource America in 1986 as a senior petroleum
engineer and has served in various executive positions with its energy subsidiaries since then.
Mr. Simmons received his Bachelor of Science degree with honors in Petroleum Engineering from
Marietta College in 1981 and his Masters degree in Business Administration from Ashland University
in 1992. Mr. Simmons devotes approximately 90% of his professional time to the business and
affairs of the managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas
Energy Management, Inc., and the remainder of his professional time to the business and affairs of
the managing general partner’s other affiliates, primarily Viking Resources and Resource Energy.
Jack L. Hollander. Senior Vice President — Direct Participation Programs since January 2002 and
before that he served as Vice President — Direct Participation Programs from January 2001 until
December 2001. Mr. Hollander also serves as Senior Vice President — Direct Participation Programs
of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander &
Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001,
and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services
company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University
of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law
degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander
is a member of the New York State bar and the Chairman of the Investment Program Association, which
is an industry association, as of March 2005. Mr. Hollander devotes approximately 100% of his
professional time to the business and affairs of the managing general partner, Atlas America, Atlas
Energy Resources, LLC and Atlas Energy Management, Inc.
Nancy J. McGurk. Senior Vice President since January 2002, Chief Financial Officer and Chief
Accounting Officer since January 2001. Ms. McGurk also serves as Senior Vice President since
January 2002 and Chief Accounting Officer of Atlas America since January 2001. Ms. McGurk has been
Chief Accounting Officer of Atlas Energy Resources, LLC and Atlas Energy Management, Inc. since
2006. Ms. McGurk served as Chief Financial Officer for Atlas America from January 2001 until
February 2004. Ms. McGurk was a Vice President of Resource America from 1992 until May 2004 and
its Treasurer and Chief Accounting Officer from 1989 until May 2004 when she resigned from Resource
America. Also, since 1995 Ms. McGurk has served as Vice President — Finance of Resource Energy,
Inc. Ms. McGurk received a Bachelor of Science degree in Accounting from Ohio State University in
1978, and has been a Certified Public Accountant since 1982. Ms. McGurk will devote approximately
80% of her professional time to the business and affairs of the managing general partner, Atlas
America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of her
professional time to the business and affairs of the managing general partner’s other affiliates.
Michael L. Staines. Senior Vice President, Secretary, and a Director since 1998. Mr. Staines has
been an Executive Vice President and Secretary of Atlas America since 1998. Mr. Staines was a
Senior Vice President of Resource America from 1989 until May 2004 when he resigned from Resource
America. Mr. Staines was a director of Resource America from 1989 to February 2000 and Secretary
from 1989 to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP since
January 2001 and its Chief Operating Officer and a member of its Managing Board since its formation
in November 1999. Mr. Staines is a member of the Ohio Oil and Gas Association and the Independent
Oil and Gas Association of New York. Mr. Staines received a Bachelor of Science degree from
Cornell University in 1971 and a Master of Business degree from Drexel University in 1977. Mr.
Staines will devote approximately 5% of his professional time to the business and affairs of the
managing general partner and Atlas America, and the remainder of his professional time to the
business and affairs of the managing general partner’s other affiliates, including Atlas Pipeline
Partners GP.
Michael G. Hartzell. Vice President — Land Administration since September 2001. Mr. Hartzell has
been Vice President — Land Administration of Atlas America since January 2002, and before that
served as Senior Land Coordinator from January 1999 to January 2002. Mr. Hartzell has been Vice
President — Land Administration of Atlas Energy Management, Inc. since 2006. Mr. Hartzell has been
with the managing general partner and its affiliates since 1980 when he began his career as a land
department representative. Mr. Hartzell manages all Land Department functions. Mr. Hartzell
serves on the Environmental Committee of the Independent Oil and Gas Association of Pennsylvania
and is a past Chairman of the Committee. Mr. Hartzell received his Bachelor of Science degree in
Business Management from the University of Phoenix in 2004. Mr. Hartzell devotes approximately
100% of his professional time to the business and affairs of the managing general partner, Atlas
America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Donald R. Laughlin. Vice President — Drilling and Production since September 2001. Mr. Laughlin
also serves as Vice President — Drilling and Production for Atlas America since January 2002, and
before that served as Senior Drilling Engineer
since May 2001 when he joined Atlas America. Mr. Laughlin has been Vice President — Drilling and
Production of Atlas Energy Management, Inc. since 2006. Mr. Laughlin has over thirty years of
experience as a petroleum engineer in the Appalachian Basin, having been employed by Columbia Gas
Transmission Corporation from October 1995 to May 2001 as a senior gas storage engineer and team
leader, Cabot Oil & Gas Corporation from 1989 to 1995 as Manager of Drilling Operations and
Technical Services, Doran & Associates, Inc. from 1977 until 1989 as Vice President—Operations, and
Columbia Gas from 1970 to 1977 as Drilling Engineer and Gas Storage Engineer. Mr. Laughlin
received his Petroleum Engineering degree from the University of Pittsburgh in 1970. He is a
member of the Society of Petroleum Engineers. Mr. Laughlin devotes approximately 100% of his
professional time to the business and affairs of the managing general partner, Atlas America, Atlas
Energy Resources, LLC and Atlas Energy Management, Inc.
Marci F. Bleichmar. Vice President of Marketing since February 2001. Ms. Bleichmar also serves as
Vice President of Marketing for Atlas America since February 2001 and was with Resource America
from February 2001 until May 2004 when she resigned from Resource America. From March 2000 until
February 2001, Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a mutual
fund manager), and from March 1998 until March 2000, she was an account executive at Bloomberg
Financial Services LP. From November 1994 until 1998, Ms. Bleichmar was an Associate on the
Derivatives Trading Desk of JP Morgan. Ms. Bleichmar received a Bachelor of Arts degree from the
University of Wisconsin in 1992. Ms. Bleichmar devotes approximately 100% of her professional time
to the business and affairs of the managing general partner, Atlas America, Atlas Energy Resources,
LLC and Atlas Energy Management, Inc.
Sherwood S. Lutz. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined Viking Resources,
which was purchased by Resource America in 1999 as senior geologist. Since 1999 Mr. Lutz has been
a senior geologist for the managing general partner and Atlas America. Mr. Lutz received his
Bachelor of Science degree in Geological Sciences from the Pennsylvania State University in 1973.
Mr. Lutz is a certified petroleum geologist with the American Association of Petroleum Geologists
as well as a licensed professional geologist in Pennsylvania. Mr. Lutz devotes approximately 100%
of his professional time to the business and affairs of the managing general partner, Atlas
America, Atlas Energy Resources, LLC and Atlas Energy Management, LLC.
Michael W. Brecko. Director of Energy Sales since November 2002. Mr. Brecko has over 19 years of
natural gas marketing experience in the oil and natural gas industry. Mr. Brecko is a 1980
graduate from The Pennsylvania State University with a Bachelor of Science degree in Civil
Engineering. His career in natural gas marketing began when he joined Equitable Gas Company, a
local distribution company, as a marketing representative in the commercial/ industrial marketing
division from May 1986 to August 1992. He subsequently joined O&R Energy, a subsidiary of Orange
and Rockland Utilities, as regional marketing manager from August 1992 to November 1993. Beginning
in December 1993 through July 2001, Mr. Brecko worked for Cabot Oil & Gas Corporation, a mid-sized
Appalachian oil and natural gas producer, as an account executive and he was promoted in August
1998 to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a multi-energy
sourced company, as a regional account manager before joining Atlas America in 2002. Mr. Brecko
devotes approximately 100% of his professional time to the business and affairs of the managing
general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Karen A. Black. Vice President — Partnership Administration since February 2003. Ms. Black is
also Vice President and Financial and Operations Principal of Anthem Securities since October 2002.
Ms. Black joined the managing general partner and Atlas America in July 2000 and served as manager
of production, revenue and partnership accounting from July 2000 through October 2001, after which
she served as manager and financial analyst until her appointment as Vice President — Partnership
Administration. Before joining the managing general partner in 2000, Ms. Black was associated with
Texas Keystone, Inc. as controller from April 1997 through June 2000. Ms. Black was employed as a
tax accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997. Ms. Black
received a Bachelor of Arts degree from the University of Pittsburgh, Johnstown in 1982. Ms. Black
devotes approximately 50% of her professional time to the business and affairs of the managing
general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and
the remainder of her professional time to the business and affairs of Anthem Securities.
Justin T. Atkinson. Director of Due Diligence since February 2003. Mr. Atkinson also serves as
President of Anthem Securities since February 2004 and as Chief Compliance Officer since October
2002. Before that Mr. Atkinson served as assistant compliance officer of Anthem Securities from
December 2001 until October 2002 and Vice President from October 2002 until February 2004. Before
his employment with the managing general partner, Mr. Atkinson was a manager of
investor and broker/dealer relations with Viking Resources Corporation from 1996 until November
2001. Mr. Atkinson earned a Bachelor of Arts degree in Business Management in 1995 from Walsh
University in North Canton, Ohio. Mr. Atkinson devotes approximately 25% of his professional time
to the business and affairs of the managing general partner, Atlas America, Atlas Energy Resources,
LLC and Atlas Energy Management, Inc., and the remainder of his professional time to the business
and affairs of Anthem Securities.
Winifred C. Loncar, Director of Investor Services since February 2003. Ms. Loncar previously held
the position of manager of investor services from the inception of the investor service department
in 1990 to February 2003. Before that she was executive secretary to the managing general partner.
Ms. Loncar received a Bachelor of Science degree in Business from Point Park University in 1998.
Ms. Loncar devotes approximately 100% of her professional time to the business and affairs of the
managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management,
Inc.
Organizational Diagram and Security Ownership of Beneficial Owners
Atlas America owns approximately 81% of the limited liability company interests of Atlas Energy
Resources, LLC, which owns 100% of the limited liability company interests of Atlas Energy
Operating Company, LLC, which owns 100% of the limited liability company interests of AIC, LLC,
which owns 100% of the limited liability company interests of the managing general partner. The
officers and directors of Atlas America and Atlas Energy Resources, LLC are set forth below. The
directors of AIC, LLC are Jonathan Z. Cohen, Michael L. Staines, and Jeffrey C. Simmons. The
biographies of Messrs. Staines and Simmons are set forth above.
On January 12, 2006, Atlas Pipeline Holdings, L.P., a wholly-owned subsidiary of Atlas
America, filed a registration statement with the SEC for an initial public offering of 3.6
million of its common units, which represented an approximate 17.1% limited partner interest
in the company. On July 26, 2006, Atlas Pipeline Holdings, L.P. issued 3.6 million common
units, representing a 17.1% ownership interest, in the initial public offering at a price of
$23 per unit, and the underwriters were granted a 30-day option to purchase up to an
additional 540,000 common units. Substantially all of the net proceeds from this offering,
approximately $77 million, have been paid to Atlas America. Atlas America continues to own
approximately 82.9% of Atlas Pipeline Holdings GP, LLC, which gives Atlas America indirect
general partner control over Atlas Pipeline Partners (APL).
Atlas America, Inc., a Delaware Company
As of August 24, 2006, the officers and directors for Atlas America include the following:
NAME
AGE
POSITION
Edward E. Cohen
67
Chairman, Chief Executive Officer and President
Frank P. Carolas
47
Executive Vice President
Freddie M. Kotek
50
Executive Vice President
Jeffrey C. Simmons
47
Executive Vice President
Michael L. Staines
57
Executive Vice President and Secretary
Matthew A. Jones
44
Chief Financial Officer
Nancy J. McGurk
50
Senior Vice President and Chief Accounting Officer
Jonathan Z. Cohen
36
Vice Chairman
Carlton M. Arrendell
44
Director
William R. Bagnell
43
Director
Donald W. Delson
55
Director
Nicholas DiNubile
54
Director
Dennis A. Holtz
66
Director
Harmon S. Spolan
70
Director
See “- Officers, Directors and Other Key Personnel,” above, for biographical information on certain
of these individuals who are also officers of the managing general partner. Biographical
information on the other officers and directors will be provided by the managing general partner on
request.
The managing general partner and its affiliates under Atlas America employ more than 205 persons.
Atlas Energy Resources, LLC, a Delaware Limited Liability Company
As of December 12, 2006, the directors, nominees and executive officers for Atlas Energy Resources,
LLC include the following:
NAME
AGE
POSITION OR OFFICE
Edward E. Cohen
67
Chairman of the Board and Chief Executive Officer
Jonathan Z. Cohen
36
Vice Chairman of the Board
Richard D. Weber
43
President, Chief Operating Officer and Director
Matthew A. Jones
44
Chief Financial Officer and Director
Nancy J. McGurk
50
Chief Accounting Officer
Lisa Washington
39
Chief Legal Officer and Secretary
Walter C. Jones
43
Director
Ellen F. Warren
50
Director
Bruce M. Wolf
58
Director
See “- Officers, Directors and Other Key Personnel,” above, for biographical information on Ms.
McGurk, who also is an officer of the managing general partner. Also, on May 9, 2006 Mr. Richard
Weber was appointed President, Chief Operating Officer and a director of Atlas Energy Resources,
LLC. In conjunction with Mr. Weber’s appointment, Atlas America and
Mr. Weber entered into an employment agreement dated April 5, 2006. Mr. Weber served from June
1997 until March 2006 as Managing Director and Group Head of the Energy Group of KeyBanc Capital
Markets, a division of KeyCorp, and its predecessor, McDonald & Company Securities, Inc. As part
of his duties, he oversaw the bank’s activities with oil and gas producers, pipeline companies and
utilities. He has a particular expertise in the Appalachian Basin, where he led over 40
transactions, including the IPOs of Atlas America and Atlas Pipeline and the sale of Viking
Resources Corporation to Atlas America.
Biographical information on the other officers and directors of Atlas Energy Resources, LLC will be
provided by the managing general partner on request.
Atlas Energy Management, Inc., a Delaware Company
As of July 28, 2006, the officers for Atlas Energy Management, Inc. include the following:
NAME
AGE
POSITION OR OFFICE
Edward E. Cohen
67
Chairman of the Board and Chief Executive Officer
Richard D. Weber
43
President, Chief Operating Officer and Director
Jeffrey C. Simmons
48
Senior Vice President
Frank P. Carolas
47
Senior Vice President
Matthew A. Jones
44
Chief Financial Officer
Nancy J. McGurk
50
Chief Accounting Officer
Donald R. Laughlin
58
Vice President — Drilling and Production
Michael G. Hartzell
51
Vice President — Land Administration
Lisa Washington
39
Chief Legal Officer and Secretary
See “- Officers, Directors and Other Key Personnel,” above, for biographical information on certain
of these individuals who are also officers of the managing general partner. Biographical
information on the other officers and directors will be provided by the managing general partner on
request.
Remuneration of Officers and Directors
No officer or director of the managing general partner will receive any direct remuneration or
other compensation from the partnerships. These persons will receive compensation solely from
affiliated companies of the managing general partner.
Code of Business Conduct and Ethics
Because the partnerships do not directly employ any persons, the managing general partner has
determined that the partnerships will rely on a Code of Business Conduct and Ethics adopted by
Atlas America, Inc. and/or Atlas Energy Resources, LLC that applies to the principal executive
officer, principal financial officer and principal accounting officer of the managing general
partner, as well as to persons performing services for the managing general partner generally. You
may obtain a copy of this Code of Business Conduct and Ethics by a request to the managing general
partner at Atlas Resources, LLC, 311 Rouser Road, Moon Township, Pennsylvania15108.
Transactions with Management and Affiliates
The managing general partner depends on its indirect parent companies, Atlas America and Atlas
Energy Resources, LLC, and their affiliates, for management and administrative functions and
financing for capital expenditures. The managing general partner paid a management fee to Atlas
America for management and administrative services, which amounted to $60 million, $47.5 million
and $21.6 million for the years ended September 30, 2006, 2005, and 2004, respectively.
Additionally, in connection with the initial public offering of Atlas Energy Resources, LLC
described above, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy
Management, Inc. (“Atlas Management”) entered into a management agreement. The management
agreement provides that Atlas Management will manage Atlas Energy Resources, LLC’s business affairs
under the supervision of Atlas Energy Resources, LLC’s board of directors (the “board”). Atlas
Management will provide Atlas Energy Resources, LLC, including the managing general partner, with
all services necessary or appropriate for the conduct of their business, including the following:
providing executive and administrative personnel, office space and office services
required in rendering services to Atlas Energy Resources, LLC and its subsidiaries;
•
investigating, analyzing and proposing possible acquisition and investment
opportunities;
•
evaluating and recommending to the board and Atlas Energy Resources, LLC’s officers
hedging strategies and engaging in hedging activities on Atlas Energy Resources, LLC’s
behalf, consistent with such strategies;
•
negotiating agreements on Atlas Energy Resources, LLC’s behalf;
•
at the direction of the audit committee of the board, causing Atlas Energy
Resources, LLC to retain qualified accountants to assist in developing appropriate
accounting procedures, compliance procedures and testing systems with respect to
financial reporting obligations, and to conduct quarterly compliance reviews with
respect thereto;
•
causing Atlas Energy Resources, LLC to qualify to do business in all applicable
jurisdictions and to obtain and maintain all appropriate licenses;
•
assisting Atlas Energy Resources, LLC in complying with all regulatory requirements
applicable to it with respect to its business activities, including preparing or
causing to be prepared all financial statements required under applicable regulations
and contractual undertakings, all required tax filings and all reports and documents,
if any, required under the Securities Exchange Act;
•
handling and resolving all claims, disputes or controversies (including all
litigation, arbitration, settlement or other proceedings or negotiations) in which
Atlas Energy Resources, LLC may be involved or to which it may be subject arising out
of its day-to-day operations, subject to such limitations or parameters as may be
imposed from time to time by the board;
•
advising Atlas Energy Resources, LLC with respect to obtaining financing for Atlas
Energy Resources, LLC’s operations;
•
performing such other services as may be required from time to time for management
and other activities relating to Atlas Energy Resources, LLC’s assets as the board
reasonably requests or Atlas Management deems appropriate under the particular
circumstances;
•
obtaining and maintaining, on Atlas Energy Resources, LLC’s behalf, insurance
coverage for Atlas Energy Resources, LLC’s business and operations, including errors
and omissions insurance with respect to the services provided by Atlas Management, in
each case in the types and minimum limits as Atlas Management determines to be
appropriate and as is consistent with standard industry practice; and
•
using commercially reasonable efforts to cause Atlas Energy Resources, LLC to comply
with all applicable laws.
In exercising its powers and discharging its duties under the management agreement, Atlas
Management must act in good faith.
Atlas Energy Resources, LLC will reimburse Atlas Management for all expenses that it incurs on
Atlas Energy Resources, LLC’s behalf pursuant to the management agreement. These expenses will
include costs for providing corporate staff and support services to Atlas Energy Resources, LLC,
including the managing general partner and its partnerships. Atlas Management will charge on a
fully-allocated cost basis for services provided to Atlas Energy Resources, LLC. This
fully-allocated cost basis is based on the percentage of time spent by personnel of Atlas
Management and its affiliates on Atlas Energy Resources, LLC’s matters and includes the
compensation paid by Atlas Management and its affiliates to such persons
and their allocated overhead. The allocation of compensation expense for such persons will be
determined based on a good faith estimate of the value of each such person’s services performed on
Atlas Energy Resources, LLC’s business and affairs, subject to the periodic review and approval of
the board’s audit or conflicts committee.
Atlas Management, its stockholders, directors, officers, employees and affiliates will not be
liable to Atlas Energy Resources, LLC, and any subsidiary of Atlas Energy Resources, LLC for acts
or omissions performed in good faith and in accordance with and pursuant to the management
agreement, except by reason of acts constituting gross negligence, bad faith, willful misconduct,
fraud or a knowing violation of criminal law. Atlas Energy Resources, LLC will indemnify Atlas
Management, its stockholders, directors, officers, employees and affiliates for all expenses and
losses arising from acts of Atlas Management, its stockholders, directors, officers, employees and
affiliates not constituting gross negligence, bad faith, willful misconduct, fraud or a knowing
violation of criminal law performed in good faith in accordance with and pursuant to the management
agreement. Atlas Management and its affiliates will indemnify Atlas Energy Resources, LLC for all
expenses and losses arising from acts of Atlas Management or its affiliates constituting gross
negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law or any
claims by employees of Atlas Management or its affiliates relating to the terms and conditions of
their employment. Atlas Management and/or Atlas America will carry errors and omissions and other
customary insurance.
The management agreement may not be amended without the prior approval of the conflicts committee
of the board if the proposed amendment will, in the reasonable discretion of the board, adversely
affect common unitholders. The management agreement does not have a specific term; however, Atlas
Management may not terminate the agreement before December 18, 2016. Atlas Energy Resources, LLC
may terminate the management agreement only upon the affirmative vote of holders of at least
two-thirds of its outstanding common units, including units held by Atlas America and its
affiliates. If Atlas Energy Resources, LLC terminates the management agreement, Atlas Management
will have the option to require the successor manager, if any, to purchase the Class A units and
management incentive interests for their fair market value as determined by agreement between the
departing manager and the successor manager.
(See “Financial Information Concerning the Managing General Partner and Atlas Resources Public
#16-2007(A) L.P.,” including the indebtedness owed by the managing general partner to Atlas
America.)
The managing general partner and its officers, directors and affiliates have in the past invested,
and may in the future invest, in partnerships sponsored by the managing general partner. They may
also subscribe for units in the partnerships as described in “Plan of Distribution.”
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION, RESULTS OF OPERATIONS,
LIQUIDITY AND CAPITAL RESOURCES
Both of the partnerships have been formed as limited partnerships under the Delaware Revised
Uniform Limited Partnership Act. The partnerships, however, have not included any historical
information in this prospectus since they have no net worth, do not own any properties on which
wells will be drilled, have no third-party investors, and have not conducted any operations. (See
“Capitalization and Source of Funds and Use of Proceeds,”“Proposed Activities,”“Competition,
Markets and Regulation,” and “Financial Information Concerning the Managing General Partner and
Atlas Resources Public #16-2007(A) L.P.”)
Each partnership will depend on the proceeds of this offering and the managing general partner’s
capital contributions to carry out its proposed activities. Each partnership intends to use its
subscription proceeds to pay the following:
•
the intangible drilling costs of the partnership’s wells;
•
the investors’ share of equipment costs of the partnership’s wells; and
•
the investors’ share of any cost overruns of drilling and completing the partnership’s wells.
The managing general partner believes that each partnership’s liquidity requirements will be satisfied from the following:
•
subscription proceeds of this offering;
•
the managing general partner’s capital contributions;
•
cash flow from future operations; and
•
partnership borrowings, if necessary.
The managing general partner also anticipates that no additional funds will be required for
operating costs before a partnership begins receiving production revenues from its wells.
Substantially all of the subscription proceeds of you and the other investors in a partnership will
be committed or expended after the offering of the partnership closes. If a partnership requires
additional funds for cost overruns or additional development or remedial work after a well begins
producing, then these funds may be provided by:
•
subscription proceeds, if available;
•
drilling fewer wells, or acquiring a lesser working interest in one or more wells;
•
borrowings from the managing general partner or its affiliates; or
•
retaining partnership revenues.
There will be no borrowings from third-parties. The amount that may be borrowed by a partnership
from the managing general partner and its affiliates may not at any time exceed 5% of the
partnership’s subscription proceeds from you and the other investors and must be without recourse
to you and the other investors. The partnership’s repayment of any borrowings would be from
partnership production revenues and would reduce or delay your cash distributions.
If the managing general partner loans money to a partnership, which it is not required to do, then:
•
the interest charged to the partnership must not exceed the managing general
partner’s interest cost or the interest that would be charged to the partnership
without reference to the managing general partner’s financial abilities or guarantees
by unrelated lenders, on comparable loans for the same purpose; and
•
the managing general partner may not receive points or other financing charges or
fees, although the actual amount of the charges incurred from third-party lenders may
be reimbursed to the managing general partner.
As of December 18, 2006, the managing general partner’s affiliate, Atlas Energy Operating Company,
LLC (“Atlas Energy Operating”) entered into a $250 million senior secured credit facility with
Wachovia Bank, National Association, as administrative agent, Wachovia Capital Markets LLC, as lead
arranger, and other lenders. The credit facility allows Atlas Energy Operating to borrow up to the
determined amount of the borrowing base, which will be based upon the loan collateral value
assigned to its various natural gas and oil properties. The initial borrowing base is $155 million.
The borrowing base will be subject to redetermination on March 14, 2007 and on a semi-annual basis
thereafter. The credit facility will mature on December 18, 2011.
Atlas Energy Operating’s obligations under the credit facility are secured by mortgages on its
natural gas and oil properties as well as a pledge of all of its ownership interests in its
operating subsidiaries including the managing general partner, other than Anthem Securities. Atlas
Energy Operating will be required to maintain the mortgages on properties representing at least 80%
of its natural gas and oil properties. Additionally, the obligations under the credit facility are
guaranteed by Atlas Energy Resources, LLC and all of Atlas Energy Operating’s existing operating
subsidiaries, including the managing general partner, and by any future subsidiaries, other than
Anthem Securities. Borrowings under the credit facility will be available
for development, exploitation and acquisition of natural gas and oil properties, working capital
and general corporate purposes.
At Atlas Energy Operating’s election, interest will be determined by reference to the London
interbank offered rate, or LIBOR, plus an applicable margin between 1.00% and 1.75% per annum,
depending on its usage of the facility or the higher of (i) the federal funds rate plus 0.50% or
(ii) the Wachovia prime rate, plus, in each case, an applicable margin between 0.00% and 0.75% per
annum, depending on its usage of the facility. Interest will generally be payable quarterly for
domestic bank rate loans and at the end of each applicable interest period for LIBOR loans.
The credit facility contains covenants that, among other things, limit Atlas Energy Resources, LLC’s ability to:
•
incur indebtedness;
•
grant certain liens;
•
enter into certain leases;
•
make certain loans, acquisitions, capital expenditures and investments;
•
enter into hedging arrangements that exceed 85% of its proved reserves;
•
make any change to the character of its business or the business of the investment partnerships;
•
merge or consolidate; or
•
engage in certain asset dispositions, including a sale of all or substantially all of its assets.
The credit facility requires Atlas Energy Operating to maintain a current ratio (defined as the
ratio of current assets to current liabilities) of not less than 1.0 to 1.0; a funded debt to
EBITDA ratio of not more than 3.5 to 1.0; and a minimum interest coverage ratio (defined as EBITDA
divided by interest expense) of not less than 2.5 to 1.0. The credit facility defines EBITDA for
any period of four fiscal quarters as the sum of consolidated net income for the period plus
interest, income taxes, depreciation, depletion and amortization.
If an event of default exists under the credit facility, the lenders will be able to accelerate the
maturity of the credit facility and exercise other customary rights and remedies, including
prohibiting Atlas Energy Resources, LLC from paying distributions. Each of the following is an
event of default:
•
failure to pay any principal when due or any interest, fees or other amounts in the credit facility;
•
failure to pay any principal or interest on any of other debt aggregating $2.5 million or more;
•
a representation, warranty or certification made under the loan documents or in any
certificate furnished thereunder is false or misleading as of the time made or
furnished in any material respect;
•
failure to perform under any obligation set forth in the credit facility, subject to
a grace period;
•
an event having a material adverse effect on Atlas Energy Resources, LLC, any of the
guarantors or the collateral used to secure indebtedness;
•
admission in writing the inability to, or being generally unable to, pay debts as they become due;
•
bankruptcy or insolvency events;
•
commencement of a proceeding or case in any court of competent jurisdiction, without
application or consent, involving:
liquidation, reorganization, dissolution or winding-up; or
•
the appointment of a trustee, receiver, custodian, liquidator or the like;
•
the entry of, and failure to pay, one or more judgments in excess of $2.5 million;
•
the loan documents cease to be in full force and effect or cease to create a valid,
binding and enforceable lien;
•
a change of control, generally defined as (i) a group or person acquiring 35% or
more of Atlas Energy Resources, LLC’s outstanding voting units (other than Atlas
America and its affiliates), (ii) Atlas Energy Resources, LLC’s failure to own 85% or
more of the outstanding shares of voting capital stock of any of its subsidiaries that
is a guarantor under the credit facility, (iii) Atlas Energy Resources, LLC’s failure
to own 100% of Atlas Energy Operating or (iv) the failure of Atlas America or any of
its wholly-owned subsidiaries to own at least 51% of the equity of Atlas Management;
and
•
concealment of property with the intent to hinder, delay or defraud any lender with
respect to their rights to such property.
The managing general partner depends on its indirect parent companies, Atlas America and Atlas
Energy Resources, LLC, and their affiliates, for management and administrative functions and
financing for capital expenditures. The managing general partner paid a management fee to Atlas
America for management and administrative services, as described in “Management — Transactions with
Management and Affiliates.” See the footnotes to the managing general partner’s audited financial
statements and the footnotes to the managing general partner’s unaudited financial statements for
more details concerning the credit facility and inter-company borrowings in “Financial Information
Concerning the Managing General Partner and Atlas Resources Public #16-2007(A) L.P.”
PROPOSED ACTIVITIES
Overview of Drilling Activities
The managing general partner anticipates that the subscription proceeds of each partnership will be
used to drill primarily natural gas development wells, which means a well drilled within the proved
area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be
productive. Stratigraphic means a layer of rock which has characteristics that differentiate it
from the rocks above and below it. Stratigraphic horizon generally means that part of a formation
or layer of rock with sufficient porosity and permeability to form a petroleum reservoir.
Currently, the partnerships do not hold any interests in any properties or prospects on which the
wells will be drilled.
Although the majority of the wells to be drilled by each partnership will be classified as natural
gas wells, which may produce a small amount of oil, some of the wells, such as wells drilled in
McKean County, Pennsylvania, if any, may be classified as oil or combination oil and natural gas
wells.
Each partnership will be a separate business entity from the other partnership, and you will be a
partner only in the partnership in which you invest. You will have no interest in the business,
assets or tax benefits of the other partnership unless you also invest in the other partnership.
Thus, your investment return will depend solely on the operations and success or lack of success of
the particular partnership in which you invest.
Each partnership generally will drill different wells, but they may own working interests and
participate in drilling and completing one or more of the same wells. The number of wells to be
drilled by a partnership cannot be determined precisely before the funding of the partnership and
is determined primarily by:
•
the amount of subscription proceeds raised by the partnership;
•
the geographical areas in which wells are drilled by the partnership;
the partnership’s percentage of working interest owned in the wells, which could
range from 25% to 100%; and
•
the cost of the partnership’s wells, including any cost overruns for intangible
drilling costs and equipment costs of the wells which are charged to you and the other
investors under the partnership agreement.
For the estimated number of wells to be drilled at the minimum subscription proceeds of $2 million
and the maximum subscription proceeds of $200 million for a partnership, see “Risk Factors — Risks
Related to an Investment in a Partnership — Spreading the Risks of Drilling Among a Number of Wells
Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are
Drilled.”
Before the managing general partner selects a prospect on which a well will be drilled by a
partnership, it will review all available geologic and production data for wells located in the
vicinity of the proposed well including, but not limited to:
•
various well logs;
•
completion reports;
•
plugging reports; and
•
production reports.
In selecting prospects for drilling, the managing general partner will use the following criteria
from adjacent prospects or in the immediate area to the extent available to it, such as production
information, sand thickness, porosities and water saturations which lead the managing general
partner to believe that the proposed well locations will be productive. In most cases, a prospect
must be classified as proved undeveloped before the managing general partner will drill the well,
which generally means that the well is being drilled to a geologic feature which contains proved
reserves and is adjacent to a prospect that has or had a productive well. See the partnership
agreement for the complete definition.
For example, production information from surrounding wells in the area is an important indicator in
evaluating the economic potential of a proposed well to be drilled. It has been the managing
general partner’s experience that natural gas production from wells drilled to the formations or
the reservoirs in the areas of operations discussed below in “- Primary Areas of Operations,” is
reasonably consistent with nearby wells, although from time to time there can be great differences
in the natural gas volumes and performance of wells located on contiguous prospects. However,
production information is only one factor, and the managing general partner may propose a well to
be drilled by a partnership because geologic trends in the immediate area, such as sand thickness,
porosities and water saturations, lead the managing general partner to believe that the proposed
well locations will be productive.
Primary Areas of Operations
The managing general partner will not decide on all of the specific wells to be drilled by a
partnership until the offering of units in that partnership has ended. However, the managing
general partner intends that Atlas Resources Public #16-2007(A) L.P. will drill the prospects
described in “Appendix A — Information Regarding Currently Proposed Prospects for Atlas Resources
Public #16-2007(A) L.P.” These prospects represent the wells to be drilled if a portion of the
nonbinding targeted subscription proceeds for that partnership, as described in “Terms of the
Offering — Subscription to a Partnership,” are received. The managing general partner will
substitute a new prospect if there are material adverse events with respect to any of the currently
proposed prospects. For example, the managing general partner will substitute a prospect if:
•
the latest geological and production data in the area from new wells being drilled
indicates that the well may be non-productive or less productive than anticipated;
•
there are potential title problems;
•
drilling rigs, tubular goods and services in the area will not be available;
approvals by federal and state departments or agencies cannot be obtained; or
•
other properties are available that appear to be of a higher quality.
Also, the managing general partner has the sole discretion to sell up to and including all of the
units in Atlas Resources Public #16-2007(A) L.P., and it may and not offer and sell any units in
Atlas Resources Public #16-2007(B) L.P. In that event, the number of prospects identified in
“Appendix A — Information Regarding Currently Proposed Prospects for Atlas Resources Public
#16-2007(A) L.P.” as a percentage of the total number of prospects to be drilled by Atlas Resources
Public #16-2007(A) L.P. would be reduced. The managing general partner also anticipates that it
will designate a portion of the prospects in the partnership designated Atlas Resources Public
#16-2007(B) L.P., if units in that partnership are offered, by a supplement or an amendment to the
registration statement of which this prospectus is a part.
Because not all of the prospects for each partnership will be specified, you will not be able to
evaluate all of the prospects that will be drilled by your partnership. However, by waiting as
long as possible before selecting all of the prospects to be drilled by a partnership, the managing
general partner may acquire additional information to help it select better prospects for the
partnership, and it may be able to include prospects that were not available when this prospectus
was written or even when the offering of units in the partnership is closed.
The following discussion includes a general description of the areas where the managing general
partner anticipates partnership wells may be drilled. All of the areas are situated in the
Appalachian Basin, which is a mature producing region in the United States overlaying the states of
New York, Pennsylvania, Ohio, Tennessee, West Virginia, Maryland, Kentucky and Virginia. The
Appalachian Basin has well known geologic characteristics as described below, although with respect
to each area listed below, the geological aspects are continually being evaluated by the managing
general partner. Thus, each area discussed may ultimately include other counties which are not set
forth below. For purposes of this prospectus, however, the counties listed below are generally
descriptive of the specific drilling area being discussed. With the exception of the north central
Tennessee area, the primary areas are situated in western Pennsylvania as discussed below. The
three primary areas for the partnerships’ drilling activities are:
•
the Mississippian/Upper Devonian Sandstone reservoirs in Fayette, Greene and
Westmoreland Counties, Pennsylvania;
•
the Clinton/Medina geological formation which includes western Pennsylvania,
primarily Crawford and Mercer Counties, Pennsylvania and also includes an area in
eastern Ohio situated primarily in Stark, Mahoning, Trumbull and Portage Counties,
Ohio; and
•
the Mississippian (carbonates) and Devonian Shale reservoirs in Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennessee.
All of the primary areas described above have the following similarities:
•
geological features such as structure and faulting generally are not factors used to
find commercial production from a well drilled to this formation or these reservoirs
and the governing factors appear to be sand or oolite (carbonate sand) quality in terms
of net pay zone thickness, porosity, and the effectiveness of fracture stimulation in
the well;
•
a well drilled to this formation or these reservoirs usually requires hydraulic
fracturing of the formation to stimulate productive capacity;
•
generally, natural gas from a well drilled to this formation or these reservoirs is
produced at rates which decline rapidly during the first few years of operations and,
although the well can produce for many years, a proportionately larger amount of the
well’s production can be expected within the first several years; and
•
it has been the managing general partner’s experience that natural gas production
from wells drilled to this formation or these reservoirs is reasonably consistent with
nearby wells, although from time to time there
can be great differences in the natural gas volumes and performance of wells on
contiguous prospects. Thus, as drilling progresses, reserves from newly completed
wells are reclassified from the proved undeveloped to the proved developed category
and additional adjacent locations are added to proved undeveloped reserves.
The managing general partner anticipates that the majority of the subscription proceeds of each
partnership will be expended in the primary areas, although some of the subscription proceeds of
each partnership may be expended in the secondary areas or in areas that are not currently known.
Among the primary areas, the managing general partner anticipates that each partnership will drill
more prospects in the Fayette County, Pennsylvania area than in the other areas. Also, see “-
Secondary Areas of Operations” for a discussion of the Marcellus Shale in the Fayette County area.
Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania.
The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found
throughout most of the Appalachian Basin. These reservoirs have porosities ranging from 5% to 20%
with attendant permeabilities. Porosity is the percentage of void space between sand grains that
is available for occupancy by either liquids or gases; and permeability is the property of porous
rock that allows fluids or gas to flow through it. See the geologic evaluation prepared by United
Energy Development Consultants, Inc., an independent geological and engineering firm in “Appendix A
- Information Regarding Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.”,
for a discussion of the development of the Mississippian/Upper Devonian Sandstone reservoirs in
Fayette, Greene and Westmoreland Counties, Pennsylvania.
The wells in the Mississippian/Upper Devonian Sandstone reservoirs will be:
•
situated on approximately 20 acres, subject to adjustment to take into account lease boundaries;
•
drilled at least 1,000 feet from a producing well, although a partnership may drill
a new well or re-enter an existing well that is closer than 1,000 feet to a plugged and
abandoned well;
•
drilled to approximately 1,900 to 6,000 feet in depth;
•
classified as natural gas wells that may produce a small amount of oil; and
•
primarily connected to the gathering system owned by Atlas Pipeline Partners and
have their natural gas production primarily marketed to UGI Energy Services, Colonial
Energy, ConocoPhillips Company and Equitable Gas Company as discussed below in “- Sale
of Natural Gas and Oil Production.”
Also, see “- Secondary Areas of Operations” for a discussion of the Marcellus Shale in the Fayette
County area.
Clinton/Medina Geological Formation in Western Pennsylvania.
The Clinton/Medina geological
formation is a blanket sandstone found throughout most of the northwestern edge of the Appalachian
Basin. The Clinton/Medina geological formation in Pennsylvania and Ohio is the same geological
formation, although in Pennsylvania it is often referred to as the Medina/Whirlpool geological
formation. For purposes of this prospectus, the term Clinton/Medina geological formation is used
for both Ohio and Pennsylvania. The Clinton/Medina geological formation is described in petroleum
industry terms as a “tight” sandstone with porosity ranging from 6% to 12% and with very low
natural permeability. Based on the managing general partner’s experience, it anticipates that all
of the natural gas wells drilled to the Clinton/Medina geological formation will be completed and
fraced in two different zones of the Clinton/Medina geological feature. See the geologic
evaluation and the model decline curve prepared by United Energy Development Consultants, Inc. in
“Appendix A — Information Regarding Currently Proposed Prospects for Atlas Resources Public
#16-2007(A) L.P.” for a discussion of the development of the Clinton/Medina Geological Formation in
western Pennsylvania and eastern Ohio.
The wells in the Clinton/Medina geological formation in western Pennsylvania and eastern Ohio will
be:
•
primarily situated in Crawford, Mercer, Lawrence, Warren, and Venango Counties,
Pennsylvania, and Stark, Mahoning, Trumbull and Portage Counties, Ohio;
situated on approximately 50 acres, subject to adjustment to take into account lease
boundaries;
•
drilled at least 1,650 feet from each other in Pennsylvania, which is greater than
the 660 feet minimum distance allowed by state law or local practice to protect against
drainage from adjacent wells, and drilled at least 1,000 feet from each other in Ohio;
•
drilled to approximately 5,000 to 6,300 feet in depth;
•
classified as natural gas wells that may produce a small amount of oil, although the
wells in eastern Ohio may be classified as oil wells; and
•
primarily connected to the gathering system owned by Atlas Pipeline Partners and
have their natural gas production primarily marketed to Hess Corporation until April 1,2007, as discussed below in “- Sale of Natural Gas and Oil Production.”
Also, see “- Secondary Areas of Operations” below, for a discussion of the Clinton/Medina
geological formation in western New York and southern Ohio.
Mississippian Carbonate and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and
Scott Counties, Tennessee.
The Mississippian carbonate reservoirs are discontinuous lens shaped
accumulations found in the southern Appalachian states of West Virginia, Virginia, Kentucky and
Tennessee. These reservoirs have porosities ranging from 6% to 20% with attendant permeabilities.
The Devonian shale is found throughout the Appalachian Basin. When the shale is highly fractured
it becomes a reservoir. See the geologic evaluation prepared by United Energy Development
Consultants, Inc. in “Appendix A — Information Regarding Currently Proposed Prospects for Atlas
Resources Public #16-2007(A) L.P.” for a discussion of the development of the Mississippian
carbonate and Devonian Shale reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties,
Tennessee.
The wells in the Mississippian carbonate and Devonian Shale reservoirs will be:
•
situated on 40 acres;
•
drilled 1,320 feet from each other unless topography dictates otherwise, however, in
all cases no less than 700 feet;
•
drilled to approximately 1,500 to 5,500 feet in depth;
•
classified as natural gas wells that may produce a small amount of oil; and
•
primarily connected to the gathering system owned by Knox Energy LLC, which is
referred to as the Coalfield Pipeline, and have their natural gas production primarily
marketed to Knox Energy LLC as discussed below in “- Sale of Natural Gas and Oil
Production.”
The prospects in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee were acquired from
Knox Energy LLC as described below in “- Interests of Parties” and Knox Energy may participate in
drilling wells in this area with the partnerships.
Secondary Areas of Operations
The managing general partner also has reserved the right to use a portion of the subscription
proceeds of each partnership to drill development wells in other areas of the Appalachian Basin or
elsewhere in the United States. The conditions that will prompt the managing general partner to
select properties in the secondary areas are access to prospects that meet the same criteria as the
primary areas, which are described in “- Overview of Drilling Activities.” However, the managing
general partner does not have available to it as many prospects in the secondary areas as it does
in the primary areas.
The secondary areas anticipated by the managing general partner, which are situated in the
Appalachian Basin, are discussed below. Additionally, during the fourth quarter of 2006 and the
first quarter of 2007, the managing general partner and an affiliated investment partnership either
drilled or plan to drill three wells to multiple pay zones, including the Marcellus Shale of
Southwest Pennsylvania. The Marcellus Shale is a black, organic rich shale formation located at
depths between 7,000 and 8,500 feet and ranges in thickness from 100 to 150 feet on their acreage
in Fayette, Westmoreland and Greene Counties.
Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania.
The Upper Devonian Sandstone
reservoirs are discontinuous lens-shaped accumulations found throughout most of the Appalachian
Basin. These reservoirs have porosities ranging from greater than 5% to 20% with attendant
permeabilities. The prospects in Armstrong and Indiana Counties, Pennsylvania will be acquired
from U.S. Energy Exploration Corporation as described below and U.S. Energy will participate in
drilling the wells in this area with the partnerships.
The wells in the Upper Devonian Sandstone reservoirs will be:
•
situated on approximately 15 acres, subject to adjustment to take into account lease boundaries;
•
drilled at least 1,000 feet from each other, although under Pennsylvania
law in certain circumstances a variance can be obtained, and some of the wells the
managing general partner has drilled to date in this general area have been drilled
less than 1,000 feet apart, but even in those cases the wells were approximately 980
feet or more from each other;
•
drilled to approximately 1,800 to 4,400 feet in depth;
•
classified as natural gas wells which may produce a small amount of oil; and
•
connected to a gathering system owned by U.S. Energy and have their
natural gas production marketed by U.S. Energy as discussed below in “- Sale of Natural
Gas and Oil Production.”
The managing general partner anticipates the leases in Armstrong and Indiana Counties, Pennsylvania
will have a net revenue interest to a partnership of 84.375%. U.S. Energy, the originator of the
leases, however, will retain a 25% working interest in the wells and participate with the
partnership in the costs of drilling, completing, and operating the wells to the extent of its
retained working interest.
Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania.
See “- Upper Devonian
Sandstone Reservoirs, Armstrong County, Pennsylvania,” above, for a description of these
reservoirs. Wells located in McKean County and drilled to the Upper Devonian Sandstone reservoirs
will be:
•
situated on approximately 5 acres, subject to adjustments to take into account lease boundaries;
•
drilled to approximately 2,000 to 2,500 feet in depth;
•
classified as combination wells producing both natural gas and oil;
•
drilled on leases with a net revenue interest of approximately 84.375% to 87.5%; and
•
connected to the gathering systems owned by Atlas Pipeline Partners and M&M Royalty,
LTD. and have their natural gas production primarily marketed to M&M Royalty, LTD. as
discussed below in
“- Sale of Natural Gas and Oil Production.”
Clinton/Medina Geological Formation in Western New York.
Wells located in western New York and drilled to the Clinton/Medina geological formation will be:
situated on approximately 40 acres, subject to adjustment to take into account lease boundaries;
•
drilled to approximately 3,800 to 4,000 feet in depth;
•
drilled on leases with a net revenue interest of approximately 84.375% to 87.5%;
•
classified as natural gas wells which may produce a small amount of oil; and
•
connected to the gathering system owned by Atlas Pipeline Partners and have their
natural gas production primarily marketed to Hess Corporation, commercial end users in
the area, and/or Great Lakes Energy Partners, L.L.C. as discussed below in “- Sale of
Natural Gas and Oil Production.”
Clinton/Medina Geological Formation in Southern Ohio.
Wells located in southern Ohio and drilled
to the Clinton/Medina geological formation will be:
•
primarily situated in Noble, Washington, Guernsey, and Muskingum Counties;
•
situated on approximately 40 acres, subject to adjustment to take into account lease boundaries;
•
drilled at least 1,000 feet from each other;
•
drilled to approximately 4,900 to 6,500 feet in depth;
•
drilled on leases with a net revenue interest of approximately 82.5% to 87.5%;
•
classified as either natural gas wells or oil wells; and
•
primarily connected to the gathering system owned by Atlas Pipeline Partners (if
classified as natural gas wells) and have their natural gas production marketed to Hess
Corporation, although a portion of the natural gas production may be gathered and
marketed by Triad Energy Corporation of West Virginia, Inc. as discussed below in “-
Sale of Natural Gas and Oil Production.”
Additionally, the managing general partner anticipates that the leases in southern Ohio will have
been originally acquired from a coal company and are subject to a provision that the well must be
abandoned if it hinders the development of the coal. Thus, the managing general partner will not
drill a well on any lease subject to this provision unless it covers lands that were previously
mined. Although this does not totally eliminate the risk because the leases may cover other coal
deposits that might be mined during the life of a well, the managing general partner believes that
drilling wells on these previously mined leases would be in the best interests of the partnerships.
Acquisition of Leases
The managing general partner will have the right, in its sole discretion, to select the prospects
which each partnership will drill. The managing general partner intends that Atlas Resources
Public #16-2007(A) L.P. will drill the prospects described in “Appendix A — Information Regarding
Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.” The managing general
partner also anticipates that it will designate a portion of the prospects in Atlas Resources
Public #16-2007(B) L.P., if units in that partnership are offered, by means of a supplement or an
amendment to the registration statement of which this supplement is a part.
The leases covering each prospect on which one well will be drilled will be acquired by a
partnership from the managing general partner or its affiliates and credited to the managing
general partner as a part of its required capital contribution to the partnership. Neither the
managing general partner nor its affiliates will receive any royalty or overriding royalty interest
on any well.
The managing general partner anticipates that it will select the prospects for each partnership,
including any additional and/or substituted prospects, from the following:
leases in its and its affiliates’ existing leasehold inventory;
•
leases that are subsequently acquired by it or its affiliates; or
•
leases owned by independent third-parties that may participate with the partnership in drilling wells.
The majority of the prospects acquired by a partnership will be in areas where the managing general
partner or its affiliates have previously conducted drilling operations. The managing general
partner believes that its and its affiliates’ leasehold inventory and leases acquired from
third-parties will be sufficient to provide all the development prospects to be drilled by the
partnerships if the targeted maximum subscription proceeds of $200 million are received. In this
regard, the managing general partner and its affiliates are continually engaged in acquiring
additional leasehold acreage in Pennsylvania, Ohio, and other areas of the United States. As of
August 15, 2006, the managing general partner’s and its affiliates’ undeveloped leasehold acreage
was as follows:
Undeveloped Lease Acreage
Gross
Net (1)
Kentucky
9,060
4,530
Montana
2,650
2,650
New York
38,534
38,534
Ohio
37,851
34,414
Pennsylvania
189,910
189,910
West Virginia
10,806
5,403
Wyoming
80
80
Total
288,891
275,521
(1)
The net acreage as to which leases expire in fiscal 2007 are as follows: Ohio: 2007 -
1,538 acres and Pennsylvania: 2007 — 12,938 acres.
Most, if not all, of the prospects to be selected for the partnerships are expected by the managing
general partner to be single well proved undeveloped prospects that are classified as
developmental. Thus, only one well will be drilled on each of those prospects and the number of
prospects that the managing general partner will assign to each partnership will be the same as the
number of wells that the partnership has the funds to drill. This also means that the partnership,
in all likelihood, will not farmout any acreage associated with those prospects. However, the need
for a farmout might arise, for example, if during drilling or subsequently the managing general
partner determines there might be a productive horizon situated above (i.e. uphole) the target
horizon, but the partnership does not have the funds to complete the well in the horizon or the
completion of the horizon would be inconsistent with the partnership’s objectives. In this event,
the managing general partner might decide to farmout the activity for the partnership. Generally,
a farmout is an agreement in which the owner of the lease or existing well agrees to assign its
interest in certain acreage under the lease or the existing well to an assignee subject to the
assignee drilling one or more wells or completing or recompleting the existing well in one or more
horizons. The owner would retain some interest in the assigned acreage or well. See “Conflicts of
Interest — Conflicts Involving the Acquisition of Leases” for the procedure for a farmout, and
“Federal Income Tax Consequences — Farmouts.”
Deep Drilling Rights Retained by Managing General Partner.
The lease assignments to each
partnership generally will be limited to a depth from the surface to the deepest depth penetrated
at the cessation of drilling operations. The managing general partner will retain the deeper
drilling rights, including ownership of any coal bed methane production that might be obtained from
the deeper formations. Conversely, as between a partnership and the managing general partner, the
partnership will own any coal bed methane production that might be obtained from the shallower
formations that are not included in the deeper drilling rights retained by the managing general
partner.
The amount of the credit the managing general partner receives for the leases it contributes to a
partnership will not include any value allocable to the deeper drilling rights retained by it. If
the managing general partner undertakes any activities
with respect to the deeper formations in the future, then the partnerships would not share in the
profits from these activities, nor would the partnerships pay any of the associated costs.
Interests of Parties
Generally, production and revenues from a well drilled by a partnership will be net of the
applicable landowner’s royalty interest, which is typically 1/8th (12.5%) of gross production, and
any interest in favor of third-parties such as an overriding royalty interest. Landowner’s royalty
interest generally means an interest that is created in favor of the landowner when an oil and gas
lease is obtained; and overriding royalty interest generally means an interest that is created in
favor of someone other than the landowner. In either case, the owner of the interest receives a
specific percentage of the natural gas and oil production free and clear of all costs of
development, operation, or maintenance of the well. This is compared with a working interest,
which generally means an interest in the lease under which the owner of the interest must pay some
portion of the cost of development, operation, or maintenance of the well. Also, the leases will
be subject to terms that are customary in the industry such as free gas to the landowner-lessor for
home heating requirements, etc.
The managing general partner anticipates that each partnership generally will have a net revenue
interest in its leases in its primary drilling areas as set forth in the chart below. Net revenue
interest generally means the percentage of revenues the owner of an interest in a well is entitled
to receive under the lease. The following chart expresses the percentage of production revenues
that the managing general partner, the landowner, other third-parties, and you and the other
investors in a partnership will share in from the wells in two of the three primary drilling areas.
The third primary drilling area in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
is discussed following the chart. The chart assumes that the partnership owns 100% of the working
interest in the well. If a partnership acquires a lesser percentage working interest in a well,
which may be the case in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee, then the
partnership’s net revenue interest in that well will decrease proportionately.
The actual number, identity and percentage of working interests or other interests in prospects to
be acquired by the partnerships will depend on, among other things:
•
the amount of subscription proceeds received by a partnership;
•
the latest geological and production data;
•
potential title or spacing problems;
•
availability and price of drilling services, tubular goods and services;
•
approvals by federal and state departments or agencies;
•
agreements with other working interest owners in the prospects;
•
farmins and farmouts; and
•
continuing review of other prospects that may be available.
Mississippian/Upper Devonian Sandstone Reservoirs in Fayette County, Pennsylvania.
Partnership
Third Party
87.5% Partnership
Entity
Interest
Royalty Interest
Net Revenue Interest (2)
Managing General Partner
32% partnership interest (1)
28.0
%
Investors
68% partnership interest (1)
59.5
%
Third Party
12.5% Landowner Royalty Interest
12.5
%
100.0
%
(1)
These percentages are for illustration purposes only, and assume that the partnership has a
100% working interest and the managing general partner contributes its minimum required
capital contribution of 25% to each partnership and the capital contributions from you and the
other investors are 75%. The actual percentages are likely to be different because they will
be based on the actual capital contributions of the managing general partner and you and the
other investors. However, the managing general partner’s total revenue share may not exceed
40% of partnership revenues regardless of the amount of its capital contributions.
Clinton/Medina Geological Formation in Western Pennsylvania.
Partnership
Third Party
84.375% Partnership
Entity
Interest
Royalty Interest
Net Revenue Interest (2)
Managing General Partner
32% partnership interest (1)
27.000
%
Investors
68% partnership interest (1)
57.375
%
Third Party
15.625% Landowner Royalty Interest
15.625
%
100.000
%
(1)
These percentages are for illustration purposes only, and assume that the partnership has a
100% working interest and the managing general partner contributes its minimum required
capital contribution of 25% to each partnership and the capital contributions from you and the
other investors are 75%. The actual percentages are likely to be different because they will
be based on the actual capital contributions of the managing general partner and you and the
other investors. However, the managing general partner’s total revenue share may not exceed
40% of partnership revenues regardless of the amount of its capital contributions.
Mississippian Carbonate and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and
Scott Counties, Tennessee.
Generally, the leases in north central Tennessee will have a net
revenue interest to a partnership ranging from 84.375% to 81.375%, assuming that a partnership has
a 100% working interest. However, the amount of the partnership’s net revenue interest in some of
the prospects could be as low as 81.375% depending primarily on whether the landowner royalty
interest is 12.5% or 15.5%. The amount of the landowner royalty depends, in turn, on whether the
natural gas produced from those prospects, if any, is sold at a price above or below $3.00 per mcf,
and on whether Knox Energy LLC and its affiliates, the originators of the leases, participate as a
working interest owner with a partnership in the leases covering those prospects. Knox Energy and
its affiliates may retain up to a 50% working interest in the wells and participate with the
partnership in the costs of drilling, completing, and operating the wells to the extent of its
retained working interest. Also, if Knox Energy does not retain a working interest in a well, then
its overriding royalty interest will be 3.125%. However, if Knox Energy retains a 50% working
interest in a well, then its overriding royalty interest of 3.125% will be reduced to 1.5625%. To
the extent that Knox Energy participates in a well as a working interest owner for less than a 50%
working interest, its overriding royalty interest will be prorated between 3.125% and 1.5625%
depending on the percentage of its working interest. The investors’ net revenue interest in the
above example would range from 57.375% to 55.335%, if presented on a 100% working interest basis
and the investors were receiving 68% of the partnership revenues.
Pursuant to the acquisition terms of the agreement between the managing general partner and its
affiliates and Knox Energy and its affiliates, no well drilled by the managing general partner and
its affiliates in this area, which includes the
partnerships, may produce coalbed methane gas, and the managing general partner or its affiliates
must drill 300 commitment
wells during the initial three year term of the agreement with Knox
Energy, which ends June 30, 2007, or they will be in breach of the agreement.
Secondary Areas
Although the managing general partner anticipates that each partnership will have a net revenue
interest ranging from 81% to 87.5% in its leases in the secondary areas described above, assuming
it owns 100% of the working interest, there is no minimum net revenue interest that a partnership
is required to own before drilling a well in other areas of the United States. The leases in these
other areas may be subject to interests in favor of third-parties that are not currently known such
as overriding royalty interests, net profits interests, carried interests, production payments,
reversionary interests pursuant to farmouts or non-consent elections under joint operating
agreements, or other retained or carried interests.
Title to Properties
Title to all leases acquired by a partnership ultimately will be held in the name of the
partnership. However, to facilitate a partnership’s acquisition of the leases title to the leases
may initially be held in the name of the managing general partner, the operator, their affiliates,
or any nominee designated by the managing general partner. Title to each partnership’s leases will
be transferred to the partnership and filed for record from time to time after the wells are
drilled and completed.
The managing general partner will take the steps it deems necessary to assure that each partnership
has acceptable title for its purposes. However, it is not the practice in the natural gas and oil
industry to warrant title or obtain title insurance on leases and the managing general partner will
provide neither for the leases it assigns to a partnership. The managing general partner will
obtain a favorable formal title opinion for the leases before each well is drilled, but will not
obtain a division order title opinion after the well is completed. The managing general partner
may use its own judgment in waiving title requirements and will not be liable for any failure of
title of the leases transferred to a partnership. Also, the partnerships may experience losses
from title defects excluded from, or not disclosed by, the formal title opinion that is provided to
the managing general partner before a well is drilled or that would have been disclosed by a
division order title opinion after the well is drilled, if the partnership obtained division order
title opinions, which it will not do. Although past performance is no guarantee of future results,
the previous drilling partnerships sponsored by the managing general partner and its affiliates
have participated in drilling more than 3,220 wells in the Appalachian Basin since 1985, and none
of the wells have been lost because of title failure. (See “Prior Activities.”)
Drilling and Completion Activities; Operation of Producing Wells
On receipt of the minimum subscription proceeds of a partnership, the managing general partner on
behalf of the partnership may break escrow, transfer the escrowed funds to a partnership account,
enter into the drilling and operating agreement, which is attached to the partnership agreement as
Exhibit II, with itself or an affiliate of the managing general partner as operator, and begin
drilling the partnership’s wells.
Under the drilling and operating agreement, the responsibility for drilling and either completing
or plugging partnership wells will be on the managing general partner or an affiliate of the
managing general partner as the operator and the general drilling contractor. Under the drilling
and operating agreement, each partnership is required to prepay the investors’ share of the
drilling and completion costs of its wells to the managing general partner as the general drilling
contractor and operator. If one or more of a partnership’s wells will be drilled in the calendar
year after the year in which the advance payment is made, the required advance payment allows the
partnership to secure tax benefits of prepaid intangible drilling costs based on a substantial
business purpose for the advance payment under the drilling and operating agreement. The managing
general partner as operator and general drilling contractor will begin drilling all of the wells no
later than March 30, 2008 for the partnerships. (See “Federal Income Tax Consequences — Drilling
Contracts.”)
During drilling operations the managing general partner’s duties as operator and general drilling
contractor will include:
•
making the necessary arrangements for drilling and completing partnership wells and
related facilities for which it has responsibility under the drilling and operating
agreement;
•
managing and conducting all field operations in connection with drilling, testing,
and equipping the wells; and
making the technical decisions required in drilling and completing the wells.
All partnership wells will be drilled to a sufficient depth to test thoroughly the objective
geological formation unless the managing general partner determines in its sole discretion that the
well shall be completed in a formation uphole from the objective geological formation.
Under the drilling and operating agreement the managing general partner, as operator and general
drilling contractor, will complete each well if there is a reasonable probability of obtaining
commercial quantities of natural gas or oil. However, based on its past experience, the managing
general partner anticipates that most of the development wells drilled by the partnerships in the
primary and secondary areas will have to be completed before the managing general partner can
determine the well’s productivity. If the managing general partner, as operator and general
drilling contractor, determines that a well should not be completed, then the well will be plugged
and abandoned.
During producing operations the managing general partner’s duties, as operator, will include:
•
managing and conducting all field operations in connection with operating and producing the wells;
•
making the technical decisions required in operating the wells; and
•
maintaining the wells, equipment, and facilities in good working order during their useful life.
The managing general partner, as operator, will be reimbursed for its direct expenses and will
receive well supervision fees at competitive rates for operating and maintaining the wells during
producing operations as discussed in “Compensation.” As discussed in “Summary of Drilling and
Operating Agreement,” the drilling and operating agreement contains a number of other material
provisions which you are urged to review.
Certain wells may be drilled by a partnership with third-parties owning a portion of the working
interest in the wells. Any other working interest owner in a well will have a separate agreement
with the managing general partner for drilling and operating the well with differing terms and
conditions from those contained in a partnership’s drilling and operating agreement. (See “Federal
Income Tax Consequences — Drilling Contracts.”)
Sale of Natural Gas and Oil Production
Policy of Treating All Wells Equally in a Geographic Area.
All benefits and liabilities from
marketing and hedging arrangements or other relationships affecting the property of the managing
general partner or its affiliates and the partnerships shall be fairly and equitably apportioned
according to the respective interests of each in the property. The managing general partner is
responsible for selling each partnership’s natural gas and oil production, and its policy is to
treat all wells in a given geographic area equally. This reduces certain potential conflicts of
interest among the owners of the various wells, including the partnerships sponsored by the
managing general partner, concerning to whom and at what price the natural gas and oil will be
sold. For example, the managing general partner calculates a weighted average selling price for
all of the natural gas sold in the geographic area and this is the price which will be paid to each
partnership in the geographic area for its natural gas. For natural gas sold in western
Pennsylvania during its previous four fiscal years, the managing general partner received an
average selling price after deducting all expenses, including transportation expenses and after the
effects of hedging arrangements, of approximately:
•
$3.34 per mcf, “mcf” means 1,000 cubic feet of natural gas, in 2002;
•
$4.78 per mcf in 2003;
•
$5.64 per mcf in 2004; and
•
$6.72 per mcf in 2005.
If all of the natural gas produced in an area cannot be sold by the managing general partner and
its affiliates, including the partnerships, because of limited gathering line or pipeline capacity,
or limited demand for the natural gas, which increases
pipeline pressure, then the production that is sold will be from those wells that have the greatest
well pressure and are able to feed into the pipeline, regardless of which partnerships own the
wells. The proceeds from these natural gas sales will be credited only to the partnerships whose
wells produced the natural gas sold.
Gathering of Natural Gas.
Under the partnership agreement the managing general partner will be
responsible for gathering and transporting the natural gas produced by the partnerships to
interstate pipeline systems, local distribution companies, and/or end-users in the area. For the
majority of each partnership’s natural gas production, including natural gas in the primary areas,
as discussed below, the managing general partner anticipates that it will use the gathering system
owned by Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating Partnership), which is a
master limited partnership formed by a subsidiary of Atlas America as managing general partner
using Atlas America personnel who act as its officers and employees. (See “Management -
Organizational Diagram and Security Ownership of Beneficial Owners.”) Atlas Pipeline Partners
acquired the natural gas gathering system and related facilities of Atlas America, Resource Energy,
and Viking Resources in February 2000. The gathering system consists of more than 1,400 miles of
intrastate pipelines located in western Pennsylvania, eastern Ohio, and western New York.
If a partnership’s natural gas is not transported through the Atlas Pipeline Partners gathering
system, it is because there is a third-party operator or the gathering system has not been extended
to the wells. In these cases, which includes the McKean County area and the north central
Tennessee area, as described in “Compensation — Gathering Fees,” the natural gas will be
transported through a third-party gathering system, and the partnership will pay the managing
general partner a competitive gathering fee, all of which will be paid by it to the third-party.
Also, in the north central Tennessee area, the managing general partner and its affiliates may
construct a gathering system in the future for which they will receive gathering fees as described
in “Compensation — Gathering Fees.”
As a part of the sale of the gathering system to Atlas Pipeline Partners in February 2000, Atlas
America and its affiliates, Resource Energy and Viking Resources (the “Atlas entities”), made
certain commitments that were intended to maximize the use and expansion of the gathering system.
Those commitments were made pursuant to a master natural gas gathering agreement and an omnibus
agreement which were entered into at the time of sale in February 2000. Both the master natural
gas gathering agreement and the omnibus agreement set forth continuing obligations of the Atlas
entities that have no specified term, except that they will terminate with respect to future wells
drilled by the Atlas entities if the general partner of Atlas Pipeline Partners, L.P., Atlas
Pipeline Partners GP, LLC (which is owned by Atlas Pipeline Holdings, L.P., a limited partnership
that recently completed a public offering as described in “Management — Organizational Diagram and
Security Ownership of Beneficial Owners”) is removed without cause and without its consent.
However, under the master natural gas gathering agreement the Atlas entities, including the
partnerships in this case, have committed the natural gas production from the wells they drill
before removal of Atlas Pipeline Partners GP, LLC without cause and without its consent, for the
life of the wells. Thus, the termination of the master natural gas gathering agreement under the
circumstance described above will only terminate the obligation of the Atlas entities, including
the partnerships, to transport their natural gas through Atlas Pipeline Partners’ gathering system
with respect to wells drilled on or after the termination of the agreement. Some of these
commitments still affect the partnerships. For example, under the master natural gas gathering
agreement the Atlas entities are required to pay a gathering fee to Atlas Pipeline Partners equal
to the greater of $0.35 per mcf or 16% of the gross sales price for each mcf transported through
Atlas Pipeline Partners’ gathering system. If a partnership pays a lesser amount, which is
anticipated by the managing general partner as described in “Compensation — Gathering Fees,” then
the Atlas entities must pay the difference to Atlas Pipeline Partners. Also, if Atlas Pipeline
Partners determines that the continued operation of any part of the gathering system is not
economically justified, then it may elect to discontinue the operation of that portion of the
gathering system. If Atlas Pipeline Partners makes this determination, then it must give the
parties to the agreement the right to purchase that part of the gathering system for $10. Pursuant
to an amendment and joinder to the gas gathering agreements, Atlas Energy Resources, LLC and Atlas
Energy Operating Company, LLC became parties to the existing master natural gas gathering
agreement. As described in “Management,” Atlas America has assumed Atlas Energy Resources, LLC’s
obligations under that agreement to pay the gathering fees to Atlas Pipeline, and Atlas Energy
Resources, LLC agreed to pay Atlas America the gathering fees it receives from the partnerships and
the managing general partner’s other investment partnerships. If Atlas America fails to pay
gathering fees to Atlas Pipeline as required by its assumption agreement with Atlas Energy
Resources, LLC, Atlas Energy Resources, LLC will have to pay to Atlas Pipeline the difference
between the gathering fee payable and the amount it receives from the investment partnerships for
gathering services out of its own resources.
Under the omnibus agreement, Atlas America is required to commit to Atlas Pipeline Partners’
gathering system all wells it drills and operates, including those of the partnerships, that are
within 2,500 feet of the Atlas Pipeline Partners gathering system. In addition, the Atlas
entities, including the partnerships, must construct at their own cost, up to 2,500 feet of
flowline as necessary to connect their wells to Atlas Pipeline Partners’ gathering system. Also,
Atlas Pipeline Partners must, at its own cost, extend its gathering system to connect to any
flowlines constructed by the Atlas entities, including the partnerships, that are within 1,000 feet
of its gathering system. With respect to wells to be drilled by Atlas America and its affiliates,
including the partnerships, that will be more than 3,500 feet from Atlas Pipeline Partners’
gathering system, Atlas Pipeline Partners has various options, in its discretion, to connect those
wells to its gathering system at its own cost. Also, Atlas America and its affiliates may not
divest their ownership of Atlas Pipeline Partners GP, LLC without also divesting their ownership of
the entities serving as managing general partner in all of their affiliated investment
partnerships, including the partnerships, to the same acquirer, except that Atlas America is
permitted to transfer its ownership interest in Atlas Pipeline Partners GP, LLC to a wholly- or
majority-owned direct or indirect subsidiary as long as Atlas America continues to control that
subsidiary. See “Management — Organizational Diagram and Security Ownership of Beneficial Owners,”
regarding the public offering in Atlas Pipeline Holdings, L.P., which owns Atlas Pipeline Partners
GP, LLC. Pursuant to an amendment and joinder to omnibus agreement, Atlas Energy Resources, LLC
and Atlas Energy Operating Company, LLC became parties to the existing omnibus agreement between
Atlas America and Atlas Pipeline which sets forth the obligations that Atlas Energy Resources, LLC,
Atlas America and Atlas Pipeline will have to connect wells to the Atlas Pipeline gathering systems
and that Atlas Energy Resources, LLC will have to provide consultation services in the construction
of new gathering systems or the extension of existing systems. Because Atlas Energy Resources, LLC
owns substantially all of Atlas America’s natural gas and oil development and production business,
Atlas Energy Resources, LLC will be primarily liable under the omnibus agreement, and Atlas America
will be secondarily liable as a guarantor of Atlas Energy Resources, LLC’s performance.
Natural Gas Contracts.
As set forth in “- Primary Areas of Operations,” each partnership has three
primary areas where it will drill its wells, and the managing general partner anticipates that
there will be a different natural gas purchaser or purchasers in each area. The managing general
partner anticipates that more prospects will be drilled in the Mississippian/Upper Devonian
Sandstone Reservoirs in the Fayette County, Pennsylvania area, which is one of the primary drilling
areas, than in the other areas, and the natural gas produced from the Fayette County area will be
sold to UGI Energy Services, ConocoPhillips Company, Equitable Gas Company and Colonial Energy
pursuant to contracts which end March 31, 2008, except with respect to Colonial Energy, which ends
March 31, 2009. The natural gas produced from north central Tennessee, which is one of the three
primary areas, will be sold to Knox Energy LLC pursuant to a contract which ends October 31, 2007.
After this contract ends, it is anticipated that Atlas America will market its production in the
future to purchasers which are not currently known. The managing general partner anticipates that
the remainder of the natural gas produced by the partnership from wells drilled in the other
primary area, which is the Crawford County area of the Clinton/Medina geological formation in
western Pennsylvania, and the secondary areas, other than the Upper Devonian Sandstone Reservoirs
in Armstrong and McKean Counties, Pennsylvania, will be sold to Hess Corporation (“Hess”) until
April 1, 2007, as discussed below. After April 1, 2007, it is anticipated that natural gas
produced from the Crawford County area of the Clinton/Medina geological formation in western
Pennsylvania, which is a primary area, and the Upper Devonian Sandstone Reservoirs in Armstrong and
McKean County, Pennsylvania, which are secondary areas, will be sold to Intrastate Gas Supply, Inc.
pursuant to a contract which ends December 31, 2008. Further, all of the natural gas contracts,
including those described above, are between the natural gas purchaser and Atlas America, Atlas
Energy Resources, LLC and/or their affiliates. Either Atlas America, Atlas Energy Resources, LLC
or their affiliates will receive sales proceeds from the natural gas purchasers and then distribute
the sales proceeds to each partnership based on the volume of natural gas produced by each
partnership. Until the sales proceeds are distributed to the partnerships, they will be subject to
the claims of Atlas America’s, Atlas Energy Resources, LLC’s or their affiliates’ creditors.
The managing general partner and its affiliates previously entered into a 10-year agreement with
First Energy Solutions Corporation. This agreement was sold by First Energy Solutions Corporation
to Hess effective April 1, 2005. Subject to the exceptions set forth below, Hess has the right to
buy all of the natural gas produced and delivered by the managing general partner and its
affiliates, which includes each partnership and the managing general partner’s other partnerships,
at certain delivery points with the facilities of East Ohio Gas Company, National Fuel Gas
Distribution, Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution
companies; and National Fuel Gas Supply, Columbia Gas Transmission Corporation and Tennessee Gas
Pipeline Company, which are interstate pipelines. This contract, which ends April 1, 2009,
is important to the managing general partner and its affiliates because as of July 31, 2006 the
managing general partner and its affiliates, including its prior affiliated partnerships, were
selling approximately 40.9% of their natural gas production under the agreement with Hess.
However, as set forth above, each partnership will sell a much smaller percentage of its natural
gas to Hess because of certain exceptions to the agreement, including natural gas sold through
interconnects established after the agreement, which includes the majority of the natural gas
produced from wells in the Fayette County, Pennsylvania area, and natural gas produced from well(s)
subject to an agreement under which a third-party was to arrange for the gathering and sale of the
natural gas such as natural gas produced from wells in north central Tennessee, one of the primary
drilling areas, or in Armstrong and McKean Counties, Pennsylvania, which are both secondary
drilling areas. Also, after April 1, 2007 natural gas production from Crawford County,
Pennsylvania will be sold to Interstate Gas Supply, Inc., instead of Hess, as discussed above.
The pricing and delivery arrangements with all of the natural gas purchasers described above are
tied to the settlement of the New York Mercantile Exchange Commission (“NYMEX”) monthly futures
contracts price, which is reported daily in the Wall Street Journal and with an additional premium,
which is referred to as the basis, paid because of the location of the natural gas (the Appalachian
Basin) in relation to the natural gas market. The premium over quoted prices on the NYMEX received
by the managing general partner and its affiliates has ranged between $0.51 to $1.07 per Mcf during
the managing general partner’s past three fiscal years. These figures are based on the overall
weighted average that the managing general partner and its affiliates used in their annual reserve
reports for their past three fiscal years. Generally, the purchase agreements may be suspended for
force majeure, which generally means an Act of God.
Pricing for natural gas and oil has been volatile and uncertain for many years. To limit the
managing general partner’s and its partnerships’ exposure to decreases in natural gas prices, the
managing general partner and its affiliates, Atlas America and/or Atlas Energy Resources, LLC, use
physical hedges through their natural gas purchasers, as discussed below, and financial hedges
through contracts such as regulated NYMEX futures and options contracts and non-regulated
over-the-counter futures contracts with qualified counterparties. The physical hedges require firm
delivery of natural gas and, therefore, are considered normal sales of natural gas, rather than
hedges, for accounting purposes. The futures contracts employed by the managing general partner
are commitments to purchase or sell natural gas at future dates and generally cover one-month
periods for up to 36 months in the future. To assure that the financial instruments will be used
solely for hedging price risks and not for speculative purposes, the managing general partner has
established a committee to assure that all financial trading is done in compliance with the
managing general partner’s hedging policies and procedures. The managing general partner does not
intend to contract for positions that it cannot offset with actual production.
All of the natural gas purchasers described above and many third-party marketers use NYMEX based
financial instruments to hedge their pricing exposure, and they make price hedging opportunities
available to the managing general partner. The physical hedges are similar to NYMEX based futures
contracts, swaps and options, but also require firm physical delivery of the natural gas. Because
of this, the managing general partner limits these arrangements to much smaller quantities of
natural gas than those projected to be available at any delivery point. The price paid by the
natural gas purchasers for certain volumes of natural gas sold under these physical hedge
agreements may be significantly different from the underlying monthly spot market value. As of
April 2, 2006, a portion of the managing general partner’s natural gas was subject to physical
hedges through March 31, 2007. After March 31, 2007, none of the managing general partner’s and
its affiliates’ natural gas is subject to physical hedges and the managing general partner and its
affiliates anticipate using financial hedges as discussed below for all of its natural gas that is
hedged, although this may change from time to time.
On October 27, 2005, Atlas America implemented financial hedges through its banking counter-party,
Wachovia Bank, and as of October 2, 2006, Atlas America on behalf of the partnerships and the other
partnerships sponsored by the managing general partner, hedged approximately 51% of their natural
gas production using fixed-for-floating financial swaps for the period April 1, 2007 through
December 31, 2009. Atlas America and/or Atlas Energy Resources, LLC and their affiliates are also
negotiating with other banking counter-parties to implement financial hedges. In this regard, the
partnerships have confirmed their authorization to Atlas America and/or Atlas Energy Resources, LLC
to enter into the hedging agreements, and have ratified all actions previously taken by Atlas
America and/or Atlas Energy Resources, LLC in connection therewith. It is anticipated that since
the transfer by Atlas America of the managing general partner to Atlas Energy Resources, LLC, a
subsidiary of Atlas Energy Resources, LLC, rather than Atlas America, will enter into these hedging
arrangements.
The percentages of natural gas that is hedged through either financial hedges, physical hedges or
not hedged at all will change from time to time in the discretion of Atlas America or Atlas Energy
Resources, LLC. It is difficult to project what portion of these hedges will be allocated to each
partnership by the managing general partner because of uncertainty about the quantity, timing, and
delivery locations of natural gas that may be produced by a partnership. Although hedging provides
the partnerships some protection against falling prices, these activities also could reduce the
potential benefits of price increases and the partnerships could incur liability on the financial
hedges. For example, if a partnership’s production is substantially less than expected, the
counterparties to the futures contracts fail to perform under the contracts or there is a sudden,
unexpected event materially impacting natural gas prices, then a partnership would be exposed to
the risk of a financial loss. Subject to the managing general partner’s and its affiliates’
interest in their natural gas contracts or pipelines and gathering systems, all benefits and
liabilities from marketing and hedging or other relationships affecting the property of the
managing general partner or its affiliates or the partnerships must be fairly and equitably
apportioned according to the interests of each in the property. In this regard, the benefits and
liabilities of the hedging agreements will be equitably allocated by Atlas America and/or Atlas
Energy Resources, LLC and the managing general partner to the partnerships and the other
partnerships sponsored by the managing general partner and its affiliates pro rata based on actual
production, consistent with past practice, and the partnerships and the other partnerships
sponsored by the managing general partner and its affiliates will be severally liable for their
respective allocated share of the liabilities under the hedging agreements, but will not be jointly
and severally liable for the entire amount of the liabilities under the hedging agreements.
Additionally, Atlas America and/or Atlas Energy Resources, LLC will not be liable for any of those
liabilities, or be entitled to any of those benefits, to the extent they are allocated to the
partnerships and the other partnerships sponsored by the managing general partner and its
affiliates.
Marketing of Natural Gas Production from Wells in Other Areas of the United States.
The managing general partner expects that natural gas produced by the partnership from wells drilled in areas of
the Appalachian Basin other than those described above will be primarily tied to the spot market
price and supplied to:
•
gas marketers;
•
local distribution companies;
•
industrial or other end-users; and/or
•
companies generating electricity.
Crude Oil.
Crude oil produced from a partnership’s wells will flow directly into storage tanks
where it will be picked up by the oil company, a common carrier, or pipeline companies acting for
the oil company which is purchasing the crude oil. Unlike natural gas, crude oil does not present
any transportation problem. The managing general partner anticipates selling any oil produced by
the wells to regional oil refining companies at the prevailing spot market price for Appalachian
crude oil in spot sales. The managing general partner received an average selling price for oil
during its previous four fiscal years of approximately $18.92 per barrel in 2002; $29.06 per barrel
in 2003; $34.41 per barrel in 2004; and $50.00 per barrel in 2005. During the term of the
partnerships it is anticipated that the price of oil will be uncertain and volatile.
Insurance Claims
Since 1972 the managing general partner and its affiliates, including its partnerships, have been
involved in drilling more than 5,300 wells, most of which were developmental wells, in Ohio,
Pennsylvania, and other areas of the Appalachian Basin. They have made only one material insurance
claim and, as discussed below, one which may evolve into a material claim. In February 2004, one
of the wells in another investment partnership incurred an uncontrolled flow of natural gas and oil
with a fire during drilling. These problems with the well were subsequently controlled, but they
resulted in the loss of a subcontractor’s drilling rig and third-party claims. As of April 19,2005, the managing general partner’s insurance carrier had paid approximately $1.6 million to
third-parties for property damage claims and additional claims have been submitted which have not
yet been paid. The managing general partner’s insurance company is exploring all avenues for
subrogation. In addition, in February 2006, there was a well fire during the drilling of a well in
Fayette County, Pennsylvania which resulted in a claim against the managing general partner’s
insurance carrier in an amount which has not been quantified. See “Actions to be Taken by Managing
General Partner to Reduce Risks of Additional Payments by Investor General Partners — Insurance”
for a discussion of the insurance coverage the managing general partner intends to be available for
a partnership’s benefit.
The partnership agreement authorizes the managing general partner to use the services of
independent outside consultants and subcontractors on behalf of the partnerships. The services
will normally be paid on a per diem or other cash fee basis and will be charged to the partnership
on whose behalf the costs were incurred as either a direct cost or as a direct expense under the
drilling and operating agreement. These charges will be in addition to the costs of subcontractor
services provided by the managing general partner’s affiliates, which will be charged at
competitive rates, and the oversight and administration fee that will be paid to the managing
general partner during drilling operations, and the well supervision fees paid to the managing
general partner as operator as discussed in “Compensation.”
COMPETITION, MARKETS AND REGULATION
Natural Gas Regulation
Governmental agencies regulate the production and transportation of natural gas. Generally, the
regulatory agency in the state where a producing natural gas well is located supervises production
activities and the transportation of natural gas sold into intrastate markets, and the Federal
Energy Regulatory Commission (“FERC”) regulates the interstate transportation of natural gas.
Natural gas prices have not been regulated since 1993, and the price of natural gas is subject to
the supply and demand for natural gas along with factors such as the natural gas’ BTU content and
where the wells are located. Since 1985 FERC has sought to promote greater competition in natural
gas markets in the United States. Traditionally, natural gas was sold by producers to interstate
pipeline companies that served as wholesalers and resold the natural gas to local distribution
companies for resale to end-users. FERC changed this market structure by requiring interstate
pipeline companies to transport natural gas for third-parties. In 1992 FERC issued Order 636 and a
series of related orders that required pipeline companies to, among other things, separate their
sales services from their transportation services and provide an open access transportation service
that is comparable in quality for all natural gas producers or suppliers. The premise behind FERC
Order 636 was that the interstate pipeline companies had an unfair advantage over other natural gas
producers or suppliers because they could bundle their sales and transportation services together.
FERC Order 636 is designed to ensure that no natural gas seller has a competitive advantage over
another natural gas seller because it also provides transportation services.
In 2000 FERC issued Order 637 and subsequent orders to further enhance competition by removing
price ceilings on short-term capacity release transactions. It also enacted other regulatory
policies that are intended to enhance competition in the
natural gas market and increase the flexibility of interstate natural gas transportation. FERC
also has required pipeline companies to develop electronic bulletin boards to provide standardized
access to information concerning capacity and prices.
Crude Oil Regulation
Oil prices are not regulated, and the price is subject to the supply and demand for oil, along with
qualitative factors such as the gravity of the crude oil and sulfur content differentials.
Competition and Markets
Many companies engage in natural gas and oil drilling operations in the Appalachian Basin, where
most or all of the wells in each partnership will be located. According to the Energy Information
Administration, the independent statistical and analytical agency within the Department of Energy,
in 2004 there were 23 quadrillion BTU of natural gas consumed in the United States which
represented approximately 23% of the total energy used. The Appalachian Basin accounted for
approximately 5.7% of the total domestic natural gas production in the United States in 2004 and
represented approximately 12.5% of the total number of wells drilled in the United States during
2004. Also, according to the Natural Gas Annual 2004 Report, which is published by the Energy
Information Administration Office of Oil and Gas, as of December 31, 2004, the Appalachian Basin’s
economically recoverable natural gas reserves represented approximately 8% of total domestic
natural gas reserves.
The natural gas and oil industry is highly competitive in all phases. In this regard, the
partnerships will operate in a highly competitive environment for acquiring leases, contracting for
drilling equipment, securing trained personnel and marketing natural gas and oil production from
their respective wells. For example, the Pennsylvania Bureau of Oil and Gas
Management estimates
that in 2005 there were 747 well operators bonded in Pennsylvania, which includes two of the
partnerships’ primary drilling areas. Product availability and price are the principal means of
competing in selling natural gas and oil. Many of the partnerships’ competitors will have
financial resources and staffs larger than those available to the partnerships. This may enable
them to identify and acquire desirable leases and market their natural gas and oil production more
effectively than the managing general partner and the partnerships. While it is impossible to
accurately determine the partnerships’ industry position, the managing general partner does not
consider that the partnerships’ intended operations will be a significant factor in the industry.
The natural gas and oil industry has from time to time experienced periods of rapid cost increases.
The increase in natural gas and oil prices over the last several years also has increased the
demand for drilling rigs and other related equipment and the costs of drilling and completing
natural gas and oil wells. Additionally, the managing general partner and its affiliates have
experienced an increase in the cost of tubular steel used in drilling wells. Because each
partnership’s wells will be drilled on a modified cost plus basis as described in “Compensation –
Drilling Contracts,” these increased costs will increase the partnerships’ costs to drill and
complete their wells. Also, the reduced availability of drilling rigs and other related equipment
may make it more difficult to drill each partnership’s wells in a timely manner or to comply with
the prepaid intangible drilling costs rules discussed in “Federal Income Tax Consequences –
Drilling Contracts.” Further, over the term of each partnership there may be fluctuating or
increasing costs in doing business which directly affect the managing general partner’s ability to
operate the partnership’s wells at acceptable price levels.
The natural gas and oil produced by your partnership’s wells must be marketed in order for you to
receive revenues. During its fiscal years ending in 2005, 2004, and 2003, the managing general
partner did not experience any problems in selling natural gas and oil, although the prices varied
significantly during those periods. As set forth above, natural gas and oil prices are not
regulated, but instead are subject to factors which are generally beyond the partnerships’ and the
managing general partner’s control such as the supply and demand for natural gas and oil. For
example, reduced natural gas demand and/or excess natural gas supplies will result in lower prices.
Other factors affecting the price and/or marketing of natural gas and oil production, which are
also beyond the control of the managing general partner and the partnerships and cannot be
accurately predicted, are the following:
•
the cost, proximity, availability, and capacity of pipelines and other transportation facilities;
•
the price and availability of other energy sources such as coal, nuclear energy, solar and wind;
•
the price and availability of alternative fuels, including when large consumers of
natural gas are able to convert to alternative fuel use systems;
•
local, state, and federal regulations regarding production, conservation, and transportation;
•
overall domestic and global economic conditions;
•
the impact of the U.S. dollar exchange rates on natural gas and oil prices;
•
technological advances affecting energy consumption;
•
domestic and foreign governmental relations, regulations and taxation;
•
the impact of energy conservation efforts;
•
the general level of supply and market demand for natural gas and oil on a regional,
national and worldwide basis;
•
weather conditions and fluctuating seasonal supply and demand for natural gas and
oil because of various factors such as home heating requirements in the winter months,
although seasonal anomalies such as mild winters or hot summers sometimes lessen this
fluctuation, and certain natural gas users with natural gas
storage facilities purchase
a portion of the natural gas they anticipate they will need for the winter during the
summer, which also can lessen seasonal demand fluctuations;
•
economic and political instability, including war or terrorist acts in natural gas
and oil producing countries, including those of the Middle East and South America;
•
the amount of domestic production of natural gas and oil; and
•
the amount and price of imports of natural gas and oil from foreign sources,
including liquid natural gas from Canada and other countries (which the managing
general partner believes becomes economic when natural gas prices are at or above $3.50
per mcf), and the actions of the members of the Organization of Petroleum Exporting
Countries (“OPEC”), which include production quotas for petroleum products from time to
time with the intent of increasing, maintaining, or decreasing price levels.
For example, the North American Free Trade Agreement (“NAFTA”) eliminated trade and investment
barriers in the United States, Canada, and Mexico. From time to time since then there have been
increased imports of Canadian natural gas into the United States. Without a corresponding increase
in demand in the United States, the imported natural gas would have an adverse effect on both the
price and volume of natural gas sales from the partnerships’ wells.
The managing general partner is unable to predict what effect the various factors set forth above
will have on the future price of the natural gas and oil sold from the partnerships’ wells.
According to the Annual Energy Outlook 2006 with Projections to 2030 published by the Energy
Information Administration (EIA), total natural gas consumption is projected to increase from 22.34
trillion cubic feet in 2003 to 26.86 trillion cubic feet by 2030. Over that same period, total
natural gas supplies are projected to grow by 4.08 trillion cubic feet, with domestic natural gas
production expected to account for 45% of the total growth in gas supply, and net imports projected
to account for the remainder. Notwithstanding, wellhead natural gas prices are projected to
decline in the early years of the forecast as a result of the following responses to the current
high prices:
•
an increase in drilling levels;
•
the coming online of new natural gas production; and
•
the increase in liquid natural gas (“LNG”) imports.
After 2011, however, natural gas prices are projected to increase in response to the higher
exploration and development costs associated with smaller and deeper natural gas deposits in the
remaining domestic natural gas resource base. Also, the managing general partner believes there
have been several developments which may increase the demand for natural gas, but may or may not be
offset by an increase in the supply of natural gas, which the managing general partner is unable to
predict. For example, the Clean Air Act Amendments of 1990 contain incentives for the future
development of “clean alternative fuel,” which includes natural gas and liquefied petroleum gas for
“clean-fuel vehicles.” Also, the accelerating deregulation of electricity transmission has caused
a convergence between the natural gas and electric industries. In 2004, according to information
from the Energy Information Administration, the breakout of energy sources for the generation of
electricity in the United States was as follows:
•
natural gas fired power plants were used to produce approximately 18%;
•
coal-fired power plants were used to produce approximately 50%;
•
nuclear power plants were used to produce approximately 20%; and
•
large scale hydroelectric projects were used to produce approximately 7%.
In recent years, the electricity industry has increased its use of natural gas because of increased
competition and the enforcement of stringent environmental regulations. For example, the
Environmental Protection Agency has sought to
enforce environmental regulations which increase the
cost of operating coal-fired power plants. According to the Energy Information Administration, the
demand for natural gas by producers of electricity is expected to increase through the decade.
Also, the last nuclear power plant to come online in the United States was in June 1996, although
the existing nuclear power plants have increased their capacity and the recent energy act includes
tax credits for constructing new nuclear power plants. Unless the price of natural gas increases
to a point where it becomes uneconomic as an energy source as compared to alternate energy sources,
the managing general partner believes that natural gas is the preferred fuel for many producers of
electricity since many electricity producers have begun moving away from dirtier-burning fuels,
such as coal and oil because of environmental compliance requirements. In this regard, some of the
new natural gas fired power plants which are coming into service are not designed to allow for
switching to other fuels.
State Regulations
Natural gas and oil operations are regulated in Pennsylvania by the Department of Environmental
Resources and in Tennessee by the Department of Environment and Conservation. Pennsylvania,
Tennessee and the other states where each partnership’s wells may be situated impose a
comprehensive statutory and regulatory scheme for natural gas and oil operations, including
supervising the production activities and the transportation of natural gas sold in intrastate
markets, which creates additional financial and operational burdens. Among other things, these
regulations involve:
•
new well permit and well registration requirements, procedures, and fees;
•
landowner notification requirements;
•
certain bonding or other security measures;
•
minimum well spacing requirements;
•
restrictions on well locations and underground gas storage;
•
certain well site restoration, groundwater protection, and safety measures;
•
discharge permits for drilling operations;
•
various reporting requirements; and
•
well plugging standards and procedures.
These state regulatory agencies also have broad regulatory and enforcement powers including those
associated with pollution and environmental control laws, which are discussed below.
Environmental Regulation
Each partnership’s drilling and producing operations will be subject to various federal, state, and
local laws covering the discharge of materials into the environment, or otherwise relating to the
protection of the environment. The Environmental Protection Agency and state and local agencies
will require the partnerships to obtain permits and take other measures with respect to:
•
the discharge of pollutants into navigable waters;
•
disposal of wastewater; and
•
air pollutant emissions.
If these requirements or permits are violated there can be substantial civil and criminal penalties
that will increase if there was willful negligence or misconduct. In addition, the partnerships
may be subject to fines, penalties and unlimited liability for cleanup costs under various federal
laws such as the Federal Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery
Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act and the Comprehensive
Environmental Response, Compensation and Liability Act of 1980 for oil and/or hazardous substance
contamination or other pollution caused by a partnership’s drilling activities or its wells and its
production activities.
Each partnership and its investor general partners may incur environmental costs and liabilities
due to the nature of the partnership’s business and substances from the partnership’s wells as
described “Risk Factors.” For example, an accidental release from one of a partnership’s wells
could subject the partnership to substantial liabilities arising from environmental cleanup and
restoration costs, claims made by neighboring landowners and other third-parties for personal
injury and property damage, and fines or penalties for related violations of environmental laws or
regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement
policies may be enacted or adopted in the future which could significantly increase a partnership’s
compliance costs and the cost of any remediation that may become necessary.
Also, a partnership’s liability can extend to pollution costs that occurred on the leases before
they were acquired by the partnership. Although the managing general partner will not transfer any
lease to a partnership if it has actual knowledge that there is an existing potential environmental
liability on the lease, there will not be an independent environmental audit of the leases before
they are transferred to a partnership. Thus, there is a risk that the leases will have potential
environmental liability even before drilling begins.
A partnership’s required compliance with these environmental laws and regulations may cause delays
or increase the cost of the partnership’s drilling and producing activities. Because these laws
and regulations are frequently changed, the managing general partner is unable to predict the
ultimate costs of complying with present and future environmental laws and regulations. Also, the
managing general partner is unable to obtain insurance to protect against many environmental
claims, including remediation costs.
Proposed Regulation
From time to time there are a number of proposals considered in Congress and in the legislatures
and agencies of various states that if enacted would significantly and adversely affect the natural
gas and oil industry and the partnerships. The proposals involve, among other things:
•
limiting the disposal of waste water from wells or the emission of greenhouse gases,
which could substantially increase a partnership’s operating costs and make the
partnership’s wells uneconomical to produce;
•
changes in the federal income tax benefits for drilling natural gas and oil wells as
discussed in “Federal Income Tax Consequences”; and
•
tax credits and other incentives for the creation or expansion of alternative energy
sources to natural gas and oil.
Also, Congress could re-enact price controls or additional taxes on natural gas and oil in the
future. However, it is impossible to accurately predict what proposals, if any, will be enacted
and their subsequent effect on a partnership’s activities.
PARTICIPATION IN COSTS AND REVENUES
In General
The partnership agreement provides for the sharing of partnership costs and revenues among the
managing general partner and you and the other investors. A tabular summary of the following
discussion appears below. Each partnership will be a separate business entity from the other
partnerships, and you will be a partner only in the partnership in which you invest. You will have
no interest in the business, assets, or tax benefits of the other partnership unless you also
invest in the other partnership. Thus, your investment return will depend solely on the operations
and success or lack of success of the particular partnership in which you invest.
Costs
1.
Organization and Offering Costs. Organization and offering costs will be charged 100% to the
managing general partner. However, the managing general partner will not receive any credit
towards its required capital contribution
or its revenue share for any organization and
offering costs charged to it in excess of 15% of a partnership’s subscription proceeds.
•
Organization and offering costs generally means all costs of organizing and selling
the offering and includes the dealer-manager fee, sales commissions and the up to .5%
reimbursement for bona fide due diligence expenses.
The managing general partner will pay a portion of a partnership’s organization and offering
costs to itself, its affiliates and independent third-parties and it will contribute the
remainder to the partnership in the form of services related to organizing this offering.
The managing general partner will receive a credit for these payments and services towards
its required capital contribution in each partnership. The managing general partner’s
credit for its contribution of services for organization costs will be determined based on
generally accepted accounting principles. The definition of organization and offering costs
is set forth in the partnership agreement.
2.
Lease Costs. Each partnership’s leases will be contributed to it by the managing general
partner. The managing general partner will be credited with a capital contribution for each
lease valued at:
•
its cost; or
•
fair market value if the managing general partner has reason to believe that cost is
materially more than fair market value.
The cost of the leases includes a portion of the managing general partner’s reasonable,
necessary and actual expenses for geological, geophysical, engineering, drafting,
accounting, legal and other like services allocated to the leases in conformity with
generally accepted accounting principles and industry standards. Also, the managing general
partner has averaged the cost of all of its leases to arrive at the average lease cost per
prospect set forth in “Compensation,” which the managing general partner believes is less
than fair market value.
3.
Intangible Drilling Costs. Ninety percent of the subscription proceeds of you and the other
investors in a partnership will be used to pay 100% of the intangible drilling costs incurred
by that partnership in drilling and completing its wells.
•
Intangible drilling costs generally means those costs of drilling and completing a
well that are currently deductible, as compared with lease costs, which must be
recovered through the depletion allowance, and equipment costs, which must be recovered
through depreciation deductions. For example, intangible
drilling costs include all expenditures made for any well before production in
commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and
expenses incident to and necessary for drilling the well and preparing the well for
production of natural gas or oil. Intangible drilling costs also include the expense
of plugging and abandoning any well before a completion attempt, and the costs (other
than equipment costs and lease acquisition costs) to re-enter and deepen an existing
well, complete the well to deeper reservoirs, or plug and abandon the well if it is
nonproductive from the targeted deeper reservoirs.
Although subscription proceeds of a partnership may be used to pay the costs of drilling
different wells depending on when the subscriptions are received, 90% of the subscription
proceeds of you and the other investors will be used to pay intangible drilling costs
regardless of when you subscribe. Also, even if the IRS successfully challenged the
managing general partner’s characterization of a portion of these costs as deductible
intangible drilling costs, and instead recharacterized the costs as some other item that may
not be currently deductible, such as equipment costs and/or lease acquisition costs, this
recharacterization by the IRS would have no effect on the allocation and payment of the
costs by you and the other investors as intangible drilling costs under the partnership
agreement.
The allocation of each partnership’s costs of drilling and completing its wells between
intangible drilling costs, as defined in the partnership agreement, and equipment costs, as
defined as “tangible costs” in the partnership agreement, will be made by the managing
general partner, in its sole discretion, when the wells are drilled.
Equipment Costs. Ten percent of the subscription proceeds of you and the other investors in
a partnership will be used to pay a portion of the equipment costs incurred by that
partnership. All equipment costs of that partnership’s wells that exceed 10% of the
subscription proceeds of you and the other investors in the partnership will be charged to the
managing general partner.
•
Equipment costs generally means the costs of drilling and completing a well that are
not currently deductible and are not lease costs.
5.
Operating Costs, Direct Costs, Administrative Costs and All Other Costs. Operating costs,
direct costs, administrative costs, and all other partnership costs of your partnership not
specifically charged under the partnership agreement will be charged between the managing
general partner and you and the other investors in the partnership in the same ratio as the
related production revenues are being credited.
•
These costs generally include all costs of partnership administration and producing
and maintaining the partnership’s wells.
Each well in a partnership will have a different productive life and when a well becomes
uneconomic to produce, it will be plugged and abandoned. The costs of plugging and
abandoning a well (other than those incurred in connection with drilling a nonproductive
well) are shared between the managing general partner and you and the other investors in the
same percentage as the related production revenues are being shared. For example, if the
investors are receiving 68% of the partnership revenues and the managing general partner is
receiving 32% of the partnership revenues, then the cost of plugging and abandoning the
wells will be shared in the same percentages. Typically, the managing general partner will
apply the salvage value of the equipment towards this obligation. The salvage value of the
equipment will be shared between you and the other investors and the managing general
partner based on the total amount of the actual equipment costs paid by each. Since the
managing general partner in each partnership will have paid a majority of the partnership’s
total equipment costs, as compared to the total amount of the partnership’s equipment costs
paid by you and the other investors, it will also receive a majority of the salvage value of
the equipment. See “Compensation – Drilling Contracts,” for a discussion of the managing
general partner’s estimated equipment costs for an average partnership well in the primary
drilling areas.
To cover any shortfall that you and the other investors might incur between your share of
the salvage value of the equipment in a well and your share of the plugging and abandoning
costs of the well, the managing general partner has the right, beginning one year after each
partnership well begins producing, to retain up to $200 per month of the partnership
revenues in partnership reserves to cover future plugging and abandonment costs of the well.
This $200 also includes the managing general partner’s share of revenues, which will be
used exclusively for the managing
general partner’s share of the plugging and abandonment costs of the well. To the extent
any portion of those reserves ultimately is not required for the plugging and abandonment
costs of the well, then it will be returned to the general operating revenues of the
partnership.
6.
The Managing General Partner’s Required Capital Contribution. The managing general partner’s
aggregate capital contributions to each partnership must not be less than 25% of all capital
contributions to that partnership. This includes such items as the managing general
partner’s:
•
credit for the cost of the leases it contributes to the partnership, or the fair
market value of the leases if the managing general partner has a reason to believe that
cost is materially more than fair market value;
•
credit for the partnership’s organization and offering costs paid or incurred by the
managing general partner, including the costs of services contributed by the managing
general partner to the partnership as organization costs; and
•
share of the partnership’s equipment costs paid by the managing general partner to
itself as operator under the drilling and operating agreement.
The managing general partner’s capital contributions must be paid or made at the time the costs are
required to be paid by the partnership, but in any event not later than the end of the year
immediately following the year in which the partnership had its final closing.
Revenues
Each partnership’s production revenues from all of its wells will be commingled. Thus, regardless
of when you subscribe to a partnership you will share in the production revenues from all of the
partnership wells in that partnership on the same basis as the other investors in the partnership
in proportion to your number of units.
1.
Proceeds from the Sale of Leases. If a partnership well is sold, a portion of the sales
proceeds will be allocated to the partners in the same proportion as their share of the
adjusted tax basis of the property. In addition, proceeds will be allocated to the managing
general partner to the extent of the pre-contribution appreciation in value of the property,
if any. Any excess will be credited as provided in 4, below.
2.
Interest Proceeds. Interest income earned on your subscription proceeds until they are paid
to the managing general partner for use in the drilling activities of the partnership in which
you subscribed before your partnership’s final closing will be credited to your account and
paid to you not later than the partnership’s first cash distributions from operations. After
your partnership’s subscription proceeds are invested in your partnership’s operations, any
interest income from temporary investments will be allocated pro rata to you and the other
investors providing the subscription proceeds. All other interest income, including interest
earned on the deposit of production revenues, will be credited as provided in 4, below.
3.
Equipment Proceeds. Proceeds from the sale or other disposition of equipment will be
credited to the parties charged with the costs of the equipment in the ratio in which the
costs were charged.
4.
Production Revenues. Subject to the managing general partner’s subordination obligation as
described below, the managing general partner and you and the other investors in a partnership
will share in all of that partnership’s other revenues, including production revenues, in the
same percentage as their respective capital contribution bears to the partnership’s total
capital contributions, except that the managing general partner will receive an additional 7%
of that partnership’s revenues.
However, the managing general partner’s total revenue share may not exceed 40% of that
partnership’s revenues regardless of the amount of its capital contributions. For example,
if the managing general partner contributes the minimum of 25% of the partnership’s total
capital contributions and the investors contribute 75% of the partnership’s total capital
contributions, then the managing general partner will receive 32% of the partnership
revenues and the investors will receive 68% of the partnership revenues. On the other hand,
if the managing general
partner contributes 35% of the partnership’s total capital contributions and the investors
contribute 65% of the partnership’s total capital contributions, then the managing general
partner will receive 40% of the partnership revenues, not 42%, because its revenue share
cannot exceed 40% of partnership revenues, and the investors will receive 60% of partnership
revenues. See “Compensation – Natural Gas and Oil Revenues” for a graphic presentation of
these amounts.
Subordination of Portion of Managing General Partner’s Net Revenue Share
Each partnership is structured to provide you and the other investors with cash distributions equal
to a minimum of 10% of capital, based on a subscription price of $10,000 per unit, regardless of
the actual subscription price you paid for your units, in each of the first five 12-month periods
beginning with that partnership’s first cash distributions from operations. To help achieve this
investment feature, the managing general partner will subordinate up to 50% of its share, as
managing general partner, of partnership net production revenues, which will be up to between 16%
and 20% of the total partnership net production revenues, depending on the amount of its capital
contributions, during this subordination period.
•
Partnership net production revenues means gross revenues after deduction of the
related operating costs, direct costs, administrative costs, and all other costs not
specifically allocated.
Each partnership’s 60-month subordination period will begin with that partnership’s first cash
distribution from operations to you and the other investors. The estimated maximum time from the
closing for a partnership to begin distributions is eight months from the closing as discussed in
“Investment Objectives.” Subordination distributions will be determined by debiting or crediting
current period partnership revenues to the managing general partner as may be necessary to provide
the distributions to you and the other investors. At any time during the subordination period the
managing general partner is entitled to an additional share of partnership revenues to recoup
previous subordination distributions to the extent your cash distributions from that partnership
exceed the 10% return of capital described above. The specific formula for determining
subordination distributions is set forth in Section 5.01(b)(4)(a) of the partnership agreement.
The managing general partner anticipates that you will benefit from the subordination if the price
of natural gas and oil received by the partnership and/or the results of the partnership’s drilling
activities, such as the volume of natural gas and oil produced from the partnership’s wells, are
unable to provide the required return of capital. However, if the wells produce small natural gas
and oil volumes or natural gas and oil prices decrease, then even with subordination your cash flow
may be very small and you may not receive the 10% return of capital for each of the first five
years beginning with the partnership’s first cash distribution from operations.
As of September 15, 2006, the managing general partner was not subordinating any of its partnership
net production revenues in the 16 limited partnerships that currently have the subordination
feature in effect. Since 1993 the managing general partner has had the same or a similar
subordination feature in 34 of its partnerships and from time to time it has subordinated its
partnership net production revenues in 16 of those partnerships. The managing general partner is
entitled to recoup those subordination distributions during the respective subordination period of
those previous partnerships to the extent cash distributions of those previous partnerships to
their respective investors would exceed the specified return to the investors.
Example of Net Revenue Sharing During a Subordination Period.
Net Revenues to
Managing General
Maximum Amount of
Partner and Investors if
Managing General
Maximum Amount of
Percentage of
Percentage of
Partner’s Share of
Managing General
Partnership
Partnership Net
Partnership Net
Partner’s Share of
Capital
Revenues Without
Revenues Available
Partnership Net Revenues
Entity
Contributions (1)
Subordination (1)
for Subordination(2)
is Subordinated (1)(2)
Managing General Partner
25
%
32
%
16
%
16
%
Investors
75
%
68
%
84
%
(1)
These percentages are for illustration purposes only and assume the managing general
partner’s minimum required capital contribution of 25% to each partnership and capital
contributions of 75% from you and the other investors. The actual percentages are likely to
be different because they will be based on the actual capital contributions of the managing
general partner and you and the other investors. However, the managing general partner’s
total revenue share may not exceed 40% of partnership revenues regardless of the amount of its
capital contribution.
(2)
Each partnership is structured to provide you and the other investors with cash distributions
equal to a minimum of 10% of capital, based on a subscription price of $10,000 per unit,
regardless of the actual subscription price you paid for your units, in each of the first five
12-month periods beginning with the partnership’s first cash distributions from operations.
To help achieve this investment feature of a 10% return of capital for each of the first five
12-month periods, the managing general partner will subordinate up to 50% of its share of
partnership net production revenues, which will be up to between 16% and 20% of the total
partnership net production revenues, depending on the amount of its capital contributions,
during this subordination period.
Example of Net Revenue Sharing After the End of a Subordination Period.
Net Revenues to Managing
Maximum Amount of
General Partner and
Managing General
Investors When None of
Percentage of
Percentage of
Partner’s Share of
Managing General
Partnership
Partnership Net
Partnership Net
Partner’s Share of
Capital
Revenues Without
Revenues Available
Partnership Net Revenues
Entity
Contributions (1)
Subordination (1)
for Subordination
is Subordinated (1)
Managing General Partner
25
%
32
%
0
%
32
%
Investors
75
%
68
%
68
%
(1)
These percentages are for illustration purposes only and assume the managing general
partner’s minimum required capital contribution of 25% to each partnership and capital
contributions of 75% from you and the other investors. The actual percentages are likely to
be different because they will be based on the actual capital contributions of the managing
general partner and you and the other investors. However, the managing general partner’s
total revenue share may not exceed 40% of partnership revenues regardless of the amount of its
capital contribution.
Table of Participation in Costs and Revenues
The following table sets forth certain partnership costs and revenues charged and credited between
the managing general partner and you and the other investors in each partnership, after deducting
from the partnership’s gross revenues, the landowner royalties and any other lease burdens.
Managing
General
Partner
Investors
Partnership Costs
Organization and offering costs
100
%
0
%
Lease costs
100
%
0
%
Intangible drilling costs (1)
0
%
100
%
Equipment costs
(2
)
(2
)
Operating costs, administrative costs, direct costs, and all other costs
(3
)
(3
)
Partnership Revenues
Interest income
(4
)
(4
)
Equipment proceeds
(2
)
(2
)
All other revenues including production revenues
(5)(6
)
(5)(6
)
Participation in Deductions and Credits
Intangible drilling costs
0
%
100
%
Depreciation
(2
)
(2
)
Percentage depletion allowance
(5)(6)(7
)
(5)(6)(7
)
Marginal well production credits
(5)(6)(7
)
(5)(6)(7
)
(1)
Ninety percent of the subscription proceeds of you and the other investors in a partnership
will be used to pay 100% of the intangible drilling costs incurred by that partnership in
drilling and completing its wells.
(2)
Ten percent of the subscription proceeds of you and the other investors in a partnership will
be used to pay a portion of the equipment costs incurred by that partnership in drilling and
completing its wells. All equipment costs in excess of 10% of that partnership’s subscription
proceeds will be paid by the managing general partner. Thus, the managing general partner
will pay the majority of each partnership’s equipment costs. Equipment proceeds, if any, will
be credited in the same percentage in which the equipment costs were charged. Thus, the
managing general partner will receive the majority of any equipment proceeds.
These costs, which also include plugging and abandonment costs of the wells after the wells
have been drilled, produced, and depleted, will be charged to the parties in the same ratio as
the related production revenues are being credited.
(4)
Interest earned on your subscription proceeds until they are paid to the managing general
partner for use in the drilling activities of the partnership in which you subscribed before a
partnership’s final closing will be credited to your account and paid to you not later than
the partnership’s first cash distributions from operations. After your partnership’s
subscription proceeds are invested in its operations, any interest income from temporary
investments will be allocated pro rata to the investors providing the subscription proceeds.
All other interest income in the partnership, including interest earned on the deposit of
operating revenues, will be credited as production revenues are credited.
(5)
In each partnership the managing general partner and you and the other investors will share
in all of the partnership’s other revenues in the same percentage that their respective
capital contributions bear to the partnership’s total capital contributions, except that the
managing general partner will receive an additional 7% of the partnership revenues. However,
the managing general partner’s total revenue share in a partnership may not exceed 40% of
partnership revenues.
(6)
If a portion of the managing general partner’s partnership net production revenues is
subordinated, then the actual allocation of partnership revenues between the managing general
partner and you and the other investors will vary from the allocation described in (5) above.
(7)
The percentage depletion allowances and any marginal well production credits will be credited
between the managing general partner and you and the other investors in the same percentages
as the production revenues are being credited.
Allocation and Adjustment Among Investors
The investors’ share as a group of each partnership’s revenues, gains, income, costs, marginal well
production credits, expenses, losses, and other charges and liabilities generally will be charged
and credited among you and the other investors in that partnership in accordance with the ratio
that your respective number of units bears to the number of units held by all investors as a group
in that partnership, based on a subscription price of $10,000 per unit regardless of the actual
subscription price you paid for your units. These allocations will take into account any investor
general partner’s status as a defaulting investor general partner. Certain investors, however,
will pay a discounted subscription price for their units as described in “Plan of Distribution.”
Thus, intangible drilling costs and the investors’ share of the equipment costs of drilling and
completing the partnership’s wells will be charged among you and the other investors in a
partnership as set forth above, except that these allocations (i.e., intangible drilling
costs and equipment costs) will be based on the respective subscription amount paid by you and the
other investors for your respective units as set forth on your respective subscription agreements,
rather than a subscription price of $10,000 per unit for all of the units.
Distributions
The managing general partner will review each partnership’s accounts at least monthly to determine
whether cash distributions are appropriate and the amount to be distributed, if any, taking into
account its subordination obligation discussed above in “– Subordination of Portion of Managing
General Partner’s Net Revenue Share.” Your partnership will distribute funds to you and the other
investors that the managing general partner, in its sole discretion, does not believe are necessary
for the partnership to retain. Distributions may be reduced or deferred to the extent partnership
revenues are used for any of the following:
•
repayment of partnership borrowings;
•
cost overruns;
•
remedial work to improve a well’s producing capability;
•
compensation and fees to the managing general partner as described in “Risk Factors
– Risks Related to an Investment In a Partnership – Compensation and Fees to the
Managing General Partner Regardless of Success of a Partnership’s Activities Will
Reduce Cash Distributions”;
•
direct costs and general and administrative expenses of the partnership;
reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or
•
indemnification of the managing general partner and its affiliates by the
partnership for losses or liabilities incurred in connection with the partnership’s
activities.
Also, funds will not be advanced or borrowed by a partnership for the purpose of making
distributions to you and the other investors if the amount advanced or borrowed would exceed the
partnership’s accrued and received revenues for the previous four quarters, less paid and accrued
operating costs with respect to the revenues. Any cash distributions from a partnership to the
managing general partner will be made only in conjunction with distributions to you and the other
investors in that partnership and only out of funds properly allocated to the managing general
partner’s account.
Liquidation
Each partnership will continue for 50 years unless it is terminated earlier by a final terminating
event as described below, or an event which causes the dissolution of a limited partnership under
the Delaware Revised Uniform Limited Partnership Act. However, if a partnership terminates on an
event which causes a dissolution of the partnership under state law and it is not a final
terminating event, then a successor limited partnership will automatically be formed. Thus, only
on a final terminating event will a partnership be liquidated. A final terminating event is any of
the following:
•
the election to terminate the partnership by the managing general partner or the
affirmative vote of investors whose units equal a majority of the total units;
•
the termination of the partnership under Section 708(b)(1)(A) of the Internal
Revenue Code because no part of its business is being carried on; or
•
the partnership ceases to be a going concern.
On the partnership’s liquidation you will receive your interest in the partnership to which you
subscribed. Generally, your interest in the partnership means an undivided interest in the
partnership’s assets, after payments to the partnership’s creditors, in the ratio that your
positive capital account bears to the positive capital accounts of all of the partners in the
partnership (including the managing general partner) until all of the capital accounts have been
reduced to zero. Thereafter, your interest in the remaining partnership assets will equal your
interest in the related partnership revenues.
Any in-kind property distributions to you from the partnership in which you invest must be made to
a liquidating trust or similar entity, unless you affirmatively consent to receive an in-kind
property distribution after being told the risks associated with the direct ownership of the
property or unless there are alternative arrangements in place which assure that you will not be
responsible for the operation or disposition of the partnership’s properties. If the managing
general partner has not received your written consent to a proposed in-kind property distribution
within 30 days after it is mailed, then it will be presumed that you have not consented. The
managing general partner may then sell the asset at the best price reasonably obtainable from an
independent third-party, or to itself or its affiliates at fair market value as determined by an
independent expert selected by the managing general partner. Also, if the partnership is
liquidated the managing general partner will be repaid any debts owed to it by the partnership
before there are any payments to you and the other investors in that partnership.
CONFLICTS OF INTEREST
In General
Conflicts of interest are inherent in natural gas and oil partnerships involving non-industry
investors because the transactions are entered into without arms’ length negotiation. Your
interests and those of the managing general partner and its affiliates may be inconsistent in some
respects or in certain instances, and the managing general partner’s actions may not be the most
advantageous to you. The following discussion describes all material possible conflicts of
interest that may arise for the managing general partner and its affiliates in the course of each
partnership. For some of the conflicts of interest, but not all, there are certain limitations on
the managing general partner that are designed to reduce, but will not eliminate, the conflicts.
Other than these limitations the managing general partner has no procedures to resolve a conflict
of interest and under the
terms of the partnership agreement the managing general partner may
resolve the conflict of interest in its sole discretion and best interest.
Further, the managing general partner depends on its indirect parent companies, Atlas America and
Atlas Energy Resources, LLC and their affiliates, for management and administrative functions and
financing for capital expenditures. Neither the partnership agreement nor any other agreement
requires Atlas America or Atlas Energy Resources, LLC to pursue a future business strategy that
favors the partnerships. The directors and officers of Atlas America and Atlas Energy Resources,
LLC and their affiliates have a fiduciary duty to make decisions in the best interests of their
respective stockholders. Because the managing general partner is allowed to take into account the
interests of parties other than the partnerships, such as Atlas America, Atlas Energy Resources,
LLC, and their affiliates in resolving partnership conflicts of interest, this has the effect of
creating a conflict of interest. However, this conflict of interest is not allowed to limit the
managing general partner’s fiduciary duty to the partnerships.
The following discussion is materially complete; however, other transactions or dealings may arise
in the future that could result in conflicts of interest for the managing general partner and its
affiliates.
Conflicts Regarding Transactions with the Managing General Partner and its Affiliates
Although the managing general partner believes that the compensation and reimbursement that it and
its affiliates will receive in connection with each partnership are reasonable, the compensation
has been determined solely by the managing general
partner and did not result from negotiations with any unaffiliated third-party dealing at arms’
length. The managing general partner and its affiliates will receive compensation and
reimbursement from each partnership for their services in drilling, completing, and operating that
partnership’s wells under the drilling and operating agreement and will receive the other fees
described in “Compensation” regardless of the success of that partnership’s wells. The managing
general partner and its affiliates providing the services or equipment can be expected to profit
from the transactions, and it is usually in the managing general partner’s best interest to enter
into contracts with itself and its affiliates, rather than unaffiliated third-parties even if the
contract terms, skill, and experience, offered by the unaffiliated third-parties are comparable.
When the managing general partner or any affiliate provides services or equipment to a partnership
the partnership agreement provides that their fees must be competitive with the fees charged by
unaffiliated third-parties in the same geographic area engaged in similar businesses. Also, before
the managing general partner or any affiliate may receive competitive fees for providing services
or equipment to a partnership they must be engaged, independently of the partnership and as an
ordinary and ongoing business, in rendering the services or selling or leasing the equipment and
supplies to a substantial extent to other persons in the natural gas and oil industry in addition
to the partnerships in which the managing general partner or an affiliate has an interest. If the
managing general partner or the affiliate is not engaged in such a business, then the compensation
must be the lesser of its cost or the competitive rate that could be obtained in the area.
Any services not otherwise described in this prospectus or the partnership agreement for which the
managing general partner or an affiliate is to be compensated by a partnership must be:
•
set forth in a written contract that describes the services to be rendered and the
compensation to be paid; and
•
cancelable without penalty on 60 days written notice by investors whose units equal
a majority of the total units.
The compensation paid by the partnership to the managing general partner or its affiliates for
additional services to the partnership under these contracts, if any, will be reported to you in
your partnership’s annual and semiannual reports, and a copy of the contract will be provided to
you on request.
There is also a conflict of interest concerning the purchase price if the managing general partner
or an affiliate purchases a property from a partnership, which they may do in certain limited
circumstances as described in “– Conflicts Involving the Acquisition of Leases – (6) Limitations on
Sale of Undeveloped and Developed Leases to the Managing General Partner,” below.
Conflict Regarding the Drilling and Operating Agreement
The managing general partner anticipates that all of the wells to be drilled by each partnership
will be drilled and operated under the drilling and operating agreement. This creates a continuing
conflict of interest because the managing general partner must monitor and enforce, on behalf of
each partnership, its own compliance, as operator with the drilling and operating agreement and as
managing general partner with the partnership agreement, and the compliance of its affiliate, Atlas
Pipeline Partners, with the gas gathering agreement.
Conflicts Regarding Sharing of Costs and Revenues
The managing general partner will receive a percentage of partnership revenues that is greater than
the percentage of partnership costs that it pays. This sharing arrangement may create a conflict
of interest between the managing general partner and you and the other investors in a partnership
concerning the determination of which wells will be drilled by the partnership based on the risk
and profit potential associated with the wells.
In addition, the allocation of all of the intangible drilling costs to you and the other investors
and the majority of the equipment costs to the managing general partner creates a conflict of
interest between the managing general partner and you and the other investors concerning whether to
complete a well. For example, the completion of a marginally productive well might prove
beneficial to you and the other investors, but not to the managing general partner. When a
completion decision is made, you and the other investors will have already paid the majority of
your costs so you will want to pay your share of the additional costs to complete the well
(i.e., 10% of the additional equipment costs to complete the well) if there is a
reasonable opportunity to recoup your share of the completion costs plus any portion of the costs
of the well paid by you before the completion attempt.
On the other hand, the managing general partner will have paid only a portion of its costs before
this time, and it will want to pay its additional equipment costs to complete the well only if it
is reasonably certain of recouping its share of the completion costs and making a profit. However,
based on its past experience the managing general partner anticipates that most of the wells in the
primary areas will have to be completed before it can determine the well’s productivity, which
would eliminate this potential conflict of interest. In any event, the managing general partner
will not cause any well to be plugged and abandoned without a completion attempt unless it makes
the decision in accordance with generally accepted oil and gas field practices in the geographic
area of the well location.
Conflicts Regarding Tax Matters Partner
The managing general partner will serve as each partnership’s tax matters partner and represent the
partnership before the IRS. The managing general partner will have broad authority to act on
behalf of you and the other investors in the partnership in any administrative or judicial
proceeding involving the IRS, and this authority may involve conflicts of interest. For example,
potential conflicts include:
•
whether or not to expend partnership funds to contest a proposed adjustment by the
IRS, if any, that would decrease:
•
the amount of a partnership’s deduction for intangible drilling costs, which
is allocated 100% to you and the other investors in the partnership; or
•
the amount of the managing general partner’s depreciation deductions, or the
credit to its capital account for contributing the leases to a partnership which
would also decrease the managing general partner’s liquidation interest in the
partnership; or
•
the amount charged to a partnership by the managing general partner as reimbursement
for expenses incurred by the managing general partner in its role as the tax matters
partner.
Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their
Affiliates
The managing general partner will be required to devote to each partnership the time and attention
that it considers necessary for the proper management of the partnership’s activities. However,
the managing general partner has sponsored and continues to manage other natural gas and oil
drilling partnerships, which may be concurrent, and it will engage in unrelated business
activities, either for its own account or on behalf of other partnerships, joint ventures,
corporations, or other entities
in which it has an interest. This creates a continuing conflict of
interest in allocating management time, services, and other activities among the partnerships in
this program and the managing general partner’s other activities.
The managing general partner will determine the allocation of its management time, services, and
other functions on an as-needed basis consistent with its fiduciary duties among the partnerships
in this program and its other activities. However, the managing general partner depends on its
indirect parent companies, Atlas America and Atlas Energy Resources, LLC and their affiliates, for
management and administrative functions and financing for capital expenditures as described in
“Management – Transactions with Management and Affiliates.” Thus, the competition for the time and
services of the managing general partner and its affiliates could result in insufficient attention
to the management and operation of the partnerships.
Subject to its fiduciary duties, the managing general partner will not be restricted from
participating in other businesses or activities, even if these other businesses or activities
compete with a partnership’s activities and operate in the same areas as a partnership. However,
the managing general partner and its affiliates may pursue business opportunities that are
consistent with a partnership’s investment objectives for their own account only after they have
determined that the opportunity either:
•
cannot be pursued by the partnership because of insufficient funds; or
•
it is not appropriate for the partnership under the existing circumstances.
Conflicts Involving the Acquisition of Leases
The managing general partner will select, in its sole discretion, the wells to be drilled by each
partnership. Conflicts of interest may arise concerning which wells will be drilled by each
partnership in this program and which wells will be drilled by the managing general partner’s and
its affiliates’ other affiliated partnerships or third-party programs in which they serve as
driller/operator. It may be in the managing general partner’s or its affiliates’ advantage to have
a partnership in this program bear the costs and risks of drilling a particular well rather than
another affiliate. These potential conflicts of interest will be increased if the managing general
partner organizes and allocates wells to more than one partnership at a time. To lessen this
conflict of interest the managing general partner generally takes a similar interest in the other
partnerships when it serves as managing general partner and/or driller/operator of the other
partnerships. Also, as discussed in “Proposed Activities,” the managing general partner has a
drilling commitment with Knox Energy for the drilling of 300 wells, which creates a conflict of
interest in deciding whether the managing general partner will select wells for each partnership to
drill in the areas that will help the managing general partner satisfy this drilling commitment.
When the managing general partner must provide prospects to two or more partnerships at the same
time it will attempt to treat each partnership fairly on a basis consistent with:
•
the funds available to the partnerships; and
•
the time limitations on the investment of funds for the partnerships.
The partnership agreement gives the managing general partner the authority to cause each
partnership in this program to acquire undivided interests in natural gas and oil properties, and
to participate with other parties, including other drilling programs previously or subsequently
conducted by the managing general partner or its affiliates, in the conduct of its drilling
operations on those properties. If conflicts between the interest of a partnership in this program
and other drilling partnerships do arise, then the managing general partner may be unable to
resolve those conflicts to the maximum advantage of a partnership in this program because the
managing general partner must deal fairly with the investors in all of its drilling partnerships.
In addition, subject to the restrictions set forth below, the managing general partner decides
which prospects and what interest in the prospects to transfer to a partnership. This will result
in a subsequent partnership sponsored by the managing general partner benefiting from knowledge
gained through a prior partnership’s drilling experience in an area and acquiring a prospect
adjacent to the prior partnership’s prospect. In this regard, as drilling progresses, reserves
from newly completed wells are reclassified from the proved undeveloped to the proved developed
category and additional adjacent locations are added to proved undeveloped reserves.
No procedures, other than the guidelines set forth below and in “– Procedures to Reduce Conflicts
of Interest,” have been established by the managing general partner to resolve any conflicts that
may arise. The partnership agreement provides that the managing general partner and its affiliates
will abide by the guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and
(9) there is an exception in the partnership agreement for another program in which the interest of
the managing general partner is substantially similar to or less than its interest in the
partnerships.
(1)
Transfers at Cost. All leases will be acquired by each partnership from the managing general
partner and credited towards its required capital contribution to the partnership at the cost
of the lease, unless the managing general partner has a reason to believe that cost is
materially more than the fair market value of the property. If the managing general partner
believes that cost is materially more than fair market value, then the managing general
partner’s credit for the contribution must be at a price not in excess of the fair market
value. See “Compensation – Lease Costs” regarding the managing general partner averaging its
lease costs and “Participation in Costs and Revenues – Costs – Lease Costs.”
•
A determination of fair market value must be supported by an appraisal from
an independent expert and maintained in the partnership’s records for at least
six years.
(2)
Equal Proportionate Interest. When the managing general partner sells or transfers an oil
and gas interest to a partnership, it must, at the same time, sell or transfer to the
partnership an equal proportionate interest in all of its other property in the same prospect.
•
The term “prospect” generally means an area which is believed to contain
commercially productive quantities of natural gas or oil.
However, a prospect will be limited to the drilling or spacing unit on which one well will
be drilled if the following two conditions are met:
•
the well is being drilled to a geological feature which contains proved
reserves as defined below; and
•
the drilling or spacing unit protects against drainage.
The managing general partner believes that for a prospect located in the primary drilling
areas as described in “Proposed Activities – Primary Areas of Operations,” a prospect will
consist of the drilling and spacing unit because it will meet the test in the preceding
sentence.
•
Proved reserves, generally, are the estimated quantities of natural gas and
oil which have been demonstrated to be recoverable in future years with
reasonable certainty under existing economic and operating conditions. Proved
reserves include proved undeveloped reserves which generally are reserves
expected to be recovered from existing wells where a relatively major
expenditure is required for recompletion or from new wells on undrilled acreage.
Reserves on undrilled acreage will be limited to those drilling units
offsetting productive units that are reasonably certain of production when
drilled. Proved Reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation or there is continuity of the reservior.
In the primary areas the managing general partner anticipates that the drilling of these
wells by each partnership may provide the managing general partner with offset sites by
allowing it to determine, at the partnership’s expense, the value of adjacent acreage in
which the partnership would not have any interest. The managing general partner owns
acreage throughout the primary areas where each partnership’s wells will be situated. To
lessen this conflict of interest, for five years the managing general partner may not drill
any well:
•
to the Clinton/Medina geologic formation, if the well would be within 1,650
feet of an existing partnership well in Pennsylvania or within 1,000 feet of an
existing partnership well in Ohio; or
to the Mississippian/Upper Devonian Sandstone reservoirs in Fayette, Greene
and Westmoreland Counties, Pennsylvania, if the well would be within at least
1,000 feet from a producing well, although a partnership may drill a new well or
re-enter an existing well that is closer than 1,000 feet to a plugged and
abandoned well.
If a partnership abandons its interest in a well, then the restrictions described above will
continue for one year following the abandonment. There are no similar prohibitions for a
partnership’s other primary drilling area, although the managing general partner believes
that none of the prospects transferred to a partnership will result in drainage from the
surrounding wells.
(3)
Subsequently Enlarging Prospect. In areas where the prospect is not limited to the drilling
or spacing unit and the area constituting a partnership’s prospect is subsequently enlarged
based on geological information, which is later acquired, then there is the following special
provision:
•
if the prospect is enlarged to cover any area where the managing general
partner owns a separate property interest and the partnership activities were
material in establishing the existence of
proved undeveloped reserves which are attributable to the separate property
interest, then the separate property interest or a portion thereof must be
sold to the partnership in accordance with (1), (2) and (4).
(4)
Transfer of Less than the Managing General Partner’s and its Affiliates’ Entire Interest. If
the managing general partner sells or transfers to a partnership less than all of its
ownership in any prospect, then it must comply with the following conditions:
•
the retained interest must be a proportionate working interest;
•
the managing general partner’s obligations and the partnership’s obligations
must be substantially the same after the sale of the interest by the managing
general partner or its affiliates; and
•
the managing general partner’s revenue interest must not exceed the amount
proportionate to its retained working interest.
For example, if the managing general partner transfers 50% of its working interest in a
prospect to a partnership and retains a 50% working interest, then the partnership will not
pay any of the costs associated with the managing general partner’s retained working
interest as a part of the transfer. This limitation does not prevent the managing general
partner and its affiliates from subsequently dealing with their retained working interest as
they may choose with unaffiliated parties or affiliated partnerships. For example, the
managing general partner may sell its retained working interest to a third-party for a
profit.
(5)
Limitations on Activities of the Managing General Partner and its Affiliates on Leases
Acquired by a Partnership. For a five year period after the final closing of a partnership,
if the managing general partner proposes to acquire an interest from an unaffiliated person in
a prospect in which the partnership owns an interest or in a prospect in which the
partnership’s interest has been terminated without compensation within one year before the
proposed acquisition, then the following conditions apply:
•
if the managing general partner does not currently own property in the
prospect separately from the partnership, then the managing general partner may
not buy an interest in the prospect; and
•
if the managing general partner currently owns a proportionate interest in
the prospect separately from the partnership, then the interest to be acquired
must be divided in the same proportion between the managing general partner and
the partnership as the other property in the prospect. However, if the
partnership does not have the cash or financing to buy the additional interest,
then the managing general partner is also prohibited from buying the additional
interest.
Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner. The
managing general partner and its affiliates, other than an affiliated partnership as set forth
in (7) below, may not purchase undeveloped leases or receive a farmout from a partnership
other than at the higher of cost or fair market value. Farmouts to the managing general
partner and its affiliates also must comply with the conditions set forth in (9) below.
The managing general partner and its affiliates, other than an affiliated income program,
may not purchase any producing natural gas or oil property from a partnership unless:
•
the sale is in connection with the liquidation of the partnership; or
•
the managing general partner’s well supervision fees under the drilling and
operating agreement for the well have exceeded the net revenues of the well,
determined without regard to the managing general partner’s well supervision
fees for the well, for a period of at least three consecutive months.
In both cases, the sale must be at fair market value supported by an appraisal of an
independent expert selected by the managing general partner. The appraisal of the property
must be maintained in the partnership’s records for at least six years.
(7)
Transfer of Leases Between Affiliated Limited Partnerships. The transfer of an undeveloped
lease from a partnership to an affiliated drilling limited partnership must be made at fair
market value if the undeveloped lease has been held by the partnership for more than two
years. Otherwise, the transfer may be made at cost if the managing general partner deems it
to be in the best interest of the partnership.
An affiliated income program may purchase a producing natural gas and oil property from a
partnership at any time at:
•
fair market value as supported by an appraisal from an independent expert if
the property has been held by the partnership for more than six months or there
have been significant expenditures made in connection with the property; or
•
cost as adjusted for intervening operations if the managing general partner
deems it to be in the best interest of the partnership.
However, these prohibitions do not apply to joint ventures or farmouts among affiliated
partnerships, provided that:
•
the respective obligations and revenue sharing of all parties to the
transaction are substantially the same; and
•
the compensation arrangement or any other interest or right of either the
managing general partner or its affiliates is the same in each affiliated
partnership or if different, the aggregate compensation of the managing general
partner or the affiliate is reduced to reflect the lower compensation
arrangement.
(8)
Leases Will Be Acquired Only for Stated Purpose of the Partnership. Each partnership must
acquire only leases that are reasonably expected to meet the stated purposes of the
partnership. Also, no leases may be acquired for the purpose of a subsequent sale, farmout or
other disposition unless the acquisition is made after a well has been drilled to a depth
sufficient to indicate that the acquisition would be in the partnership’s best interest.
(9)
Farmout. The managing general partner may not assign the working interest in a prospect to a
partnership for the purpose of a subsequent farmout, sale or other disposition, nor may the
managing general partner enter into a farmout to avoid paying its share of the costs related
to drilling a well on an undeveloped lease. However, the managing general partner’s decision
with respect to making a farmout and the terms of a farmout from a partnership
involve conflicts of interest since the managing general partner may benefit from cost savings and
reduction of its risk.
The partnership may farmout an undeveloped lease or well activity to the managing general
partner, its affiliates or an unaffiliated third-party only if the managing general partner,
exercising the standard of a prudent operator, determines that:
•
the partnership lacks the funds to complete the oil and gas operations on the
lease or well and cannot obtain suitable financing;
•
drilling on the lease or the intended well activity would concentrate
excessive funds in one location, creating undue risks to the partnership;
•
the leases or well activity have been downgraded by events occurring after
assignment to the partnership so that development of the leases or well activity
would not be desirable; or
•
the best interests of the partnership would be served.
If the partnership farmouts a lease or well activity, the managing general partner must
retain on behalf of the partnership the economic interests and concessions as a reasonably
prudent oil and gas operator would or could retain under the circumstances prevailing at the
time, consistent with industry practices. However, if the farmout is made to the managing
general partner or its affiliates there is a conflict of interest since the managing general
partner will represent both the partnership and itself or an affiliate. Although the
conflict of interest may be resolved to the managing general partner’s benefit, the managing
general partner must still retain on behalf of the partnership the economic interests and
concessions as a reasonably prudent oil and gas operator would or could retain under the
circumstances prevailing at the time, consistent with industry practices.
Conflicts Regarding Order of Pipeline Construction and Gathering Fees
There are conflicts between you and the managing general partner and its affiliates, because the
managing general partner must monitor and enforce on behalf of the partnerships the compliance of
its affiliate, Atlas Pipeline Partners, with the gas gathering agreement. Also, the managing
general partner may choose well locations for the partnerships that are situated near Atlas
Pipeline Partners’ gathering system which would benefit the managing general partner’s indirect
parent company, Atlas America, by providing more gathering fees to Atlas Pipeline Partners, even if
there are other well locations available in the same area or other areas which offer the
partnerships a greater potential return. (See “Management – Organizational Diagram and Security
Ownership of Beneficial Owners.”) However, the managing general partner believes this conflict of
interest is substantially reduced because the managing general partner expects to make the largest
single capital contribution in each partnership as explained in “Capitalization and Source of Funds
and Use of Proceeds.”
In addition, Atlas America or an affiliate will operate the Atlas Pipeline Partners gathering
system. Thus, the expansion of the Atlas Pipeline Partners gathering system will be within the
control of the managing general partner’s affiliate, which the managing general partner believes
will attempt to expand the Atlas Pipeline Partners gathering system to those areas with the
greatest number of wells with the greatest potential reserves. However, Atlas Pipeline Holdings,
L.P., a wholly-owned subsidiary of Atlas America, recently completed an initial public offering of
a minority interest in its units and, as a public company, may be more susceptible to a change of
control. (See “Risk Factors – Risks Related to the Partnerships’ Oil and Gas Operations – Adverse
Events in Marketing a Partnership’s Natural Gas Could Reduce Partnership Distributions.”)
Further, certain of the managing general partner’s affiliates, including Atlas America and/or Atlas
Energy Resources, LLC, are obligated through their agreement with Atlas Pipeline Partners to pay
the difference between the amount a partnership pays for gathering fees to the managing general
partner as set forth in “Compensation – Gathering Fees,” and the greater of $.35 per mcf or 16% of
the gross sales price for the natural gas. This creates a conflict of interest between the
managing general partner and a partnership because the managing general partner has an economic
incentive to increase the amount of gathering fees paid by the partnership so as to reduce the
amount paid by Atlas America and/or Atlas Energy Resources, LLC to Atlas Pipeline Partners, but any
increase cannot exceed a competitive rate. Further, if Atlas Pipeline Partners GP, LLC were
removed as general partner of Atlas Pipeline Partners without cause and without its consent, this
could create further
pressure to increase the amount of gathering fees required to be paid by a
partnership for natural gas transported through Atlas Pipeline Partners’ gathering system. This
could happen because Atlas Pipeline Partners GP, LLC would no longer receive revenues from Atlas
Pipeline Partners, but Atlas America and its affiliates would still be obligated to pay the
difference between the amount of gathering fees set forth in the master natural gas gathering
agreement, as described above, and the amount of gathering fees paid by a partnership, other than
with respect to new wells drilled by the partnership after the removal of Atlas Pipeline Partners
GP, LLC as general partner of Atlas Pipeline Partners, if any. Thus, the managing general partner
and its affiliates would have a further economic incentive to increase the gathering fees. Any
increase in the gathering fees that a partnership pays would reduce your cash distributions from
the partnership. However, the gathering fees paid to the managing general partner may not exceed
competitive rates.
Conflicts Between Investors and the Managing General Partner as an Investor
The managing general partner, its officers, directors, and its affiliates may subscribe for units
in each partnership and the subscription price of their units will be reduced by 10% as described
in “Plan of Distribution.” Even though they pay a reduced price for their units, these investors
generally will:
•
share in the partnership’s costs, revenues, and distributions on the same basis as
the other investors as described in “Participation in Costs and Revenues”; and
•
have the same voting rights, except as discussed below.
Any subscription for units by the managing general partner, its officers, directors, or affiliates
in the partnership in which you invest will dilute the voting rights of you and the other investors
and there may be a conflict with respect to certain matters. The managing general partner and its
officers, directors and affiliates, however, are prohibited from voting with respect to certain
matters as described in “Summary of Partnership Agreement – Voting Rights.”
Lack of Independent Underwriter and Due Diligence Investigation
The terms of this offering, the partnership agreement, and the drilling and operating agreement
were determined by the managing general partner without arms’ length negotiations. You and the
other investors have not been separately represented by legal counsel, who might have negotiated
more favorable terms for you and the other investors in this offering and the agreements.
Also, there was not an extensive in-depth “due diligence” investigation of the existing and
proposed business activities of the partnerships and the managing general partner that would be
provided by independent underwriters. Although Anthem Securities, which is affiliated with the
managing general partner, serves as dealer-manager of this offering and will receive reimbursement
of bona fide due diligence expenses for certain due diligence investigations conducted by the
selling agents, all of which will be reallowed by Anthem Securities to the selling agents, its due
diligence examination concerning this offering cannot be considered to be independent or as
comprehensive as a due diligence examination that would have been conducted by an independent
underwriter.
Conflicts Concerning Legal Counsel
The managing general partner anticipates that its legal counsel will also serve as legal counsel to
each partnership and that this dual representation will continue in the future. However, if a
future dispute arises between the managing general partner and you and the other investors in a
partnership, then the managing general partner will cause you and the other investors to retain
separate counsel. Also, if counsel advises the managing general partner that counsel reasonably
believes its representation of a partnership will be adversely affected by its responsibilities to
the managing general partner, then the managing general partner will cause you and the other
investors in a partnership to retain separate counsel.
Conflicts Regarding Presentment Feature
You and the other investors in a partnership have the right to present your units in the
partnership to the managing general partner for purchase beginning with the fifth calendar year
after the end of the calendar year in which your partnership closes. This creates the following
conflicts of interest between you and the managing general partner.
The managing general partner may suspend the presentment feature if it does not have
the necessary cash flow or it cannot borrow funds for this purpose on terms which it
deems reasonable. Both of these determinations are subjective and will be made in the
managing general partner’s sole discretion.
•
The managing general partner will also determine the purchase price based on a
reserve report that it prepares and is reviewed by an independent expert that it
chooses. The formula for arriving at the purchase price has many subjective
determinations that are within the discretion of the managing general partner.
Conflicts Regarding Managing General Partner Withdrawing or Assigning an Interest
A conflict of interest is created with you and the other investors by the managing general
partner’s right to do any of the following:
•
mortgage its managing general partner interest in each partnership;
•
withdraw an interest in each partnership’s wells equal to or less than its revenue
interest to be used as collateral for a loan to the managing general partner; or
•
assign, subject to the managing general partner’s subordination obligation, its
managing general partner interest in each partnership to its affiliates which also may
mortgage the interests as collateral for their loans, if any.
If the managing general partner assigned a portion or all, of its managing general partner interest
in a partnership to an affiliate, the amount of partnership net production revenues available to
the managing general partner or an affiliated assignee for their respective subordination
obligations to you and the other investors could be reduced or eliminated if there was a default
under a loan to the managing general partner or the affiliated assignee. Also, under certain
circumstances, if the managing general partner or an affiliated assignee if a portion or all, of
the managing general partner’s managing general partner interest in a partnership was assigned by
the managing general partner to an affiliate as discussed above, made a subordination distribution
to you and the other investors after a default to its lenders, then the lenders may be able to
recoup that subordination distribution from you and the other investors.
Procedures to Reduce Conflicts of Interest
In addition to the procedures set forth in “– Conflicts Involving the Acquisition of Leases,” the
managing general partner and its affiliates will comply with the following procedures in the
partnership agreement to reduce some of the conflicts of interest with you and the other investors.
The managing general partner does not have any other conflict of interest resolution procedures.
Thus, conflicts of interest between the managing general partner and you and the other investors
may not necessarily be resolved in your best interests. However, the managing general partner
believes that its significant capital contribution to each partnership will reduce the conflicts of
interest.
(1)
Fair and Reasonable. The managing general partner may not sell, transfer, or convey any
property to, or purchase any property from, a partnership except pursuant to transactions that
are fair and reasonable; nor take any action with respect to the assets or property of a
partnership which does not primarily benefit the partnership.
(2)
No Compensating Balances. The managing general partner may not use a partnership’s funds as
a compensating balance for its own benefit. Thus, a partnership’s funds may not be used to
satisfy any deposit requirements imposed by a bank or other financial institution on the
managing general partner for its own corporate purposes.
(3)
Future Production. The managing general partner may not commit the future production of a
partnership well exclusively for the managing general partner’s own benefit.
(4)
Disclosure. Any agreement or arrangement that binds a partnership must be fully disclosed in
this prospectus.
(5)
No Loans from a Partnership. A partnership may not loan money to the managing general
partner.
No Rebates. The managing general partner may not participate in any business arrangements
which would circumvent these guidelines including receiving rebates or give-ups.
(7)
Sale of Assets. The sale of all or substantially all of the assets of a partnership may only
be made with the consent of investors whose units equal a majority of the total units.
(8)
Participation in Other Partnerships. If a partnership participates in other partnerships or
joint ventures, then the terms of the arrangements must not circumvent any of the requirements
contained in the partnership agreement, including the following:
•
there may be no duplication or increase in organization and offering expenses, the
managing general partner’s compensation, partnership expenses, or other fees and costs;
•
there may be no substantive change in the fiduciary and contractual relationship
between the managing general partner and you and the other investors; and
•
there may be no diminishment in your voting rights.
(9)
Investments. A partnership’s funds may not be invested in the securities of another person
except in the following instances:
•
investments in working interests made in the ordinary course of the partnership’s
business;
•
temporary investments in income producing short-term highly liquid investments, in
which there is appropriate safety of principal, such as U.S. Treasury Bills;
•
multi-tier arrangements meeting the requirements of (8) above;
•
investments involving less than 5% of the total subscription proceeds of the
partnership that are a necessary and incidental part of a property acquisition
transaction; and
•
investments in entities established solely to limit the partnership’s liabilities
associated with the ownership or operation of property or equipment, provided that
duplicative fees and expenses are prohibited.
(10)
Safekeeping of Funds. The managing general partner may not employ, or permit another to
employ, the funds or assets of a partnership in any manner except for the exclusive benefit of
the partnership. The managing general partner has a fiduciary responsibility for the
safekeeping and use of all funds and assets of each partnership whether or not in the managing
general partner’s possession or control.
(11)
Advance Payments. Advance payments by each partnership to the managing general partner and
its affiliates are prohibited except when advance payments are required to secure the tax
benefits of prepaid intangible drilling costs and for a business purpose.
Policy Regarding Roll-Ups
It is possible at some indeterminate time in the future that each partnership may become involved
in a roll-up. In general, a roll-up means a transaction involving the acquisition, merger,
conversion, or consolidation of a partnership with or into another partnership, corporation or
other entity, and the issuance of securities by the roll-up entity to you and the other investors.
A roll-up will also include any change in the rights, preferences, and privileges of you and the
other investors in the partnership. These changes could include the following:
•
increasing the compensation of the managing general partner;
•
amending your voting rights;
•
listing the units on a national securities exchange or on NASDAQ;
changing the partnership’s fundamental investment objectives; or
•
materially altering the partnership’s duration.
If a roll-up should occur in the future, the partnership agreement provides various policies which
include the following:
•
an independent expert must appraise all partnership assets as discussed in
§4.03(d)(16)(a) of the partnership agreement, and you must receive a summary of the
appraisal in connection with a proposed roll-up;
•
if you vote “no” on the roll-up proposal, then you will be offered a choice of:
•
accepting the securities of the roll-up entity; or
•
one of the following:
•
remaining a partner in the partnership and preserving your units in
the partnership on the same terms and conditions as existed previously;
or
•
receiving cash in an amount equal to your pro-rata share of the
appraised value of the partnership’s net assets; and
•
the partnership will not participate in a proposed roll-up:
•
unless approved by investors whose units equal a majority of the total units;
•
which would result in the diminishment of your voting rights under the
roll-up entity’s chartering agreement;
•
which includes provisions which would operate to materially impede or
frustrate the accumulation of shares by you of the securities of the roll-up
entity;
•
in which your right of access to the records of the roll-up entity would be
less than those provided by the partnership agreement; or
•
in which any of the transaction costs would be borne by the partnership if
the proposed roll-up is not approved by investors whose units equal a majority
of the total units.
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER
In General
The managing general partner will manage your partnership and its assets. In conducting your
partnership’s affairs the managing general partner is accountable to you as a fiduciary, which
under Delaware law generally means that the managing general partner must exercise due care and
deal fairly with you and the other investors. Neither the partnership agreement nor any other
agreement between the managing general partner and each partnership may contractually limit any
fiduciary duty owed to you and the other investors by the managing general partner under applicable
law except as set forth in Sections 4.01, 4.02, 4.03, 4.04, 4.05, and 4.06 of the partnership
agreement. See “Conflicts of Interest – In General” regarding the managing general partner’s
dependence on its indirect parent companies, Atlas America and Atlas Energy Resources, LLC and
their affiliates, for management and administrative functions and financing for capital
expenditures and “Management – Organizational Diagrams and Security Ownership of Beneficial
Owners.” In this regard, the partnership agreement does permit the managing general partner and
its affiliates to:
•
have business interests or activities that may conflict with the partnerships if
they determine that the business opportunity either:
cannot be pursued by the partnership because of insufficient funds; or
•
it is not appropriate for the partnership under the existing circumstances;
•
devote only so much of their time as is necessary to manage the affairs of each
partnership, as determined by the managing general partner in its sole discretion;
•
conduct business with the partnerships in a capacity other than as managing general
partner or sponsor as described in §§4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of the
partnership agreement;
•
manage multiple programs simultaneously; and
•
be indemnified and held harmless as described below in “– Limitations on Managing
General Partner Liability as Fiduciary.”
The fiduciary duty owed by the managing general partner to the partnership is analogous to the
fiduciary duty owed by directors to a corporation and its stockholders, which is commonly referred
to as the “business judgment rule.” This rule provides that directors are not liable for mistakes
made in the good faith exercise of honest business judgment or for losses incurred in the good
faith performance of their duties when performed with such care as an ordinarily prudent person
would use.
If the managing general partner breaches its fiduciary responsibilities, then you are entitled to
an accounting and the recovery of any economic loss caused by the breach. The Delaware Revised
Uniform Limited Partnership Act provides that a limited
partner may institute legal action (a “derivative” action) on a partnership’s behalf to recover
damages from a third-party when the managing general partner refuses to institute the action or
where an effort to cause the managing general partner to do so is not likely to succeed. In
addition, the statutory or case law may permit a limited partner to institute legal action on
behalf of himself and all other similarly situated limited partners (a “class action”) to recover
damages from the managing general partner for violations of its fiduciary duties to the limited
partners. This is a rapidly expanding and changing area of the law, and if you have questions
concerning the managing general partner’s duties you are urged to consult your own counsel.
Limitations on Managing General Partner Liability as Fiduciary
Under the terms of the partnership agreement the managing general partner, the operator, and their
affiliates have limited their liability to each partnership and to you and the other investors for
any loss suffered by your partnership or you and the other investors in the partnership which
arises out of any action or inaction on their part if:
•
they determined in good faith that the course of conduct was in the best interest of the partnership;
•
they were acting on behalf of, or performing services for, the partnership; and
•
their course of conduct did not constitute negligence or misconduct.
In addition, the partnership agreement provides for indemnification of the managing general
partner, the operator, and their affiliates by each partnership against any losses, judgments,
liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection
with that partnership provided that they meet the standards set forth above. However, there is a
more restrictive standard for indemnification for losses arising from or out of an alleged
violation of federal or state securities laws. Also, to the extent that any indemnification
provision in the partnership agreement purports to include indemnification for liabilities arising
under the Securities Act of 1933, as amended, you should be aware that in the SEC’s opinion this
indemnification provision would be contrary to public policy and therefore unenforceable.
Payments to the managing general partner or its affiliates arising from the indemnification or
agreement to hold harmless provisions of the partnership agreement are recoverable only out of the
partnership’s tangible net assets, which include its revenues and any insurance proceeds from the
types of insurance for which the managing general partner, the operator and their affiliates may be
indemnified under the partnership agreement. Still, the use of partnership funds or assets to
indemnify
the managing general partner, the operator, or an affiliate would reduce amounts
available for partnership operations or for distribution to you and the other investors.
A partnership may not pay the cost of the portion of any insurance that insures the managing
general partner, the operator, or an affiliate against any liability for which they cannot be
indemnified. However, a partnership’s funds can be advanced to them for legal expenses and other
costs incurred in any legal action for which indemnification is being sought if the partnership has
adequate funds available and certain conditions in the partnership agreement are met.
The effect of the foregoing provisions and the business judgment rule may be to limit your recourse
against the managing general partner.
FEDERAL INCOME TAX CONSEQUENCES
Introduction
Because no advance ruling on any federal tax issue of an investment in a partnership will be
requested from the IRS, the IRS could disagree with the tax position taken by the partnerships.
However, the managing general partner has obtained a tax opinion letter from Kunzman & Bollinger,
Inc., special counsel for this offering, with respect to the material and any significant federal
income tax issues involving an investment in a partnership by a “typical investor” as that term is
defined in “– Managing General Partner’s Representations,” below. You are urged to read the entire
tax opinion letter, which has been filed as Exhibit 8 to the registration statement of which this
prospectus is a part. (See “Additional Information,” for information on how to obtain a copy of
special counsel’s tax opinion letter.)
Although special counsel’s tax opinions express what it believes a court would probably conclude if
presented with the applicable federal tax issues, special counsel’s tax opinions are only
predictions, and are not guarantees, of the outcome of
the particular tax issues being addressed. The IRS could challenge special counsel’s tax opinions,
and the challenge could be sustained in the courts if litigated and cause adverse tax consequences
to you and your partnership’s other investors. Special counsel’s tax opinions are based in part on
representations and statements made by the managing general partner in the tax opinion letter and
in this prospectus, including forward looking statements relating to the partnership and its
proposed activities. (See “Forward Looking Statements and Associated Risks.”)
Disclosures in Tax Opinion Letter
The following disclosures are made in special counsel’s tax opinion letter.
•
The tax opinion letter was written to support the promotion or marketing of units in
the partnerships to potential investors, and special counsel to the partnerships has
helped the managing general partner organize and document the offering of units in the
partnerships.
•
The tax opinion letter is not confidential. There are no limitations on the
disclosure by any potential investor in a partnership to any other person of the tax
treatment or tax structure of the partnerships.
•
Investors in a partnership have no contractual protection against the possibility
that a portion or all of their intended tax benefits from an investment in the
partnership ultimately are not sustained if challenged by the IRS. (See “Risk Factors
– Tax Risks – Your Tax Benefits from an Investment in a Partnership Are Not
Contractually Protected.”)
•
Each potential investor in a partnership is urged to seek advice based on his
particular circumstances from an independent tax advisor with respect to the federal
tax consequences to him of an investment in a partnership.
Special Counsel’s Assumptions
Set forth below is a synopsis of the principal assumptions made by special counsel in giving its
federal income tax opinions.
•
You will not borrow money to buy units in a partnership from any other investor in the partnership.
You will be personally liable to repay any money you borrow to buy units in a partnership.
•
You will not protect yourself through nonrecourse financing, guarantees, stop loss
agreements or other similar arrangements from losing the money you invest in a
partnership.
Managing General Partner’s Representations
In giving its opinions, special counsel relied in part on representations from the managing general
partner set forth in the tax opinion letter, including the principal representations summarized
below.
•
A “typical investor” in each partnership will be a natural person who purchases
units in this offering and is a U.S. citizen.
•
The investor general partner units in each partnership will be converted by the
managing general partner to limited partner units after all of the wells in that
partnership have been drilled and completed. (See “Actions to be Taken by Managing
General Partner to Reduce Risks of Additional Payments by Investor General Partners.”
•
Each partnership will elect to currently deduct all of the intangible drilling costs
of all of its wells.
•
The managing general partner anticipates that all of each partnership’s subscription
proceeds will be expended in 2007, and you will include your share of your
partnership’s deduction for intangible drilling costs on your individual federal income
tax return for 2007, subject to your right to elect to capitalize and
amortize over a 60-month period a portion or all of your share of your partnership’s
deduction for intangible drilling costs.
•
Each partnership may have its final closing as late in the year as December 31,2007. Thus, depending primarily on when its subscription proceeds are received, each
partnership may prepay in 2007 most, if not all, of its intangible drilling costs for
wells the drilling of which will not begin until 2008.
•
Each partnership will have a calendar year taxable year.
•
The managing general partner anticipates that most, if not all, of each
partnership’s natural gas and oil production from its productive wells will be marginal
production that will qualify for the potentially higher rates of percentage depletion
and potentially available marginal well production credits depending primarily on the
applicable reference prices for natural gas and oil, which may vary from year to year.
•
The principal purpose of each partnership is to locate, produce and market natural
gas and oil on a profitable basis to its investors, apart from tax benefits, as
discussed in this prospectus.
•
Each partnership’s total abandonment losses under §165 of the Code, which could
include, for example, abandonment losses incurred by a partnership for wells drilled
which are nonproductive (i.e. a “dry hole”), and abandonment losses incurred by a
partnership for productive wells which have been operated until their commercial
natural gas and oil reserves have been depleted, will be less than $2 million, in the
aggregate, in any taxable year of each partnership and less than $4 million, in the
aggregate, during each partnership’s first six taxable years.
Additional details, assumptions of special counsel, representations of the managing general
partner, and other matters affecting special counsel’s opinions are contained in special counsel’s
tax opinion letter. You are urged to read the entire tax opinion letter, which is attached as
Exhibit 8 to the Registration Statement of which this prospectus is a part, to assist your
understanding of the federal tax benefits and risks of an investment in a partnership.
Special Counsel’s Opinions
Taxpayers bear the burden of proof to support claimed deductions and tax credits, and special
counsel’s tax opinions are not binding on the IRS or the courts. Special counsel’s tax opinions
with respect to an investment in a partnership by a typical
investor, who is sometimes referred to
in special counsel’s opinions as a “Participant,”“Investor General Partner” or “Limited Partner,”
are set forth below.
(1)
Partnership Classification. Each Partnership will be classified as a
partnership for federal income tax purposes, and not as a corporation.
(2)
Limitations on Passive Activity Losses and Credits. The passive activity
limitations on losses and credits under §469 of the Code will apply to:
•
the initial Limited Partners in a Partnership; and
•
will not apply to the Investor General Partners in a Partnership until after
their Investor General Partner Units are converted to Limited Partner Units.
(3)
Not a Publicly Traded Partnership. Neither Partnership will be treated as a
publicly traded partnership under the Code.
(4)
Business Expenses. Business expenses, including payments for personal services
actually rendered in the taxable year in which accrued by a Partnership, which are
reasonable, ordinary and necessary and do not include amounts for items such as Lease
acquisition costs, Tangible Costs, Organization and Offering Costs and other items that
are required to be capitalized under the Code, are currently deductible by each
Partnership.
•
Potential Limitations on Deductions. A Participant’s ability in any taxable
year to use his share of these deductions of the Partnership in which he invests
on his individual federal income tax returns may be reduced, eliminated or
deferred by the following limitations:
•
the Participant’s personal tax situation, such as the amount of his
regular taxable income, alternative minimum taxable income, losses,
itemized deductions, personal exemptions, etc., which are not related to
his investment in a Partnership;
•
the amount of the Participant’s adjusted basis in his Units at the end
of the Partnership’s taxable year;
•
the amount of the Participant’s “at risk” amount in the Partnership in
which he invests at the end of the Partnership’s taxable year; and
•
the passive activity limitations on losses, and credits, if any, of
the Partnership in which they invest in the case of Limited Partners
(including Investor General Partners after their Units are converted to
Limited Partner Units) who are natural persons or are entities that also
are subject to the passive activity limitations on losses and credits
under §469 of the Code.
(5)
Intangible Drilling Costs. Although each Partnership will elect to deduct
currently all of its Intangible Drilling Costs, each Participant in a Partnership may
still elect to capitalize and deduct all or part of his share of his Partnership’s
Intangible Drilling Costs (which do not include drilling and completion costs of a
re-entry well that are not related to deepening the well, if any) ratably over a
60-month period. Subject to the foregoing, Intangible Drilling Costs paid by a
Partnership under the terms of bona fide drilling contracts for the Partnership’s wells
will be deductible by Participants in that Partnership who elect to currently deduct
their share of their Partnership’s Intangible Drilling Costs in the taxable year in
which the payments are made and the drilling services are rendered.
A Participant’s ability in any taxable year to use his share of these Partnership
deductions on his personal federal income tax returns may be reduced, eliminated or
deferred by the “Potential Limitations on Deductions” set forth in opinion (4) above.
(6)
Prepaid Intangible Drilling Costs. Subject to each Participant’s election to
capitalize and amortize a portion or all of his share of his Partnership’s Intangible
Drilling Costs as set forth in opinion (5) above, any prepayments of Intangible
Drilling Costs by a Partnership in 2007 for wells the drilling of which will begin
after December 31, 2007, but on or before March 30, 2008, will be deductible by the
Participants in 2007.
A Participant’s ability in any taxable year to use his share of these Partnership
deductions on his personal federal income tax returns may be reduced, eliminated or
deferred by the “Potential Limitations on Deductions” set forth in opinion (4) above.
(7)
Depletion Allowance. The greater of the cost depletion allowance or the
percentage depletion allowance will be available to qualified Participants as a current
deduction against their share of their Partnership’s gross income from the sale of
natural gas and oil production in each taxable year, subject to the following
restrictions:
•
a Participant’s cost depletion allowance cannot exceed his adjusted tax basis
in the natural gas or oil property to which it relates; and
•
a Participant’s percentage depletion allowance:
•
may not exceed 100% of his taxable income from each natural gas and
oil property before the deduction for depletion, however, this limitation
is suspended for 2007; and
•
is limited to 65% of his taxable income for the year computed without
regard to percentage depletion, net operating loss carry-backs and
capital loss carry-backs and, in the case of a Participant that is a
trust, any distributions to its beneficiaries.
(8)
MACRS. Each Partnership’s reasonable Tangible Costs for equipment placed in
its productive wells that cannot be deducted immediately will be eligible for cost
recovery deductions under the Modified Accelerated Cost Recovery System (“MACRS”) over
a seven year “cost recovery period” on a well-by-well basis, beginning in the taxable
year each well is drilled, completed and made capable of production, i.e. placed in
service.
A Participant’s ability in any taxable year to use his share of these Partnership
deductions on his personal federal income tax returns may be reduced, eliminated or
deferred by the “Potential Limitations on Deductions” set forth in opinion (4),
above.
(9)
Tax Basis of Units. Each Participant’s initial adjusted tax basis in his Units
will be the amount of money that he paid for his Units.
(10)
At Risk Limitation on Losses. Each Participant’s initial “at risk” amount in
the Partnership in which he invests will be the amount of money that he paid for his
Units.
(11)
Allocations. The allocations of income, gain, loss, deduction, and credit, or
items thereof, and distributions set forth in the Partnership Agreement for each
Partnership, including the allocations of basis and amount realized with respect to a
Partnership’s natural gas and oil properties, will govern each Participant’s allocable
share of those items to the extent the allocations do not cause or increase a deficit
balance in his Capital Account in the Partnership in which he invests.
Subscription. No gain or loss will be recognized by the Participants on
payment of their subscriptions to the Partnership in which they invest.
(13)
Profit Motive, IRS Anti-Abuse Rule and Potentially Relevant Judicial Doctrines.
The Partnerships will possess the requisite profit motive under §183 of the Code.
Also, the IRS anti-abuse rule in Treas. Reg. §1.701-2 and potentially relevant judicial
doctrines will not have a material adverse effect on the tax consequences of an
investment in a Partnership by a Participant as described in our opinions.
(14)
Reportable Transactions. Neither Partnership is, nor should be in the future,
a reportable transactions under §6707A(c) of the Code.
(15)
Overall Conclusion. Special counsel’s overall conclusion is that the federal
tax treatment of a typical Participant’s investment in a Partnership as set forth in
its opinions above is the proper federal tax treatment and will be upheld on the merits
if challenged by the IRS and litigated. Our evaluation of the federal income tax laws
and the expected activities of the Partnerships as represented to us by the Managing
General Partner in this tax opinion letter and as described in the Prospectus causes us
to believe that the deduction by a typical Participant of all, or substantially all, of
his allocable share of his Partnership’s Intangible Drilling Costs in 2007 (even if the
drilling of most or all of his Partnership’s wells begins after December 31, 2007, but
on or before March 30, 2008), as set forth in opinions (5) and (6) above, is the
principal tax benefit offered by each Partnership to its potential Participants and
also is the proper federal tax treatment, subject to each Participant’s election to
capitalize and amortize a portion or all of his share of his Partnership’s deduction
for Intangible Drilling.
A Participant’s ability in any taxable year to use his share of these Partnership
deductions on his personal federal income tax returns may be reduced, eliminated or
deferred by the “Potential Limitations on Deductions” set forth in opinion (4),
above.
The discussion in the Prospectus under the caption “FEDERAL INCOME TAX CONSEQUENCES,”
insofar as it contains statements of federal income tax law, is correct in all
material respects.
Discussion of Federal Income Tax Consequences
Introduction
Special counsel’s tax opinions are limited to those set forth above. The following is a discussion
of all material federal income tax issues or consequences, and any significant federal tax issues,
related to the purchase, ownership and disposition of a partnership’s units that will apply to
typical investors in each partnership. Except as otherwise noted below, however, different tax
consequences from those discussed below may apply to foreign persons, corporations, partnerships,
trusts and other prospective investors that are not treated as typical investors for federal income
tax purposes. Also, the proper treatment of a partnership’s tax attributes by a typical investor
on his individual federal income tax returns may vary from that of another typical investor. This
is because the practical utility of the tax aspects of any investment depends largely on each
investor’s particular income tax position in the year in which items of income, gain, loss,
deduction, or credit, if any, are properly taken into account in computing his federal income tax
liability. In addition, the IRS may challenge the deductions, and credits, if any, claimed by a
partnership or you and the other investors in a partnership, or the taxable year in which the
deductions, and credits, if any, are claimed, and it is possible that the challenge would be upheld
if litigated. Accordingly, you are urged to seek advice based on your particular circumstances
from an independent tax advisor in evaluating the potential tax consequences to you of an
investment in a partnership.
Partnership Classification
For federal income tax purposes a partnership is not a taxable entity. Thus, the partners, rather
than the partnership, receive and report any deductions and tax credits, if any, as well as the
income, from a partnership’s operations. Each partnership has been formed as a limited partnership
under the Delaware Revised Uniform Limited Partnership Act, which describes each partnership as a
“partnership.” Thus, each partnership automatically will be classified as a partnership for
federal tax purposes since the managing general partner has represented that neither partnership
will elect to be taxed as a corporation. Treas. Reg. §301.7701-2.
The managing general partner anticipates that all of the subscription proceeds of each partnership
will be expended in 2007, and the related income, if any, and deductions, including the deduction
for intangible drilling costs, will be reflected on their respective investors’ federal income tax
returns for 2007, subject to each investor’s right to elect to capitalize and amortize over a
60-month period a portion or all of the investor’s share of his partnership’s deduction for
intangible drilling costs. See “Capitalization and Source of Funds and Use of Proceeds” and
“Participation in Costs and Revenues” and “– Intangible Drilling Costs,”“– Drilling Contracts,”“–
Depletion Allowance,”“– Depreciation and Cost Recovery Deductions” and
“– Alternative Minimum Tax,” below.).
Limitations on Passive Activity Losses and Credits
Under the passive activity rules of §469 of the Code, all income of a taxpayer who is subject to
the rules is categorized as:
•
income from passive activities, such as limited partners’ interests in a business;
•
active income, such as salary, bonuses, etc.; or
•
portfolio income, such as gain, interest, dividends and royalties unless earned in
the ordinary course of a trade or business, and gain not derived in the ordinary course
of a trade or business on the sale of property that generates portfolio income or is
held for investment.
Losses generated by passive activities can offset only passive income and cannot be applied against
active income or portfolio income. Similar rules apply with respect to tax credits. (See “–
Marginal Well Production Credits,” below.) Suspended passive losses and passive credits that an
investor cannot use in his current tax year may be carried forward indefinitely, but not back, and
used to offset future years’ passive activity income, or offset passive activity regular federal
income tax liability (in the case of passive activity credits).
The passive activity rules apply to:
•
individuals, estates, and trusts;
•
closely held C corporations which under §§469(j)(1), 465(a)(1)(B) and 542(a)(2) of
the Code are regular corporations with five or fewer individuals who own directly or
indirectly more than 50% in value of the outstanding stock at any time during the last
half of the taxable year (for this purpose, U.S. trusts forming part of a stock bonus,
pension or profit-sharing plan of an employer for the exclusive benefit of its
employees or their beneficiaries that constitutes a “qualified trust” under §401(a) of
the Code, trusts forming part of a plan providing for the payment of supplemental
employee unemployment compensation benefits that meet the requirements of §501(c)(17)
of the Code, domestic or foreign “private foundations” described in §501(c)(3) of the
Code, and a portion of a trust permanently set aside or to be used exclusively for the
charitable purposes described in §642(c) of the Code or a corresponding provision of a
prior income tax law, are considered to be individuals); and
•
personal service corporations, which under §§469(j)(2), 269A(b) and 318(a)(2)(C) of
the Code are corporations the principal activity of which is the performance of
personal services and those services are substantially performed by employee-owners.
For this purpose, the term “employee-owners” includes any employee who owns, on any day
during the taxable year, any of the outstanding stock of the personal service
corporation, and an employee is considered to own:
•
the employee’s proportionate share of any stock of the personal service
corporation owned, directly or indirectly, by or for a partnership or estate in
which the employee is a partner or beneficiary;
•
the employee’s proportionate share of any stock of the personal service
corporation owned, directly or indirectly, by or for a trust (other than an
employee’s trust that is a qualified pension, profit-sharing, or stock bonus
plan and is exempt from the tax) if the employee is a beneficiary;
all of the stock of the personal service corporation owned, directly or
indirectly, by or for any portion of a trust of that the employee is considered
the owner under the Code; and
•
if any stock in a corporation is owned, directly or indirectly, for or by the
employee, the employee’s portionate share of the stock of the personal service
corporation owned, directly or indirectly, by or for that corporation.
Provided, however, that a corporation will not be treated as a personal service
corporation for purposes of §469 of the Code unless more than 10% of the stock (by
value) in the corporation is held by employee-owners (as described above). I.R.C.
§469(j)(2)(B).
However, if a closely held C corporation, other than a personal service corporation in which
employee-owners own more than 10% (by value) of the stock, has net active income (i.e.,
taxable income determined without regard to any income or loss from a passive activity and without
regard to any item of portfolio income, expense (including interest expense), or gain or loss) for
a taxable year, its passive loss for that taxable year can be applied against its net active income
for that taxable year. Similar rules apply to its passive credits, if any. I.R.C. §469(e)(2).
Passive activities include any trade or business in which the taxpayer does not materially
participate on a regular, continuous, and substantial basis. Under the partnership agreement,
limited partners will not have material participation in the partnership in which they invest.
Thus, if you are subject to the passive activity rules as described above and you invest in a
partnership as a limited partner, your investment in the partnership will be subject to the passive
activity limitations on losses and credits. (See “Risk Factors – Tax Risks – Limited Partners Need
Passive Income to Use Their Deduction for Intangible Drilling Costs.”)
Investor general partners also will not materially participate in the partnership in which they
invest. However, because each partnership will own only “working interests,” as defined by the
Code, in its wells, and investor general partners will not
have limited liability under the Delaware Revised Uniform Limited Partnership Act until they are
converted to limited partners, their deductions and any credits from their partnership will not be
treated as passive deductions or credits under the Code before the conversion, unless they invest
in a partnership through an entity which limits their liability. For example, if an individual
invests in a partnership indirectly as an investor general partner by using an entity that limits
his personal liability under state law to purchase his units, such as a limited partnership in
which he is not a general partner, a limited liability company or an S corporation, he will be
subject to the passive activity limitations on deductions and credits the same as if he had
invested in the partnership as a limited partner. (See “– Conversion from Investor General Partner
to Limited Partner” and “– Marginal Well Production Credits,” below.)
As compared with limitations on liability under state law as discussed above, contractual
limitations on the liability of investor general partners under the partnership agreement, such as
insurance, limited indemnification by the managing general partner, etc. will not cause investor
general partners to be subject to the passive activity limitations on losses and credits. Investor
general partners, however, may be subject to an additional limitation on their deduction of
investment interest expense as a result of their non-passive deduction of intangible drilling
costs. (See “– Limitations on Deduction of Investment Interest,” below.)
A Limited Partner’s “at risk” amount is reduced by losses allowed under §465 of the Code even if
the losses are suspended by the passive activity limitations. (See “– ‘At Risk’ Limitation on
Losses,” below.) Similarly, a Limited Partner’s basis is reduced by deductions even if the
deductions are suspended under the passive activity limitations. (See “– Tax Basis of Units,”
below.)
Suspended passive losses and passive credits that cannot be used by a taxpayer in his current tax
year may be carried forward indefinitely, but not back, and can be used to offset passive income in
future years or, in the case of passive credits, can be used to offset regular federal income tax
liability attributable to passive income in future years. I.R.C. §469(b). A suspended passive
loss, but not a suspended passive credit, is allowed in full when a taxpayer’s entire interest in a
passive activity is sold to an unrelated third-party in a fully taxable transaction, and in part on
the taxable disposition of substantially all of a taxpayer’s interest in a passive activity if the
suspended passive loss as well as current gross income and deductions of the
passive activity can
be allocated to the part disposed of with reasonable certainty. I.R.C. §469(g)(1). In an
installment sale of a taxpayer’s entire interest in a passive activity, passive losses become
available in the same ratio that gain recognized each year bears to the total gain on the sale.
I.R.C. §469(g)(3). (See “Transferability of Units – Restrictions on Transfer Imposed by the
Securities Laws, the Tax Laws and the Partnership Agreement.”)
Any suspended passive losses remaining at a taxpayer’s death are allowed as deductions on the
decedent’s final return, subject to a reduction to the extent the amount of the suspended passive
losses is greater than the excess of the basis of the property in the hands of the transferee over
the property’s adjusted basis immediately before the decedent’s death. I.R.C. §469(g)(2). If a
taxpayer makes a gift of his entire interest in a passive activity, the basis in the property of
the person receiving the gift is increased by any suspended passive losses and no deductions are
allowed. If the interest is later sold at a loss, the basis in the property of the person
receiving the gift is limited to the fair market value of the property on the date the gift was
made. I.R.C. §469(j)(6).
Publicly Traded Partnership Rules
Net losses and most net credits of a partner from a publicly traded partnership are suspended and
carried forward to be netted against income or regular federal income tax liability, respectively,
from that publicly traded partnership only. In addition, net losses from other passive activities
may not be used to offset net passive income from a publicly traded partnership. I.R.C.
§§469(k)(2) and 7704. A publicly traded partnership is a partnership in which interests in the
partnership are traded on an established securities market or are readily tradable on either a
secondary market or the substantial equivalent of a secondary market. However, in special
counsel’s opinion neither of the partnerships will be treated as a publicly traded partnership
under the Code. This opinion is based primarily on the substantial restrictions in the partnership
agreement on the ability of you and the other investors to transfer your units in your partnership.
(See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax
Laws and the Partnership Agreement.”) Also, the managing general partner has represented that the
partnerships’ respective units will be not traded on an established securities market.
Conversion from Investor General Partner to Limited Partner
If you invest in a partnership as an investor general partner, then your share of the partnership’s
deduction for intangible drilling costs in 2007 will not be subject to the passive activity
limitations on losses and credits. This is because the investor general partner units in each
partnership will not be converted to limited partner units under §6.01(b)(1) of the partnership
agreement until after all of the wells in that partnership have been drilled and completed. (See
“Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor
General Partners,” and “– Drilling Contracts,” below.) After the investor general partner units
have been converted to limited partner units, each former investor general partner will have
limited liability as a limited partner under the Delaware Revised Uniform Limited Partnership Act
after the date of the conversion.
Concurrently, the former investor general partner will become subject to the passive activity
limitations on losses and credits as a limited partner. However, the former investor general
partner previously will have received a non-passive loss as an investor general partner in 2007 as
a result of his share of his partnership’s deduction for intangible drilling costs. Therefore, the
Code requires that his net income from the partnership’s wells after his conversion to a limited
partner must continue to be characterized as non-passive income that cannot be offset with passive
losses. For a discussion of the effect of this rule on an investor general partner’s tax credits,
if any, from his partnership, see “– Marginal Well Production Credits,” below. The conversion of
the investor general partner units into limited partner units should not have any other adverse tax
consequences on an investor general partner unless his share, if any, of any partnership
liabilities is reduced as a result of the conversion. (See “– Tax Basis of Units,” below.)
Taxable Year and Method of Accounting
Each partnership will adopt a calendar year taxable year and will use the accrual method of
accounting for federal income tax purposes.
Taxable Year. Each partnership will have a calendar year taxable year. I.R.C. §§706(a) and (b).
The taxable year of the partnership in which you invest is important to you because your share of
the partnership’s deductions, tax credits, if any, income and other items of tax significance must
be taken into account on your personal federal income tax return for your taxable year within or
with which the partnership’s taxable year ends.
Method of Accounting. Each partnership will use the accrual method of accounting for federal
income tax purposes. I.R.C. §448(a). Under the accrual method of accounting, income is taken into
account for the year in which all events have occurred that fix the right to receive it and the
amount is determinable with reasonable accuracy, rather than the time of receipt. Consequently,
you and the other investors in the partnership in which you invest may have income tax liability
resulting from the partnership’s accrual of income in one tax year even though it does not receive
the income in cash until the next tax year. Expenses are deducted for the year in which all events
have occurred that determine the fact of the liability, the amount is determinable with reasonable
accuracy and the economic performance test is satisfied. Under §461(h) of the Code, if the
liability of the taxpayer arises out of the providing of services or property to the taxpayer by
another person, economic performance occurs as the services or property, respectively, are
provided. If the liability of the taxpayer arises out of the use of the property by the taxpayer,
economic performance occurs as the property is used.
A special rule in the Code, however, provides that there is economic performance in the current
taxable year with respect to amounts paid in that taxable year for intangible drilling costs of
drilling and completing a natural gas or oil well so long as the drilling of the well begins before
the close of the 90th day after the close of the taxable year in which the payments were
made. I.R.C. §461(i). (See “– Drilling Contracts,” below, for a discussion of the federal income
tax treatment of any prepaid intangible drilling costs by the partnerships.)
Business Expenses
Ordinary and necessary business expenses, including reasonable compensation for personal services
actually rendered, are deductible in the year incurred. In this regard, the managing general
partner has represented that the amounts payable by each partnership to it and its affiliates under
the partnership agreement and the drilling and operating agreement are reasonable and competitive
amounts that ordinarily would be paid for similar services in similar transactions between persons
having no affiliation and dealing with each other “at arms” length in the proposed areas of the
partnerships’ operations. (See Treas. Reg. §1.162-7(b)(3) and “Compensation” and “– Drilling
Contracts,” below.) The fees paid to the managing general
partner and its affiliates by the partnerships will not be currently deductible, however, to the
extent it is determined by the IRS or the courts that they are:
•
in excess of reasonable compensation;
•
properly characterized as organization or syndication fees or other capital costs,
such as lease acquisition costs or equipment costs (i.e., “Tangible Costs”); or
•
not “ordinary and necessary” business expenses.
In the event of an IRS audit of a partnership, payments to the managing general partner and its
affiliates by the partnership would be scrutinized by the IRS to a greater extent than payments to
an unrelated party.
Your ability in any taxable year to use your share of these partnership deductions on your personal
federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on
Deductions” set forth in special counsel’s opinion (4) in “Special Counsel’s Opinions,” above.
Although the partnerships will engage in the production of natural gas and oil from wells drilled
in the United States, the partnerships will not qualify for the “U.S. production activities
deduction.” This is because the deduction cannot exceed 50% of the IRS Form W-2 wages paid by a
taxpayer for a tax year, and the partnerships will not pay any Form W-2 wages since they will not
have any employees. Instead, the partnerships will rely on the managing general partner and its
affiliates to manage them and their respective businesses. (See “Management.”)
Intangible Drilling Costs
You may elect to deduct your share of your partnership’s intangible drilling costs, which include
items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling necessary
to the drilling of a well and preparing it for the production of natural gas or oil, in the taxable
year in which your partnership’s wells are drilled and completed. I.R.C. §263(c), Treas. Reg.
§1.612-4(a). For a discussion of the deduction in 2007 of intangible drilling costs that are
prepaid by your partnership in 2007 for wells the drilling of which will not begin until 2008, if
any, see “– Drilling Contracts,” below.
Your share of your partnership’s gain (if a partnership well is sold at a gain), or your gain (if
your units are sold at a gain), will be treated as ordinary income, rather than capital gain, to
the extent of the previous deductions for intangible drilling costs you have claimed, but not for
the deductions for operating expenses related to a re-entry well, if any. (See “– Sale of the
Properties” and “– Disposition of Units,” below.) Also, productive-well intangible drilling costs
may subject you to an alternative minimum tax in excess of regular tax unless you elect to deduct
all or part of these costs ratably over a 60 month period. (See “– Alternative Minimum Tax,”
below.)
Under the partnership agreement, 90% of the subscription proceeds received by each partnership from
its respective investors will be used to pay 100% of the partnership’s intangible drilling costs of
drilling and completing its wells. (See “Application of Proceeds” and “Participation in Costs and
Revenues.”) The IRS could challenge the characterization of a portion of these costs as currently
deductible intangible drilling costs and recharacterize the costs as some other item that may not
be currently deductible, such as lease acquisition expenses, equipment costs or syndication fees.
However, this would have no effect on the allocation and payment of the intangible drilling costs
by you and the other investors under the partnership agreement.
Also, if a partnership re-enters an existing well as described in “Proposed Activities – Primary
Areas of Operations – Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County,
Pennsylvania,” the costs of deepening the well and completing it to deeper reservoirs, if any,
other than equipment costs and lease acquisition costs, will be treated under the Code as
intangible drilling costs. The remaining intangible drilling costs of drilling and completing a
re-entry well that are not related to deepening the well, if any, however, will be treated under
the Code as operating expenses that should be expensed in the taxable year they are incurred for
federal income tax purposes. Any intangible drilling costs of a re-entry well that are treated as
operating expenses for federal income tax purposes, however, will not be characterized as operating
costs, instead of intangible drilling costs, for purposes of allocating the payment of the costs
between the managing general partner, on the one hand, and you and the other investors , on the
other hand. In addition, under the Code costs related to a re-entry well that are characterized as
operating costs under the Code cannot be amortized as intangible drilling costs over a 60-month
period as described in “– Alternative Minimum Tax,” below, even though they may be characterized as
intangible drilling costs for purposes of the partnership agreement as discussed above. (See
“Participation in Costs and Revenues.”)
In the case of corporations, other than S corporations, which are “integrated oil companies,” the
amount allowable as a deduction for intangible drilling costs in any taxable year is reduced by
30%. I.R.C. §291(b)(1). Integrated oil companies are:
•
those taxpayers who directly or through a related person engage in the retail sale
of natural gas and oil and whose gross receipts for the taxable year from those
activities exceed $5 million; or
•
those taxpayers and related persons who have average daily refinery runs in excess
of 75,000 barrels for the taxable year. I.R.C. §291(b)(4).
Amounts of an integrated oil company’s intangible drilling costs that are disallowed as a current
deduction under §291 of the Code are allowable, however, as a deduction ratably over the 60-month
period beginning with the month in which the costs are paid or incurred. Neither partnership will
be an integrated oil company.
Your ability in any taxable year to use your share of these partnership deductions on your personal
federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on
Deductions” set forth in special counsel’s opinion (4) in “Special Counsel’s Opinions,” above.
You are urged to seek advice based on your particular circumstances from an independent tax advisor
concerning the tax benefits to you of your share of the deduction for intangible drilling costs of
the partnership in which you invest.
Drilling Contracts
Each partnership will enter into the drilling and operating agreement with the managing general
partner to drill and complete the partnership’s wells for an amount equal to the sum of the
following items: (i) the cost of permits, supplies, materials, equipment, and all other items used
in the drilling and completion of a well provided by third-parties, or if the foregoing items are
provided by affiliates of the managing general partner, then those items will be charged at
competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the
managing general partner’s affiliates, which will be
charged at competitive rates; (iv) an administration and oversight fee of $15,000 per well, which
will be charged to you and the other investors as part of each well’s intangible drilling costs and
the portion of equipment costs paid by you and the other investors; and (v) a mark-up in an amount
equal to 15% of the sum of (i), (ii), (iii) and (iv), above, for the managing general partner’s
services as general drilling contractor. Notwithstanding, if the managing general partner drills a
well for a partnership that it determines is not an average well in the area because of the well’s
depth, complexity associated with either drilling or completing the well or as otherwise determined
by the managing general partner, the administration and oversight fee of $15,000 per well described
in §4.02(d)(1)(iv) of the partnership agreement may be increased to a competitive rate as
determined by the managing general partner.
The managing general partner anticipates that, on average over all of the wells that are drilled
and completed by each partnership, assuming a 100% working interest in each well, its mark-up of
15% will be approximately $42,254 per well with respect to the intangible drilling costs and the
portion of equipment costs paid by you and the other investors in your partnership as described in
“Compensation – Drilling Contracts.” However, the actual cost of drilling and completing the wells
may be more or less than the amounts estimated by the managing general partner, due primarily to
the uncertain nature of drilling operations. Therefore, the managing general partner’s 15% mark-up
discussed above also could be more or less than the dollar amount estimated by the managing general
partner as set forth above. The managing general partner believes that the compensation payable to
it and its affiliates under the drilling and operating agreement is competitive in the proposed
areas of operation. Nevertheless, the amount of fees and profit realized by the managing general
partner under the drilling and operating agreement could be challenged by the IRS as being
unreasonable and disallowed as a deductible intangible drilling cost.
Depending primarily on when their respective subscription proceeds are received, the managing
general partner anticipates that each partnership may prepay in 2007 most, if not all, of its
intangible drilling costs for wells the drilling of which will begin in 2008. In Keller v.
Commissioner, 79 T.C. 7 (1982), aff’d 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a
two-part test for the current deductibility of prepaid intangible drilling and development costs.
The test is:
•
the expenditure must be a payment rather than a refundable deposit; and
•
the deduction must not result in a material distortion of income taking into
substantial consideration the business purpose aspects of the transaction.
The drilling partnership in Keller entered into footage and daywork drilling contracts that
permitted it to terminate the contracts at any time, without a default by the driller, and receive
a return of the prepaid amounts less amounts earned by the driller. The Tax Court found that the
right to receive, by unilateral action, a refund of the prepayments on the footage and daywork
drilling contracts rendered the prepayments deposits instead of payments. Therefore, the
prepayments were held to be nondeductible in the year they were paid to the extent they had not
been earned by the driller. The Tax Court further found that the drilling partnership failed to
show a convincing business purpose for the prepayments under the footage and daywork drilling
contracts.
The drilling partnership in Keller also entered into turnkey drilling contracts that
permitted it to stop work under the contract at any time and apply the unearned balance of the
prepaid amounts to another well to be drilled on a turnkey basis. The Tax Court found that these
prepayments constituted “payments” and not nondeductible deposits, despite the right of
substitution. Further, the Tax Court noted that the turnkey drilling contracts obligated “the
driller to drill to the contract depth for a stated price regardless of the time, materials or
expenses required to drill the well,” thereby locking in prices and shifting the risks of drilling
from the drilling partnership to the driller. Since the drilling partnership, a cash basis
taxpayer, received the benefit of the turnkey obligation in the year of prepayment, the Tax Court
found that the amounts prepaid on turnkey drilling contracts clearly reflected income and were
deductible in the year of prepayment.
In Leonard T. Ruth, TC Memo 1983-586, a drilling program entered into nine separate turnkey
contracts with a general contractor, the parent corporation of the drilling program’s corporate
general partner, to drill nine program wells. Each contract identified the prospect to be drilled,
stated the turnkey price, and required the full price to be paid in 1974. The program paid the
full turnkey price to the general contractor on December 31, 1974; the receipt of which was found
by the court to be significant in the general contractor’s financial planning. The program had no
right to receive a refund of any of the payments. The actual drilling of the nine wells was
subcontracted by the general contractor to independent contractors
who were paid by the general contractor in accordance with their individual contracts. The
drilling of all of the wells began in 1975 and all of the wells were completed in 1975. The amount
paid by the general contractor to the independent driller for its work on the nine wells was
approximately $365,000 less than the amount prepaid by the program to the general contractor. The
program claimed a deduction for intangible drilling and development costs in 1974. The IRS
challenged the timing of the deduction, contending that there was no business purpose for the
payments in 1974, that the turnkey arrangements were merely “contracts of convenience” designed to
create a tax deduction in 1974, and that the turnkey contracts constituted assets having a life
beyond the taxable year and that to allow a deduction for their entire costs in 1974 distorted
income. The Tax Court, relying on Keller, held that the program could deduct the full
amount of the payments in 1974. The court found that the program entered into turnkey contracts,
paid a premium to secure the turnkey obligations, and thereby locked in the drilling price and
shifted the risks of drilling to the general contractor. Further, the court found that by signing
and paying the turnkey obligation, the program got its bargained-for benefit in 1974, therefore the
deduction of the payments in 1974 clearly reflected income.
Each partnership will attempt to comply with the guidelines set forth in Keller with
respect to any prepaid intangible drilling costs. In this regard, the drilling and operating
agreement will require each partnership to prepay in 2007 all of the partnership’s share of the
estimated intangible drilling costs, and all of the investors’ share of your partnership’s share of
the estimated equipment costs, for drilling and completing specified wells for that partnership,
the drilling of which may begin in 2008. These prepayments of intangible drilling costs should not
result in a loss of a current deduction for the intangible drilling costs in 2007 if:
•
the guidelines set forth in Keller are complied with;
•
there is a legitimate business purpose for the required prepayment;
•
the drilling of the prepaid wells begins on or before March 30, 2008;
•
the contract is not merely a sham to control the timing of the deduction; and
•
there is an enforceable contract of economic substance.
In this regard, the drilling and operating agreement will require each partnership to prepay the
managing general partner’s estimate of the intangible drilling costs and the investor’s share of
the equipment costs to drill and complete the wells specified in the drilling and operating
agreement in order to enable the operator to:
•
begin site preparation for the wells;
•
obtain suitable subcontractors at the then current prices; and
•
insure the availability of equipment and materials.
Under the drilling and operating agreement excess prepaid intangible drilling costs, if any, will
not be refundable to a partnership, but instead will be applied only to intangible drilling cost
overruns, if any, on the other specified wells being drilled or completed by the partnership or to
intangible drilling costs to be incurred by the partnership in drilling and completing substitute
wells. Under Keller, a provision for substitute wells should not result in the prepayments
being characterized as refundable deposits.
The likelihood that prepayments of intangible drilling costs will be challenged by the IRS on the
grounds that there is no business purpose for the prepayments is increased if prepayments are not
required with respect to 100% of the working interest in the well. In this regard, the managing
general partner anticipates that less than 100% of the working interest will be acquired by each
partnership in one or more of its wells, and prepayments of intangible drilling costs will not be
required of the other owners of working interests in those wells. In the view of special counsel,
however, a legitimate business purpose for the required prepayments of intangible drilling costs by
the partnerships may exist under the guidelines set forth in Keller, even though
prepayments are not required by the drilling contractor with respect to a portion of the working
interest in the wells.
In addition, a current deduction for prepaid intangible drilling costs is available only if the
drilling of the wells begins before the close of the 90th day after the close of the
taxable year in which the prepayment was made. See the discussion of §461(i) of the Code in “–
Method of Accounting,” above. Therefore, under the drilling and operating agreement, the managing
general partner, serving as operator and general drilling contractor, must begin drilling the wells
that are prepaid by the partnership in 2007, if any, no later than March 30, 2008, which is before
the close of the 90th day after the close of the 2007 calendar taxable year of each
partnership in which a partnership’s intangible drilling costs are prepaid. However, the drilling
of any partnership well may be delayed due to circumstances beyond the control of the managing
general partner and the drilling subcontractors. These circumstances include, for example:
•
the unavailability of drilling rigs;
•
decisions of third-party operators to delay drilling the wells;
•
poor weather conditions;
•
inability to obtain drilling permits or access right to the drilling site; or
•
title problems;
and the managing general partner will have no liability under the partnership agreement or the
drilling and operating agreement to either partnership or their respective investors if these types
of events (i.e., “force majeure”) delay beginning the drilling of any partnership prepaid
well beyond the 90 day limit imposed by §461(i) of the Code (i.e., March 30, 2008).
If the drilling of a prepaid partnership well does not begin within the 90 day time constraint
imposed by §461(i) of the Code (i.e., March 30, 2008), deductions claimed by you and the
other investors in that partnership for prepaid intangible drilling costs for the well in 2007,
would not be lost, but those deductions would be deferred to 2008 when the well is actually
drilled.
Your ability in any taxable year to use your share of these partnership deductions on your personal
federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on
Deductions” set forth in special counsel’s opinion (4) in “Special Counsel’s Opinions,” above.
Depletion Allowance
Proceeds from the sale of each partnership’s natural gas and oil production will constitute
ordinary income. A portion of that income will not be taxable under the depletion allowance, which
permits the deduction from gross income for federal income tax purposes of either the percentage
depletion allowance or the cost depletion allowance, whichever is greater. I.R.C. §§611, 613 and
613A. Your share of your partnership’s gain (if a partnership well is sold at a gain), or your
gain (if you sell your units at a gain), will be treated as ordinary income rather than capital
gain to the extent of your previous deductions for depletion that reduced your adjusted basis in
the property or your units. (See “– Sale of the Properties” and “– Disposition of Units,” below.)
Cost depletion for any year is determined by dividing the adjusted tax basis for the property by
the total units of natural gas or oil expected to be recoverable from the property and then
multiplying the resultant quotient by the number of units actually sold during the year. Cost
depletion cannot exceed the adjusted tax basis of the property to which it relates.
Percentage depletion is available to taxpayers other than “integrated oil companies,” as that term
is defined in “– Intangible Drilling Costs,” above, which does not include the partnerships. Your
percentage depletion allowance is based on your share of your partnership’s gross production income
from its natural gas and oil properties. Under §613A(c) of the Code, percentage depletion is
available with respect to 6 million cubic feet of average daily production of domestic natural gas
or 1,000 barrels of average daily production of domestic crude oil. However, taxpayers who have
both natural gas and oil production may allocate the production limitation between the production.
The rate of percentage depletion is 15%. However, percentage depletion for marginal production
increases 1%, up to a maximum increase of 10%, for each whole dollar that the domestic wellhead
price of crude oil for the immediately preceding year is less than $20 per barrel without
adjustment for inflation. I.R.C. §613A(c)(6). The term “marginal production”
includes natural gas and oil produced from a domestic stripper well property, which is defined in
§613A(c)(6)(E) of the Code as any property that produces a daily average of 15 or less equivalent
barrels of oil, which is equivalent to 90 mcf of natural gas, per producing well on the property in
the calendar year. In this regard, the managing general partner has represented that most, if not
all, of the natural gas and oil production from each partnership’s productive wells will be
marginal production under this definition in the Code. Therefore, most, if not all, of each
partnership’s gross income from the sale of its natural gas and oil production will qualify for
these potentially higher rates of percentage depletion. The managing general partner anticipates
that the rate of percentage depletion for marginal production in 2007 will be 15%. This rate may
fluctuate from year to year depending on the price of oil, but will not be less than the statutory
rate of 15% nor more than 25%.
Also, percentage depletion:
•
may not exceed 100% of the taxable income from each natural gas and oil property
before the deduction for depletion, however, this limitation has been suspended in 2007
with respect to marginal properties, which the managing general partner has represented
will include most, if not all, of each partnership’s wells; and
•
is limited to 65% of the taxpayer’s taxable income for the year computed without
regard to percentage depletion, net operating loss carry-backs and capital loss
carry-backs and, in the case of an investor that is a trust, any distributions to its
beneficiaries. Any disallowed percentage depletion deductions under this limitation
may be carried forward to the next taxable year.
The availability in any taxable year of the percentage depletion allowance must be computed
separately by you and not by your partnership or for investors in your partnership as a whole. You
are urged to seek advice based on your particular circumstances from an independent tax advisor
with respect to the availability of the percentage depletion allowance to you.
Depreciation and Cost Recovery Deductions
Ten percent of each partnership’s subscription proceeds from you and the other investors will be
used to pay equipment costs (i.e. “Tangible Costs”), and the managing general partner will pay all
of the partnership’s remaining equipment costs of drilling and completing its wells. The related
depreciation deductions, i.e., cost recovery deductions under the modified accelerated cost
recovery system (“MACRS”), will be allocated under the partnership agreement between the managing
general partner, on the one hand, and you and the other investors in each partnership, on the other
hand, in proportion to the actual amount of the partnership’s equipment costs paid by each.
A partnership’s reasonable Tangible Costs for equipment placed in its wells that cannot be deducted
immediately will be recovered through depreciation deductions over a seven year cost recovery
period, using the 200% declining balance method with a switch to straight-line to maximize the
deduction, beginning in the taxable year in which each well is drilled, completed and made capable
of production, (i.e., “placed in service”) by the partnership. I.R.C. §168(c). In this regard,
the managing general partner anticipates that it may take up to 12 months before all of a
partnership’s wells are drilled, completed and placed in service for the production of natural gas
or oil after that partnership’s final closing. In the case of a short partnership tax year, the
MACRS deduction will be prorated on a 12-month basis. No distinction is made between new and used
property and salvage value is disregarded. Under §168(d)(1) of the Code, all property assigned to
the 7-year class is treated as placed in service, or disposed of, in the middle of the year, unless
more than 40% of the total cost of all equipment in a partnership’s wells placed in service during
the year is placed in service during the last three months of the year. If that happens, then
under §168(d)(3) of the Code the depreciation for the full year will be multiplied by a fraction
based on the quarter the equipment is placed in service: 87.5% for the first quarter, 62.5% for the
second, 37.5% for the third, and 12.5% for the fourth. All of these cost recovery deductions
claimed by a partnership and you and the other investors in that partnership are subject to
recapture as ordinary income rather than capital gain on the sale or other taxable disposition of
the property by the partnership or your units by you. (See “– Sale of the Properties” and “–
Disposition of Units,” below.) Depreciation for alternative minimum tax purposes is computed using
the 150% declining balance method switching to straight-line, for most personal property. This
will result in adjustments in computing the alternative minimum taxable income of you and the other
investors in a partnership in taxable years in which the partnership claims depreciation
deductions. (See “– Alternative Minimum Tax,” below.)
Your ability in any taxable year to use your share of these partnership deductions on your personal
federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on
Deductions” set forth in special counsel’s opinion (4) in “Special Counsel’s Opinions,” above.
Marginal Well Production Credits
There is a marginal well production credit of 50¢ per mcf of qualified natural gas production and
$3 per barrel of qualified oil production for purposes of the regular federal income tax. A tax
credit, unlike a tax deduction, reduces tax liability on a dollar-for-dollar basis. This credit is
part of the general business credit under §38 of the Code, but under current law this credit cannot
be used against the alternative minimum tax. (See “– Alternative Minimum Tax,” below.) Natural
gas and oil production that qualifies as marginal production under the percentage depletion rules
of §613A(c)(6) of the Code as discussed above in “– Depletion Allowance,” which the managing
general partner has represented will include most, if not all, of the natural gas and oil
production from each partnership’s productive wells, is also qualified marginal production for
purposes of this credit. Also, the credit will be reduced proportionately if the reference prices
for the previous calendar year are between $1.67 and $2.00 per mcf for natural gas and $15 and $18
per barrel for oil. In this regard, the managing general partner anticipates that neither of the
partnership’s natural gas and oil production in 2007, if any, will qualify for this credit, because
as of the date of this prospectus the prices for natural gas and oil in 2006 were substantially
above the $2.00 per mcf of natural gas and $18.00 per barrel of oil prices where the credit phases
out completely.
Based on the prices for natural gas and oil in recent years compared with the prices at which the
credit phases out completely, it may appear unlikely that either partnership’s natural gas and oil
production will ever qualify for this credit. (See “Proposed Activities – Sale of Natural Gas
Production – Policy of Treating All Wells Equally in a Geographic Area.”) However, prices for
natural gas and oil are volatile and could decrease in the future. (See “Risk Factors – Risks
Related To The Partnerships’ Oil and Gas Operations – Partnership Distributions May be Reduced if
There is a Decrease in the Price of Natural Gas and Oil.”) Thus, it is possible that the
partnerships’ production of natural gas or oil in one or more taxable years after 2007 could
qualify for the marginal well production credit, depending primarily on the applicable reference
prices for natural gas and oil in the future. However, depending primarily on market prices for
natural gas and oil, which are volatile, each partnership’s production of natural gas and oil may
not qualify for marginal well production credits for many years, if ever.
To the extent that your share of your partnership’s marginal well production credits, if any,
exceeds your regular federal income tax owed on your share of the partnership’s taxable income, the
excess credits, if any, can be used by you to offset any other regular federal income taxes owed by
you, on a dollar-for-dollar basis, subject to the passive activity limitations if you invest in a
partnership as a limited partner. (See “– Limitations on Passive Activity Losses and Credits,”
above.) Also, if you invest in a partnership as an investor general partner, your share of your
partnership’s marginal well production credits, if any, will be an active credit that may offset
your regular federal income tax liability on any type of income. However, after you are converted
to a limited partner in the partnership in which you invest, your share of the partnership’s
marginal well production credits, if any, will be active credits only to the extent of your regular
federal income tax liability that is allocable to your share of any net income of the partnership
from the sale of its natural gas and oil production, since your share of that net income must
continue to be treated by you as non-passive income even after you have been converted to a limited
partner. (See “– Conversion from Investor General Partner to Limited Partner,” above.) Any
credits allocable to you as a converted investor general partner in excess of that amount, as well
as all of the marginal well production credits allocable to those investors who originally invest
in the partnership as limited partners, will be passive credits that under current law can reduce
only your regular income tax liability attributable to net passive income from the partnership in
which you invest or your other passive activities, if any, other than publicly traded partnership
passive activities.
Lease Acquisition Costs and Abandonment
Lease acquisition costs, together with the related cost depletion deduction, and any amortization
deductions for geological and geophysical expenses incurred by the managing general partner after
August 8, 2005, with respect to a partnership’s prospects and any abandonment loss for lease
acquisition costs, are allocated under the partnership agreement 100% to the managing general
partner, which will contribute the leases to each partnership as a part of its capital
contribution.
Tax Basis of Units
Your share of your partnership’s losses is allowable only to the extent of the adjusted basis of
your units at the end of your partnership’s taxable year. I.R.C. §704(d). The adjusted basis of
your units will be adjusted, but not below zero, for any gain
or loss to you from a sale or other taxable disposition by your partnership of a natural gas or oil
property, and will be increased by your:
•
cash subscription payment;
•
share of partnership income; and
•
share, if any, of partnership debt.
The adjusted basis of your units will be reduced by your:
•
share of partnership losses;
•
share of partnership expenditures that are not deductible in computing its taxable
income and are not properly chargeable to capital account;
•
depletion deductions, but not below zero;
•
cash distributions from the partnership; and
•
any reduction in your share of your partnership’s debt, if any. I.R.C. §§705, 722 and 742.
The reduction in your share of partnership liabilities, if any, is considered a cash distribution
to you. Although you will not be personally liable on any partnership loans, if you invest in a
partnership as an investor general partner you will be liable for other obligations of the
partnership. (See “Risk Factors – Risks Related to an Investment In a Partnership – If You Choose
to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner.”) Should cash
distributions to you from your partnership exceed the tax basis of your units immediately before
the distributions, taxable gain would result to you to the extent of the excess. (See “–
Distributions From a Partnership,” below.)
“At Risk” Limitation on Losses
You may use your share of your partnership’s losses to offset income from other sources, to the
extent that your use of those losses is not limited by the adjusted tax basis of your units or the
passive activity limitations on losses and credits, but only to the extent of the amount you have
“at risk” in the partnership under §465 of the Code at the end of a taxable year. (See
“– Limitations on Passive Activity Losses and Credits” and “– Tax Basis of Units,” above.) “Loss,”
for purposes of the “at risk” rules, means the excess of your share of the allocable deductions for
a taxable year from the partnership in which you invest over the amount of income actually received
or accrued by you during the year from that partnership. This “at risk” limitation on your share
of your partnership’s losses, however, does not apply to you if you are a corporation that is
neither an S corporation nor a corporation in which at any time during the last half of the taxable
year five or fewer individuals owned more than 50% (in value) of the outstanding stock under
§542(a)(2) of the Code. (See “– Limitations on Passive Activity Losses and Credits,” above,
relating to the application of §469 of the Code to closely held C corporations for additional
information on the stock ownership requirements under §542(a)(2) of the Code.
Your initial “at risk” amount in the partnership in which you invest will be equal to the amount of
money you paid for your units. However, any amounts borrowed by you to buy your units will not be
considered “at risk” if the amounts are borrowed from another investor in your partnership or
anyone related to another investor in your partnership. In this regard, the managing general
partner has represented that it and its affiliates will not make or arrange financing for you or
any other potential investors to use to purchase units in the partnerships. Also, the amount you
have “at risk” in your partnership will not include the amount of any loss that you are protected
against through:
The amount of any loss that exceeds your “at risk” amount in the partnership in which you invest at
the end of any taxable year must be carried forward by you to the next taxable year, and will then
be available to the extent you are “at risk” in the partnership at the end of that taxable year.
Further, your “at risk” amount in subsequent taxable years of the partnership will be reduced by
any portion of a partnership loss that is allowable to you as a deduction.
Since income, gains, losses and distributions of the partnership in which you invest will affect
your “at risk” amount in the partnership, the extent to which you are “at risk” in the partnership
must be determined annually. Previously allowed losses must be included in your gross income if
your “at risk” amount is reduced below zero. The amount included in your income, however, may be
deducted in the next taxable year to the extent of any increase in the amount that you have “at
risk” in your partnership.
Distributions From a Partnership
A cash distribution from your partnership to you in excess of the adjusted basis of your units
immediately before the distribution is treated as gain to you from the sale or exchange of your
units to the extent of the excess. I.R.C. §731(a)(1). Different rules apply, however, to payments
by a partnership to a deceased investor’s successor in interest and to payments for an investor’s
share of his partnership’s unrealized receivables and inventory items as those terms are defined in
§751 of the Code. Under §731(a)(2) of the Code, no loss can be recognized by you on these types of
distributions, unless the distribution is made to liquidate your units in your partnership and then
only to the extent of the excess, if any, of your adjusted basis in your units over the sum of the
amount of money distributed to you plus your share of the basis (as determined under §732 of the
Code) of any unrealized receivables and inventory items of your partnership. (See
“– Disposition of Units,” below, for a discussion of a partnership’s unrealized receivables and
inventory items under §751 of the Code.)
No gain or loss will be recognized by the partnership in which you invest on cash distributions to
you and the other investors. I.R.C. §731(b). If property is distributed by the partnership to the
managing general partner and you and the other investors in that partnership, basis adjustments to
the partnership’s properties may be made by the partnership, and adjustments to the basis in their
respective interests in the partnership may be made by the managing general partner and you and the
other investors. I.R.C. §§732, 733, 734, and 754. (See §5.04(d) of the Partnership Agreement and
“– Tax Elections,” below.) Other distributions of cash, disproportionate distributions of
property, if any, and liquidating distributions of the partnership may result in taxable gain or
loss to you and the other investors.
Sale of the Properties
The maximum tax rate on a noncorporate taxpayer’s adjusted net capital gain on the sale of most
capital assets held more than a year is 15%, or 5% to the extent the gain would have been taxed at
a 10% or 15% rate if it had been ordinary income, respectively, for most capital assets. In
addition, the 5% tax rate on adjusted net capital gain will be reduced to 0%. The former maximum
tax rates of 18% and 8%, respectively, on qualified five-year gain have been eliminated. These
capital gain rates also apply for purposes of the alternative minimum tax. (See
“– Alternative Minimum Tax,” below.) However, the former tax rates on adjusted net capital gain of
20% and 10%, respectively, are scheduled to be reinstated on January 1, 2011.
Under §1(h)(3) of the Code, “adjusted net capital gain” means net capital gain determined without
taking qualified dividend income into account:
•
reduced (but not below zero) by:
•
any amount of qualified dividend income taken into account as investment
income under §163(d)(4)(B)(iii) of the Code;
•
net capital gain that is taxed a maximum rate of 28% (such as gain on the
sale of most collectibles and gain on the sale of qualified small business stock
qualified under §1202 of the Code); and
net capital gain that is taxed at a maximum rate of 25% (gain attributable to
real estate depreciation); and
•
increased by the amount of qualified dividend income.
“Net capital gain” means the excess of net long-term gain (the excess of long-term gains over
long-term losses) over net short-term loss (the excess of short-term gains over short-term losses).
The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus
the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or
the excess of capital losses over capital gains. I.R.C. §1211(b)
Gains from the sale by a partnership of a natural gas and oil property held by it for more than 12
months will be treated as long-term capital gain, while a net loss will be an ordinary deduction,
except to the extent of depreciation recapture on equipment and recapture of intangible drilling
costs and depletion deductions as discussed below. In addition, gain on the sale of the
partnership’s natural gas and oil properties may be recaptured as ordinary income to the extent of
non-recaptured §1231 losses (as defined below) for the five most recent preceding taxable years on
previous sales, if any, of the partnership’s natural gas and oil properties or other assets.
I.R.C. §1231(c). If, for any taxable year, the §1231 gains exceed the §1231 losses, the gains and
losses will be treated as long-term capital gains or long-term capital losses, as the case may be.
If the §1231 gains do not exceed the §1231 losses, the gains and losses will not be treated as
gains and losses from sales or exchanges of capital assets. For this purpose, the term Ҥ1231
gain” means any recognized gain:
•
on the sale or exchange of a property used in a trade or business; and
•
from the involuntary conversion into other property or money of:
•
property used in a trade or business; or
•
any capital assets that are held for more than one year and are held in
connection with a trade or business or a transaction entered into for profit.
The term “§1231 loss” means any recognized loss from a sale or exchange or conversion described
above.
The term “property used in a trade or business” means depreciable property and real property that
are used in a trade or business and are held for more than one year, which are not inventory and
are not held primarily for sale to customers in the ordinary course of a trade or business.
Net §1231 gain will be treated as ordinary income to the extent the gain does not exceed the
non-recaptured net §1231 losses. The term “non-recaptured net §1231 losses” means the excess of:
•
the aggregate amount of the net §1231 losses for the five most recent taxable years;
over
•
the portion of those losses taken into account to determine whether the net §1231
gain for any taxable year should be treated as ordinary income to the extent the gain
does not exceed the non-recaptured net §1231 losses, as discussed above, for those
preceding taxable years.
Other gains and losses on sales of natural gas and oil properties held by the partnership for less
than 12 months, if any, will result in ordinary gains or losses.
In addition, as discussed above deductions for intangible drilling costs and depletion allowances
that are incurred in connection with a natural gas or oil property may be recaptured as ordinary
income when the property is sold or otherwise disposed of in a taxable transaction by the
partnership. The amount of gain recaptured as ordinary income is the lesser of:
•
the aggregate amount of expenditures that have been deducted as intangible drilling
costs with respect to the property and which, but for being deducted, would have been
included in the adjusted basis of the property, plus deductions for depletion that
reduced the adjusted basis of the property; or
the amount realized, in the case of a sale, exchange or involuntary conversion; or
•
the fair market value of the interest, in the case of any other taxable disposition;
over the adjusted basis of the property. I.R.C. §1254(a).
(See “– Intangible Drilling Costs” and “– Depletion Allowance,” above.)
Also, all gain on the sale or other taxable disposition of equipment by the partnership will be
treated as ordinary income to the extent of MACRS deductions previously claimed by the partnership.
I.R.C. §1254(a). (See “– Depreciation and Cost Recovery Deductions,” above.)
Disposition of Units
The sale or exchange, including a purchase by the managing general partner, of all or some of your
units, if held by you as a capital asset for more than 12 months, will result in your recognition
of long-term capital gain or loss, except for your share of your partnership’s “§751 assets”
(i.e. inventory items and unrealized receivables). “Unrealized receivables” includes any
right to payment for goods delivered, or to be delivered, to the extent the proceeds would be
treated as amounts received from the sale or exchange of non-capital assets, services rendered or
to be rendered, to the extent not previously includable in income under your partnership’s
accounting methods, and deductions previously claimed by you for depreciation, depletion and
intangible drilling costs with respect to the partnership in which you invest. “Inventory items”
includes property properly includable in inventory and property held primarily for sale to
customers in the ordinary course of business and any other property that would produce ordinary
income if sold, including accounts receivable for goods and services. These tax items are
sometimes referred to in this discussion as “§751 assets.” All of these tax items may be
recaptured as ordinary income rather than capital gain regardless of how long you have owned your
units. (See “– Sale of the Properties,” above.)
If your units are held for 12 months or less, your gain or loss will be short-term gain or loss.
Also, your pro rata share of your partnership’s liabilities, if any, as of the date of the sale or
exchange, must be included in the amount realized by you. Thus, the gain recognized by you may
result in a tax liability to you greater than the cash proceeds, if any, received by you from the
disposition of your units. In addition to gain from a passive activity, a portion of any gain
recognized by a limited partner on the sale or other taxable disposition of his units will be
characterized as portfolio income under the passive activity loss rules to the extent the gain is
attributable to portfolio income, e.g. interest income on investments of working capital. Treas.
Reg. §1.469-2T(e)(3). (See “– Limitations on Passive Activity Losses and Credits,” above.)
A gift of your units may result in federal and/or state income tax and gift tax liability to you.
Also, interests in different partnerships do not qualify for tax-free like-kind exchanges. I.R.C.
§1031(a)(2)(D). Other types of dispositions of your units may or may not result in recognition of
taxable gain. However, no gain should be recognized by an investor general partner on the
conversion of his investor general partner units to limited partner units so long as there is no
change in his share of his partnership’s liabilities or §751 assets as a result of the conversion.
Revenue Ruling 84-52, 1984-1 C.B. 157. In addition, if you sell or exchange all or some of your
units you are required by the Code to notify your partnership within 30 days or by January 15 of
the following year, if earlier. The partnership will then report to the IRS any information
required by the IRS to be reported regarding the transfer of the units, including your share of
your partnership’s §751 assets that are subject to recapture as ordinary income as discussed above.
If you die, or sell or exchange all of your units, the taxable year of your partnership will close
with respect to you, but not the remaining investors, on the date of death, sale or exchange, and
there will be a proration of partnership items for the partnership’s taxable year. If you sell
less than all of your units, the partnership’s taxable year will not terminate with respect to you,
but your proportionate share of the partnership’s items of income, gain, loss, deduction and credit
will be determined by taking into account your varying interests in the partnership during the
taxable year.
If you sell or exchange all or some of your units in the partnership in which you invest, you are
required under §6050K of the Code to notify the partnership within 30 days or by January 15 of the
following year, if earlier. After receiving the notice, the partnership must file a return with
the IRS setting forth the name and address of both you, as the transferor, and the
transferee, the fair market value of the portion of the partnership’s unrealized receivables and
appreciated inventory (i.e., §751 assets) allocable to the units sold or exchanged by you
(which is subject to recapture as ordinary income instead of capital gain as discussed above) and
any other information as may be required by the IRS. The partnership also must provide each person
whose name is set forth in the return a written statement showing the information set forth on the
return.
You are urged to seek advice based on your particular circumstances from an independent tax advisor
before any sale or other disposition of your units, including any purchase of your units by the
managing general partner.
Alternative Minimum Tax
With limited exceptions, under §55 of the Code you must pay an alternative minimum tax if it
exceeds your regular federal income tax for the year. Alternative minimum taxable income (“AMTI”)
is regular federal taxable income, plus or minus various adjustments, plus tax preference items.
The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for married
individuals filing separately, of a taxpayer’s AMTI in excess of the applicable exemption amount
(as set forth below); and additional AMTI is taxed at 28%. However, the regular tax rates on
capital gains also will apply for purposes of the alternative minimum tax. (See “– Sale of the
Properties,” above.) Exemption amounts for alternative minimum tax purposes are different from the
regular tax personal exemptions, which are not allowed, and the types and amounts of itemized
deductions allowed for minimum tax purposes are more limited than those allowed for regular tax
purposes as discussed below.
For tax years beginning in 2006, the exemption amounts for individuals under the Tax Increase
Prevention Act were the following amounts:
•
married individuals filing jointly and surviving spouses, $62,550, less 25% of AMTI
exceeding $150,000 (zero exemption when AMTI is $400,200);
•
unmarried individuals, $42,500, less 25% of AMTI exceeding $112,500 (zero exemption
when AMTI is $282,500); and
•
married individuals filing separately, $31,275, less 25% of AMTI exceeding $75,000
(zero exemption when AMTI is $200,100). Also, AMTI of married individuals filing
separately was increased by the lesser of $31,275 or 25% of the excess of AMTI (without
regard to the exemption reduction) over $200,100.
Unless Congress takes further action, for tax years beginning in 2007 the exemption amounts for
individuals for alternative minimum tax purposes will be reduced substantially from those set forth
above as follows: $45,000 for married individuals filing jointly and surviving spouses, $33,750 for
single persons other than surviving spouses, and $22,500 for married individuals filing separately.
Code sections suspending losses, such as the rules concerning your “at risk” amount in the
partnership, the amount of your passive activity losses from the partnership, and your basis in
your units, are recomputed for alternative minimum tax purposes, and the amounts of the deductions
that are suspended, or capital gains that are recaptured as ordinary income, may differ for regular
income tax and alternative minimum tax purposes. Due to the inherently factual nature of these
determinations and each investor’s different tax situation, special counsel is unable to express an
opinion as to whether any investor will incur, or increase, his alternative minimum tax liability
because of an investment in the partnership.
As of the date of this prospectus, the 2006 exemption amounts for the AMTI of a noncorporate
taxpayer that were available for 2006 had not been extended to 2007. Thus, you are urged to seek
advice from an independent tax advisor to determine whether changes to the alternative minimum tax
laws have been made after the date of this prospectus.
Some of the principal adjustments to taxable income that are used to determine an individual’s AMTI
include those summarized below:
•
Depreciation deductions of the costs of the equipment placed in service in the wells
(“Tangible Costs”) may not exceed deductions computed using the 150% declining balance
method. These adjustments are discussed in greater detail below. (See “– Depreciation
and Cost Recovery Deductions,” above.)
Miscellaneous itemized deductions are not allowed.
•
Medical expenses are deductible only to the extent they exceed 10% of adjusted gross income.
•
State and local property taxes and income taxes, or, at the taxpayer’s election,
state and local sales taxes, which are itemized and deducted for regular tax purposes,
are not deductible.
•
Interest deductions are restricted.
•
The standard deduction and personal exemptions are not allowed.
•
Only some types of operating losses are deductible.
•
Passive activity losses are computed differently.
•
Earlier recognition of income from incentive stock options may be required.
The principal tax preference items that must be added to taxable income for alternative minimum tax purposes include:
•
excess intangible drilling costs, as discussed below; and
•
tax-exempt interest earned on certain private activity bonds, less any
deductions that would have been allowable if the interest were included in gross income
for regular income tax purposes.
For taxpayers other than “integrated oil companies” as that term is defined in “– Intangible
Drilling Costs,” above, which does not include the partnerships, the 1992 National Energy Bill
repealed:
•
the preference for excess intangible drilling costs; and
•
the excess percentage depletion preference for natural gas and oil.
The repeal of the excess intangible drilling costs preference, however, under current law may not
result in more than a 40% reduction in the amount of the taxpayer’s AMTI computed as if the excess
intangible drilling costs preference had not been repealed. I.R.C. §57(a)(2)(E). Under the prior
rules, the amount of intangible drilling costs that is not deductible for alternative minimum tax
purposes is the excess of the “excess intangible drilling costs” over 65% of net income from
natural gas and oil properties. Net natural gas and oil income is determined for this purpose
without subtracting excess intangible drilling costs. Excess intangible drilling costs is the
regular intangible drilling costs deduction minus the amount that would have been deducted under
120-month straight-line amortization, or, at the taxpayer’s election, under the cost depletion
method. There is no preference item for costs of nonproductive wells.
Also, you may elect under §59(e) of the Code to capitalize all or part of your share of your
partnership’s intangible drilling costs (which does not include your share of the partnership’s
intangible drilling costs of a re-entry well that are treated under the Code as operating costs, if
any) and deduct the costs ratably over a 60-month period beginning with the month in which the
costs were paid or incurred by the partnership. This election also applies for regular tax
purposes and can be revoked only with the IRS’ consent. Making this election, therefore, will
include the following principal consequences to you:
•
your regular federal income tax deduction for intangible drilling costs in 2007 will
be reduced because you must spread the deduction for the amount of intangible drilling
costs which you elect to capitalize over the 60-month amortization period; and
•
the capitalized intangible drilling costs will not be treated as a preference that
is included in your alternative minimum taxable income.
Other than intangible drilling costs as discussed above, and passive activity losses and credits in
the case of limited partners, the principal tax item that may have an impact on your alternative
minimum taxable income as a result of investing in a
partnership is depreciation of the partnership’s equipment expenses. (See “– Limitations on
Passive Activity Losses and Credits,” above.) As noted in “– Depreciation and Cost Recovery
Deductions,” above, each partnership’s cost recovery deductions for regular income tax purposes
will be computed differently than for alternative minimum tax purposes. Consequently, in the early
years of the cost recovery period of your partnership’s equipment, but not in the later years, your
depreciation deductions from the partnership will be smaller for alternative minimum tax purposes
than your depreciation deductions for regular income tax purposes on the same equipment. This
could cause you to incur, or may increase, your alternative minimum tax liability in those taxable
years. Conversely, this adjustment may decrease your alternative minimum taxable income in the
later years of the cost recovery period. Also, under current law, your share of your partnership’s
marginal well production credits, if any, may not be used to reduce your alternative minimum tax
liability, if any. In addition, the rules relating to the alternative minimum tax for corporations
are different from those for individuals that are discussed above.
All prospective investors contemplating purchasing units in a partnership are urged to seek advice
based on their particular circumstances from an independent tax advisor as to the likelihood of
them incurring or increasing any alternative minimum tax liability as a result of an investment in
a partnership.
Limitations on Deduction of Investment Interest
Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net
investment income each year, with an indefinite carryforward of disallowed investment interest
expense deductions to subsequent taxable years. I.R.C. §163(d). An investor general partner’s
share of any interest expense incurred by the partnership in which he invests before his investor
general partner units are converted to limited partner units will be subject to the investment
interest limitation. I.R.C. §163(d)(5)(A)(ii). In addition, an investor general partner’s share
of the partnership’s loss in 2007 as a result of the deduction for intangible drilling costs will
reduce his net investment income and may reduce or eliminate the deductibility of his investment
interest expenses, if any, in 2007, with the disallowed portion to be carried forward to subsequent
taxable years. This limitation on the deduction of investment interest expenses, however, will not
apply to any income or expenses taken into account by limited partners in computing their income or
loss from the partnership as a passive activity under §469 of the Code. I.R.C. §163(d)(4)(D).
(See “– Limitations on Passive Activity Losses and Credits,” above.)
Allocations
The partnership agreement allocates to you your share of your partnership’s income, gains, losses,
deductions, and credits, if any, including the deductions for intangible drilling costs and
depreciation. Allocations under the partnership agreement of some tax items are made in ratios
that are different from allocations of other tax items (i.e., “special allocations”). Your capital
account in the partnership in which you invest will be adjusted to reflect your share of these
allocations, and your capital account, as adjusted, will be given effect by the partnership in
making distributions to you on liquidation of the partnership or your units. Also, the basis of
the natural gas and oil properties owned by your partnership for purposes of computing cost
depletion and gain or loss on disposition of a property will be allocated and reallocated when
necessary in the ratio in which the expenditure giving rise to the tax basis of each property was
charged as of the end of the year. (See §5.03(b) of the Partnership Agreement.)
Your capital account in the partnership in which you invest will be:
•
increased by the amount of money you contribute to the partnership and allocations
of partnership income and gain to you; and
•
decreased by the value of property or cash distributed to you by the partnership and
allocations of partnership losses and deductions to you.
Allocations made in a manner that is disproportionate to the respective interests of the partners
in a partnership of any item of partnership income, gain, loss, deduction or credit will not be
given effect unless the allocation has “substantial economic effect.” I.R.C. §704(b). Economic
effect means that if there is an economic benefit or burden that corresponds to an allocation, the
partner to whom the allocation is made must receive the economic benefit or bear the economic
burden. The economic effect of an allocation is substantial if there is a reasonable possibility
that the allocation will affect substantially the dollar amounts to be received by the partners
from the partnership, independent of tax consequences and taking into
account the partners’ tax attributes that are unrelated to the partnership. The allocations under
the partnership agreement will have economic effect if throughout the term of the partnership in
which you invest:
•
the partners’ capital accounts are increased and decreased as described above;
•
liquidation proceeds are distributed in accordance with the partners’ capital accounts; and
•
any partner with a deficit balance in his capital account following the liquidation
of his interest in the partnership is required to restore the amount of the deficit to
the partnership.
Even though you and the other investors are not required under the partnership agreement to restore
any deficit balance in your capital accounts in your partnership by making additional capital
contributions to the partnership, an allocation that is not attributable to nonrecourse debt or tax
credits will still be considered to have economic effect under the Treasury Regulations to the
extent it does not cause or increase a deficit balance in your capital account if:
•
the partners’ capital accounts are increased and decreased as described above;
•
the partnership’s liquidation proceeds are distributed in accordance with the
partners’ capital accounts; and
•
the partnership agreement provides that if you unexpectedly incur a deficit balance
in your capital account because of certain adjustments, allocations, or distributions
of the partnership, then you will be allocated an additional amount of partnership
income and gain that is sufficient to eliminate the deficit balance as quickly as
possible.
Treas. Reg. §1.704-1(b)(2)(ii)(d). These provisions are included in the partnership agreement (See
§§5.02, 5.03(h), and 7.02(a) of the partnership agreement.)
Special provisions of the Treasury Regulations apply to deductions that are related to nonrecourse
debt and tax credits, since allocations of those tax items cannot have substantial economic effect
under the Treasury Regulations. If the managing general partner or an affiliate makes a
nonrecourse loan to the partnership in which you invest (a “partner nonrecourse liability”), then
that partnership’s losses, deductions, or §705(a)(2)(B) expenditures attributable to the loan must
be allocated to the managing general partner. Also, if there is a net decrease in partner
nonrecourse liability minimum gain with respect to the loan, the managing general partner must be
allocated income and gain equal to the net decrease. (See §§5.03(a)(1) and 5.03(i) of the
partnership agreement.) In addition, any marginal well production credits of the partnership will
be allocated among the managing general partner and you and the other investors in the partnership
in accordance with each partner’s respective interest in the partnership’s production revenues from
the sale or its natural gas and oil production. (See §5.03(g) of the partnership agreement,
“Participation in Costs and Revenues,” and “– Marginal Well Production Credits,” above.)
If you sell or transfer your unit in the partnership in which you invest, or on the death of an
investor, or the admission of an additional partner, the partnership’s income, gain, loss, credits
and deductions will be allocated among its partners according to their varying interests in the
partnership during the taxable year. In addition, the Code may require the partnership’s property
to be revalued on the admission of additional partners, if any, if disproportionate distributions
are made to the partners, or if there are “built-in” losses on the transfer of a partner’s units or
any distribution of the partnership’s property to its partners. (See “– Tax Elections,” below.)
It also should be noted that your share of items of income, gain, loss, deduction, and credit, if
any, in the partnership in which you invest must be taken into account by you whether or not you
receive any cash distributions from the partnership. For example, your share of partnership
revenues applied by your partnership to the repayment of loans, if any, or the reserve for plugging
wells, will be included in your gross income in a manner analogous to an actual distribution of the
revenues (and income) to you. Thus, you may have tax liability on taxable income from your
partnership for a particular year in excess of any cash distributions from the partnership to you
with respect to that year. To the extent a partnership has cash available for distribution,
however, it is the managing general partner’s policy that partnership cash distributions to you and
the other investors in that partnership will not be less than the managing general partner’s
estimate of the investors’ income tax liability (as a group) with respect to that partnership’s
income.
If any allocation under the partnership agreement is not recognized for federal income tax
purposes, your share of the items subject to the allocation will be determined in accordance with
your interest in the partnership in which you invest by considering all of the relevant facts and
circumstances. To the extent deductions or credits allocated by the partnership agreement exceed
deductions or credits which would be allowed under a reallocation of those tax items by the IRS,
you may incur a greater tax burden.
Partnership Borrowings
Under the partnership agreement, only the managing general partner and its affiliates may make
loans to the partnerships. The use of partnership revenues taxable to you to repay borrowings by
your partnership could create income tax liability for you in excess of your cash distributions
from the partnership, since repayments of principal are not deductible for federal income tax
purposes. In addition, interest on the loans will not be deductible unless the loans are bona fide
loans that will not be treated by the IRS as capital contributions to the partnership by the
managing general partner or its affiliates in light of all of the surrounding facts and
circumstances. Also, the “at risk” amounts of you and the other investors in the partnership in
which you invest, which limit the amount of partnership losses you and the other investors can
claim as discussed in “– ‘At Risk’ Limitation on Losses,” above, will not be increased by the
amount of any partnership borrowings from the managing general partner or its affiliates, because
you and the other investors will not bear any risk of repaying the borrowings from your
non-partnership assets, even if you invest in the partnership as an investor general partner.
Partnership Organization and Offering Costs
Expenses connected with the offer and sale of units in a partnership, such as the dealer-manager
fee, sales commissions, and other selling expenses, professional fees, and printing costs, which
are charged under the partnership agreement 100% to the managing general partner as organization
and offering costs, are not deductible. Although expenses incident to the creation of a
partnership may be amortized over a period of not less than 180 months, these expenses also will be
paid by the managing general partner as part of each partnership’s organization costs. Thus, any
related deductions, which the managing general partner does not anticipate will be material in
amount as compared to the total amount of subscription proceeds of each partnership, will be
allocated under the partnership agreement to the managing general partner.
Tax Elections
Each partnership may elect to adjust the basis of its property (other than cash) on the transfer of
a unit in the partnership by sale or exchange or on the death of an investor, and on the
distribution of property (other than money) by the partnership to an investor (the §754 election).
If the §754 election is made, the transferees of the units are treated, for purposes of
depreciation and gain, as though they had acquired a direct interest in the partnership assets and
the partnership is treated for these purposes, on distributions to the investors, as though it had
newly acquired an interest in the partnership assets and therefore acquired a new cost basis for
the assets. Any election, once made, may not be revoked without the consent of the IRS.
In this regard, due to the complexities and added expense of the tax accounting required to
implement a §754 election to adjust the basis of a partnership’s property when units are sold,
taking into account the limitations on the sale of the partnership’s units as described in
“Transferability of Units,” the managing general partner anticipates that the partnerships will not
make the §754 election, although they reserve the right to do so. Even if the partnerships do not
make the §754 election, however, the basis adjustment described above is mandatory under the Code
with respect to the transferee partner only, if at the time a unit is transferred by sale or
exchange, or on the death of an investor, a partnership’s adjusted basis in its property exceeds
the fair market value of the property by more than $250,000 immediately after the transfer of the
unit. Similarly, a basis adjustment is mandatory under the Code if a partnership distributes
property in-kind to a partner and the sum of the partner’s loss on the distribution and the basis
increase to the distributed property is more than $250,000. I.R.C. §§734 and 743. In this regard,
under §7.02 of the partnership agreement, a partnership will not distribute its assets in-kind to
its investors except to a liquidating trust or similar entity for the benefit of its investors on
the dissolution and termination of the partnership, unless at the time of the distribution its
investors have been offered the election of receiving in-kind property distributions, and you or
any other investor in that partnership accepts the offer after being advised of the risks
associated with direct ownership; or there are alternative arrangements in place which assure that
you and the other investors in that partnership will not, at any time, be responsible for the
operation or disposition of the partnership’s properties.
If the basis of a partnership’s assets must be adjusted as discussed above, the primary effect on
the partnership, other than the federal income tax consequences discussed above, would be an
increase in its administrative and accounting expenses to make the required basis adjustments to
its properties and separately account for those adjustments after they are made. In this regard,
the partnerships will not make in-kind property distributions to their respective investors except
in the limited circumstances described above, and the units will have no readily available market
and will be subject to substantial restrictions on their transfer. (See “Transferability of Units
– Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership
Agreement.”) These factors will tend to reduce the likelihood that a partnership will be required
to make mandatory basis adjustments to its properties.
In addition to the §754 election, each partnership may make various elections under the Code for
federal tax reporting purposes that could result in the deductions of intangible drilling costs and
depreciation, and the depletion allowance, being treated differently for tax purposes than for
accounting purposes. Also, under §195 of the Code “start-up expenditures” may be capitalized and
amortized over a 180-month period. The term “start-up expenditure” for this purpose includes any
amount:
•
paid or incurred in connection with:
•
investigating the creation or acquisition of an active trade or business;
•
creating an active trade or business; or
•
any activity engaged in for profit and for the production of income before
the day on which the active trade or business begins, in anticipation of that
activity becoming an active trade or business; and
•
that would be allowable as a deduction if paid or incurred in connection with the
expansion of an existing business.
If it is ultimately determined by the IRS or the courts that any of a partnership’s expenses
constituted start-up expenditures, that partnership’s deductions for those expenses, including your
share, if any, of those deductions under the partnership agreement would be amortized over the
180-month period.
Tax Returns and IRS Audits
The tax treatment of most partnership items is determined at the partnership, rather than the
partner level. Accordingly, you are required to treat the partnership’s tax items of the
partnership in which you invest on your individual federal income tax returns in a manner that is
consistent with the treatment of the partnership items on the partnership’s federal information
income tax returns, unless you disclose to the IRS, by attaching the required IRS notice to your
individual federal income tax return, that your tax treatment of the partnership’s tax items on
your personal federal income tax returns is different from their partnership’s tax treatment of
those partnership tax items. I.R.C. §§6221 and 6222. Treasury Regulations define partnership tax
items for this purpose as including distributive share items that must be allocated among the
partners, such as partnership liabilities, data pertaining to the computation of the depletion
allowance, and guaranteed payments. Treas. Reg. §301.6231(a)(3)-1.
In most cases, the IRS must make an administrative determination as to partnership tax items at the
partnership level before conducting deficiency proceedings against a partner, and the partners must
file a request for an IRS administrative determination with respect to the partnership before
filing suit for any credit or refund. Also, the period for assessing tax against you and the other
investors because of a partnership tax item may be extended by agreement between the IRS and the
managing general partner, which will serve as each partnership’s representative (“Tax Matters
Partner”) in all administrative tax proceedings and tax litigation, if any, conducted at the
partnership level.
The Tax Matters Partner may enter into a settlement on behalf of, and binding on, any investor
owning less than a 1% profits interest in a partnership if there are more than 100 partners in the
partnership, unless that investor timely files a statement with the Secretary of the Treasury
providing that the Tax Matters Partner does not have authority to enter into a settlement agreement
on behalf of that investor. Based on its past experience, the managing general partner anticipates
that there will be
more than 100 investors in each partnership in which units are offered for sale. However, by
executing the Subscription Agreement you also are executing the partnership agreement if your
Subscription Agreement is accepted by the managing general partner. Under the partnership
agreement, you and the other investors in that partnership agree that you will not form or exercise
any right as a member of a notice group and will not file a statement notifying the IRS that the
Tax Matters Partner does not have binding settlement authority. In addition, a partnership with at
least 100 partners may elect to be governed under simplified tax reporting and audit rules as an
“electing large partnership.” However, most limitations affecting the calculation of the taxable
income and tax credits of an electing large partnership are applied at the partnership level and
not the partner level. Thus, the managing general partner does not anticipate that the
partnerships will make this election, although they reserve the right to do so.
All expenses of any tax proceedings involving a partnership and the managing general partner acting
as Tax Matters Partner, which might be substantial, will be paid for by the partnership and not by
the managing general partner from its own funds. The managing general partner, however, is not
obligated to contest any adjustments made by the IRS to a partnership’s federal information income
tax returns, even if the adjustment also would affect the individual federal income tax returns of
you and the other investors in that partnership. The managing general partner will notify you and
the other investors in your partnership of any IRS audits or other tax proceedings involving your
partnership, and will provide you and the other investors any other information regarding the
proceedings as may be required by the partnership agreement or law.
Tax Returns. Your individual income tax returns are your responsibility. Each partnership will
provide its investors with the tax information applicable to their investment in the partnership
necessary to prepare their tax returns.
Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines Limitations on Deductions
Under §183 of the Code, your ability to deduct your share of your partnership’s deductions could be
limited or lost if the partnership lacks the appropriate profit motive as determined from an
examination of all facts and circumstances at the time. Section 183 of the Code creates a
presumption that an activity is engaged in for profit if, in any three of five consecutive taxable
years, the gross income derived from the activity exceeds the deductions attributable to the
activity. Thus, if your partnership fails to show a profit in at least three out of five
consecutive years this presumption will not be available and the possibility that the IRS could
successfully challenge the partnership deductions claimed by you would be substantially increased.
The fact that the possibility of ultimately obtaining profits is uncertain, standing alone, does
not appear under the Treasury Regulations to be sufficient grounds for the denial of losses. Also,
if a principal purpose of a partnership is to reduce substantially the partners’ federal income tax
liability in a manner that is inconsistent with the intent of the partnership rules of the Code,
based on all the facts and circumstances, the IRS is authorized under Treasury Regulation §1.701-2
to remedy the abuse. Finally, under potentially relevant judicial doctrines such as the step
transaction, business purpose, economic substance, substance over form, and sham transaction
doctrines, tax deductions and tax credits from a transaction, including each partnership’s
deduction for intangible drilling costs in 2007, would be disallowed if your partnership were found
by the IRS or the courts, to have no economic substance apart from the tax benefits.
With respect to these issues, special counsel has given its opinions that the partnerships will
possess the requisite profit motive, and the IRS anti-abuse rule in Treas. Reg. §1.701-2 and the
potentially relevant judicial doctrines listed above will not have a material adverse effect on the
tax consequences of an investment in a partnership by a typical investor as described in special
counsel’s opinions. These opinions are based in part on the results of the previous partnerships
sponsored by the managing general partner as set forth in “Prior Activities” and the managing
general partner’s representations to special counsel, which are set forth in its tax opinion letter
attached as Exhibit 8 to the Registration Statement of which this prospectus is a part. The
managing general partner’s representations include that each partnership will be operated as
described in this prospectus (see “Management” and “Proposed Activities”) and the principal purpose
of each partnership is to locate, produce and market natural gas and oil on a profitable basis to
its investors, apart from tax benefits, as described in this prospectus. Also, see the information
concerning the partnerships’ proposed drilling areas in “Proposed Activities,” and the geological
evaluations and other information for the specific prospects proposed to be drilled by Atlas
Resources Public #16-2007(A) L.P. included in Appendix A to this prospectus, which represent a
portion of the prospects to be drilled if that partnership’s targeted maximum subscription proceeds
of $100 million are received (which is not binding on the partnership) as described in “Terms of
the Offering – Subscription to a Partnership.” Also, the managing general partner has represented
that Appendix A in this prospectus will be supplemented or amended to cover a portion of the
specific prospects proposed to be drilled by Atlas Resources Public #16-2007(B) L.P. if units in
that partnership are offered to prospective investors.
Taxpayers must pay tax and interest on underpayments of federal income taxes and the Code contains
various penalties, including penalties for negligence and substantial valuation misstatements with
respect to their individual federal income tax returns. In addition, there is a penalty equal to
20% of the amount of a substantial understatement of federal income tax liability. There is a
substantial understatement by a noncorporate taxpayer if the correct income tax, as finally
determined by the IRS or the courts, exceeds the income tax liability shown on the taxpayer’s
federal income tax return by the greater of 10% of the correct tax, or $5,000. In the case of a
corporation, other than an S corporation, or a personal holding company as defined in §542 of the
Code, an understatement is substantial if it exceeds the lesser of: (i) 10% of the correct tax (or,
if greater, $10,000); or (ii) $10 million). I.R.C. §6662. A noncorporate taxpayer may avoid this
penalty if the understatement was not attributable to a “tax shelter,” as that term is defined
below, and there is or was substantial authority for the taxpayer’s tax treatment of the item that
caused the understatement, or if the relevant facts were adequately disclosed on the taxpayer’s
individual federal income tax return or a statement attached to the return and the taxpayer had a
“reasonable basis” for the tax treatment of that item. In the case of an understatement that is
attributable to a “tax shelter,” however, which may include each of the partnerships for this
purpose, the penalty may be avoided by a non-corporate taxpayer only if there was reasonable cause
for the underpayment and the taxpayer acted in good faith, or there is or was substantial authority
for the taxpayer’s treatment of the item that caused the understatement, and the taxpayer
reasonably believed that his or her treatment of the item on his individual federal income tax
return was more likely than not the proper treatment.
For purposes of this penalty, the term “tax shelter” includes a partnership if a significant
purpose of the partnership is the avoidance or evasion of federal income tax. Because the IRS has
not explained what a “significant” purpose of avoiding or evading federal income taxes means,
special counsel cannot give an opinion as to whether the partnerships are “tax shelters” as defined
by the Code for purposes of this penalty.
Also, under §6662A of the Code, there is a 20% penalty for reportable transaction understatements
of federal income taxes on a taxpayer’s individual federal income tax return for any tax year.
However, if the disclosure rules for reportable transactions under the Code and the Treasury
Regulations are not met by the taxpayer, this penalty is increased from 20% to 30%, and a
“reasonable cause” exception to the penalty that is set forth in §6664(d) of the Code will not be
available to the taxpayer. Under Treasury Regulation §1.6011-4, a taxpayer who participates in a
reportable transaction in any taxable year must attach to his individual federal income tax return
IRS Form 8886 “Reportable Transaction Disclosure Statement,” and file it with the IRS as directed
in the Regulation, in order to comply with the disclosure rules.
A tax item is subject to the reportable transaction rules if the tax item is attributable to:
•
any listed transaction, which is a transaction that is the same as, or substantially
similar to, a transaction that the IRS has publicly pronounced to be a tax avoidance
transaction; or
•
any of four additional types of reportable transactions, if a significant purpose of
the transaction is federal income tax avoidance or evasion.
A “loss transaction” is one type of reportable transaction, but only if a “significant” purpose of
the transaction is federal income tax avoidance or evasion. As set forth above, special counsel
cannot give an opinion with respect to whether or not each partnership has a “significant” purpose
of avoiding or evading federal income taxes, because the IRS has not explained what that phrase
means for purposes of this penalty. Subject to the foregoing, under Treasury Regulation
§1.6011-4(b)(5), there is a loss transaction if a partnership or any of its noncorporate partners
claims a loss under §165 of the Code of at least $2 million, in the aggregate, in any taxable year
of the partnership, or at least $4 million, in the aggregate, over the partnership’s first six
years. In this regard, however, special counsel has given its opinion that the partnerships are
not, and should not be in the future, reportable transactions under the Code.
For purposes of the “loss transaction” rules, a §165 loss includes an amount deductible under a
provision of the Code that treats a transaction as a sale or other disposition of property, or
otherwise results in a deduction under §165. A §165 loss includes, for example, a loss resulting
from a sale or exchange of a partnership interest, such as an investor’s units in a partnership.
The amount of a §165 loss is adjusted for any salvage value and for any insurance or other
compensation received. However, a §165 loss for this purpose does not take into account offsetting
gains or other income limitations under the Code.
Each partnership will incur a tax loss in 2007 in excess of $2 million if the partnership receives
subscription proceeds of approximately $2,225,000 or more, or a loss in excess of $4 million if
subscription proceeds of at least $4,450,000 are received by the partnership, due primarily to the
amount of intangible drilling costs for productive wells that each partnership intends to claim as
a deduction. Notwithstanding the foregoing, in special counsel’s opinion the partnerships’ losses
resulting from deductions claimed for intangible drilling costs for productive wells properly
should be treated as losses under §263(c) of the Code and Treas. Reg. §1.612-4(a), and should not
be treated as §165 losses for purposes of the “loss transaction” rules under Treas. Reg.
1.6011-4(b)(5). However, the partnerships may incur losses under §165 of the Code, such as losses
for the abandonment by a partnership of:
•
wells drilled that are nonproductive (i.e. a “dry hole”), if any, in which case the
intangible drilling costs, the tangible costs, and possibly the lease acquisition costs
of the abandoned wells would be deducted as §165 losses; and
•
wells that have been operated until their commercial natural gas and oil reserves
have been depleted, in which case the undepreciated tangible costs, if any, and
possibly the lease acquisition costs, would be deducted as §165 losses.
In this regard, based primarily on its past experience (as shown in “Prior Activities”), including
Atlas America’s 97% completion rate for wells drilled by its previous development drilling
partnerships in the Appalachian Basin (see
“– Management”), the managing general partner has represented the following:
•
when a well is plugged and abandoned by a partnership, the salvage value of the
well’s equipment usually will cover a substantial amount of the costs of abandoning and
reclaiming the well site;
•
each partnership will drill relatively few non-productive wells (i.e., “dry holes”),
if any;
•
each productive well drilled by a partnership will have a different productive life
and the wells will not all be depleted and abandoned in the same taxable year;
•
each productive well drilled by a partnership will produce for more than six years;
and
•
approximately 389 gross wells (which is approximately 355) net wells will be drilled
by Atlas Resources Public #16-2007(A) L.P. if its targeted maximum subscription
proceeds of $100 million are received, based on the managing general partner’s estimate
of the average weighted cost of drilling and completing the partnership’s wells. (See
“Compensation – Drilling Contracts).
State and Local Taxes
Each partnership will operate in states and localities that may impose a tax on it, or on you and
the partnership’s other investors, based on the partnership’s assets or income or your share of its
assets or income. Because of widespread state budget deficits, several states are evaluating ways
to subject partnerships to entity-level taxation through the imposition of state income, franchise
or other forms of taxation. If any state were to impose a tax upon your partnership as an entity,
the cash available for distribution to you would be reduced. Each partnership also may be subject
to state income tax withholding requirements on its income allocable to you and its other
investors, whether or not the revenues that created the income are distributed to you and its other
investors. Deductions and credits, including federal marginal well production credits, if any,
which may be available to you for federal income tax purposes, may not be available to you for
state or local income tax purposes. If you reside in a state or locality that imposes income taxes
on its residents, you likely will be required under those income tax laws to include your share of
your partnership’s net income or net loss in determining your reportable income for state or local
tax purposes in the jurisdiction in which you reside. To the extent that you pay tax to another
state because of partnership operations within that state, you may be entitled to a deduction or
credit against tax owed to your state of residence with respect to the same income. Also, due to a
partnership’s operations in a state or local jurisdiction, state or local estate or inheritance
taxes may be payable on the death of an investor in addition to taxes imposed by his own domicile.
Each partnership’s units may be sold in all 50 states and the District of Columbia and other
jurisdictions, and it is not practical for special counsel to evaluate the many different state and
local tax laws that may affect one or more of a
partnership’s investors with respect to their investment in the partnership. You are urged to seek
advice based on your particular circumstances from an independent tax advisor to determine the
effect state and local taxes, including gift and death taxes as well as income taxes, may have on
you in connection with an investment in a partnership.
Severance and Ad Valorem (Real Estate) Taxes
Each partnership will incur various ad valorem or severance taxes imposed by state or local taxing
authorities on its natural gas and oil wells and/or natural gas and oil production from the wells.
These taxes will reduce the amount of each partnership’s cash available for distribution to you and
its other investors.
Social Security Benefits and Self-Employment Tax
A limited partner’s share of income or loss from a partnership is excluded from the definition of
“net earnings from self-employment.” No increased benefits under the Social Security Act will be
earned by limited partners and if any limited partners are currently receiving Social Security
benefits, their shares of partnership taxable income will not be taken into account in determining
any reduction in benefits because of “excess earnings.”
An investor general partner’s share of income or loss from a partnership will constitute “net
earnings from self-employment” for these purposes. The ceiling for social security tax of 12.4% in
2007 is $97,500, which will be adjusted annually for inflation in 2008 and subsequent years. There
is no ceiling for Medicare tax of 2.9%. Self-employed individuals can deduct one-half of their
self-employment tax.
Farmouts
Under a farmout by a partnership, if a property interest, other than an interest in the drilling
unit assigned to the partnership well in question, is earned by the farmee (anyone other than the
partnership) from the farmor (the partnership) as a result of the farmee drilling or completing the
well, then the farmee must recognize income equal to the fair market value of the outside interest
earned, and the farmor must recognize gain or loss on a deemed sale equal to the difference between
the fair market value of the outside interest and the farmor’s tax basis in the outside interest.
Neither the farmor nor the farmee would have received any cash to pay the tax. The managing
general partner has represented that it will attempt to eliminate or reduce any gain to a
partnership from a farmout, if any. However, if the IRS claims that a farmout by a partnership
results in taxable income to the partnership and its position is ultimately sustained, you and the
other investors in that partnership would be required to include your share of the resulting
taxable income on your individual income tax returns, even though the partnership and you and the
other investors in that partnership received no cash from the farmout.
Foreign Partners
Each partnership will be required to withhold and pay income tax to the IRS at the highest rate
under the Code applicable to partnership income allocable to its foreign investors, even if no cash
distributions are made to them. In the event of overwithholding, a foreign investor must seek a
refund on his individual United States federal income tax return. For withholding purposes, a
foreign investor means an investor who is not a United States person and includes a nonresident
alien individual, a foreign corporation, a foreign partnership, and a foreign trust or estate,
unless the investor has certified to his partnership the investor’s status as a U.S. person on Form
W-9 or any other form permitted by the IRS for that purpose.
Foreign investors are urged to seek advice based on their particular circumstances from an
independent tax advisor regarding the applicability of these rules and the other tax consequences
of an investment in a partnership to them.
Estate and Gift Taxation
There is no federal tax on lifetime or testamentary transfers of property between spouses. The
gift tax annual exclusion amount was $12,000 per donee in 2007, which will be adjusted in 2008 and
subsequent years for inflation. Under the Economic Growth and Tax Relief Reconciliation Act of
2001 (the “2001 Tax Act”), the maximum estate and gift tax rate is 45% from 2007 through 2009.
Estates of $2.0 million or less in 2007, which increases to estates of $3.5 million or less in
2009, are not subject to federal estate tax to the extent those exemption amounts (i.e.,
unified credit amounts) were not previously used by the decedent to reduce gift taxes on any
lifetime gifts in excess of the applicable annual exclusion amount for gifts. Under the 2001 Tax
Act, the federal estate tax will be repealed in 2010, and the maximum gift tax rate in 2010 will be
35%. In 2011, however, the federal estate and gift taxes are scheduled to be reinstated under the
rules in effect before the 2001 Tax Act was enacted, which would, among other things, reduce the
unified credit amount and increase the tax rates.
Your tax benefits from an investment in a partnership may be affected by changes in the tax laws.
For example, in 2003 the top four federal income tax brackets for individuals were reduced through
December 31, 2010, including reducing the top bracket to 35% from 38.6%. The lower federal income
tax rates will reduce to some degree the amount of taxes you can save by virtue of your share of
your partnership’s deductions for intangible drilling costs, depletion and depreciation, and
marginal well production credits, if any. On the other hand, the lower federal income tax rates
also will reduce the amount of federal income tax liability incurred by you on your share of your
partnership’s net income. However, the federal income tax brackets discussed above could be
changed again, even before 2011, and other changes in the tax laws could be made which would affect
your tax benefits from an investment in a partnership.
You are urged to seek advice based on your particular circumstances from an independent tax advisor
with respect to the impact of recent federal tax legislation on an investment in a partnership and
the status of federal and state legislative, regulatory or administrative tax developments and tax
proposals and their potential effect on the tax consequences to you of an investment in a
partnership.
SUMMARY OF PARTNERSHIP AGREEMENT
The rights and obligations of the managing general partner and you and the other investors in
a partnership are governed by the form of partnership agreement, a copy of which attached as
Exhibit (A) to this prospectus. You are urged to thoroughly review the partnership agreement
before you decide to invest in a partnership. The following is a summary of the material
provisions in the partnership agreement that are not covered elsewhere in this prospectus. Thus,
this prospectus summarizes all of the material provisions of the partnership agreement.
Liability of Limited Partners
Each partnership will be governed by the Delaware Revised Uniform Limited Partnership Act. If you
invest as a limited partner, then generally you will not be liable to third-parties for the
obligations of your partnership unless you:
•
also invest as an investor general partner;
•
take part in the control of the partnership’s business in addition to the exercise
of your rights and powers as a limited partner; or
•
fail to make a required capital contribution to the extent of the required capital
contribution.
In addition, you may be required to return any distribution you receive from a partnership if you
knew at the time the distribution was made that it was improper because it rendered the partnership
insolvent.
Amendments
Amendments to the partnership agreement of a partnership may be proposed in writing by:
•
the managing general partner and adopted with the consent of investors whose units
equal a majority of the total units in the partnership; or
•
investors whose units equal 10% or more of the total units in the partnership and
adopted by an affirmative vote of investors whose units equal a majority of the total
units in the partnership.
The partnership agreement of each partnership may also be amended by the managing general partner
without the consent of the investors for certain limited purposes. However, an amendment that
materially and adversely affects the investors can only be made with the consent of the affected
investors. For example, an amendment may not increase the duties or liabilities of the investors,
decrease the duties or liabilities of the managing general partner, decrease the investors’ profit
sharing interest, or increase the investors’ loss sharing interest, increase the required capital
contribution of the investors or decrease the required capital contribution of the managing general
partner without the approval of the investors, and any amendment may not affect the classification
of partnership income and loss for federal income tax purposes without the unanimous approval of
all investors.
when the managing general partner gives you and other investors notice it begins to
run from the date of mailing the notice and is binding even if it is not received;
•
the notice periods are frequently quite short, a minimum of 22 calendar days, and
apply to matters that may seriously affect your rights; and
•
if you fail to respond in the specified time to the managing general partner’s
second request for approval of or concurrence in a proposed action, then you will
conclusively be deemed to have approved the action unless the partnership agreement
expressly requires your affirmative approval.
Voting Rights
Other than as set forth below, you generally will not be entitled to vote on any partnership
matters at any partnership meeting. At any time, however, investors whose units equal 10% or more
of the total units in a partnership may call a meeting to vote, or vote without a meeting, on the
matters set forth below without the concurrence of the managing general partner. On the matters
being voted on you are entitled to one vote per unit or if you own a fractional unit that fraction
of one vote equal to the fractional interest in the unit. Investors whose units equal a majority
of the total units in a partnership may vote to:
•
dissolve the partnership;
•
remove the managing general partner and elect a new managing general partner;
•
elect a new managing general partner if the managing general partner elects to
withdraw from the partnership;
•
remove the operator and elect a new operator;
•
approve or disapprove the sale of all or substantially all of the partnership’s assets;
•
cancel any contract for services with the managing general partner, the operator, or
their affiliates without penalty on 60 days notice; and
•
amend the partnership agreement, however, any amendment may not:
•
without the approval of you or the managing general partner increase the
duties or liabilities of you or the managing general partner, or increase or
decrease the profits or losses or required capital contribution of you or the
managing general partner; or
•
without the unanimous approval of all investors in the partnership, affect
the classification of partnership income and loss for federal income tax
purposes.
The managing general partner, its officers, directors, and affiliates may also subscribe for units
in each partnership on a discounted basis, and they may vote on all matters, including the issues
set forth above, other than:
•
removing the managing general partner and operator; and
•
any transaction between the managing general partner or its affiliates and the partnership.
Any units owned by the managing general partner and its affiliates will not be included in
determining the requisite number of units necessary to approve any partnership matter on which the
managing general partner and its affiliates may not vote or consent.
You will have access to all records of your partnership at any reasonable time on adequate notice.
However, logs, well reports, and other drilling and operating data may be kept confidential for
reasonable periods of time. Also, your ability to obtain the list of investors is subject to
additional requirements set forth in the partnership agreement.
Withdrawal of Managing General Partner
After 10 years the managing general partner may voluntarily withdraw as managing general partner of
a partnership for any reason by giving 120 days’ written notice to you and the other investors in
the partnership. Although the withdrawing managing general partner is not required to provide a
substitute managing general partner, a new managing general partner may be substituted by the
affirmative vote of investors whose units equal a majority of the total units in the partnership.
If the investors, however, choose not to continue the partnership and do not select a substitute
managing general partner, then the partnership would dissolve and terminate, which could result in
adverse tax and other consequences to you.
Also, the managing general partner may assign its general partner interest in the partnership to
its affiliates, and it may withdraw a property interest in the form of a working interest in the
partnership’s wells equal to or less than its revenue interest at any time if the withdrawal is:
•
to satisfy the bona fide request of its creditors; or
•
approved by investors in the partnership whose units equal a majority of the total units.
(See “Management – Managing General Partner and Operator” and “Conflicts of Interest – Conflicts
Regarding the Managing General Partner Withdrawing or Assigning an Interest.”
Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months
Although the managing general partner anticipates that each partnership will spend all of its
subscription proceeds soon after the offering of the partnership closes, each partnership will have
12 months in which to use or commit its subscription proceeds to drilling activities. If within
the 12-month period the partnership has not used, or committed for use, all of its subscription
proceeds, then the managing general partner will distribute the remaining subscription proceeds to
you and the other investors in the partnership in accordance with your respective subscription
amounts as a return of capital.
SUMMARY OF DRILLING AND OPERATING AGREEMENT
The managing general partner will serve as the operator under the drilling and operating
agreement, Exhibit (II) to the partnership agreement. The operator may be replaced at any time on
60 days’ advance written notice by the managing general partner acting on behalf of a partnership
on the affirmative vote of investors whose units equal a majority of the total units in the
partnership. You are urged to thoroughly review the drilling and operating agreement before you
decide to invest in a partnership. The following is a summary of the material provisions of the
drilling and operating agreement that are not covered elsewhere in this prospectus. Thus, this
prospectus summarizes all of the material provisions of the drilling and operating agreement.
The drilling and operating agreement includes the material provisions set forth below.
•
The operator’s right to resign after five years.
•
The operator’s right beginning one year after a partnership well begins producing to
retain $200 per month to cover future plugging and abandonment costs of the well.
•
The grant of a first lien and security interest in the wells and related production
to secure payment of amounts due to the operator by a partnership.
•
The prescribed insurance coverage to be maintained by the operator.
Limitations on the operator’s authority to incur extraordinary costs with respect to
producing wells in excess of $5,000 per well.
•
Restrictions on the partnership’s ability to transfer its interest in fewer than all
wells unless the transfer is of an equal undivided interest in all of the wells.
•
The limitation of the operator’s liability to a partnership under section 4.05 of
partnership agreement, which provides that the operator will not have any liability for
any loss suffered by the partnership or the participants which arises out of any action
or inaction of the operator if the operator determined in good faith that the course of
conduct was in the best interest of the partnership, the operator was performing
services for the partnership and the operator’s course of conduct did not constitute
negligence or misconduct.
•
The excuse for nonperformance by the operator due to force majeure which generally
means acts of God, catastrophes and other causes which preclude the operator’s
performance and are beyond its control.
REPORTS TO INVESTORS
Under the partnership agreement for each partnership you and certain state securities
commissions will be provided the reports and information set forth below for your partnership,
which your partnership will pay as a direct cost.
•
Beginning with the calendar year in which your partnership closes, you will be
provided an annual report within 120 days after the close of the calendar year, and
beginning with the following calendar year, a report within 75 days after the end of
the first six months of its calendar year, containing at least the following
information.
•
Audited financial statements of the partnership prepared on an accrual basis
in accordance with generally accepted accounting principles with a
reconciliation for information furnished for income tax purposes. Independent
certified public accountants will audit the financial statements to be included
in the annual report, but semiannual reports will not be audited.
•
A summary of the total fees and compensation paid by the partnership to the
managing general partner, the operator, and their affiliates. In this regard,
the independent certified public accountant will provide written attestation
annually, which will be included in the annual report, that the method used to
make allocations was consistent with the method described in §4.04(a)(2)(c) of
the partnership agreement and that the total amount of costs allocated did not
materially exceed the amounts actually incurred by the managing general partner.
If the managing general partner subsequently decides to allocate expenses in a
manner different from that described in §4.04(a)(2)(c) of the partnership
agreement, then the change must be reported to you and the other investors
with an explanation of the reason for the change and the basis used for
determining the reasonableness of the new allocation method.
•
A description of each prospect owned by the partnership, including the cost,
location, number of acres, and the interest.
•
A list of the wells drilled or abandoned by the partnership indicating:
•
whether each of the wells has or has not been completed; and
•
a statement of the cost of each well completed or abandoned.
•
A description of all farmouts, farmins, and joint ventures.
the costs paid by the managing general partner and the costs paid by the investors;
•
the total partnership revenues; and
•
the revenues received or credited to the managing general partner and
the revenues received or credited to you and the other investors.
•
On request the managing general partner will provide you the information specified
by Form 10-Q (if that report is required to be filed with the SEC) within 45 days after
the close of each quarterly fiscal period. Also, this information is available at the
SEC website www.sec.gov.
•
By March 15 of each year you will receive the information that is required for you
to file your federal and state income tax returns.
•
Beginning with the second calendar year after your partnership closes, and every
year thereafter, you will receive a computation of the partnership’s total natural gas
and oil proved reserves and its dollar value. The reserve computations will be based
on engineering reports prepared by the managing general partner and reviewed by an
independent expert.
PRESENTMENT FEATURE
Beginning with the fifth calendar year after your partnership closes, you and the other
investors in your partnership may present your units to the managing general partner to purchase
your units. However, you are not required to offer your units to the managing general partner, and
you may receive a greater return if you retain your units. The managing general partner will not
purchase less than one unit unless the fractional unit represents your entire interest in the
partnership.
The managing general partner has no obligation or intention to establish a reserve to satisfy the
presentment feature and it may immediately suspend the presentment obligation by notice to you if
it determines, in its sole discretion, that it:
•
does not have the necessary cash flow; or
•
cannot borrow funds for this purpose on terms it deems reasonable.
If fewer than all units presented at any time are to be purchased by the managing general partner,
then the units to be purchased will be selected by lot.
The managing general partner’s obligation to purchase the units presented may be discharged for its
benefit by a third-party or an affiliate. If you sell your unit it will be transferred to the
party who pays for it, and you will be required to deliver an executed assignment of your unit
along with any other documents that the managing general partner requests. Your presentment of
your units to the managing general partner for purchase is subject to the following conditions:
•
the managing general partner will not purchase more than 5% of the total outstanding
units in a partnership in any calendar year;
•
your presentment request must be made within 120 days of the partnership reserve
report discussed below;
•
in accordance with Treas. Reg. §1.7704-1(f) the managing general partner may not
purchase your units until at least 60 calendar days after you notify the partnership in
writing of your intent to present your units for purchase; and
the purchase of your units will not be considered effective until the presentment
price has been paid to you in cash.
The amount of the presentment price for your units that is attributable to a partnership’s natural
gas and oil reserves, as discussed below, will be determined based on the last reserve report
prepared by the managing general partner and reviewed by an independent expert. Beginning with the
second calendar year after your partnership closes and every year thereafter, the managing general
partner will estimate the present worth of future net revenues attributable to your partnership’s
interest in proved reserves. In making this estimate, the managing general partner will use:
•
a 10% discount rate;
•
a constant oil price; and
•
base natural gas prices on the existing natural gas contracts at the time of the presentment.
Your presentment price will be based on your share of your partnership’s net assets and liabilities
as described below, based on the ratio that your number of units bears to the total number of units
in your partnership. The presentment price will include the sum of the following partnership
items:
•
an amount based on 70% of the present worth of future net revenues from the proved
reserves determined as described above;
•
cash on hand;
•
prepaid expenses and accounts receivable, less a reasonable amount for doubtful accounts; and
•
the estimated market value of all assets not separately specified above, determined
in accordance with standard industry valuation procedures.
There will be deducted from the foregoing sum the following partnership items:
•
an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and
•
any distributions made to you between the date of your presentment request and the
date the presentment price is paid to you. However, if any cash distributed to you by
the partnership, after your presentment request was derived from the sale of oil,
natural gas, or a producing property the amount of those cash distributions will be
discounted at the same rate used to take into account the risk factors employed to
determine the present worth of the partnership’s proved reserves for purposes of
determining the reduction of the presentment price.
The presentment price may be further adjusted by the managing general partner for estimated changes
from the date of the reserve report discussed above to the date of payment of the presentment price
to you due to the following:
•
the production or sales of, or additions to, reserves and lease and well equipment,
sale or abandonment of leases, and similar matters occurring before the presentment
request; and
•
any of the following occurring before payment of the presentment price to you;
•
changes in well performance;
•
increases or decreases in the market price of oil, natural gas, or other minerals;
•
revision of regulations relating to the importing of hydrocarbons; and
changes in income, ad valorem, and other tax laws such as material variations
in the provisions for depletion; and
•
similar matters.
As of September 15 2006, approximately 230 units have been presented to the managing general
partner for purchase in its previous 53 limited partnerships.
TRANSFERABILITY OF UNITS
Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership
Agreement
Your ability to sell or otherwise transfer your units in your partnership is restricted by the
securities laws, the tax laws, and the partnership agreement as described below. Also, the sale or
other transfer of your units may create negative tax consequences to you as described in “Federal
Income Tax Consequences – Disposition of Units.”
First, due to the tax laws, the partnership agreement provides that you will not be able to sell,
assign, exchange, or transfer your unit if it would, in the opinion of counsel for the partnership,
result in the following:
•
the termination of your partnership for tax purposes; or
•
your partnership being treated as a “publicly traded” partnership for tax purposes.
Second, under the partnership agreement sales or other transfers of the units are subject to the
following additional limitations:
•
except as provided by operation of law, the partnership will recognize the transfer
of only one or more whole units unless you own less than a whole unit, in which case
your entire fractional interest must be transferred;
•
the costs and expenses associated with the transfer must be paid by the person transferring the unit;
•
the form of transfer must be in a form satisfactory to the managing general partner; and
•
the terms of the transfer must not contravene those of the partnership agreement.
Your transfer of a unit will not:
•
relieve you of your responsibility for any obligations related to your units under
the partnership agreement;
•
grant rights under the partnership agreement as among your transferees, to more than
one party unanimously designated by the transferees to the managing general partner;
nor
•
require an accounting of the partnership by the managing general partner.
If the assignee of the unit does not become a substituted partner as described below in “–
Conditions to Becoming a Substitute Partner,” the transfer will be effective as of midnight of the
last day of the calendar month in which it is made or, at the managing general partner’s election,
7:00 A.M. of the following day.
Finally, you will not be able to sell, assign, pledge, hypothecate, or transfer your unit if the
managing general partner requires, in its sole discretion, that you must provide an opinion of
counsel acceptable to the managing general partner that the registration and qualification under
any applicable federal or state securities laws are not required.
An assignee of a unit will not be entitled to any of the rights granted to a partner under the
partnership agreement, other than the right to receive all or part of the share of the profits,
losses, income, gain, credits and cash distributions or returns of
capital to which his assignor would otherwise be entitled, unless the assignee becomes a
substituted partner in accordance with the provisions set forth below. The conditions to become a
substitute partner are as follows:
•
the assignor gives the assignee the right;
•
the assignee pays all costs and expenses incurred in connection with the substitution; and
•
the assignee executes and delivers, in a form acceptable to the managing general
partner, the instruments necessary to establish that a legal transfer has taken place
and to confirm his agreement to be bound by all of the terms and provisions of the
partnership agreement.
A substitute partner is entitled to all of the rights of full ownership of the assigned units,
including the right to vote. Each partnership will amend its records at least once each calendar
quarter to effect the substitution of substituted partners.
PLAN OF DISTRIBUTION
Commissions
The units in each partnership will be offered on a “best efforts” basis by Anthem Securities, which
is an affiliate of the managing general partner, acting as dealer-manager and by other selected
registered broker/dealers that are members of the NASD acting as selling agents. Anthem Securities
was formed for the purpose of serving as dealer-manager of partnerships sponsored by the managing
general partner and became an NASD member firm in April, 1997.
The dealer-manager will manage and oversee the offering of the units as described above. Best
efforts generally means that the dealer-manager and selling agents will not guarantee that a
certain number of units will be sold. Units may also be sold by the officers and directors of the
managing general partner, other than those individuals who are associated persons of Anthem
Securities, in those states where they are licensed to do so or are exempt from licensing. All
offers and sales of units by the managing general partner’s officers and directors who are not
associated persons of Anthem Securities will be made under the SEC safe harbor from broker/dealer
registration provided by Rule 3a4-1. In this regard, none of the officers and directors of the
managing general partner who may offer and sell units:
•
is subject to a statutory disqualification, as that term is defined in Section
3(a)(39) of the Act, at the time of his participation;
•
is compensated in connection with his participation by the payment of commissions or
other remuneration based either directly or indirectly on transactions in securities;
and
•
is at the time of his participation an associated person of a broker or dealer.
Also, each of the officers and directors who may offer and sell units:
•
performs, or is intended primarily to perform at the end of the offering,
substantial duties for or on behalf of the managing general partner otherwise than in
connection with transactions in securities;
•
was not a broker or dealer, or an associated person of a broker or dealer, within
the preceding 12 months; and
•
will not participate in selling an offering of securities for any issuer more than
once every 12 months, with the understanding that for securities issued pursuant to
Rule 415 under Securities Act of 1933, the 12 month period begins with the last sale of
any security included within one Rule 415 registration.
Subject to the exceptions described below, the dealer-manager will receive on each unit sold:
•
a 2.5% dealer-manager fee;
•
a 7% sales commission; and
•
an up to .5% reimbursement of the selling agent’s bona fide due diligence expenses.
All of the reimbursement of the selling agents’ bona fide due diligence expenses and generally all
of the 7% sales commission will be reallowed by the dealer-manager to the selling agents. With
respect to the up to .5% reimbursement of a selling agent’s bona fide due diligence expenses, any
bill presented by a selling agent to the dealer-manager for reimbursement of costs associated with
its due diligence activities must be for actual costs, including overhead, incurred by the selling
agent and may not include a profit margin. It is the responsibility of the managing general
partner and the dealer-manager to ensure compliance with the above guideline. If the selling agent
provides the dealer-manager an itemized bill for actual due diligence expenses which is in excess
of .5%, then the excess over .5% will not be included within the 10% compensation guideline, but
instead will be included within the 4.5% organization and offering cost guideline under NASD
Conduct Rule 2810.
From the 2.5% dealer-manager fee, the dealer-manager may pay up to a .5% marketing fee if the
selling agent provides marketing support. Additionally, the Dealer-Manager may use a portion of
its Dealer-Manager fee to pay for permissible non-cash compensation. Under Rule 2810 of the NASD
Conduct Rules, non-cash compensation means any form of compensation received in connection with the
sale of the units that is not cash compensation, including but not limited to merchandise, gifts
and prizes, travel expenses, meals and lodging. Permissible non-cash compensation includes the
following:
•
an accountable reimbursement for training and education meetings for associated
persons of the selling agents;
•
gifts that do not exceed $100 per year and are not preconditioned on achievement of
a sales target;
•
an occasional meal, a ticket to a sporting event or the theater, or comparable
entertainment which is neither so frequent nor so extensive as to raise any question of
propriety and is not preconditioned on achievement of a sales target; and
•
contributions to a non-cash compensation arrangement between a selling agent and its
associated persons, provided that neither the managing general partner nor the
dealer-manager directly or indirectly participates in the selling agent’s organization
of a permissible non-cash compensation arrangement.
In no event shall a selling agent receive non-cash compensation and the marketing fee if it
represents more than .5% per unit.
The managing general partner is also using the services of wholesalers who are employed by it or
its affiliates and are registered through Anthem Securities. The wholesalers include four Regional
Marketing Directors. A portion of the 2.5% dealer-manager fee will be reallowed to the affiliated
wholesalers for subscriptions obtained through their efforts and their reimbursement of expenses.
The dealer-manager will retain the remainder of the dealer-manager fee not reallowed to the
wholesalers or as described in the prior paragraph.
The offering will be made in compliance with Rule 2810 of the NASD Conduct Rules and all
compensation, including non-cash compensation, to broker/dealers and wholesalers, regardless of the
source, will be limited to 10% of the gross proceeds of the offering plus the .5% reimbursement for
bona fide due diligence expenses on each subscription. Also, the offering will be made in
compliance with Rule 2810(b)(2)(C) of the NASD Conduct Rules and the broker/dealers and wholesalers
will not execute a transaction for the purchase of units in a discretionary account without the
prior written approval of the transaction by the customer. Finally, the offering will be conducted
in compliance with SEC Rule 15c2-4.
Subject to the following, you and the other investors will pay $10,000 per unit and generally will
share costs, revenues, and distributions in the partnership in which you invest in proportion to
your respective number of units. However, the subscription price for certain investors will be
reduced as set forth below:
•
the subscription price for the managing general partner, its officers, directors,
and affiliates, and investors who buy units through the officers and directors of the
managing general partner, will be reduced by an amount equal to the 2.5% dealer-manager
fee, the 7% sales commission and the .5% reimbursement for bona fide due diligence
expenses, which will not be paid with respect to these sales; and
•
the subscription price for registered investment advisors and their clients, and
selling agents and their registered representatives and principals, will be reduced by
an amount equal to the 7% sales commission, which will not be paid with respect to
these sales.
No more than 5% of the total units in each partnership may be sold with the discounts described
above. These investors who pay a reduced price for their units generally will share in a
partnership’s costs, revenues, and distributions on the same basis as the other investors who pay
$10,000 per unit as discussed in “Participation in Costs and Revenues – Allocation and Adjustments
Among Investors.” Although the managing general partner and its affiliates may buy up to 5% of the
units, they do not currently anticipate buying any units. If they do buy units, then those units
will not be applied towards the minimum subscription proceeds required for a partnership to begin
operations.
To help assure an orderly market for the units, the managing general partner, the dealer-manager
and the selling agents may use such methods as they deem appropriate to allocate units among
interested investors if they anticipate that demand for units will exceed the available supply,
provided that no changes to compensation may be made. These methods may include, but will not be
limited to:
•
allocations of units to selling agents;
•
priority acceptance of subscriptions from previous investors in partnerships
sponsored by the managing general partner;
•
priority treatment for investors whose subscriptions were declined by earlier
partnerships sponsored by the managing general partner because the number of units
available was not sufficient to accommodate their subscriptions; or
•
any other methods as may be approved by the managing general partner.
After the minimum subscription proceeds are received in a partnership and the checks have cleared
the banking system, the dealer-manager fee and the sales commissions will be paid to the
dealer-manager and selling agents approximately every two weeks until the offering closes.
Indemnification
The dealer-manager is an underwriter as that term is defined in the 1933 Act and the sales
commissions and dealer-manager fees will be deemed underwriting compensation. The managing general
partner and the dealer-manager have agreed to indemnify each other, and it is anticipated that the
dealer-manager and each selling agent will agree to indemnify each other against certain
liabilities, including liabilities under the 1933 Act.
SALES MATERIAL
In addition to the prospectus, the managing general partner intends to use the following sales
material with the offering of the units:
•
a flyer entitled “Atlas Resources Public #16-2007 Program”;
•
an article entitled “Tax Rewards with Oil and Gas Partnerships”;
a brochure of tax scenarios entitled “How an Investment in Atlas Resources Public
#16-2007 Program Can Help Achieve an Investor’s Tax Objectives”;
•
a booklet entitled “Outline of Tax Consequences of Oil and Gas Drilling Programs”;
•
a brochure entitled “Investment Insights – Tax Time”;
•
a brochure entitled “Frequently Asked Questions”;
•
a brochure entitled “The Drilling Process”; and
•
possibly other supplementary materials.
The managing general partner has not authorized the use of other sales material and the offering of
units is made only by means of this prospectus. The sales material is subject to the following
considerations:
•
it must be preceded or accompanied by this prospectus;
•
it is not complete;
•
it does not contain any information which is inconsistent with this prospectus; and
•
it should not be considered a part of or incorporated into this prospectus or the
registration statement of which this prospectus is a part.
In addition, supplementary materials, including prepared presentations for group meetings, must be
submitted to the state administrators before they are used and their use must either be preceded by
or accompanied by a prospectus. Also, all advertisements of, and oral or written invitations to,
“seminars” or other group meetings at which the units are to be described, offered, or sold will
clearly indicate the following:
•
that the purpose of the meeting is to offer the units for sale;
•
the minimum purchase price of the units;
•
the suitability standards to be employed; and
•
the name of the person selling the units.
Also, no cash, merchandise, or other items of value may be offered as an inducement to you or any
other prospective investor to attend the meeting. All written or prepared audiovisual
presentations, including scripts prepared in advance for oral presentations to be made at the
meetings, must be submitted to the state administrators within a prescribed review period. These
provisions, however, will not apply to meetings consisting only of the registered representatives
of the selling agents.
You should rely only on the information contained in this prospectus in making your investment
decision. No one is authorized to provide you with information that is different.
LEGAL OPINIONS
Kunzman & Bollinger, Inc., has issued its opinion to the managing general partner regarding
the validity and due issuance of the units, including assessibility, and its opinion on the
material and any significant federal tax issues involving individual typical investors in the
partnerships. However, the factual statements in this prospectus are those of the partnerships or
the managing general partner, and counsel has not given any opinions with respect to any of the tax
or other legal aspects of this offering except as expressly set forth above.
The financial statements included in this prospectus for Atlas Resources, LLC, the managing
general partner, as of and for the years ended September 30, 2005 and 2004 and the balance sheet
for Atlas Resources Public #16-2007(A) L.P. have been audited by Grant Thornton LLP, as of the
dates indicated in its reports which appear elsewhere in this prospectus. These financial
statements have been included in this prospectus in reliance on the reports of Grant Thornton LLP
on the authority of that firm as an expert in accounting and auditing.
The information concerning the estimated future net cash flows from proved reserves presented under
“Prior Activities – Table 3 Investor Operating Results-Including Expenses” was prepared by Wright &
Company, Inc., Brentwood, Tennessee, independent petroleum consultants, which is not affiliated
with the managing general partner or its affiliates, and is included in this prospectus in reliance
on Wright & Company, Inc. as an expert in petroleum consulting.
The geologic evaluations of United Energy Development Consultants, Inc., which is not affiliated
with the managing general partner or its affiliates, appearing elsewhere in this prospectus have
been included in this prospectus on the authority of United Energy Development Consultants, Inc. as
an expert with respect to the matters covered by the evaluations and in the giving of the
evaluations.
LITIGATION
The managing general partner knows of no litigation pending or threatened to which the
managing general partner or the partnerships are subject or may be a party, which it believes would
have a material adverse effect on the partnerships or their business, and no such proceedings are
known to be contemplated by governmental authorities or other parties.
FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS RESOURCES PUBLIC
#16-2007(A) L.P.
Financial information concerning the managing general partner and the second partnership in
the program, Atlas Resources Public #16-2007(A) L.P., is reflected in the following financial
statements. With respect to the managing general partner’s financial information, the managing
general partner was changed from a corporation to a limited liability company in March, 2006. (See
“Management – Managing General Partner and Operator.”)
The securities offered by this prospectus are not securities of, nor are you acquiring an interest
in the managing general partner, its affiliates, or any other entity other than the partnership in
which you purchase units.
INDEX TO FINANCIAL STATEMENTS
ATLAS RESOURCES PUBLIC #16-2007(A) L.P. FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners Atlas Resources Public 16-2007 (A) L.P.
(A Delaware Limited Partnership)
We have audited the accompanying balance sheet of Atlas Resources Public 16-2007 (A) L.P. (A
Delaware Limited Partnership) formerly known as (“Atlas America
Public #16-2007 (A) L.P.”) as of
September 30, 2006. This financial statement is the responsibility of the Partnership’s
management. Our responsibility is to express an opinion on this financial statement based on our
audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. The
Partnership is not required to have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the
Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.
An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements, assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe
that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statement referred to above presents fairly, in all material
respects, the financial position of Atlas Resources Public 16-2007 (A) L.P. as of September 30,2006, in conformity with accounting principles generally accepted in the United States of America.
Atlas Resources Public 16-2007 (A) L.P. (the “Partnership”) is a Delaware limited
partnership in which Atlas Resources, LLC (“Atlas Resources”) of Pittsburgh, Pennsylvania
(a second-tier wholly-owned subsidiary of Atlas America, Inc., a publicly traded
company), will be Managing General Partner and Operator, and subscribers to units will be
either Limited Partners or Investor General Partners depending upon their individual
elections.
The Partnership will be funded to drill development wells which are proposed to be
located primarily in the Appalachian Basin located in western Pennsylvania, eastern and
southern Ohio, western New York and north central Tennessee.
Subscriptions at a cost of $10,000 per unit, subject to discounts for certain investors,
generally will be sold using wholesalers and through broker-dealers including Anthem
Securities, Inc., an affiliated company, which will receive on each unit sold to an
investor, a 2.5% dealer-manager fee, a 7% sales commission and up to a .5% reimbursement
of the selling agents’ bona fide due diligence expenses. Commencement of Partnership
operations is subject to the receipt of minimum Partnership subscriptions of $2,000,000
(up to a maximum of $200,000,000) by December 31, 2007.
2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Accounting
The Partnership prepares its financial statements in accordance with accounting
principles generally accepted in the United States of America.
Oil and Gas Properties
The Partnership will use the successful efforts method of accounting for oil and gas
producing activities. Costs to acquire mineral interests in oil and gas properties and
to drill and equip wells will be capitalized. Depreciation and depletion will be
computed on a field-by field basis by the unit-of-production method based on periodic
estimates of oil and gas reserves. Undeveloped leaseholds and proved properties will be
assessed periodically or whenever events or circumstances indicate that the carrying
amount of these assets may not be recoverable. Proved properties will be assessed based
on estimates of future cash flows.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Use of Estimates
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make estimates
and assumptions that affect the amounts reported in the financial statements and
accompanying notes. Actual results could differ from those estimates.
3.
FEDERAL INCOME TAXES
The Partnership will not be treated as a taxable entity for federal income tax purposes.
Any item of income, gain, loss, deduction or credit would flow through to the partners as
though each partner has incurred such item directly. As a result, each partner must take
into account his or her pro-rata share under the partnership agreement of all items of
Partnership income and deductions in computing his or her federal income tax liability.
4.
PARTICIPATION IN REVENUES AND COSTS
The Managing General Partner and the investor partners will participate in revenues and
costs in the following manner:
Managing
General
Investor
Partner
Partners
Partnership Costs
Organization and offering costs
100
%
0
%
Lease costs
100
%
0
%
Intangible drilling costs (1)
0
%
100
%
Equipment costs
(2
)
(2
)
Operating costs, administrative costs, direct costs, and all other costs
An amount equal to 90% of the subscription proceeds of investor partners in the
partnership will be used to pay 100% of the intangible drilling costs incurred by the
partnership in drilling and completing its wells.
(2)
An amount equal to 10% of the subscription proceeds of investor partners in the
partnership will be used to pay a portion of the equipment costs incurred by the
partnership in drilling and completing its wells. All equipment costs in excess of that
amount will be charged to the Managing General Partner. Equipment proceeds, if any,
will be credited in the same percentage in which the equipment costs were charged.
(3)
These costs will be charged to the parties in the same ratio as the related
production revenues are being credited. These costs also include plugging and
abandonment costs of the wells after the wells have been drilled and produced.
(4)
Interest earned on subscription proceeds before the final closing of the
partnership will be credited to investor partners’ accounts and paid not later than the
partnerships first cash distribution from operations. After the final closing of the
partnership and until the subscription proceeds are invested in the partnership’s
natural gas and oil operations any interest income from temporary investments will be
allocated pro rata to the investor partners providing the subscription proceeds. All
other interest income, including interest earned on the deposit of operating revenues,
will be credited as natural gas and oil production revenues are credited.
(5)
The managing general partner and the investor partners in the partnership will
share in all of the partnership’s other revenues in the same percentage as their
respective capital contributions bear to the total partnership capital contributions
except that the managing general partner will receive an additional 7% of the
partnership revenues. However, the managing general partner’s total revenue share may
not exceed 40% of partnership revenues.
The partnership will enter into a drilling and operating agreement with Atlas
Resources to drill and complete all of the partnership wells for an amount equal to
the sum of the following items (i) the cost of permits, supplies, materials,
equipment, and all other items used in the drilling and completion of a well provided
by third-parties, or if the foregoing items are provided by affiliates of the managing
general partner, then those items will be charged at competitive rates; (ii) fees for
third-party services; (iii) fees for services provided by the managing general
partner’s affiliates, which will be charged at competitive rates; (iv) an
administration and oversight fee of $15,000 per well, which will be charged to the
investors as part of each well’s intangible drilling costs and the portion of
equipment costs paid by the investors; and (v) a mark-up in an amount equal to 15% of
the sum of (i), (ii), (iii) and (iv), above, for the managing general partner’s
services as general drilling contractor. This will be proportionately reduced if the
partnership’s working interest in a well is less than 100%.
The actual allocation of partnership revenues between the managing general
partner and the investor partners will vary from the allocation described in (5) above
if a portion of the managing general partner’s partnership net production revenues is
subordinated as described in note 7.
5.
TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES
The Partnership intends to enter into the following significant transactions with Atlas
Resources and its affiliates as provider under the Partnership agreement:
The partnership will enter into a drilling and operating agreement with Atlas Resources to
drill and complete all of the partnership wells for an amount equal to the sum of the
following items (i) the cost of permits, supplies, materials, equipment, and all other items
used in the drilling and completion of a well provided by third-parties, or if the foregoing
items are provided by affiliates of the managing general partner, then those items will be
charged at competitive rates; (ii) fees for third-party services; (iii) fees for services
provided by the managing general partner’s affiliates, which will be charged at competitive
rates; (iv) an administration and oversight fee of $15,000 per well, which will be charged to
the investors as part of each well’s intangible drilling costs and the portion of equipment
costs paid by the investors; and (v) a mark-up in an amount equal to 15% of the sum of (i),
(ii), (iii) and (iv), above, for the managing general partner’s services as general drilling
contractor. This will be proportionately reduced if the partnership’s working interest in a
well is less than 100%. The cost of the wells will include all ordinary and actual costs of
drilling, testing and completing the wells.
Atlas Resources will receive an unaccountable, fixed payment reimbursement for its
administrative costs at $75 per well per month, which will be proportionately reduced if the
partnership’s working interest in a well is less than 100%.
Atlas Resources will receive well supervision fees for operating and maintaining the wells
during producing operations at a competitive rate (currently the competitive rate is $362 per
well per month in the primary and secondary drilling areas). The well supervision fees will
be proportionately reduced if the partnership’s working interest in a well is less than 100%.
Atlas Resources will charge the partnership a fee for gathering and transportation at a
competitive rate (currently 10% of the natural gas price).
Atlas Resources will contribute all the undeveloped leases necessary to cover each of the
partnership’s prospects and will receive a credit for its capital account in the partnership
equal to the cost of the leases (approximately $11,310 per prospect which will be
proportionately reduced if the Partnership’s working interest is the prospect is less than
100%).
TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES (continued)
As the Managing General Partner, Atlas Resources will perform all administrative and
management functions for the partnership including billing and collecting revenues and paying
expenses. Atlas Resources will be reimbursed for all direct costs expended on behalf of the
partnership.
6.
PURCHASE COMMITMENT
Subject to certain conditions, investor partners may present their interests after five years
from the partnership’s first cash distribution from operations for purchase by the Managing
General Partner. The Managing General Partner is not obligated to purchase more than 5% of
the units in any calendar year. In the event that the Managing General Partner is unable to
obtain the necessary funds, the Managing General Partner may suspend its purchase obligation.
7.
SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER’S NET PRODUCER REVENUE SHARE
The Managing General Partner will subordinate up to 50% of its share of production revenues
of the Partnership, net of related operating costs, direct costs, administrative costs, and
all other costs not specifically allocated, to the receipt by the investor partners of cash
distributions from the Partnership equal to at least 10% per unit, based on $10,000 per unit
regardless of the actual price paid, determined on a cumulative basis, in each of the first
five 12-month periods beginning with the Partnership’s first cash distribution from
operations.
8.
INDEMNIFICATION
In order to limit the potential liability of the investor general partners for partnership
liabilities and obligations, Atlas Resources has agreed to indemnify each investor general
partner from any liability incurred which exceeds such partner’s share of undistributed
Partnership net assets and insurance proceeds.
Report of Independent Registered Public Accounting Firm
Board of Directors ATLAS RESOURCES, LLC
We have audited the accompanying consolidated balance sheets of Atlas Resources,
LLC (a Pennsylvania corporation) and subsidiaries (formerly “Atlas Resources,
Inc.”) as of December 31, 2006 and 2005 and the related consolidated statements of
income, changes in member’s equity, cash flows and comprehensive income for the
year ended December 31, 2006, the three month period ended December 31, 2005 and
for each of the years in the periods ended September 30, 2005 and 2004. These
financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform an audit of its internal control over
financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are appropriate
in the circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the Company’s internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Atlas Resources, LLC and
subsidiaries as of December 31, 2006 and 2005, and the consolidated results of
their operations and their cash flows for the year ended December 31, 2006, the
three month period ended December 31, 2005 and for each of the years in the
periods ended September 30, 2005 and 2004, in conformity with accounting
principles generally accepted in the United States of America.
ATLAS RESOURCES, LLC
CONSOLIDATED NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2006
NOTE 1 — NATURE OF OPERATIONS
Atlas Resources, LLC, (“the Company”), a Pennsylvania limited liability company, is a
wholly-owned subsidiary of Atlas Energy Resources, LLC (NYSE: ATN), (the “Parent” or “Atlas
Energy”). The Company is engaged in the exploration, development and production of natural gas
and oil primarily in the Appalachian Basin area. In addition, the Company performs contract
drilling and well operation services. The Company’s operations are dependent upon the resources
and services provided by Atlas Energy. Atlas Energy conducts its operations through Atlas Energy
Operating LLC, its wholly owned subsidiary. The Company finances a substantial portion of its
drilling activities through drilling partnerships it sponsors. The
Company typically is the
managing general partner and has a material interest in these partnerships.
Atlas America, Inc., (“Atlas,” NASDAQ: ATLS), in anticipation of an initial public offering of
Atlas Energy, formed the Company on March 24, 2006 and Atlas Resources, Inc. was merged into it.
The assets and liabilities of Atlas Resources, Inc. were transferred into Atlas Resources, LLC
without any changes to their cost bases. The shareholder’s equity from Atlas Resources, Inc. was
transferred to member’s equity in Atlas Resources LLC to reflect the entity’s change from a
corporation to a limited liability company. The results of operations up through March 23, 2006
are from Atlas Resources, Inc. before it was merged into a non-taxable entity. Deferred tax assets
and liabilities were eliminated upon the merger since the Company is a non-taxable entity. On the
effective date of the merger, the Company became a single member LLC and each share of Atlas
Resources, Inc. was cancelled.
Public Offering of Atlas Energy Resources, LLC
In December 2006, Atlas contributed substantially all of its natural gas and oil assets and
its investment partnership management business to Atlas Energy, a then wholly-owned subsidiary.
Concurrent with this transaction, Atlas Energy issued 7,273,750 common units, representing a 19.4%
ownership interest, in an initial public offering at a price of $21.00 per unit. The net proceeds
of approximately $139.9 million after underwriting discounts and commissions were distributed to
Atlas in the form of a nontaxable dividend and repayment of debt.
Change in Fiscal Year End
On June 15, 2006, Atlas America’s Board of Directors approved the change of its and its
subsidiaries (including the Company’s) fiscal year end to December 31 from September
30. Accordingly, these financial statements reflect the Company’s new year end of December 31 and
for the year ended December 31, 2006. Additionally, financial statements for the three-months
ended December 31, 2005, and the years ended September 30, 2005 and 2004 are presented.
Spin-off of Atlas from Resource America, Inc.
On June 30, 2005, Resource America, Inc. (“RAI”) Atlas Resources Inc.’s former indirect Parent
distributed its remaining 10.7 million shares of Atlas to its stockholders in the form of a
tax-free dividend. Although the distribution itself is tax-free to RAI stockholders, as a result
of the deconsolidation there may be some tax liability arising from prior unrelated corporate
transactions between Atlas and some of its subsidiaries. The Company does not anticipate that
there will be direct material impact on its financial position or results of operations resulting
from the settlement, if any, of those potential tax liabilities. Since June 30, 2005, Atlas (and
the Company) is no longer included within RAI’s consolidated tax return.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned
subsidiary. The Company also owns individual interests in the assets, and is separately liable for
its share of the liabilities of energy partnerships, whose activities include only exploration and
production activities. In accordance with established practice in the oil and gas industry, the
Company includes in its consolidated financial statements its pro-rata share of assets,
liabilities, income and costs and expenses of the energy partnerships in which it has an interest.
All material intercompany transactions have been eliminated.
Use of Estimates
Preparation of the financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the financial statements and the reported amounts of revenues, costs
and expenses during the reporting period. Actual results could differ from these estimates.
Reclassification
Certain reclassifications have been made to the fiscal 2004, 2005 and the three months ended
December 31, 2005 consolidated financial statements to conform to the 2006 presentation.
Accounts Receivable and Allowance for Possible Losses
In evaluating its allowance for possible losses, the Company performs ongoing credit
evaluations of its customers and adjusts credit limits based upon payment history and the
customers’ current creditworthiness, as determined by the Company’s review of its customers’ credit
information. The Company extends credit on an unsecured basis to many of its energy customers. At
December 31, 2006, and 2005, the Company’s credit evaluation indicated that it has no need for an
allowance for possible losses.
Revenue Recognition
The Company conducts certain energy activities through, and a portion of its revenues are
attributable to, investment partnerships. The Company contracts with the investment partnerships to
drill partnership wells. The contracts require that the investment partnerships must pay the
Company the full contract price upon execution. The income from a drilling contract is recognized
as the services are performed using the percentage of completion method. The contracts are
typically completed in less than 60 days. On an uncompleted contract, the Company classifies the
difference between the contract payments it has received and the revenue earned as a current
liability.
The Company recognizes gathering revenues at the time the natural gas is delivered.
The Company recognizes well services revenues at the time the services are performed.
The Company is entitled to receive administration and oversight fees according to the
respective partnership agreements and recognizes such fees as income when services are performed.
The Company records the income from its working interests and overriding royalties of wells in
which it owns an interest when the gas and oil are delivered.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Revenue Recognition (Continued)
Because there are timing differences between the delivery of natural gas and oil and the
Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are
accrued based upon volumetric data from the Company’s records and the Company’s estimates of the
related transportation and compression fees, which are, in turn, based upon applicable product
prices. Accounts receivable include unbilled trade receivables at December 31, 2006 and
December 31, 2005 of $12.1 million, and $9.9 million respectively.
Fair Value of Financial Instruments
The Company used the following assumptions in estimating the fair value of each class of
financial instrument for which it is practicable to estimate fair value:
For receivables and payables, the carrying amounts approximate fair value because of the short
maturity of these instruments.
For derivatives the carrying value approximates fair value because the Company marks to market
all derivatives.
For debt the carrying value approximates fair value because of the short maturity of these
instruments.
Concentration of Credit Risk
Financial instruments, which potentially subject the Company to concentrations of credit risk,
consist principally of periodic temporary investments of cash and cash equivalents. The Company
places its temporary cash investments in short- term money market instruments and deposits with
financial institutions and brokerage firms. At December 31, 2006, December 31, 2005, the Company
had $8.8, and $19.6 million in deposits at two banks, of which, $8.7, and $19.5 million,
respectively, was over the insurance limit of the Federal Deposit Insurance Corporation. No losses
have been experienced on such investments.
Supplemental Cash Flow Information
The Company considers temporary investments with maturity at the date of acquisition of 90
days or less to be cash equivalents.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Derivative Instruments
The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and
Hedging Activities” and its various amendments (“SFAS 133”). SFAS 133 requires each derivative
instrument to be recorded in the balance sheet as either an asset or liability measured at fair
value. Changes in a derivative instrument’s fair value are recognized currently in earnings unless
specific hedge accounting criteria are met. All derivative activity reflected in the combined
financial statements was transacted by Atlas with third parties and allocated to the Company.
Comprehensive Income
Comprehensive income includes net income and other gains and losses affecting member’s equity
from non-owner sources that, under accounting principles generally accepted in the United States of
America, have not been recognized in the calculation of net income. For the Company, this includes
only changes in the fair value of unrealized hedging gains and losses.
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to
the protection of the environment. The Company has established procedures for the ongoing
evaluation of its operations, to identify potential environmental exposures and to comply with
regulatory policies and procedures.
The Company accounts for environmental contingencies in accordance with SFAS No. 5 “Accounting
for Contingencies.” Environmental expenditures that relate to current operations are expensed or
capitalized as appropriate. Expenditures that relate to an existing condition caused by past
operations, and do not contribute to current or future revenue generation, are expensed.
Liabilities for environmental contingencies are recorded when environmental assessments and/or
clean-ups are probable and the costs can be reasonably estimated. The Company maintains insurance
which may cover in whole or in part certain types of environmental contingencies. For the year
ended December 31, 2006 the three months ended December 31, 2005 and the years ended September 30,2005 and 2004, the Company had no environmental contingencies requiring specific disclosure or the
recording of a liability.
Goodwill
The Company applies the provisions of SFAS No. 142 (“SFAS 142”) Goodwill and Other Intangible
Assets, which requires that goodwill be evaluated for impairment at least annually. The evaluation
of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the
future performance of the Company’s operations, including anticipated future revenues, expected
future operating costs and the discount factor used. Actual results could differ from projections,
resulting in revisions to the Company’s assumptions and, if required, recognition of an impairment
loss. The Company’s evaluation of goodwill at December 31, 2006 and 2005 indicated there was no
impairment loss. The Company will continue to evaluate its goodwill at least annually or when
impairment indicators arise, and will reflect the impairment of goodwill, if any, within the
consolidated statements of income in the period in which the impairment is indicated.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 2
— SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Property and Equipment
Property and equipment is stated at cost. Depletion and amortization of oil and gas
properties is calculated based on cost less estimated salvage value primarily using the
unit-of-production method. Other fixed assets are depreciated using the straight-line method over
the assets estimated useful lives. Maintenance and repairs are expensed as incurred. Major
renewals and improvements that extend the useful lives of property are capitalized.
The estimated service lives of property and equipment are as follows:
Land, building and improvements
10-40 years
Furniture and equipment
3-7 years
Other
3-10 years
Property and equipment consists of the following at the dates indicated (in thousands):
Accumulated depreciation, depletion and amortization
Oil and gas properties
(35,237
)
(49,223
)
Other
(1,514
)
(2,089
)
(36,751
)
(51,312
)
$
168,778
$
224,764
Oil and Gas Properties
The Company follows the successful efforts method of accounting for oil and gas producing
activities. Exploratory drilling costs are capitalized pending determination of whether a well is
successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs
resulting in exploratory discoveries and all development costs, whether successful or not, are
capitalized. Geological and geophysical costs and delay rentals are expensed. Oil is converted to
gas equivalent basis (“Mcfe”) at the rate one-barrel equals 6 Mcf. Depletion is provided on the
units-of-production method. Unproved properties are reviewed annually for impairment or whenever
events or circumstances indicate that the carrying amount of an asset may not be recoverable.
Impairment charges are recorded if conditions indicate the Company will not explore the acreage
prior to expiration of the applicable leases or if it is determined that the carrying value of the
properties is above their fair value.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Oil and Gas Properties (Continued)
The Company’s long-lived assets are reviewed for impairment whenever events or changes in
circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are
reviewed for potential impairments at the lowest levels for which there are identifiable cash flows
that are largely independent of other groups of assets. The review is done by determining if the
historical cost of proved properties less the applicable accumulated depreciation, depletion and
amortization and abandonment is less than the estimated expected undiscounted future cash flows.
The expected future cash flows are estimated based on the Company’s plans to continue to produce
and develop proved reserves. Expected future cash flow from the sale of production of reserves is
calculated based on estimated future prices. The Company estimates prices based upon market related
information including published futures prices. The estimated future level of production is based
on assumptions surrounding future levels of prices and costs, field decline rates, market demand
and supply, and the economic and regulatory climates. If the carrying value exceeds such cash
flows, an impairment loss is recognized for the difference between the estimated fair market value,
(as determined by discounted future cash flows) and the carrying value of the assets.
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated
from the property accounts, and the resultant gain or loss is reclassified to income. Upon the sale
of an individual well the proceeds are credited to accumulated depreciation and depletion. Upon the
sale of an entire interest in an unproved property where the property had been assessed for
impairment individually, a gain or loss is recognized in the statements of income. If a partial
interest in an unproved property is sold, any funds received are accounted for as a reduction of
the cost in the interest retained.
Asset Retirement Obligation
The Company accounts for asset retirement obligations as required under FAS No. 143,
Accounting for Retirement Asset Obligations (“SFAS 143”). SFAS 143 requires that the fair value of
a liability for an asset retirement obligation be recognized in the period in which it is incurred,
with the associated asset retirement costs being capitalized as a part of the carrying amount of
the long-lived asset. The Company has asset retirement obligations related to its plugging and
abandonment of its oil and gas wells. SFAS 143 requires the Company to consider estimated salvage
value in the calculation of depreciation, depletion and amortization. Consistent with industry
practice, historically the Company had determined the cost of plugging and abandonment on its oil
and gas properties would be offset by salvage values received.
In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset
Retirement Obligations (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement
obligation” as used in FAS No. 143 refers to a legal obligation to perform an asset retirement
activity in which the timing and/or method of settlement are conditional on a future event that may
or may not be within the control of the entity. Since the obligation to perform the asset
retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a
conditional asset obligation should be recognized if that fair value can be reasonably estimated,
even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies
when an entity would have sufficient information to reasonably estimate the fair value of a
conditional asset retirement obligation under FAS No. 143.
The
Company adopted FIN 47 as of December 31, 2006 and recognized $3.4 million in 2006 as the
cumulative effect of an accounting change. The Company’s balance sheet recognized an increase as of
December 31, 2006 in its asset retirement obligation of $3.5 million, and a net increase in
property and equipment of approximately $6.9 million.
Under FASB No. 143, the Company had recorded its asset retirement obligation based on a
probability factor which considered the Company’s history of selling its wells or otherwise
disposing of them without incurring a disposal expense. FIN 47 requires the Company to record its
retirement obligation without regard to its prior practice and accrue for obligations for all wells
owned by the Company without regard to their probability of being sold or otherwise disposed of
without incurring a disposal expense.
Had the Company implemented FIN 47 retroactively to October 1, 2002, the following pro forma
information summarizes the impact for the periods presented (in thousands):
The Company was included in the federal income tax return of its Parent up through the merger
date in March 2006. Income taxes were presented as if the Company had filed a return on a
separate company basis utilizing its calculated effective rate of 34% for the three months ended
December 31, 2005, 23% for year ended September 30, 2005, and 18% for the year ended September 30,2004. The Company’s effective tax rate is lower than the federal statutory rate in fiscal 2005 and
2004 due to the benefit of percentage depletion. Deferred taxes, which are included in Advances
from Parent, reflect the tax effect of temporary differences between the tax basis of the Company’s
assets and liabilities and the amounts reported in the financial statements. Separate company
state tax returns are filed in those states in which the Company is registered to do business. The
net balance of Atlas Resources, Inc.’s deferred tax liability of $16.9 million has been eliminated
through a credit to the Company’s earnings before taxes in accordance with Financial Accounting
Standard Board Statement 109. The current tax expense of $635,000 incurred from January 1, 2006 up
to the merger at March 23, 2006 has also been charged to income from operations. The Company’s
financial reporting bases of its net assets exceeded the tax bases of its net assets by $58.5
million at December 31, 2005.
After the merger, the Company became a single member limited liability company. The Company’s
single member is a limited liability company, thus no provision for federal income tax purposes is
made because taxable income or loss is included in the tax returns of the individual members.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Recently Issued Financial Accounting Standards
In September 2006, the SEC staff issued Staff Accounting Bulletin No. 108, Considering the
Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year financial
statements (“SAB 108”). SAB 108 was issued to provide consistency in how registrants quantify
financial statement misstatements. The Company is required to and does apply SAB 108 in connection
with the preparation of its annual financial statements for the year ending December 31, 2006. The
application of SAB 108 did not have a material effect on its financial position or results of
operations.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair
Value Measurement (“SFAS 157”). SFAS 157 addresses the need for increased consistency in fair value
measurements, defining fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement date.
It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS
157 is effective for the Company beginning January 1, 2008. The Company is currently evaluating the
impact of the adoption of SFAS 157 on its financial position and results of operations.
NOTE 3 — OTHER ASSETS, INTANGIBLE ASSETS
Goodwill
Goodwill represents the excess of purchase price of an acquired business over the amounts assigned
to assets acquired and liabilities assumed in the transaction. The Company’s goodwill amounts are
assessed for recoverability annually or on an interim basis when impairment indicators are present.
The Company has not recognized any impairment losses related to its goodwill for the periods
presented. The carrying value of goodwill at December 31, 2005 and 2006 was $20.9 million net of
accumulated amortization was $2.3 million.
Intangible Assets
The following table provides information about other assets at the dates indicated:
Management and operating contracts, net of accumulated
amortization of $3,504 and $3,982
$
2,848
$
2,370
Security deposits
53
52
$
2,901
$
2,422
Partnership management and operating contracts were acquired through acquisitions and
were recorded at fair value on their acquisition dates. The Company amortizes contracts acquired on
the straight-line method, over their respective estimated lives, ranging from five to thirteen
years. Amortization expense for these contracts for the years ended December 31, 2006 and the three
months ended December 31, 2005 was $478,000 and $120,000 respectively. Amortization expense for
the years ended September 30, 2005 and 2004 was $478,000 per year.
The aggregate estimated annual amortization expense partnership management and operating
contracts for the next five years ending December 31 is as follows: 2007—$478,000; 2008—$478,000;
2009—$478,000; 2010—$478,000 and 2010—$458,000.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 4 — ASSET RETIREMENT OBLIGATION
The Company follows SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) and
FASB Interpretation No. 47 Accounting for Conditional Asset Retirement Obligations, which require
the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas
wells. Under SFAS 143, the Company must currently recognize
a liability for future asset retirement obligations if a reasonable estimate of the fair value of
that liability can be made. The associated asset retirement costs are capitalized as part of the
carrying amount of the long-lived asset. SFAS 143 requires the Company to consider estimated
salvage value in the calculation of depreciation, depletion and amortization.
The estimated liability is based on historical experience in plugging and abandoning wells,
estimated remaining lives of those wells based on reserve estimates, external estimates as to the
cost to plug and abandon the wells in the future, and federal and state regulatory requirements.
The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to
the liability could occur due to changes in estimates of plugging and abandonment costs or
remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment
requirements. The increase in asset retirement obligations in fiscal 2005 was due to an upward
revision in the estimated cost of plugging and abandoning wells.
The Company has no assets legally restricted for purposes of settling asset retirement
obligations. Except for the item previously referenced, the Company has determined that there are
no other material retirement obligations associated with tangible long-lived assets.
A reconciliation of the Company’s liability for well plugging and abandonment costs for the
periods indicated is as follows (in thousands):
The above accretion expense is included in depreciation, depletion and amortization in the
Company’s statements of income.
NOTE 5 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Advances from Parent shown on the Company’s Balance Sheets represents amounts owed for
advances and other transactions in the normal course of business. The advances are subordinated to
any third party debt. The Company incurred interest expense related to inter company transactions
for the year ended December 31, 2006, three months ended December 31, 2005 and the years ended
September 30, 2005 and 2004 of $284,000, $164,000, $1.6 million and $2.1 million, respectively.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 6 — COMMITMENTS AND CONTINGENCIES
The Company is the managing general partner of various energy partnerships, and has agreed to
indemnify each investor partner from any liability that exceeds such partner’s share of partnership
assets. Subject to certain conditions, investor partners in certain energy partnerships have the
right to present their interests for purchase by the Company, as managing general partner. The
Company is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based
on past experience, the Company believes that any liability incurred would not be material. The
Company may also be required to subordinate a part of its net partnership revenues to the receipt
by investor partners of cash distributions from the energy partnerships equal to at least 10% of
their agreed subscriptions determined on a cumulative basis, in accordance with the terms of the
partnership agreements.
Concurrent with the closing of Atlas Energy’s initial public offering, on December 18, 2006,
Atlas America Inc. terminated its credit facility with Wachovia Bank and Atlas Energy Operating
Company, LLC (a wholly-owned subsidiary of Atlas Energy) entered into a new credit facility
agreement led by Wachovia Bank, which has a current borrowing base of $155 million.
Atlas Energy Operating LLC may draw from its revolving credit facility on behalf of the
Company. The facility permits draws based on the remaining proved natural gas and oil reserves
attributable to all wells that Atlas Energy has an interest in, including the wells of the Company,
and the projected fees and revenues from operation of the wells and the administration of the
energy partnerships. Up to $50.0 million of the facility may be in the form of standby letters of
credit. The facility is secured by the Parent’s assets, including those of the Company. The
revolving credit facility has a term ending in December 2011, when all outstanding borrowings must
be repaid and bears interest at one of two rates (elected at the borrower’s option) which increases
as the amount outstanding under the facility increases. At December 31, 2006 Atlas Energy
Operating LLC had $.5 million outstanding under this facility under letters of credit. At December31, 2005 Atlas the Parent on that date, had $16.5 million outstanding under this facility under
letters of credit. The amounts are not reflected as borrowings on the Parent’s balance sheet.
The Company is a party to various routine legal proceedings arising out of the ordinary course
of its business. Management believes that none of these actions, individually or in the aggregate,
will have a material adverse effect on the Company’s financial position or results of operations.
NOTE 7 — DERIVATIVE INSTRUMENTS
Atlas from time to time enters into natural gas futures and option contracts on the Company’s
behalf to hedge its exposure to changes in natural gas prices. At any point in time, such
contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options
contracts and non-regulated over-the-counter futures contracts with qualified counterparties.
NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery
of natural gas.
Atlas Energy and the Company formally document all relationships between hedging instruments
and the items being hedged, including the Company’s risk management objectives and strategy for
undertaking the hedging transactions. This includes matching the natural gas futures and options
contracts to the forecasted transactions. The Company assesses both at the inception
of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting
changes in fair value of hedged items. Historically these contracts have qualified and been
designated as cash flow hedges and recorded at their fair values. Gains or losses on future
contracts are determined as the difference between the contract price and a reference price,
generally prices on NYMEX. Such gains and losses are charged or credited to Accumulated Other
Comprehensive Income (Loss) and recognized as a component of oil and gas production revenues in the
month the hedged gas is sold. If it is determined that a derivative is not highly effective as a
hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between
changes in gas reference prices under a hedging instrument and actual gas prices, the Company will
discontinue hedge accounting for the derivative and subsequent changes in fair value for the
derivative will be recognized immediately into earnings.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 7 — DERIVATIVE INSTRUMENTS (CONTINUED)
At December 31, 2006, the Company had 234 open natural gas futures contracts allocated to it
by Atlas related to natural gas sales covering 23,521,115 dekatherms (“Dth”) (net to the Company)
of natural gas, maturing through December 31, 2010 at a combined average settlement price of $8.48
per Dth. At December 31, 2006, the Company reflected net hedging assets on its balance sheet of
$20.3 million. Of the $20.3 million net gain in accumulated other comprehensive income at December31, 2006, if the fair values of the instruments remain at current market values, the Company will
reclassify $11.8 million of net gains to its statement of operations over the next twelve month
period as these contracts expire, and $8.5 million of net gains will be reclassified in later
periods. Actual amounts that will be reclassified will vary as a result of future price changes.
Ineffective hedge gains or losses are recorded within the statement of operations while the hedge
contract is open and may increase or decrease until settlement of the contract. The Company
recognized gains of $6.8 million for the year ended December 31, 2006 within its statement of
operations related to the settlement of qualifying hedge instruments. The Company recognized no
gains or losses during the year ended December 31, 2006 for hedge ineffectiveness or as a result of
the discontinuance of these cash flow hedges.
Derivatives are recorded on the balance sheet as assets or liabilities at fair value. For
derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in
member’s equity as Accumulated Other Comprehensive Income (Loss) and reclassified to earnings as
such transactions are settled. For non-qualifying derivatives and for the ineffective portion of
qualifying derivatives, changes in fair value are recognized in earnings as they occur.
At December 31, 2006, Atlas had allocated the following natural gas fixed-price swaps in place
to the Company:
Natural Gas Fixed — Price Swaps
Twelve Month
Average
Fair Value
Period
Volumes
Fixed Price
Asset(2)
Ended December 31,
(MMBTU)(1)
(per MMBTU)
(in thousands)
2007
6,273,000
$
8.596
$
11,105
2008
6,766,000
8.914
4,903
2009
6,731,000
8.306
3,293
2010
2,312,000
7.532
251
$
19,552
Costless Collars
Twelve Month
Average
Fair Value
Period
Volumes
Floor and Cap
Asset
Ended December 31,
(MMBTU)
(in thousands)
2007
771,000
$
7.50-8.60
$
647
Puts purchased
2007
771,000
7.50-8.60
—
Calls sold
2008
668,000
7.50-9.40
120
Puts purchased
2008
668,000
7.50-9.40
—
Calls sold
$
767
Total assets
$
20,319
(1)
MMBTU represents million British Thermal Units.
(2)
Fair value based on forward NYMEX natural gas prices, as applicable, on December31, 2006.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 8 — SUPPLEMENTAL OIL AND GAS INFORMATION (CONTINUED)
Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized
costs related to the Company’s oil and gas-producing activities are as follows (in thousands):
Accumulated depreciation,
depletion and amortization
(35,237
)
(53,214
)
Net capitalized costs.
$
166,896
$
219,745
Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Company in
its oil and gas activities during the periods indicated are as follows (in thousands):
The development costs above for the periods noted were substantially all incurred for the
development of proved undeveloped properties.
Oil and Gas Reserve Information (Unaudited). The estimates of the Company’s proved and
unproved gas and oil reserves are based upon evaluations made by management and verified by Wright
& Company, Inc., an independent petroleum engineering firm, as of September 30, and 2005 and
December 31, 2006. All reserves are located within the United States. Reserves are estimated in
accordance with guidelines established by the Securities and Exchange Commission and the Financial
Accounting Standards Board which require that reserve estimates be prepared under existing economic
and operating conditions with no provisions for price and cost escalation except by contractual
arrangements.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 8 — SUPPLEMENTAL OIL AND GAS INFORMATION (CONTINUED)
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating conditions, i.e. prices and costs
as of the date the estimate is made. Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on escalations based upon future conditions.
•
Reservoirs are considered proved if economic producibility is supported by either actual
production or conclusive formation tests. The area of a reservoir considered proved includes
(a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if
any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available geological and engineering data.
In the absence of information on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
•
Reserves which can be produced economically through application of improved recovery
techniques (such as fluid injection) are included in the “proved” classification when
successful testing by a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on which the project or program was
based.
•
Estimates of proved reserves do not include the following: (a) oil that may become
available from known reservoirs but is classified separately as “indicated additional
reservoirs”, (b) crude oil and natural gas, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics or economic factors;
(c) crude oil and natural gas, that may occur in undrilled prospects; and (d) crude oil and
natural gas, and NGLs, that may be recovered from oil shales, coal, gilsonite and other such
sources.
Proved developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operation methods. Additional oil and gas
expected to be obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary recovery should be
included as “proved developed reserves” only after testing by a pilot project or after the
operation of an installed program has confirmed through production response that increased recovery
will be achieved.
There are numerous uncertainties inherent in estimating quantities of proven reserves and in
projecting future net revenues and the timing of development expenditures. The reserve data
presented represents estimates only and should not be construed as being exact. In addition, the
standardized measure of discounted future net cash flows may not represent the fair market value of
the Company’s oil and gas reserves or the present value of future cash flows of equivalent
reserves, due to anticipated future changes in oil and gas prices and in production and development
costs and other factors for effects have not been proved.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 8 — SUPPLEMENTAL OIL AND GAS INFORMATION (CONTINUED)
The following schedule presents the standardized measure of estimated discounted future net
cash flows relating to proved oil and gas reserves. The estimated future production is priced at
fiscal year-end prices, adjusted only for fixed and determinable increases in natural gas and oil
prices provided by contractual agreements. The resulting estimated future cash inflows are reduced
by estimated future costs to develop and produce the proved reserves based on fiscal year-end cost
levels and includes the effect on cash flows of settlement of asset retirement obligations on gas
and oil properties. The future net cash flows are reduced to present value amounts by applying a
10% discount factor. The standardized measure of future cash flows was prepared using the
prevailing economic conditions existing at the period ends indicated below and such conditions
continually change. Accordingly, such information should not serve as a basis in making any
judgment on the potential value of recoverable reserves or in estimating future results of
operations.
Less 10% annual
discount for
estimated timing
of cash flows
(222,143
)
(575,713
)
(389,406
)
(320,239
)
Standardized measure of
discounted future net
cash flows
$
136,522
$
399,962
$
283,397
$
151,715
The future cash flows estimated to be spent to develop proved undeveloped properties in
the years ended December 31, 2007, 2008 and 2009 are $48.1 million, $50.8 million and $50.7
million, respectively.
ATLAS RESOURCES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2006
NOTE 8 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (CONTINUED)
The following table summarizes the changes in the standardized measure of discounted future
net cash flows from estimated production of proved oil and gas
reserves after income taxes. Income taxes have been removed from the
beginning balance for the year ended December 31, 2006 due to the Company’s change in structure to a
pass-through entity for taxes.
INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS
The partnerships do not currently hold any interests in any prospects on which the wells will
be drilled, and the managing general partner has absolute discretion in determining which prospects
will be acquired to be drilled. However, set forth below is information relating to certain
proposed prospects and the wells which will be drilled on the prospects by Atlas Resources Public
#16-2007(A) L.P., which is the first partnership in the program. It is referred to in this section
as the “2007(A) Partnership.” One well will be drilled on each development prospect, and for
purposes of this discussion the well and prospect are referred to together as the “well.” The
managing general partner does not anticipate that the wells will be selected in the order in which
they are set forth below. Also, the wells currently proposed to be drilled by the 2007(A)
Partnership when its subscription proceeds are released from escrow, and from time to time
thereafter, are subject to the managing general partner’s right to:
•
withdraw the wells and to substitute other wells;
•
take a lesser working interest in the wells;
•
add other wells; or
•
any combination of the foregoing.
The specified wells represent the necessary wells if subscription proceeds of approximately $66.4
million are raised and the 2007(A) Partnership takes the working interests in the wells that are
set forth below in the “Lease Information” for each area. The managing general partner has not
proposed any other wells if:
•
a greater amount of subscription proceeds is raised;
•
a lesser working interest in the wells is acquired; or
•
other wells are substituted for the proposed wells for any of the reasons set forth below.
The managing general partner has not authorized any person to make any representations to you
concerning the possible inclusion of any other wells which will be drilled by the 2007(A)
Partnership or the other remaining partnership, and you should rely only on the information in this
prospectus. The currently proposed wells will be assigned to the 2007(A) Partnership unless there
are circumstances which, in the managing general partner’s opinion, lessen the relative suitability
of the wells. These considerations include:
•
the amount of the subscription proceeds received by the 2007(A) Partnership;
•
the latest geological and production data available;
•
potential title or spacing problems;
•
availability and price of drilling services, tubular goods and services;
•
approvals by federal and state departments or agencies;
•
agreements with other working interest owners in the wells;
•
farmins; and
•
continuing review of other properties which may be available.
Any substituted and/or additional wells will meet the same general criteria that the managing
general partner used in selecting the currently proposed wells, and generally will be located in
areas where the managing general partner or its affiliates have
previously conducted drilling operations. You, however, will not have the opportunity to evaluate
for yourself the relevant production and geological information for the substituted and/or
additional wells.
The information regarding the currently proposed wells is intended to help you evaluate the
economic potential and risks of drilling the proposed wells. This includes production information
for wells in the same general area as the proposed well, which the managing general partner
believes is an important indicator in evaluating the economic potential of any well to be drilled.
However, generally, there will be a lack of production information from surrounding wells for the
majority of the wells to be drilled by a partnership, which results in greater uncertainty to you
and the other investors. This lack of production information results primarily from the managing
general partner, as operator, proposing wells to be drilled in a partnership that are adjacent to
wells it has previously drilled as operator in prior partnerships that have not yet been completed,
have not yet been put on-line to sell production, or have been producing for only a short period of
time so there is little or no production information available. If the managing general partner
was not the operator of a previously drilled well, then the production information is not available
if the well was drilled within the last five years since the Pennsylvania Department of
Environmental Resources keeps production data confidential for the first five years from the time a
well starts producing. See “Risk Factors – Risks Related to an Investment In a Partnership – Lack
of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the
Feasibility of a Partnership’s Drilling Program.” The managing general partner has proposed these
wells to be drilled, even though there is no production data for other wells in the immediate area,
because geologic trends in the immediate area, such as sand thickness, porosities and water
saturations, lead the managing general partner to believe that the proposed wells also will be
productive.
When reviewing production information for each well offsetting, or in the general area, of a
proposed well to be drilled, you should consider the factors set forth below.
•
The length of time that the well has been on-line, and the time period for which
production information is shown. Generally, the shorter the period for which
production information is shown the less reliable the information is in predicting the
ultimate recovery of reserves from a well.
•
Production from a well declines throughout the life of the well. The rate of
decline, the “decline curve,” varies based on which geological formation is producing,
and may be affected by the operation of the well. For example, the wells in the
Clinton/Medina geological formation in western Pennsylvania will have a different
decline curve from the wells in the Mississippian/Upper Devonian Sandstone Reservoir in
Fayette, Greene and Westmoreland Counties, which also are situated in western
Pennsylvania. Also, each well in a geological formation or reservoir will have a
different rate of decline from the other wells in the same formation or reservoirs.
•
The greatest volume of production (“flush production”) from a well usually occurs in
the early period of well operations and may indicate a greater reserve volume
(generally, the ultimate amount of natural gas and oil recoverable from a well) than
the well actually will produce. This period of flush production can vary depending on
how the well is operated and the location of the well.
•
There is no production information for the majority of the wells. The designation
“N/A” means:
•
the production information was not available to the managing general partner
because there was a third-party operator as discussed in “Risk Factors – Risks
Related to an Investment In a Partnership – Lack of Production Information
Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a
Partnership’s Drilling Program”; or
•
if the managing general partner was the operator, then when the information
was prepared the well was:
•
not completed;
•
completed, but was not on-line to sell production; or
Production information for wells located close to a proposed well tends to be more
relevant than production information for wells located farther away, although
performance and volume of production from wells located on contiguous prospects can be
much different since the geological conditions in these areas can change in a short
distance.
•
Consistency in production among wells tends to confirm the reliability and
predictability of the production.
The information set forth below is included to help you become familiar with the proposed wells.
•
A map of western Pennsylvania and eastern Ohio showing their counties.
4
•
Fayette County, Pennsylvania (Mississippian/Upper Devonian Sandstone Reservoirs)
•
Lease information for Fayette, Greene and Westmoreland Counties, Pennsylvania.
6
•
Location and Production Maps for Fayette, Greene and Westmoreland
Counties, Pennsylvania showing the proposed wells and the wells in the
area.
12
•
Production data for Fayette, Greene and Westmoreland Counties,
Pennsylvania.
24
•
United Energy Development Consultants, Inc.’s geologic evaluation for
the currently proposed wells in Fayette, Greene and Westmoreland
Counties, Pennsylvania.
46
•
Western Pennsylvania (Clinton/Medina Geological Formation)
•
Lease information for western Pennsylvania and eastern Ohio.
52
•
Location and Production Maps for western Pennsylvania and eastern Ohio
showing the proposed wells and the wells in the area.
55
•
Production data for western Pennsylvania and eastern Ohio.
59
•
United Energy Development Consultants, Inc.’s geologic evaluation for
the currently proposed wells in western Pennsylvania and eastern Ohio.
63
•
Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
(Mississippian Carbonate and Devonian Shale Reservoirs)
•
A map of Tennessee showing its Counties
69
•
Lease information for Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee.
71
•
Location and Production Maps for Anderson, Campbell, Morgan, Roane and
Scott Counties, Tennessee showing the proposed wells and the wells in the
area.
73
•
Production data for Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee
78
•
United Energy Development Consultants, Inc.’s geologic evaluation for
the primary drilling area in Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The purpose of the following investigation is to evaluate the geologic feasibility and
further development of the Fayette Prospect Area as proposed by Atlas Energy Resources, LLC
(“Atlas”).
AREA OF INVESTIGATION
A portion of this prospect area, herein identified for drilling in ATLAS RESOURCES
PUBLIC #16-2007(A) L.P., contains acreage in Newell Borough, Springhill, Nicholson, German,
Redstone, Georges, Jefferson and Dunbar Townships of Fayette County; Cumberland, Jefferson, Greene
and Dunkard Townships of Greene County; Beallsville and Deemston Boroughs of Washington County;
and Salem and Rostraver Townships of Westmoreland County; located in southwestern Pennsylvania.
One hundred thirty-five (135) drilling prospects have currently been designated for this program
in the prospect area, which will be targeted to produce natural gas from Mississippian and Upper
Devonian reservoirs, found at depths from 1900 feet to 6000 feet beneath the earth’s surface.
These will be the only prospects evaluated for the purposes of this report.
METHODOLOGY
Atlas provided the data incorporated into this report. Geological mapping and the
interpretations by Atlas geologists were also examined. Available “electric” log, completion and
production data on “key” wells within and adjacent to the defined prospect area were utilized to
determine productive and depositional trends
PROSPECT AREA HISTORY
DRILLING ACTIVITY
The proposed drilling area lies within a region of southwestern Pennsylvania, which has
been active for the past six years in terms of exploration for, and exploitation of natural gas
reserves. Development within and adjacent to the Fayette Prospect Area has continued steadily
since 1996. Over fourteen hundred (1400) wells have been drilled in the area during this period.
Atlas has encountered favorable drilling and production results while solidifying a strong acreage
position of nearly 100,000 acres, as Atlas continues to identify and extend productive trends.
Drilling is ongoing as of the date of this report with recent wells displaying favorable initial
drilling and completion results.
The area of proposed drilling is situated in portions of Fayette and Greene Counties that have
had established production from shallower, historic pay zones. Atlas will drill at least 1000 feet
from producing wells, although Atlas may drill a new well or re-enter an existing well closer than
1000 feet from plugged and abandoned wells.
GEOLOGY
STRATIGRAPHY, LITHOLOGY & DEPOSITION
The Mississippian reservoirs currently producing in the Fayette Prospect Area are the
Burgoon Sandstone (lower Big Injun) and the 2nd Gas Sand. The Burgoon Sandstone is part
of the massive Big Injun fluvial-deltaic sand system, which extends from eastern Kentucky through
West Virginia into southwestern Pennsylvania. This reservoir is an historic producing zone in this
region, with some wells still producing long beyond fifty years. There is not much history of
production from the 2nd Gas Sand in this area.
The Upper Devonian reservoirs consist of three groups of sands, Upper Venango, Lower Venango
and Bradford. Each of these “Groups” has multiple reservoirs making up their total rock section.
The Upper Venango Group consists of the Gantz Sand and the Fifty Foot Sand. The Lower Venango Group
consists of the Fifth Sand and the Bayard Sand. Depositional environments of these Upper and Lower
Venango Group sands are of near shore to offshore
marine settings related to the last major advance of the Catskill Delta. The Bradford Group
consists of the Lower Warren Sand, Upper Speechley Sand, Lower Speechley Sand, Upper Balltown Sand
and the First Bradford Sand. Depositional environments of these sands are offshore marine,
pro-delta and basin floor settings related to the intermediate advance of the Catskill Delta.
Stratigraphic relationships are illustrated in the diagram. Stratigraphically, in descending
order, the potentially productive units of the Mississippian and Upper Devonian Groups are:
Burgoon, 2nd Gas Sand, Gantz, Fifty Foot, Fifth, Bayard, Lower Warren, Upper Speechley,
Lower Speechley, Upper Balltown, and First Bradford Sand.
§
The Burgoon Sandstone is a fine to
medium grained, medium to massively bedded, light-gray sandstone ranging in thickness from
200-250 feet. Average porosity values for this sand range from 6% to 12% regionally. It is not
uncommon to encounter porosities as high as 20% and attendant producible natural open flows from
this sand. Tracking these producible natural open flow trends is targeted for further
development. Also, this zone does produce water in certain locales within the Fayette Prospect
Area. This reservoir is considered a secondary target in the natural open flow trend areas.
§
The
2ndGas Sand of this region has limited areal extent and therefore is not
discussed in the literature regarding lithology, thickness etc. It can be inferred from underlying
and overlying sands that it is probably a fine to very fine grained, light gray sand. Subsurface
mapping indicates that the sand can achieve a thickness of twenty (20) feet. Average porosity
values for this sand range from 10% to 13% when this zone is present in the area. Peak porosities
of 17% have been encountered within the prospect area. This reservoir is considered to be a
secondary target when encountered.
§ The Gantz Sand is a white to light-gray, medium to coarse-grained sandstone ranging in
thickness from a few feet to over sixty (60) feet. Average porosity values for this sand range from
5% to 10% regionally. Within the area of investigation, porosities in excess of 13% occur within
localized trends characterized by producible natural open flows. These trends are targeted for
future development. This reservoir is considered a primary target in the natural open flow trend
areas.
§ The Fifty Foot Sand is a white to light gray, thinly bedded, fine-grained sandstone ranging in
thickness from ten (10) to thirty (30) feet. Average porosity values for this sand range from 5% to
8% regionally. Within the prospect area, porosities in excess of 12% occur within localized trends
targeted for future development. This sand reservoir is considered a secondary target.
• The Fifth Sand is a white to light gray, very fine to fine grained sandstone ranging in
thickness from a few feet to forty (40) feet. Within the main Fifth fairway, porosity values average
from 9% to 15%. This sand is considered a primary target and will be exploited in future
development.
§ The Bayard Sand in the prospect area ranges in thickness from a few feet to more than sixty
(60) feet. Average porosity values range from 5% to 12% for this fine to coarse-grained
sandstone. Discrete reservoirs within the sand have been identified and mapped. Gas shows
in the member sandstones delineate trends within the prospect area and will be targeted for future
development. This sand is considered a primary target.
§ The Lower Warren Sand is a primary target in the prospect area. Average thickness for this
sand ranges from zero (0) feet to over forty (40) feet. Porosities average between 8% and 12%
in the area. Gas shows are commonly found in this sand, which is probably a fine-grained, well-
sorted sand. This reservoir is targeted for future development.
§ The Upper Speechley Sand is considered a secondary target with average thickness ranging
from two (2) feet to ten (10) feet over much of the prospect area. Gas shows from this sand are
common throughout the area and the zone is combined with other zones when treated.
§ The Lower Speechley Sand is a primary target in the area with reservoir thickness ranging
from zero (0) to over forty (40) feet. Average porosity values range from 5% to 12% where the
sand is present. Significant natural and after treatment flows from this sand have been
encountered. This sand is being targeted throughout the prospect area.
§ The Upper Balltown Sand is currently being produced in a few wells in the prospect area.
The zone is a siltstone with fracture-enhanced porosity, based on log interpretation, and has
associated gas shows. This sand is considered a secondary target and is usually combined with
other zones when treated.
§ The First Bradford Sand, like the Balltown above, is currently being produced in a few wells
in the prospect area. This silty-sand does have porosity up to 10% in the area and is considered
to be a secondary target when encountered.
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable barrier trapping
commercial quantities of natural gas in a more permeable medium. In the Mississippian and Upper
Devonian reservoirs, this occurs either stratigraphically when a permeable sand containing
hydrocarbons encounters impermeable shale or when permeable sand changes gradually into
non-permeable sand by a cementation process known as “diagenesis”. Thus, this type of trap
represents cemented-in hydrocarbon accumulations.
Electric well logs can be used in conjunction with
production to interpret reservoir parameters. When
sandstones in the Mississippian and Upper Devonian
reservoirs develop porosity in excess of 8%, or a bulk
density of 2.50 or less, the permeability of the
reservoir can become great enough to allow commercial
production of natural gas. Small, naturally occurring
cracks in the formation, referred to as micro-fractures,
can also enhance permeability.
A gamma, bulk density, neutron, induction and
temperature log suite showing sand development in both
the Mississippian and Upper Devonian reservoirs is
illustrated.
The temperature log shown in the illustration at
left identifies where gas is entering the wellbore.
Evidence of a temperature “kick” or cooling is also an
indication of enhanced permeability and the willingness
of the reservoir to produce natural gas.
PRODUCTION
The Fayette prospect area produces from a number of reservoirs of different age and
type. Each well has a unique combination of these reservoirs yielding different production
declines. While Atlas anticipates production from each reservoir to be comparable to like
reservoirs historically produced throughout the Appalachian Basin, a model decline curve for this
prospect area is not included due to multiple sets of commingled reservoirs exclusively found in
this area.
UEDC has conducted a geologic feasibility study of the drilling area for ATLAS RESOURCES
PUBLIC #16-2007(A) L.P., which will consist of developmental drilling of Lower Mississippian and
Upper Devonian reservoirs in Fayette, Greene, Washington and Westmoreland Counties, Pennsylvania.
It is the professional opinion of UEDC that the drilling of the one hundred thirty-five (135)
wells by ATLAS RESOURCES PUBLIC #16-2007(A) L.P. is supported by sufficient geologic and
engineering data.
DISCLAIMER
For the purpose of this evaluation, UEDC did not visit any leaseholds or inspect any of
the associated production equipment. Likewise, UEDC has no knowledge as to the validity of title,
liabilities, or corporate matters affecting these properties. UEDC does not warrant individual
well performance.
NON-INTEREST
We hereby confirm that UEDC is an independent consulting firm and that neither this firm
or any of it’s employees, contract consultants, or officers has, or is committed to acquire any
interest, directly or indirectly, in Atlas Energy Resources, LLC; nor is this firm, or any
employee, contract consultant, or officer thereof, otherwise affiliated with Atlas Energy
Resources, LLC. We also confirm that neither the employment of, nor payment of compensation
received by UEDC in connection with this report, is on a contingent basis.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have
the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have
the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have
the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The purpose of the following investigation is to evaluate the geologic feasibility and
further development of the Crawford Prospect Area as proposed by Atlas Energy Resources, LLC
(“Atlas”).
AREA OF INVESTIGATION
A portion of this prospect area, herein identified for drilling in ATLAS RESOURCES
PUBLIC #16-2007(A) L.P., contains acreage in Athens, Steuben, East Mead, Richmond, Randolph and
Woodcock Townships of Crawford County, located in northwestern Pennsylvania. Forty (40) drilling
prospects will be designated for this program and will be targeted to produce natural gas from
Clinton-Medina Group reservoirs, found at an average depth range of approximately 5,000 to 6,300
feet beneath the earth’s surface over the prospect area. These will be the only prospects
evaluated for the purposes of this report.
METHODOLOGY
The data incorporated into this report was provided by Atlas and the in-house archives
of UEDC, Inc. Geological mapping and the interpretations by Atlas geologists were also examined.
Available “electric” log, completion, and production data on “key” wells within and adjacent to
the defined prospect area were utilized to determine productive and depositional trends.
PROSPECT AREA HISTORY
DRILLING ACTIVITY
The proposed drilling area lies within a region of northwestern Pennsylvania which has
been very active for the past decade in terms of exploration for, and exploitation of natural gas
reserves. Development within and adjacent to the Crawford Prospect Area has escalated since 1986,
with Atlas and its affiliates drilling over fourteen hundred (1400) wells during this period. Atlas
has encountered favorable drilling and production results while solidifying a strong acreage
position, and continues to identify and extend productive trends. Drilling is ongoing as of the
date of this report with recent wells displaying favorable initial drilling and completion results.
Competitive activity has begun east of the prospect area, confirming the Clinton-Medina Group of
Lower Silurian age as a viable target for the further development of producible quantities of
natural gas.
GEOLOGY
STRATIGRAPHY, LITHOLOGY & DEPOSITION
Regionally, the Clinton-Medina Group was deposited in
tide-dominated shoreline, deltaic, and shelf environments and is
lithologically comprised of alternating sandstones, siltstones and
shales. Productive sandstones are composed of siliceous to dolomitic
subarkoses, sublitharenites, and quartz arenites. Reservoir quality
sands occur throughout the delta-complex from eastern Ohio through
northwestern Pennsylvania and western New York. The Clinton-Medina
Group, deposited during the Lower Silurian, overlies the Upper
Ordovician age Queenston shale and is capped by the Middle Silurian
Reynales Formation. This dolomitic limestone “cap” is known locally
to drillers as the “Packer Shell”.
Stratigraphically, in descending order, the potentially productive units of the
Clinton-Medina Group consist of the: 1) Thorold, 2) Grimsby, 3) Cabot Head, 4) Whirlpool members.
The diagram illustrates these stratigraphic relationships.
The Whirlpool is a light gray quartzose sandstone to siltstone ranging in thickness from five
(5) to twenty (20) feet. Average porosity values for this sand member range from five (5) to ten
(10) percent regionally. Within the area of investigation, porosities in excess of twelve (12)
percent occur within localized trends targeted for further development.
The Cabot Head is a dark green to black shale, most likely of marine origin. Within the
investigated area the Cabot Head sandstone has been encountered in numerous wells. This formation
has been found to contribute natural gas when reservoir characteristics, including evidence of
enhanced permeability, warrant completion. This sand member is considered a secondary target.
The Grimsby is the thickest sandstone member of the Clinton-Medina Group. Sand development
ranges from ten (10) to forty-five (45) feet within an interval comprised of fine to very fine,
light gray to red sandstones and siltstones broken up by thin dark gray silty shale layers. Average
porosity values for the Grimsby are approximately six (6) to (10) percent over the pay interval
regionally. Permeability may be enhanced locally by the presence of naturally occurring
micro-fractures. Future development focuses on established production trends.
The Thorold sandstone is the uppermost producing interval of the Clinton-Medina sequence.
This interbedded ferric sand, silt and shale interval averages forty (40) to seventy (70) feet,
from west to east in the prospect area. Where pay sand development occurs, porosities are in the
typical Clinton-Medina group range of six (6) to (10) percent. Permeability may be enhanced
locally by the presence of naturally occurring micro-fractures.
RESERVOIR CHARACTERISTICS
Petroleum reservoirs are formed by the presence of an impermeable barrier trapping natural gas
of commercial quantities in a more permeable medium. In the Clinton-Medina, this occurs either
stratigraphically when a permeable sand containing hydrocarbons encounters an impermeable shale or
when a permeable sand changes gradually into a non-permeable sand by a cementation process known as
“diagenesis”. Thus, this type of trap represents cemented-in hydrocarbon accumulations.
Electric well logs can be used in conjunction with
production to interpret reservoir parameters. When sandstones in
the Thorold, Grimsby, Cabot Head or Whirlpool develop porosity
in excess of 6%, or a bulk density of 2.55 or less, the
permeability of the reservoir (which ranges from <0.l to
>0.2 mD) can become great enough to allow commercial
production of natural gas. Small, naturally occurring cracks in
the formation, referred to as micro-fractures, can also enhance
permeability. A gamma, bulk density, density porosity and
neutron log suite showing sand development in the Grimsby, Cabot
Head and Whirlpool is illustrated.
Two other phenomena detected by well logs can occur which
are indicators of enhanced permeability. These indicators used
to detect productive intervals are:
•Mudcake buildup across the zone of interest — after
loading the wellbore with brine fluid and circulating, an
interval with enhanced permeability will accept fluid, filtering
out the solids and leaving behind a buildup (or mudcake) on the
formation wall. This is detectable with a caliper log.
•Invasion profile — during circulation, a brine that has a high conductivity (or low
resistivity) that is accepted into the formation (as described above) will change the electrical
conductivity of the reservoir rock near and around the wellbore. The resistivitv will be low
nearest to the wellbore and will increase away from the wellbore. As
shown in the example, a dual laterolog can be used to
detect this profile created by a permeable zone — it records resistivity near the wellbore as well
as deeper into the formation. A zone with enhanced permeability will show a separation between the
shallow and deep laterologs, while a zone with little or no permeability would cause the two
resistivity measurements to read exactly the same.
PRODUCTION
A model decline curve has been created based on the production histories from
approximately 900 wells drilled by Atlas and its programs in the adjacent Mercer Fields. This
model decline curve is consistent with the average estimated decline curves for over 200
undeveloped well locations in the Mercer Field which were used by Wright & Company, Inc.,
independent petroleum consultants, in preparing Atlas’ year 2000 reserve report. The model decline
curve is illustrated in the diagram below:
It is important to note that the model decline curve is intended only to present how a well’s
production may decline from year to year, and does not attempt to predict the average recoverable
reserves per well.
Also, the model decline curve is a forward-looking statement based on certain assumptions and
analyses of historical trends, current conditions and expected future developments. The model
decline curve is subject to a number of risks and uncertainties including the risk that the wells
are productive but do not produce enough revenue to return the investment made and uncertainties
concerning the price of natural gas and oil. Actual results in this drilling program will vary from
the model decline curve, although a rapid decline in production within the first several years can
be expected.
UEDC has conducted a geologic feasibility study of the drilling area for ATLAS RESOURCES
PUBLIC #16-2007(A) L.P., which will consist of developmental drilling of the Clinton-Medina Group
sands in Crawford County, Pennsylvania. It is the professional opinion of UEDC that the drilling
of the forty (40) wells by ATLAS RESOURCES PUBLIC #16-2007(A) L.P. is supported by sufficient
geologic and engineering data.
DISCLAIMER
For the purpose of this evaluation, UEDC did not visit any leaseholds or inspect any of
the associated production equipment. Likewise, UEDC has no knowledge as to the validity of title,
liabilities, or corporate matters affecting these properties. UEDC does not warrant individual
well performance.
NON-INTEREST
We hereby confirm that UEDC is an independent consulting firm and that neither this firm
or any of it’s employees, contract consultants, or officers has, or is committed to acquire any
interest, directly or indirectly, in Atlas Energy Resources, LLC; nor is this firm, or any
employee, contract consultant, or officer thereof, otherwise affiliated with Atlas Energy
Resources, LLC. We also confirm that neither the employment of, nor payment of compensation
received by UEDC in connection with this report, is on a contingent basis.
Subject to maintenance of drilling commitments during the primary term
thereof; each well drilled is earned and rights do not expire with the termination of
rights to continue development.
(2)
Overriding royalty interests to Knox Energy, LLC are reduced when Knox chooses to
participate in the development of a well. If Knox participates in a well for a 50% working
interest, the well will be burdened by an overriding royalty of 1/64 or 1.5625%. If Knox
participates in a well for less than 50% working interest, the overriding royalty to Knox
will be determined by subtracting from an overriding royalty of 3.125% an amount determined
by multiplying 1.5625% by a fraction, the numerator of which is Knox’s working interest and
the denominator of which is 50%.
(3)
Knox has the right to participate in any or all wells at an amount equal to or less
than 50% working interest. Participation by Knox will cause an adjustment to the Net
Revenue Intrest and the Working Interest available to the Partnership.
(4)
Forty acres are earned for each well.
(5)
Held by production, provided Lessee maintains its annual drilling commitment.
(6)
12.5% of the gross proceeds free of all costs and expenses whatsoever for all gas
sold at the price of $3.00 per MMBtu. For all gross proceeds in excess of $3.00 per MMBtu,
Heartwood will receive an additional royalty equal to 3% of the gross proceeds received by
Lessee in excess of $3.00 per MMBtu. The payment for gas sold at a price of greater than
$3.00 per MMBtu will affect the Net Revenue Interest computation.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results,
although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
The purpose of the following investigation is to evaluate the geologic feasibility and
further development of the Tennessee Knox Energy Prospect Area as proposed by Atlas Energy
Resources, LLC (“Atlas”).
AREA OF INVESTIGATION
A portion of this prospect area, herein identified for drilling in ATLAS RESOURCES PUBLIC
#16-2007(A) L.P., contains acreage in Scott, Anderson and Morgan Counties of Tennessee. Twenty-one
(21) drilling prospects have currently been designated for this program in the prospect area, which
will be targeted to produce natural gas from Mississippian and Devonian reservoirs, found at depths
from 1500 feet to 5500 feet beneath the earth’s surface. These will be the only prospects evaluated
for the purposes of this report.
METHODOLOGY
Atlas and the in-house archives of UEDC, Inc. provided the data incorporated into this
report. Geological mapping and the interpretations by Atlas geologists were also examined.
Available “electric” log, completion and production data on “key” wells within and adjacent to the
defined prospect area were used to determine productive and depositional trends.
TENNESSEE KNOX ENERGY PROSPECT AREA
DRILLING ACTIVITY
The proposed drilling area lies in the Appalachian Plateau portion of northern Tennessee.
This historically oil producing area has seen recent activity targeting zones that have yielded
commercial gas production. Atlas has been actively drilling for natural gas for the last two years
and has established production in a few locales within this vast area. Drilling is ongoing as of
the date of this report with recent wells displaying favorable initial drilling and completion
results.
The depositional environments for the Mississippian carbonates range from shelf to lagoon
and near shore settings. The Devonian or Chattanooga Shale formed in an organic rich sea offshore
from the Catskill Delta.
The Mississippian reservoirs consist of the Monteagle limestone, St. Louis dolomite, Warsaw
limey siltstone and the Ft. Payne cherty limestone. The Chattanooga Shale underlies the Ft. Payne.
Diagram illustrates stratigraphic relationships.
The primary target in all wells in this area is the Monteagle Limestone. This limestone
contains thick deposits of Oolites, which provide porosity as high as 20%. Some wells have
encountered as much as 30 feet of this reservoir.
The Devonian Shale is another primary target in the area. This reservoir underlies the
Mississippian carbonates and is found in all wells throughout the area. This formation is not
only a reservoir when fractured, but is considered the source of the hydrocarbons found in the
overlying carbonates.
Secondary targets may also show development. The Ft. Payne is the primary reservoir for the
oil in adjacent fields found north and west of the prospect area. The St. Louis and Warsaw
reservoirs have been encountered less often, but could be considerable contributors in yet to be
developed parts of the vast prospect area.
Petroleum reservoirs are formed by the presence of an impermeable barrier trapping
commercial quantities of natural gas or oil in a more permeable medium. In the Mississippian
carbonate reservoirs this occurs in two ways. One way is when ooids (carbonate sands) are formed
and deposited (oolites) and are encased in less permeable limestones. Another way is when
limestone changes to dolomite during a change (“diagenesis”) at the atomic level of the rock.
Electric well logs (right) can be used in conjunction with production to interpret reservoir
parameters. When the carbonates in the Mississippian reservoirs develop porosity in excess of 5%,
the permeability of the reservoir can become great enough to allow commercial production of natural
gas. When small, naturally occurring cracks or fractures exist in the Chattanooga Shale,
permeability of the reservoir is enhanced. Audio logs can detect the small amounts of natural gas
that flow from the shale.
PRODUCTION
The Tennessee Knox Energy prospect area produces from several reservoirs of different age
and type. Each well has a unique combination of these reservoirs yielding different production
declines. While Atlas anticipates production from each reservoir to be comparable to like
reservoirs historically produced throughout the Appalachian Basin, a model decline curve for this
prospect area is not included due to the multiple sets of commingled reservoirs exclusively found
in this area.
UEDC has conducted a geologic feasibility study of the drilling area for ATLAS RESOURCES
PUBLIC #16-2007(A) L.P., which will consist of developmental drilling of Mississippian and Devonian
reservoirs in Scott, Anderson and Morgan Counties of Tennessee. It is the professional opinion of
UEDC that the drilling of the twenty-one (21) wells by ATLAS RESOURCES PUBLIC #16-2007(A) L.P. is
supported by sufficient geologic and engineering data.
DISCLAIMER
For the purpose of this evaluation, UEDC did not visit any leaseholds or inspect any of
the associated production equipment. Likewise, UEDC has no knowledge as to the validity of title,
liabilities, or corporate matters affecting these properties. UEDC does not warrant individual
well performance.
NON-INTEREST
We hereby confirm that UEDC is an independent consulting firm and that neither this firm
or any of it’s employees, contract consultants, or officers has, or is committed to acquire any
interest, directly or indirectly, in Atlas Energy Resources, LLC; nor is this firm, or any
employee, contract consultant, or officer thereof, otherwise affiliated with Atlas Energy
Resources, LLC. We also confirm that neither the employment of, nor payment of compensation
received by UEDC in connection with this report, is on a contingent basis.
FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED
PARTNERSHIP FOR ATLAS RESOURCES PUBLIC #16-2007(A) L.P.
[FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED
PARTNERSHIP FOR ATLAS RESOURCES PUBLIC #16-2007(B) L.P.]
THIS AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP (“AGREEMENT”), amending
and restating the original Certificate of Limited Partnership, is made and entered into as of the
date set forth below, by and among Atlas Resources, LLC, referred to as “Atlas” or the “Managing
General Partner,” and the remaining parties from time to time signing a Subscription Agreement for
Limited Partner Units, these parties sometimes referred to as “Limited Partners,” or for Investor
General Partner Units, these parties sometimes referred to as “Investor General Partners.”
ARTICLE I
FORMATION
1.01. Formation. The parties have formed a limited partnership under the Delaware Revised Uniform
Limited Partnership Act on the terms and conditions set forth in this Agreement.
1.02. Certificate of Limited Partnership. This document is not only an agreement among the
parties, but also is the Amended and Restated Certificate and Agreement of Limited Partnership of
the Partnership. This document shall be filed or recorded in the public offices required under
applicable law or deemed advisable in the discretion of the Managing General Partner. Amendments
to the certificate of limited partnership shall be filed or recorded in the public offices required
under applicable law or deemed advisable in the discretion of the Managing General Partner.
1.03. Name, Principal Office and Residence.
1.03(a). Name. The name of the Partnership is Atlas Resources Public #16-2007(A) L.P. [Atlas
Resources Public #16-2007(B) L.P.].
1.03(b). Residence. The residence of the Managing General Partner is its principal place of
business at 311 Rouser Road, Moon Township, Pennsylvania15108, which shall also serve as the
principal place of business of the Partnership.
The residence of each Participant shall be as set forth on the Subscription Agreement executed by
the Participant.
All addresses shall be subject to change on notice to the parties.
1.03(c). Agent for Service of Process. The name and address of the agent for service of process
shall be Andrew M. Lubin at 110 S. Poplar Street, Suite 101, Wilmington, Delaware19801.
1.04. Purpose. The Partnership shall engage in all phases of the natural gas and oil business.
This includes, without limitation, exploration for, development and production of natural gas and
oil on the terms and conditions set forth below and any other proper purpose under the Delaware
Revised Uniform Limited Partnership Act.
The Managing General Partner may not, without the affirmative vote of Participants whose Units
equal a majority of the total Units, do the following:
(i)
change the investment and business purpose of the Partnership; or
(ii)
cause the Partnership to engage in activities outside the stated business
purposes of the Partnership through joint ventures with other entities.
2.01. Definitions. As used in this Agreement, the following terms shall have the meanings set
forth below:
1.
“Administrative Costs” means all customary and routine expenses incurred by the
Sponsor for the conduct of Partnership administration, including: in-house legal,
finance, in-house accounting, secretarial, travel, office rent, telephone, data
processing and other items of a similar nature. Administrative Costs shall be limited
as follows:
(i)
no Administrative Costs charged shall be duplicated under any
other category of expense or cost; and
(ii)
no portion of the salaries, benefits, compensation or
remuneration of controlling persons of the Managing General Partner shall be
reimbursed by the Partnership as Administrative Costs. Controlling persons
include directors, executive officers and those holding a 5% or more equity
interest in the Managing General Partner or a person having power to direct or
cause the direction of the Managing General Partner, whether through the
ownership of voting securities, by contract, or otherwise.
2.
“Administrator” means the official or agency administering the securities laws
of a state.
3.
“Affiliate” means with respect to a specific person:
(i)
any person directly or indirectly owning, controlling, or holding
with power to vote 10% or more of the outstanding voting securities of the
specified person;
(ii)
any person 10% or more of whose outstanding voting securities are
directly or indirectly owned, controlled, or held with power to vote, by the
specified person;
(iii)
any person directly or indirectly controlling, controlled by, or
under common control with the specified person;
(iv)
any officer, director, trustee or partner of the specified
person; and
(v)
if the specified person is an officer, director, trustee or
partner, any person for which the person acts in any such capacity.
4.
“Agreement” means this Amended and Restated Certificate and Agreement of
Limited Partnership, including all exhibits to this Agreement.
5.
“Anthem Securities” means Anthem Securities, Inc., whose principal executive
offices are located at 311 Rouser Road, P.O. Box 926, Moon Township, Pennsylvania15108-0926.
6.
“Assessments” means additional amounts of capital which may be mandatorily
required of or paid voluntarily by a Participant beyond his subscription commitment.
7.
“Atlas” means Atlas Resources, LLC, a Pennsylvania limited liability company,
whose principal executive offices are located at 311 Rouser Road, Moon Township,
Pennsylvania15108, and any successor entity to Atlas Resources, LLC, whether by merger
or any other form of reorganization, or the acquisition of all, or substantially all,
of Atlas Resources, LLC’s assets.
8.
“Atlas Resources Public #16-2007 Program” means the offering of Units in a
series of up to two limited partnerships entitled Atlas Resources Public #16-2007(A)
L.P. and Atlas Resources Public #16-2007(B) L.P.
“Capital Account” or “account” means the account established for each party,
maintained as provided in §5.02 and its subsections.
10.
“Capital Contribution” means the amount agreed to be contributed to the
Partnership by a Partner pursuant to §§3.04 and 3.05 and their subsections.
11.
“Carried Interest” means an equity interest in the Partnership issued to a
Person without consideration, in the form of cash or tangible property, in an amount
proportionately equivalent to that received from the Participants.
12.
“Code” means the Internal Revenue Code of 1986, as amended.
13.
“Cost,” when used with respect to the sale or transfer of property to the
Partnership, means:
(i)
the sum of the prices paid by the seller or transferor to an
unaffiliated person for the property, including bonuses;
(ii)
title insurance or examination costs, brokers’ commissions,
filing fees, recording costs, transfer taxes, if any, and like charges in
connection with the acquisition of the property;
(iii)
a pro rata portion of the seller’s or transferor’s actual
necessary and reasonable expenses for seismic and geophysical services; and
(iv)
rentals and ad valorem taxes paid by the seller or transferor for
the property to the date of its transfer to the buyer, interest and points
actually incurred on funds used to acquire or maintain the property, and the
portion of the seller’s or transferor’s reasonable, necessary and actual
expenses for geological, geophysical, engineering, drafting, accounting, legal
and other like services allocated to the property cost in conformity with
generally accepted accounting principles and industry standards, except for
expenses in connection with the past drilling of wells which are not producers
of sufficient quantities of oil or gas to make commercially reasonable their
continued operations, and provided that the expenses enumerated in this
subsection (iv) shall have been incurred not more than 36 months before the sale
or transfer to the Partnership.
“Cost,” when used with respect to services, means the reasonable, necessary and
actual expense incurred by the seller on behalf of the Partnership in providing the
services, determined in accordance with generally accepted accounting principles.
As used elsewhere, “Cost” means the price paid by the seller in an arm’s-length
transaction.
14.
“Dealer-Manager” means Anthem Securities, Inc., an Affiliate of the Managing
General Partner, the broker/dealer which will manage the offering and sale of the
Units.
15.
“Development Well” means a well drilled within the proved area of a natural gas
or oil reservoir to the depth of a stratigraphic Horizon known to be productive.
16.
“Direct Costs” means all actual and necessary costs directly incurred for the
benefit of the Partnership and generally attributable to the goods and services
provided to the Partnership by parties other than the Sponsor or its Affiliates.
Direct Costs may not include any cost otherwise classified as Organization and Offering
Costs, Administrative Costs, Intangible Drilling Costs, Tangible Costs, Operating Costs
or costs related to the Leases, but may include the cost of services provided by the
Sponsor or its Affiliates if the
services are provided pursuant to written contracts and in compliance with
§4.03(d)(7) or pursuant to the Managing General Partner’s role as Tax Matters
Partner.
“Distribution Interest” means an undivided interest in the Partnership’s assets
after payments to the Partnership’s creditors or the creation of a reasonable reserve
therefor, in the ratio the positive balance of a party’s Capital Account bears to the
aggregate positive balance of the Capital Accounts of all of the parties determined
after taking into account all Capital Account adjustments for the taxable year during
which liquidation occurs (other than those made pursuant to liquidating distributions
or restoration of deficit Capital Account balances). Provided, however, after the
Capital Accounts of all of the parties have been reduced to zero, the interest in the
remaining Partnership assets shall equal a party’s interest in the related Partnership
revenues as set forth in §5.01 and its subsections.
18.
“Drilling and Operating Agreement” means the proposed Drilling and Operating
Agreement between the Managing General Partner or an Affiliate as Operator, and the
Partnership as Developer, a copy of the proposed form of which is attached to this
Agreement as Exhibit (II).
19.
“Exploratory Well” means a well drilled to:
(i)
find commercially productive hydrocarbons in an unproved area;
(ii)
find a new commercially productive Horizon in a field previously
found to be productive of hydrocarbons at another Horizon; or
(iii)
significantly extend a known prospect.
20.
“Farmout” means an agreement by the owner of the leasehold or Working Interest
to assign his interest in certain acreage or well to the assignees, retaining some
interest such as an Overriding Royalty Interest, an oil and gas payment, offset acreage
or other type of interest, subject to the drilling of one or more specific wells or
other performance as a condition of the assignment.
21.
“Final Terminating Event” means any one of the following:
(i)
the expiration of the Partnership’s fixed term;
(ii)
notice to the Participants by the Managing General Partner of its
election to terminate the Partnership’s affairs;
(iii)
notice by the Participants to the Managing General Partner of
their similar election through the affirmative vote of Participants whose Units
equal a majority of the total Units; or
(iv)
the termination of the Partnership under §708(b)(1)(A) of the
Code or the Partnership ceases to be a going concern.
22.
“Horizon” means a zone of a particular formation; that part of a formation of
sufficient porosity and permeability to form a petroleum reservoir.
23.
“Independent Expert” means a person with no material relationship to the
Sponsor or its Affiliates who is qualified and in the business of rendering opinions
regarding the value of natural gas and oil properties based on the evaluation of all
pertinent economic, financial, geologic and engineering information available to the
Sponsor or its Affiliates.
24.
“Initial Closing Date” means the date after the minimum amount of subscription
proceeds has been received when subscription proceeds are first withdrawn from the
escrow account.
25.
“Intangible Drilling Costs” or “Non-Capital Expenditures” means those
expenditures associated with property acquisition and the drilling and completion of
natural gas and oil wells that under present law are generally accepted as fully
deductible currently for federal income tax purposes. This includes:
all expenditures made for any well before production in
commercial quantities for wages, fuel, repairs, hauling, supplies and other
costs and expenses incident to and necessary for drilling the well and preparing
the well for production of natural gas or oil, that are currently deductible
pursuant to Section 263(c) of the Code and Treasury Reg. Section 1.612-4, and
are generally termed “intangible drilling and development costs”;
(ii)
the expense of plugging and abandoning any well before a
completion attempt; and
(iii)
the costs (other than Tangible Costs and Lease acquisition
costs) to re-enter and deepen an existing well, complete the well to deeper
reservoirs, or plug and abandon the well if it is nonproductive from the
targeted deeper reservoirs.
26.
“Interim Closing Date” means those date(s) after the Initial Closing Date, but
before the Offering Termination Date, that the Managing General Partner, in its sole
discretion, applies additional subscription proceeds to additional Partnership
activities, including drilling activities.
27.
“Investor General Partners” means:
(i)
the Persons signing the Subscription Agreement as Investor
General Partners; and
(ii)
the Managing General Partner to the extent of any optional
subscription as an Investor General Partner under §3.03(b)(1).
All Investor General Partners shall be of the same class and have the same rights.
28.
“Landowner’s Royalty Interest” means an interest in production, or its
proceeds, to be received free and clear of all costs of development, operation, or
maintenance, reserved by a landowner on the creation of a Lease.
29.
“Leases” means full or partial interests in natural gas and oil leases, oil and
natural gas mineral rights, fee rights, licenses, concessions, or other rights under
which the holder is entitled to explore for and produce oil and/or natural gas, and
includes any contractual rights to acquire any such interest.
30.
“Limited Partners” means:
(i)
the Persons signing the Subscription Agreement as Limited
Partners;
(ii)
the Managing General Partner to the extent of any optional
subscription as a Limited Partner under §3.03(b)(1);
(iii)
the Investor General Partners on the conversion of their
Investor General Partner Units to Limited Partner Units pursuant to §6.01(b);
and
(iv)
any other Persons who are admitted to the Partnership as
additional or substituted Limited Partners.
Except as provided in §3.05(b), with respect to the required additional Capital
Contributions of Investor General Partners, all Limited Partners shall be of the same
class and have the same rights.
31.
“Managing General Partner” means:
(i)
Atlas; or
(ii)
any Person admitted to the Partnership as a general partner,
other than as an Investor General Partner, who is designated to exclusively
supervise and manage the operations of the Partnership.
“Managing General Partner Signature Page” means an execution and subscription
instrument in the form attached as Exhibit (I-A) to this Agreement, which is
incorporated in this Agreement by reference.
33.
“Offering Termination Date” means the date after the minimum amount of
subscription proceeds has been received on which the Managing General Partner
determines, in its sole discretion, that the Partnership’s subscription period is
closed and the acceptance of subscriptions ceases, which may be any date up to and
including December 31, 2007.
Notwithstanding the above, the Offering Termination Date may not extend beyond the
time that subscriptions for the maximum number of Units set forth in §3.03(c)(1) have
been received and accepted by the Managing General Partner.
34.
“Operating Costs” means expenditures made and costs incurred in producing and
marketing natural gas or oil from completed wells. These costs include, but are not
limited to:
(i)
labor, fuel, repairs, hauling, materials, supplies, utility
charges and other costs incident to or related to producing and marketing
natural gas and oil;
(ii)
ad valorem and severance taxes;
(iii)
insurance and casualty loss expense; and
(iv)
compensation to well operators or others for services rendered in conducting these operations.
Operating Costs also include reworking, workover, subsequent equipping, and similar
expenses relating to any well, the Managing General Partner’s gathering fees set
forth in §4.04(a)(2)(d) and the reimbursement of the Managing General Partner’s
Administrative Costs set forth in §4.04(a)(2)(c); but do not include the costs to
re-enter and deepen an existing well, complete the well to deeper formations or
reservoirs, or plug and abandon the well if it is nonproductive from the targeted
deeper formations or reservoirs.
35.
“Operator” means Atlas, as operator of Partnership Wells in Pennsylvania, and
Atlas or an Affiliate as Operator of Partnership Wells in other areas of the United
States.
36.
“Organization and Offering Costs” means all costs of organizing and selling the
offering including, but not limited to:
(i)
total underwriting and brokerage discounts and commissions,
including fees of the underwriters’ attorneys, the Dealer-Manager fee, sales
commissions and the up to .5% reimbursement for bona fide due diligence
expenses;
(ii)
expenses for printing, engraving, mailing, salaries of employees
while engaged in sales activities, charges of transfer agents, registrars,
trustees, escrow holders, depositaries, engineers and other experts;
(iii)
expenses of qualification of the sale of the securities under
federal and state law, including taxes and fees, accountants’ and attorneys’
fees; and
(iv)
other front-end fees.
37.
“Organization Costs” means all costs of organizing the offering including, but
not limited to:
(i)
expenses for printing, engraving, mailing, salaries of employees
while engaged in sales activities, charges of transfer agents, registrars,
trustees, escrow holders, depositaries, engineers and other experts;
expenses of qualification of the sale of the securities under
federal and state law, including taxes and fees, accountants’ and attorneys’
fees; and
(iii)
other front-end fees.
38.
“Overriding Royalty Interest” means an interest in the natural gas and oil
produced under a Lease, or the proceeds from the sale thereof, carved out of the
Working Interest, to be received free and clear of all costs of development, operation,
or maintenance.
39.
“Participants” means:
(i)
the Managing General Partner to the extent of its optional
subscription under §3.03(b)(1);
(ii)
the Limited Partners; and
(iii)
the Investor General Partners.
40.
“Partners” means:
(i)
the Managing General Partner;
(ii)
the Investor General Partners; and
(iii)
the Limited Partners.
41.
“Partnership” means Atlas Resources Public #16-2007(A) L.P. [Atlas Resources
Public #16-2007(B) L.P.].
42.
“Partnership Net Production Revenues” means gross revenues after deduction of
the related Operating Costs, Direct Costs, Administrative Costs and all other
Partnership costs not specifically allocated.
43.
“Partnership Well” means a well, some portion of the revenues from which is
received by the Partnership.
44.
“Person” means a natural person, partnership, corporation, association, trust
or other legal entity.
45.
“Production Purchase” or “Income” Program means any program whose investment
objective is to directly acquire, hold, operate, and/or dispose of producing oil and
gas properties. Such a program may acquire any type of ownership interest in a
producing property, including, but not limited to, working interests, royalties, or
production payments. A program which spends at least 90% of capital contributions and
funds borrowed (excluding offering and organizational expenses) in the above described
activities is presumed to be a production purchase or income program.
46.
“Program” means one or more limited or general partnerships or other investment
vehicles formed, or to be formed, for the primary purpose of:
(i)
exploring for natural gas, oil and other hydrocarbon substances;
or
(ii)
investing in or holding any property interests which permit the
exploration for or production of hydrocarbons or the receipt of such production
or its proceeds.
47.
“Prospect” means an area covering lands which are believed by the Managing
General Partner to contain subsurface structural or stratigraphic conditions making it
susceptible to the accumulations of hydrocarbons in commercially productive quantities
at one or more Horizons. The area, which may be different for different Horizons,
shall be:
designated by the Managing General Partner in writing before the
conduct of Partnership operations; and
(ii)
enlarged or contracted from time to time on the basis of
subsequently acquired information to define the anticipated limits of the
associated hydrocarbon reserves and to include all acreage encompassed therein.
If the well to be drilled by the Partnership is to a Horizon containing Proved
Reserves, then a “Prospect” for a particular Horizon may be limited to the minimum
area permitted by state law or local practice, whichever is applicable, to protect
against drainage from adjacent wells. Subject to the foregoing sentence, “Prospect”
shall be deemed the drilling or spacing unit for the Clinton/Medina geological
formation, the Mississippian and/or Upper Devonian Sandstone reservoirs and the
Marcellus Shale reservoir in Ohio, Pennsylvania, and New York and the Mississippian
Carbonate or the Devonian Shale reservoirs in Anderson, Campbell, Morgan, Roane and
Scott Counties, Tennessee.
48.
“Prospectus” means the Prospectus included in the Registration Statement on
Form S-1 relating to the offer and sale of the Units which has been filed with the
Securities and Exchange Commission (the “Commission”) under the Securities Act of 1933,
as amended (the “Act”). As used in this Agreement, the terms “Prospectus” and
“Registration Statement” refer solely to the Prospectus and Registration Statement, as
amended, described above, except that:
(i)
from and after the date on which any post-effective amendment to
the Registration Statement is declared effective by the Commission, the term
“Registration Statement” shall refer to the Registration Statement as amended by
that post-effective amendment, and the term “Prospectus” shall refer to the
Prospectus then forming a part of the Registration Statement; and
(ii)
if the Prospectus filed pursuant to Rule 424(b) or (c)
promulgated by the Commission under the Act differs from the Prospectus on file
with the Commission at the time the Registration Statement or any post-effective
amendment thereto shall have become effective, the term “Prospectus” shall refer
to the Prospectus filed pursuant thereto from and after the date on which it was
filed.
49.
“Proved Developed Oil and Gas Reserves” means reserves that can be expected to
be recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural forces
and mechanisms of primary recovery should be included as “proved developed reserves”
only after testing by a pilot project or after the operation of an installed program
has confirmed through production response that increased recovery will be achieved.
50.
“Proved Reserves” means the estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date the estimate
is made. Prices include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future conditions.
(i)
Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The area of
a reservoir considered proved includes:
(a)
that portion delineated by drilling and defined by
gas-oil and/or oil-water contacts, if any; and
(b)
the immediately adjoining portions not yet drilled,
but which can be reasonably judged as economically productive on the
basis of available geological and engineering data.
In the absence of information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii)
Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are included in the
“proved” classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii)
Estimates of proved reserves do not include the following:
(a)
oil that may become available from known reservoirs
but is classified separately as “indicated additional reserves”;
(b)
crude oil, natural gas, and natural gas liquids,
the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic
factors;
(c)
crude oil, natural gas, and natural gas liquids,
that may occur in undrilled prospects; and
(d)
crude oil, natural gas, and natural gas liquids,
that may be recovered from oil shales, coal, gilsonite and other such
sources.
51.
“Proved Undeveloped Reserves” means reserves that are expected to be recovered
from either:
(i)
new wells on undrilled acreage; or
(ii)
from existing wells where a relatively major expenditure is
required for recompletion.
Reserves on undrilled acreage shall be limited to those drilling units offsetting
productive units that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where it can be demonstrated
with certainty that there is continuity of production from the existing productive
formation or there is continuity of the reservoir. Under no circumstances should
estimates for proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual tests in the area and in
the same reservoir.
52.
“Roll-Up” means a transaction involving the acquisition, merger, conversion or
consolidation, either directly or indirectly, of the Partnership and the issuance of
securities of a Roll-Up Entity. The term does not include:
(i)
a transaction involving securities of the Partnership that have
been listed for at least 12 months on a national exchange or traded through the
National Association of Securities Dealers Automated Quotation National Market
System; or
(ii)
a transaction involving the conversion to corporate, trust or
association form of only the Partnership if, as a consequence of the
transaction, there will be no significant adverse change in any of the
following:
“Roll-Up Entity” means a partnership, trust, corporation or other entity that
would be created or survive after the successful completion of a proposed roll-up
transaction.
54.
“Sales Commissions” means all underwriting and brokerage discounts and
commissions incurred in the sale of Units payable to registered broker/dealers, but
excluding the following:
(i)
the 2.5% Dealer-Manager fee; and
(ii)
the up to .5% reimbursement for bona fide due diligence expenses.
55.
“Selling Agents” means the broker/dealers which are selected by the
Dealer-Manager to participate in the offer and sale of the Units.
56.
“Sponsor” means any person directly or indirectly instrumental in organizing,
wholly or in part, a program or any person who will manage or is entitled to manage or
participate in the management or control of a program. The definition includes:
(i)
the managing and controlling general partner(s) and any other
person who actually controls or selects the person who controls 25% or more of
the exploratory, development or producing activities of the program, or any
segment thereof, even if that person has not entered into a contract at the time
of formation of the program; and
(ii)
whenever the context so requires, the term “sponsor” shall be
deemed to include its affiliates.
“Sponsor” does not include wholly independent third-parties such as attorneys,
accountants, and underwriters whose only compensation is for professional services
rendered in connection with the offering of units.
57.
“Subscription Agreement” means an execution and subscription instrument in the
form attached as Exhibit (I-B) to this Agreement, which is incorporated in this
Agreement by reference.
58.
“Tangible Costs” or “Capital Expenditures” means those costs associated with
property acquisition and drilling and completing natural gas and oil wells which are
generally accepted as capital expenditures under the Code. This includes all of the
following:
(i)
costs of equipment, parts and items of hardware used in drilling
and completing a well;
(ii)
the costs (other than Intangible Drilling Costs and Lease
acquisition costs) to re-enter and deepen an existing well, complete the well to
deeper reservoirs, or plug and abandon the well if it is nonproductive from the
targeted deeper reservoirs; and
(iii)
those items necessary to deliver acceptable natural gas and oil
production to purchasers to the extent installed downstream from the wellhead of
any well and which are required to be capitalized under the Code and its
regulations.
59.
“Tax Matters Partner” means the Managing General Partner.
60.
“Units” or “Units of Participation” means up to 100 Limited Partner interests
in the Partnership and up to 19,900 Investor General Partner interests in the
Partnership, which will be converted to up to 19,900 Limited Partner Units as set forth
in §6.01(b), purchased by Participants in the Partnership under the provisions of §3.03
and its subsections, including any rights to profits, losses, income, gain, credits,
deductions, cash distributions or returns of capital or other attributes of the Units.
61.
“Working Interest” means an interest in a Lease which is subject to some
portion of the cost of development, operation, or maintenance of the Lease.
ARTICLE III
SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
3.01. Designation of Managing General Partner and Participants. Atlas shall serve as Managing
General Partner of the Partnership. Atlas shall further serve as a Participant to the extent of
any subscription made by it pursuant to §3.03(b)(1).
Limited Partners and Investor General Partners, including the Managing General Partner and its
Affiliates to the extent, if any, they purchase Units, shall serve as Participants.
3.02. Participants.
3.02(a). Limited Partner at Formation. Atlas America, Inc., as Original Limited Partner, has
acquired one Unit and has made a Capital Contribution of $100. On the admission of one or more
Limited Partners, the Partnership shall return to the Original Limited Partner its Capital
Contribution and shall reacquire its Unit. The Original Limited Partner shall then cease to be a
Limited Partner in the Partnership with respect to that Unit.
3.02(b). Offering of Interests. The Partnership is authorized to admit to the Partnership at the
Initial Closing Date, any Interim Closing Date(s), and the Offering Termination Date additional
Participants whose Subscription Agreements are accepted by the Managing General Partner if, after
the admission of the additional Participants, the total Units sold do not exceed the maximum number
of Units set forth in §3.03(c)(1).
3.02(c). Admission of Participants. No action or consent by the Participants shall be required
for the admission of additional Participants pursuant to this Agreement.
All subscribers’ funds shall be held in an interest bearing account or accounts by an independent
escrow holder and shall not be released to the Partnership until the receipt and acceptance of the
minimum amount of subscription proceeds set forth in §3.03(c)(2). Thereafter, subscriptions may be
paid directly to the Partnership account.
3.03. Subscriptions to the Partnership.
3.03(a). Subscriptions by Participants.
3.03(a)(1). Subscription Price and Minimum Subscription. The subscription price of a Unit in the
Partnership shall be $10,000, except as set forth below, and shall be designated on each
Participant’s Subscription Agreement and payable as set forth in §3.05(b)(1). The minimum
subscription per Participant shall be one Unit ($10,000). Larger subscriptions shall be accepted
in $1,000 increments, beginning with $11,000, $12,000, etc.
Notwithstanding the foregoing, the subscription price for:
(i)
the Managing General Partner, its officers, directors, and Affiliates, and
Participants who buy Units through the officers and directors of the Managing General
Partner, shall be reduced by an amount equal to the 2.5% Dealer-Manager fee, the 7%
Sales Commission and the .5% reimbursement of the Selling Agents’ bona fide due
diligence expenses, which shall not be paid with respect to those sales; and
(ii)
Registered Investment Advisors and their clients, and Selling Agents and their
registered representatives and principals, shall be reduced by an amount equal to the
7% Sales Commission, which shall not be paid with respect to those sales.
No more than 5% of the total Units in the Partnership shall be sold with the discounts described
above.
3.03(a)(2). Effect of Subscription. Execution of a Subscription Agreement shall serve as an
agreement by the Participant to be bound by each and every term of this Agreement.
3.03(b). Optional Subscriptions for Units by Managing General Partner.
3.03(b)(1). Managing General Partner’s Optional Subscriptions for Units. In addition to the
Managing General Partner’s required Capital Contributions under §3.04(a), on the Initial Closing
Date the Managing General Partner may subscribe under the provisions of §3.03(a) and its
subsections for up to 5% of the total Units sold in the Partnership as of the Initial Closing Date,
which shall not be applied towards the minimum number of Units required to be sold under
§3.03(c)(2), and, subject to the limitations on voting rights set forth in §4.03(c)(3), to that
extent shall be deemed to be a Participant in the Partnership for all purposes under this
Agreement.
3.03(b)(2). Effect of and Evidencing Subscription. The Managing General Partner has executed a
Managing General Partner Signature Page which:
(i)
evidences the Managing General Partner’s required Capital Contributions under
§3.04(a); and
(ii)
may be amended, from time-to-time, to reflect the amount of any optional
subscriptions for Units as a Participant under §3.03(b)(1).
Execution of the Managing General Partner Signature Page serves as an agreement by the Managing
General Partner to be bound by each and every term of this Agreement.
3.03(c). Maximum and Minimum Number of Units.
3.03(c)(1). Maximum Number of Units. The maximum number of Units may not exceed 20,000 Units,
which is up to $200,000,000 of cash subscription proceeds, excluding the subscription discounts
permitted under §3.03(a)(1). Notwithstanding the foregoing, the maximum number of Units in all of
the partnerships in the Atlas Resources Public #16-2007 Program, in the aggregate, shall not exceed
20,000 Units which is up to $200,000,000 of cash subscription proceeds excluding the subscription
discounts permitted under §3.03(a)(1).
3.03(c)(2). Minimum Number of Units. The minimum number of Units shall equal at least 200 Units,
but in any event not less than the number of Units that provides the Partnership with cash
subscription proceeds of $2,000,000, excluding the subscription discounts permitted under
§3.03(a)(1).
If subscriptions for the minimum number of Units have not been received and accepted at the
Offering Termination Date, then all monies deposited by subscribers shall be promptly returned to
them. They shall receive interest earned on their subscription proceeds from the date the monies
were deposited in escrow through the date of refund, without deduction for any fees.
The partnership may break escrow and begin its drilling activities, in the Managing General
Partner’s sole discretion, on receipt and acceptance of the minimum subscription proceeds.
3.03(d). Acceptance of Subscriptions.
3.03(d)(1). Discretion by the Managing General Partner. Acceptance of subscriptions is
discretionary with the Managing General Partner. The Managing General Partner may reject any
subscription for any reason it deems appropriate.
3.03(d)(2). Time Period in Which to Accept Subscriptions. Subscriptions shall be accepted or
rejected by the Managing General Partner within 30 days of their receipt. If a subscription is
rejected, then all of the subscriber’s funds shall be returned to the subscriber promptly, with
interest earned and without deduction for any fees.
3.03(d)(3). Admission to the Partnership. The Participants shall be admitted to the Partnership
as follows:
(i)
not later than 15 days after the release from the escrow account of
Participants’ subscription proceeds to the Partnership; or
if a Participant’s subscription proceeds are received by the Partnership after
the close of the escrow account, then not later than the last day of the calendar month
in which his Subscription Agreement was accepted by the Managing General Partner.
3.04. Capital Contributions of the Managing General Partner.
3.04(a). Managing General Partner’s Required Capital Contributions. The Managing General Partner,
as a general partner and not as a Participant, is required to pay the costs or make the other
required Capital Contributions charged to it under this Agreement, including contributing to the
Partnership the Leases which will be drilled by the Partnership on the terms set forth in
§4.01(a)(4), in an amount equal to not less than 25%, in the aggregate, of all Capital
Contributions to the Partnership, at the time the costs are required to be paid by the Partnership,
but no later than December 31, 2008.
3.04(b). On Liquidation the Managing General Partner Must Contribute Deficit Balance in Its
Capital Account. The Managing General Partner shall contribute to the Partnership any deficit
balance in its Capital Account on the occurrence of either of the following events:
(i)
the liquidation of the Partnership; or
(ii)
the liquidation of the Managing General Partner’s interest in the Partnership.
This shall be determined after taking into account all adjustments for the Partnership’s taxable
year during which the liquidation occurs, other than adjustments made pursuant to this requirement,
by the end of the taxable year in which the liquidation occurs or, if later, within 90 days after
the date of the liquidation.
3.04(c). Managing General Partner’s Partnership Interest for Capital Contributions. The interest
of the Managing General Partner, as Managing General Partner and not as a Participant, in the
capital and profits of the Partnership is fully vested and nonforfeitable as of the date of the
formation of the Partnership and is in consideration for, and is the only consideration for, its
required Capital Contributions to the Partnership.
3.04(d). Managing General Partner’s Right to Assign Its Partnership Interest. Subject to
§5.01(b)(4)(a) regarding the Managing General Partner’s subordination obligation, the Managing
General Partner has the right at any time, in its discretion, without the consent of the
Participants, and without affecting the allocation of costs and revenues to the Participants or the
Managing General Partner’s voting rights under this Agreement, to sell, contribute, exchange or
otherwise transfer all or any portion of its interest as Managing General Partner or as a
Participant (if it purchases Units) in the Partnership, or any interest therein to an Affiliate of
the Managing General Partner. In that event, except as otherwise may be permitted under this
Agreement, if the Affiliated transferee of the Managing General Partner’s transferred interest in
the Partnership does not become a substituted Managing General Partner in the Partnership, the
Affiliated transferee, as a partner in the Partnership for tax purposes only, shall have the right
to receive the share of the Partnership’s profits, losses, income, gains, deductions, credits and
depletion allowances, or items thereof, and cash distributions and returns of capital (including,
but not limited to, cash distributions and returns of capital on dissolution and liquidation of the
Partnership) to which the Managing General Partner would otherwise be entitled under this Agreement
with respect to its transferred interest in the Partnership.
Subject to the foregoing, the transfer of the Managing General Partner’s interest in the
Partnership to any of its Affiliates may be made on any terms and conditions as the Managing
General Partner determines, in its discretion, and the Partnership and the Participants shall have
no right to receive or otherwise share in any consideration received by the Managing General
Partner from its Affiliates for the transfer of the Managing General Partner’s interest in the
Partnership.
No transfer of the Managing General Partner’s interest in the Partnership to its Affiliates under
this §3.04(d) shall require an accounting by the Managing General Partner or the Partnership to the
Participants.
3.05. Payment of Subscriptions.
3.05(a). Managing General Partner’s Subscriptions. The Managing General Partner shall pay any
optional subscription under §3.03(b)(1) as set forth in §3.05(b)(1).
3.05(b). Participant Subscriptions and Additional Capital Contributions of the Investor General
Partners.
3.05(b)(1). Payment of Subscription Agreements. A Participant shall pay the subscription amount
designated on his Subscription Agreement 100% in cash at the time of subscribing. A Participant
shall receive interest on the amount he pays from the time his subscription proceeds are deposited
in the escrow account, or a Partnership account after the minimum number of Units have been
received as provided in §3.06(b), until his subscription proceeds are paid by the Partnership to
the Managing General Partner under the Drilling and Operating Agreement for use in the
Partnership’s drilling activities. All interest distributions shall be in the ratio that the
number of Units held by each Participant multiplied by the number of days the Participant’s
subscription proceeds were held in the escrow account, or a Partnership account after the minimum
number of Units have been received as provided in §3.06(b), bears to the sum of that calculation
for all Participants whose subscription proceeds were paid to the Managing General Partner at the
same time.
3.05(b)(2). Additional Required Capital Contributions of the Investor General Partners. Investor
General Partners must make Capital Contributions to the Partnership when called by the Managing
General Partner, in addition to their subscription amounts, for their pro rata share of any
Partnership obligations and liabilities which are recourse to the Investor General Partners and are
represented by their ownership of Units before the conversion of Investor General Units to Limited
Partner Units under §6.01(b).
3.05(b)(3). Default Provisions. The failure of an Investor General Partner to timely make a
required additional Capital Contribution under this section results in his personal liability to
the other Investor General Partners for the amount in default. The remaining Investor General
Partners, in proportion to their respective number of Units, must pay the defaulting Investor
General Partner’s share of Partnership liabilities and obligations called for by the Managing
General Partner. In that event, the remaining Investor General Partners:
(i)
shall have a first and preferred lien on the defaulting Investor General
Partner’s interest in the Partnership to secure payment of the amount in default plus
interest at the legal rate;
(ii)
shall be entitled to receive 100% of the defaulting Investor General Partner’s
cash distributions, in proportion to their respective number of Units, until the amount
in default is recovered in full plus interest at the legal rate; and
(iii)
may commence legal action to collect the amount due plus interest at the legal
rate.
3.06. Partnership Funds.
3.06(a). Fiduciary Duty. The Managing General Partner has a fiduciary responsibility for the
safekeeping and use of all funds and assets of the Partnership, whether or not in the Managing
General Partner’s possession or control. The Managing General Partner shall not employ, or permit
another to employ, the funds and assets of the Partnership in any manner except for the exclusive
benefit of the Partnership.
Neither this Agreement nor any other agreement between the Managing General Partner and the
Partnership shall contractually limit any fiduciary duty owed to the Participants by the Managing
General Partner under applicable law.
3.06(b). Special Account After the Receipt of the Minimum Partnership Subscriptions. Following
the receipt of the minimum number of Units and breaking escrow, the funds of the Partnership shall
be held in a separate interest-bearing account maintained for the Partnership and shall not be
commingled with funds of any other entity.
3.06(c). Investment.
3.06(c)(1). Investments in Other Entities. Partnership funds shall not be invested in the
securities of another person except in the following instances:
(i)
investments in Working Interests or undivided Lease interests made in the
ordinary course of the Partnership’s business;
temporary investments made as set forth in §3.06(c)(2);
(iii)
multi-tier arrangements meeting the requirements of §4.03(d)(15);
(iv)
investments involving less than 5% of the Partnership’s subscription proceeds
which are a necessary and incidental part of a property acquisition transaction; and
(v)
investments in entities established solely to limit the Partnership’s
liabilities associated with the ownership or operation of property or equipment,
provided that duplicative fees and expenses shall be prohibited.
3.06(c)(2). Permissible Investments Before Investment in Partnership Activities. After the
Initial Closing Date and until proceeds from the offering are invested in the Partnership’s
operations, the proceeds may be temporarily invested in income producing short-term, highly liquid
investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills.
ARTICLE IV
CONDUCT OF OPERATIONS
4.01. Acquisition of Leases.
4.01(a). Assignment to Partnership.
4.01(a)(1). In General. The Managing General Partner shall select, acquire and assign or cause to
have assigned to the Partnership full or partial interests in Leases, by any method customary in
the natural gas and oil industry, subject to the terms and conditions set forth below.
The Partnership and the other partnerships in the Atlas Resources Public #16-2007 Program may
acquire and develop interests in Leases covering one or more of the same Prospects, in the Managing
General Partner’s discretion.
The Partnership shall acquire only Leases reasonably expected to meet the stated purposes of the
Partnership. No Leases shall be acquired for the purpose of a subsequent sale, Farmout, or other
disposition unless the acquisition is made after a well has been drilled to a depth sufficient to
indicate that the acquisition would be in the Partnership’s best interest.
4.01(a)(2). Federal and State Leases. The Partnership is authorized to acquire Leases on federal
and state lands.
4.01(a)(3). Managing General Partner’s Discretion as to Terms and Burdens of Acquisition. Subject
to the provisions of §4.03(d) and its subsections, the acquisitions of Leases or other property may
be made under any terms and obligations, including any limitations as to the Horizons to be
assigned to the Partnership and subject to any burdens as the Managing General Partner deems
necessary in its sole discretion.
4.01(a)(4). Cost of Leases. All Leases shall be:
(i)
contributed to the Partnership by the Managing General Partner or its
Affiliates; and
(ii)
credited towards the Managing General Partner’s required Capital Contribution
set forth in §3.04(a) at the Cost of the Lease, unless the Managing General Partner has
cause to believe that Cost is materially more than the fair market value of the
property, in which case the credit for the contribution must be made at a price not in
excess of the fair market value.
A determination of fair market value must be supported by an appraisal from an Independent Expert.
4.01(a)(5). The Managing General Partner, Operator or Their Affiliates’ Rights in the Remainder
Interests. Subject to the provisions of §4.03(d) and its subsections, to the extent the
Partnership does not acquire a full interest in a Lease from the Managing General Partner or its
Affiliates, the remainder of the interest in the Lease may be held by the Managing General Partner
or its Affiliates. They may either:
retain and exploit the remaining interest for their own account; or
(ii)
sell or otherwise dispose of all or a part of the remaining interest.
Profits from the exploitation and/or disposition of their retained interests in the Leases shall be
for the benefit of the Managing General Partner or its Affiliates to the exclusion of the
Partnership and the Participants.
4.01(a)(6). No Breach of Duty. Subject to the provisions of §4.03 and its subsections,
acquisition of Leases from the Managing General Partner, the Operator or their Affiliates shall not
be considered a breach of any obligation owed by them to the Partnership or the Participants.
4.01(b). No Overriding Royalty Interests. Neither the Managing General Partner, the Operator nor
any Affiliate shall retain any Overriding Royalty Interest on the Leases acquired by the
Partnership.
4.01(c). Title and Nominee Arrangements.
4.01(c)(1). Legal Title. Legal title to all Leases acquired by the Partnership shall be held on a
permanent basis in the name of the Partnership. However, Partnership properties may be held
temporarily in the name of:
(i)
the Managing General Partner;
(ii)
the Operator;
(iii)
their Affiliates; or
(iv)
in the name of any nominee designated by the Managing General Partner to
facilitate the acquisition of the properties.
4.01(c)(2). Managing General Partner’s Discretion. The Managing General Partner shall take the
steps which are necessary in its best judgment to render title to the Leases to be acquired by the
Partnership acceptable for the purposes of the Partnership. The Managing General Partner shall be
free, however, to use its own best judgment in waiving title requirements.
The Managing General Partner shall not be liable to the Partnership or to the other parties for any
mistakes of judgment; nor shall the Managing General Partner be deemed to be making any warranties
or representations, express or implied, as to the validity or merchantability of the title to the
Leases assigned to the Partnership or the extent of the interest covered thereby except as
otherwise provided in the Drilling and Operating Agreement.
4.01(c)(3). Commencement of Operations. The Partnership shall not begin operations on its Leases
unless the Managing General Partner is satisfied that necessary title requirements have been
satisfied.
4.02. Conduct of Operations.
4.02(a). In General. The Managing General Partner shall establish a program of operations for the
Partnership. Subject to the limitations contained in Article III of this Agreement concerning the
maximum Capital Contribution which can be required of a Limited Partner, the Managing General
Partner, the Limited Partners, and the Investor General Partners agree to participate in the
program so established by the Managing General Partner.
4.02(b). Management. Subject to any restrictions contained in this Agreement, the Managing
General Partner shall exercise full control over all operations of the Partnership.
4.02(c). General Powers of the Managing General Partner.
4.02(c)(1). In General. Subject to the provisions of §4.03 and its subsections, and to any
authority that may be granted the Operator under §4.02(c)(3)(b), the Managing General Partner shall
have full authority to do all things deemed necessary or
desirable by it in the conduct of the
business of the Partnership. Without limiting the generality of the foregoing, the Managing
General Partner is expressly authorized to engage in:
(i)
the making of all determinations of which Leases, wells and operations will be
participated in by the Partnership, which includes:
(a)
which Leases are developed;
(b)
which Leases are abandoned; or
(c)
which Leases are sold or assigned to other parties, including
other investor ventures organized by the Managing General Partner, the Operator,
or any of their Affiliates;
(ii)
the negotiation and execution on any terms deemed desirable in its sole
discretion of any contracts, conveyances, or other instruments, considered useful to
the conduct of the operations or the implementation of the powers granted it under this
Agreement, including, without limitation:
(a)
the making of agreements for the conduct of operations, including
agreements and financial instruments relating to hedging the Partnership’s
natural gas and oil and in this regard, the partnership has confirmed its
authorization to Atlas America and/or Atlas Energy Resources, LLC to enter into
hedging agreements on its behalf, and has ratified all actions previously taken
by Atlas America and/or Atlas Energy Resources, LLC in connection therewith;
(b)
the exercise of any options, elections, or decisions under any
such agreements; and
(c)
the furnishing of equipment, facilities, supplies and material,
services, and personnel;
(iii)
the exercise, on behalf of the Partnership or the parties, as the Managing
General Partner in its sole judgment deems best, of all rights, elections and options
granted or imposed by any agreement, statute, rule, regulation, or order;
(iv)
the making of all decisions concerning the desirability of payment, and the
payment or supervision of the payment, of all delay rentals and shut-in and minimum or
advance royalty payments;
(v)
the selection of full or part-time employees and outside consultants and
contractors and the determination of their compensation and other terms of employment
or hiring;
(vi)
the maintenance of insurance for the benefit of the Partnership and the parties
as it deems necessary, but in no event less in amount or type than the following:
(a)
worker’s compensation insurance in full compliance with the laws
of the Commonwealth of Pennsylvania and any other applicable state laws;
(b)
liability insurance, including automobile, which has a $1,000,000
combined single limit for bodily injury and property damage in any one accident
or occurrence and in the aggregate; and
(c)
liability and excess liability insurance as to bodily injury and
property damage with combined limits of $50,000,000 during drilling operations
and thereafter, per occurrence or accident and in the aggregate, which includes
$1,000,000 of seepage, pollution and contamination insurance which protects and
defends the insured against property damage or bodily injury claims from
third-parties, other than a co-owner of the Working Interest, alleging seepage,
pollution or contamination damage resulting from a pollution incident. The
excess liability insurance, which is for general liability only, shall be in
place and effective no later than the date drilling operations begin and, for
purposes of satisfying this requirement, the Partnership shall have the benefit
of the Managing General
Partner’s $50,000,000 liability insurance on the same
basis as the Managing General Partner and its other Affiliates, including the
Managing General Partner’s other Programs;
(vii)
the use of the funds and revenues of the Partnership, and the borrowing on
behalf of, and the loan of money to, the Partnership, on any terms it sees fit, for any
purpose, including without limitation:
(a)
the conduct or financing, in whole or in part, of the drilling
and other activities of the Partnership;
(b)
the conduct of additional operations; and
(c)
the repayment of any borrowings or loans used initially to
finance these operations or activities;
(viii)
the disposition, hypothecation, sale, exchange, release, surrender, reassignment or
abandonment of any or all assets of the Partnership, including without limitation, the
Leases, wells, equipment and production therefrom, provided that the sale of all or
substantially all of the assets of the Partnership shall only be made as provided in
§4.03(d)(6);
(ix)
the formation of any further limited or general partnership, tax partnership,
joint venture, or other relationship which it deems desirable with any parties who it,
in its sole discretion, selects, including any of its Affiliates;
(x)
the control of any matters affecting the rights and obligations of the
Partnership, including:
(a)
the employment of attorneys to advise and otherwise represent the
Partnership;
(b)
the conduct of litigation and incurring other legal expenses; and
(c)
the settlement of claims and litigation;
(xi)
the operation of producing wells drilled on the Leases or on a Prospect which
includes any part of the Leases;
(xii)
the exercise of the rights granted to it under the power of attorney created
under this Agreement; and
(xiii)
the incurring of all costs and the making of all expenditures in any way related to
any of the foregoing.
4.02(c)(2). Scope of Powers. The Managing General Partner’s powers shall extend to any operation
participated in by the Partnership or affecting its Leases, or other property or assets,
irrespective of whether or not the Managing General Partner is designated operator of the operation
by any outside persons participating therein.
4.02(c)(3). Delegation of Authority.
4.02(c)(3)(a). In General. The Managing General Partner may subcontract and delegate all or any
part of its duties under this Agreement to any entity chosen by it, including an entity Affiliated
with it, which party shall have the same powers in the conduct of the duties as would the Managing
General Partner. The delegation, however, shall not relieve the Managing General Partner of its
responsibilities under this Agreement.
4.02(c)(3)(b). Delegation to Operator. The Managing General Partner is specifically authorized to
delegate any or all of its duties to the Operator by executing the Drilling and Operating
Agreement. This delegation shall not relieve the Managing General Partner of its responsibilities
under this Agreement.
In no event shall any consideration received for operator services be in excess of competitive
rates or duplicative of any consideration or reimbursements received under this Agreement. The
Managing General Partner may not benefit by interpositioning itself between the Partnership and the
actual provider of operator services.
4.02(c)(4). Related Party Transactions. Subject to the provisions of §4.03 and its subsections,
any transaction which the Managing General Partner is authorized to enter into on behalf of the
Partnership under the authority granted in this section and its subsections, may be entered into by
the Managing General Partner with itself or with any other general partner, the Operator, or any of
their Affiliates.
4.02(d). Additional Powers. In addition to the powers granted the Managing General Partner under
§4.02(c) and its subsections or elsewhere in this Agreement, the Managing General Partner, when
specified, shall have the following additional express powers.
4.02(d)(1). Drilling Contracts. All Partnership Wells shall be drilled under the Drilling and
Operating Agreement for an amount equal to the sum of the following items:
(i)
the Cost of permits, supplies, materials, equipment, and all other items used
in the drilling and completion of a well provided by third-parties, or if the foregoing
items are provided by Affiliates of the Managing General Partner, then those items will
be charged at competitive rates;
(ii)
fees for third-party services;
(iii)
fees for services provided by the Managing General Partner’s Affiliates, which
will be charged at competitive rates;
(iv)
an administration and oversight fee of $15,000 per well, which will be charged
to the Participants as part of each well’s Intangible Drilling Costs and the portion of
equipment costs paid by the Participants; and
(v)
a mark-up in an amount equal to 15% of the sum of (i), (ii), (iii) and (iv),
above, for the Managing General Partner’s services as general drilling contractor.
Additionally, if the Managing General Partner drills a well for the Partnership that the Managing
General Partner determines is not an average well in the area because of the well’s depth,
complexity associated with either drilling or completing the well, or as otherwise determined by
the Managing General Partner, the administration and oversight fee of $15,000 per well described in
§4.02(d)(1)(iv) may be increased to a competitive rate as determined by the Managing General
Partner.
The Managing General Partner or its Affiliates, as drilling contractor, may not receive a rate that
is not competitive with the rates charged by unaffiliated contractors in the same geographic
region, enter into a turnkey drilling contract with the Partnership, profit by drilling in
contravention of its fiduciary obligations to the Partnership, or benefit by interpositioning
itself between the Partnership and the actual provider of drilling contractor services.
4.02(d)(2). Power of Attorney.
4.02(d)(2)(a). In General. Each Participant appoints the Managing General Partner his true and
lawful attorney-in-fact for him and in his name, place, and stead and for his use and benefit, from
time to time:
(i)
to create, prepare, complete, execute, file, swear to, deliver, endorse, and
record any and all documents, certificates, government reports, or other instruments as
may be required by law, or are necessary to amend this Agreement as authorized under
the terms of this Agreement, or to qualify the Partnership as a limited partnership or
partnership in commendam and to conduct business under the laws of any jurisdiction in
which the Managing General Partner elects to qualify the Partnership or conduct
business; and
(ii)
to create, prepare, complete, execute, file, swear to, deliver, endorse and
record any and all instruments, assignments, security agreements, financing statements,
certificates, and other documents as may be necessary from time to time to implement
the borrowing powers granted under this Agreement.
4.02(d)(2)(b). Further Action. Each Participant authorizes the attorney-in-fact to take any
further action which the attorney-in-fact considers necessary or advisable in connection with any
of the foregoing powers and rights granted the Managing
General Partner under this section and its
subsections. Each party acknowledges that the power of attorney granted under §4.02(d)(2)(a):
(i)
is a special power of attorney coupled with an interest and is irrevocable; and
(ii)
shall survive the assignment by the Participant of the whole or a portion of
his Units; except when the assignment is of all of the Participant’s Units and the
purchaser, transferee, or assignee of the Units is admitted as a successor Participant,
the power of attorney shall survive the delivery of the assignment for the sole purpose
of enabling the attorney-in-fact to execute, acknowledge, and file any agreement,
certificate, instrument or document necessary to effect the substitution.
4.02(d)(2)(c). Power of Attorney to Operator. The Managing General Partner is hereby authorized
to grant a Power of Attorney to the Operator on behalf of the Partnership.
4.02(e). Borrowings and Use of Partnership Revenues.
4.02(e)(1). Power to Borrow or Use Partnership Revenues.
4.02(e)(1)(a). In General. If additional funds over the Participants’ Capital Contributions are
needed for Partnership operations, then the Managing General Partner may:
(i)
use Partnership revenues for such purposes; or
(ii)
the Managing General Partner and its Affiliates may advance the necessary funds
to the Partnership under §4.03(d)(8)(b), although they are not obligated to advance the
funds to the Partnership.
4.02(e)(1)(b). Limitation on Borrowing. Partnership borrowings, other than credit transactions on
open account customary in the industry to obtain goods and services, shall be subject to the
following limitations:
(i)
the borrowings must be without recourse to the Investor General Partners and
the Limited Partners except as otherwise provided in this Agreement; and
(ii)
the amount that may be borrowed at any one time may not exceed an amount equal
to 5% of the Partnership’s subscription proceeds.
4.02(f). Tax Matters Partner.
4.02(f)(1). Designation of Tax Matters Partner. The Managing General Partner is hereby designated
the Tax Matters Partner of the Partnership under Section 6231(a)(7) of the Code. The Managing
General Partner is authorized to act in this capacity on behalf of the Partnership and the
Participants and to take any action, including settlement or litigation, which it in its sole
discretion deems to be in the best interest of the Partnership.
4.02(f)(2). Costs Incurred by Tax Matters Partner. Costs incurred by the Tax Matters Partner
shall be considered a Direct Cost of the Partnership.
4.02(f)(3). Notice to Participants of IRS Proceedings. The Tax Matters Partner shall notify all
of the Participants of any administrative or other legal proceedings involving the Partnership and
the IRS or any other taxing authority, and thereafter shall furnish all of the Participants
periodic reports at least quarterly on the status of the proceedings.
4.02(f)(4). Participant Restrictions. Each Participant agrees as follows:
(i)
he will not file the statement described in Section 6224(c)(3)(B) of the Code
prohibiting the Managing General Partner as the Tax Matters Partner for the Partnership
from entering into a settlement on his behalf with respect to partnership items, as
that term is defined in Section 6231(a)(3) of Code, of the Partnership;
he will not form or become and exercise any rights as a member of a group of
Partners having a 5% or greater interest in the profits of the Partnership under
Section 6223(b)(2) of the Code; and
(iii)
the Managing General Partner is authorized to file a copy of this Agreement,
or pertinent portions of this Agreement, with the IRS under Section 6224(b) of the Code
if necessary to perfect the waiver of rights under this subsection.
4.03. General Rights and Obligations of the Participants and Restricted and Prohibited
Transactions.
4.03(a)(1). Limited Liability of Limited Partners. Limited Partners shall not be bound by the
obligations of the Partnership other than as provided under the Delaware Revised Uniform Limited
Partnership Act. Limited Partners shall not be personally liable for any debts of the Partnership
or any of the obligations or losses of the Partnership beyond the subscription amount designated on
the Subscription Agreement executed by each respective Limited Partner unless:
(i)
they also subscribe to the Partnership as Investor General Partners; or
(ii)
in the case of the Managing General Partner, it purchases Limited Partner
Units.
4.03(a)(2). No Management Authority of Participants. Participants, other than the Managing
General Partner if it buys Units, shall have no power over the conduct of the affairs of the
Partnership. No Participant, other than the Managing General Partner if it buys Units, shall take
part in the management of the business of the Partnership, or have the power to sign for or to bind
the Partnership.
4.03(b). Reports and Disclosures.
4.03(b)(1). Annual Reports and Financial Statements. Beginning with the calendar year in which
the Partnership had its Offering Termination Date, the Partnership shall provide each Participant
an annual report within 120 days after the close of that calendar year, and beginning with the
following calendar year, a report within 75 days after the end of the first six months of its
calendar year, containing except as otherwise indicated, at least the information set forth below:
(i)
Audited financial statements of the Partnership, including a balance sheet and
statements of income, cash flow, and Partners’ equity, which shall be prepared on an
accrual basis in accordance with generally accepted accounting principles with a
reconciliation with respect to information furnished for income tax purposes and
accompanied by an auditor’s report containing an opinion of an independent public
accountant selected by the Managing General Partner stating that his audit was made in
accordance with generally accepted auditing standards and that in his opinion the
financial statements present fairly the financial position, results of operations,
partners’ equity, and cash flows in accordance with generally accepted accounting
principles. Semiannual reports are not required to be audited.
(ii)
A summary itemization, by type and/or classification of the total fees and
compensation, including any nonaccountable, fixed payment reimbursements for
Administrative Costs and Operating Costs, paid by, or on behalf of, the Partnership to
the Managing General Partner, the Operator, and their Affiliates.
Also, the independent certified public accountant shall provide written attestation
annually, which will be included in the annual report, that the method used to make
allocations of the Partnership’s Administrative Costs was consistent with the method
described in §4.04(a)(2)(c) of this Agreement and that the total amount of
Administrative Costs allocated did not materially exceed the amounts actually
incurred by the Managing General Partner in providing administrative services to, or
on behalf of, the Partnership as described in §4.04(a)(2)(c), including
administrative services provided to the Partnership by the Managing General Partner’s
Affiliates or independent third-parties at the sole expense of the Managing General
Partner. If the Managing General Partner subsequently decides to allocate
Administrative Costs in a manner different from that described in §4.04(a)(2)(c) of
this Agreement, then the change must be reported to the Participants together with an
explanation of the reason for the change and the basis used for determining the
reasonableness of the new allocation method.
A description of each Prospect in which the Partnership owns an interest,
including:
(a)
the cost, location, and number of acres under Lease; and
(b)
the Working Interest owned in the Prospect by the Partnership.
Succeeding reports, however, must only contain material changes, if any, regarding the Prospects.
(iv)
A list of the wells drilled or abandoned by the Partnership during the period of the report, indicating:
(a)
whether each of the wells has or has not been completed;
(b)
a statement of the cost of each well completed or abandoned; and
(c)
justification for wells abandoned after production has begun.
(v)
A description of all Farmouts, farmins, and joint ventures, made during the
period of the report, including:
(a)
the Managing General Partner’s justification for the arrangement;
and
(b)
a description of the material terms.
(vi)
A schedule reflecting:
(a)
the total Partnership costs;
(b)
the costs paid by the Managing General Partner and the costs paid
by the Participants;
(c)
the total Partnership revenues;
(d)
the revenues received or credited to the Managing General Partner
and the revenues received and credited to the Participants; and
(e)
a reconciliation of the expenses and revenues in accordance with
the provisions of Article V.
Additionally, on request the Managing General Partner will provide the information specified by
Form 10-Q (if such report is required to be filed with the SEC) within 45 days after the close of
each quarterly fiscal period.
4.03(b)(2). Tax Information. The Partnership shall, by March 15 of each year, prepare, or
supervise the preparation of, and transmit to each Participant the information needed for the
Participant to file the following:
(i)
his federal income tax return;
(ii)
any required state income tax return; and
(iii)
any other reporting or filing requirements imposed by any governmental agency
or authority.
4.03(b)(3). Reserve Report. Beginning with the second calendar year after the Offering
Termination Date and every year thereafter, the Partnership shall provide to each Participant the
following:
(i)
a summary of the computation of the Partnership’s total natural gas and oil
Proved Reserves;
(ii)
a summary of the computation of the present worth of the reserves determined
using:
basing the price of natural gas on the existing natural gas
contracts;
(iii)
a statement of each Participant’s interest in the reserves; and
(iv)
an estimate of the time required for the extraction of the reserves with a
statement that because of the time period required to extract the reserves the present
value of revenues to be obtained in the future is less than if immediately receivable.
The reserve computations shall be based on engineering reports prepared by the Managing General
Partner and reviewed by an Independent Expert.
Also, if any event reduces the Partnership’s Proved Reserves by 10% or more, excluding a reduction
of reserves as a result of normal production, sales of reserves, or natural gas or oil price
changes, then a computation and estimate of the amount of the reduction in reserves must be sent to
each Participant within 90 days after the Managing General Partner determines that such a reduction
in reserves has occurred.
4.03(b)(4). Cost of Reports. The cost of all reports described in this §4.03(b) shall be paid by
the Partnership as Direct Costs.
4.03(b)(5). Participant Access to Records. The Participants and/or their representatives shall be
permitted access to all Partnership records, provided that access to the list of Participants shall
be subject to §4.03(b)(7) below. Subject to the foregoing, a Participant may inspect and copy any
of the Partnership’s records after giving adequate notice to the Managing General Partner at any
reasonable time.
Notwithstanding the foregoing, the Managing General Partner may keep logs, well reports, and other
drilling and operating data confidential for reasonable periods of time. The Managing General
Partner may release information concerning the
operations of the Partnership to the sources that are customary in the industry or required by
rule, regulation, or order of any regulatory body.
4.03(b)(6). Required Length of Time to Hold Records. The Managing General Partner must maintain
and preserve during the term of the Partnership and for six years thereafter all accounts, books
and other relevant documents which include:
(i)
a record that a Participant meets the suitability standards established in
connection with an investment in the Partnership; and
(ii)
any appraisal of the fair market value of the Leases as set forth in
§4.01(a)(4), along with associated supporting information, or fair market value of any
producing property as set forth in §4.03(d)(3).
4.03(b)(7). Participant Lists. The following provisions apply regarding access to the list of
Participants:
(i)
an alphabetical list of the names, addresses, and business telephone numbers of
the Participants along with the number of Units held by each of them (the “Participant
List”) must be maintained as a part of the Partnership’s books and records and be
available for inspection by any Participant or his designated agent at the home office
of the Partnership on the Participant’s request;
(ii)
the Participant List must be updated at least quarterly to reflect changes in
the information contained in the Participant List;
(iii)
a copy of the Participant List must be mailed to any Participant requesting
the Participant List within 10 days of the written request, printed in alphabetical
order on white paper, and in a readily readable type size in no event smaller than
10-point type and a reasonable charge for copy work will be charged by the Partnership;
the purposes for which a Participant may request a copy of the Participant List
include, without limitation, matters relating to Participant’s voting rights under this
Agreement and the exercise of Participant’s rights under the federal proxy laws; and
(v)
if the Managing General Partner neglects or refuses to exhibit, produce, or
mail a copy of the Participant List as requested, the Managing General Partner shall be
liable to any Participant requesting the list for the costs, including attorneys fees,
incurred by that Participant for compelling the production of the Participant List, and
for actual damages suffered by any Participant by reason of the refusal or neglect. It
shall be a defense that the actual purpose and reason for the request for inspection or
for a copy of the Participant List is to secure the list of Participants or other
information for the purpose of selling the list or information or copies of the list,
or of using the same for a commercial purpose other than in the interest of the
applicant as a Participant relative to the affairs of the Partnership. The Managing
General Partner will require the Participant requesting the Participant List to
represent in writing that the list was not requested for a commercial purpose unrelated
to the Participant’s interest in the Partnership. The remedies provided under this
subsection to Participants requesting copies of the Participant List are in addition
to, and shall not in any way limit, other remedies available to Participants under
federal law or the laws of any state.
4.03(b)(8). State Filings. Concurrently with their transmittal to Participants, and as required,
the Managing General Partner shall file a copy of each report provided for in this §4.03(b) with:
(i)
the California Commissioner of Corporations;
(ii)
the Arizona Corporation Commission;
(iii)
the Alabama Securities Commission; and
(iv)
the securities commissions of other states which request the report.
4.03(c). Meetings of Participants.
4.03(c)(1). Procedure for a Participant Meeting.
4.03(c)(1)(a). Meetings May Be Called by Managing General Partner or Participants. Meetings of
the Participants may be called as follows:
(i)
by the Managing General Partner; or
(ii)
by Participants whose Units equal 10% or more of the total Units for any
matters on which Participants may vote.
The call for a meeting by the Participants as described above shall be deemed to have been made on
receipt by the Managing General Partner of a written request from holders of the requisite
percentage of Units stating the purpose(s) of the meeting.
4.03(c)(1)(b). Notice Requirement. The Managing General Partner shall deposit in the United
States mail within 15 days after the receipt of the request, written notice to all Participants of
the meeting and the purpose of the meeting. The meeting shall be held on a date not less than 30
days nor more than 60 days after the date of the mailing of the notice, at a reasonable time and
place.
Notwithstanding the foregoing, the date for notice of the meeting may be extended for a period of
up to 60 days if, in the opinion of the Managing General Partner, the additional time is necessary
to permit preparation of proxy or information statements or other documents required to be
delivered in connection with the meeting by the SEC or other regulatory authorities.
4.03(c)(1)(c). May Vote by Proxy. Participants shall have the right to vote at any Participant
meeting either:
4.03(c)(2). Special Voting Rights. At the request of Participants whose Units equal 10% or more
of the total Units, the Managing General Partner shall call for a vote by Participants. Each Unit
is entitled to one vote on all matters, and each fractional Unit is entitled to that fraction of
one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority
of the total Units may, without the concurrence of the Managing General Partner or its Affiliates,
vote to:
(i)
dissolve the Partnership;
(ii)
remove the Managing General Partner and elect a new Managing General Partner;
(iii)
elect a new Managing General Partner if the Managing General Partner elects to
withdraw from the Partnership;
(iv)
remove the Operator and elect a new Operator;
(v)
approve or disapprove the sale of all or substantially all of the assets of the
Partnership;
(vi)
cancel any contract for services with the Managing General Partner, the
Operator, or their Affiliates without penalty on 60 days notice; and
(vii)
amend this Agreement; provided however:
(a)
any amendment may not increase the duties or liabilities of any
Participant or the Managing General Partner or increase or decrease the profit
or loss sharing or required Capital Contribution of any Participant or the
Managing General Partner without the approval of the Participant or the Managing
General Partner, respectively; and
(b)
any amendment may not affect the classification of Partnership
income and loss for federal income tax purposes without the unanimous approval
of all Participants.
4.03(c)(3). Restrictions on Managing General Partner’s Voting Rights. With respect to Units owned
by the Managing General Partner or its Affiliates, the Managing General Partner and its Affiliates
may vote or consent on all matters other than the following:
(i)
the matters set forth in §4.03(c)(2)(ii) and (iv) above; or
(ii)
any transaction between the Partnership and the Managing General Partner or its
Affiliates.
In determining the requisite percentage in interest of Units necessary to approve any Partnership
matter on which the Managing General Partner and its Affiliates may not vote or consent, any Units
owned by the Managing General Partner and its Affiliates shall not be included.
4.03(c)(4). Restrictions on Limited Partner Voting Rights. The exercise by the Limited Partners
of the rights granted Participants under §4.03(c), except for the special voting rights granted
Participants under §4.03(c)(2), shall be subject to the prior legal determination that the grant or
exercise of the powers will not adversely affect the limited liability of Limited Partners.
Notwithstanding the foregoing, if in the opinion of counsel to the Partnership the legal
determination is not necessary under Delaware law to maintain the limited liability of the Limited
Partners, then it shall not be required. A legal determination under this paragraph may be made
either pursuant to:
(i)
an opinion of counsel, the counsel being independent of the Partnership and
selected on the vote of Limited Partners whose Units equal a majority of the total
Units held by Limited Partners; or
a declaratory judgment issued by a court of competent jurisdiction.
The Investor General Partners may exercise the rights granted to the Participants whether or not
the Limited Partners can participate in the vote if the Investor General Partners represent the
requisite percentage of Units necessary to take the action.
4.03(d). Transactions with the Managing General Partner.
4.03(d)(1). Transfer of Equal Proportionate Interest. When the Managing General Partner or an
Affiliate (excluding another Program in which the interest of the Managing General Partner or its
Affiliates is substantially similar to or less than their interest in the Partnership) sells,
transfers or conveys any natural gas, oil or other mineral interests or property to the
Partnership, it must, at the same time, sell, transfer or convey to the Partnership an equal
proportionate interest in all its other property in the same Prospect. Notwithstanding, a Prospect
shall be deemed to consist of the drilling or spacing unit on which the well will be drilled by the
Partnership, which is the minimum area permitted by state law or local practice on which one well
may be drilled, if the following two conditions are met:
(i)
the geological feature to which the well will be drilled contains Proved
Reserves; and
(ii)
the drilling or spacing unit protects against drainage.
With respect to a Prospect located in Ohio, Pennsylvania and New York on which a well will be
drilled by the Partnership to test the Clinton/Medina geological formation, the Mississippian
and/or Upper Devonian Sandstone reservoirs or the Marcellus Shale reservoir, and with respect to a
Prospect located in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee on which a well
will be drilled to test the Mississippian carbonate or Devonian Shale reservoirs, a
Prospect shall be deemed to consist of the drilling and spacing unit if it meets the test in the
preceding sentence. Additionally, for a period of five years after the drilling of the Partnership
Well neither the Managing General Partner nor its Affiliates may drill any well:
(i)
to the Clinton/Medina geological formation, if the well would be within 1,650
feet of an existing Partnership Well in Pennsylvania or within 1,000 feet of an
existing Partnership Well in Ohio; or
(ii)
to the Mississippian and/or Upper Devonian Sandstone reservoirs in Fayette,
Greene and Westmoreland Counties, Pennsylvania, if the well would be within 1,000 feet
from a producing Partnership Well, although the Partnership may drill a new well or
re-enter an existing well which is closer than 1,000 feet to a plugged and abandoned
well.
If the Partnership abandons its interest in a well, then the restrictions described above shall
continue for one year following the abandonment.
If the area constituting the Partnership’s Prospect is subsequently enlarged to encompass any area
in which the Managing General Partner or an Affiliate (excluding another Program in which the
interest of the Managing General Partner or its Affiliates is substantially similar to or less than
their interest in the Partnership) owns a separate property interest and the activities of the
Partnership were material in establishing the existence of Proved Undeveloped Reserves that are
attributable to the separate property interest, then the separate property interest or a portion
thereof must be sold, transferred, or conveyed to the Partnership as set forth in this section and
§§4.01(a)(4) and 4.03(d)(2).
Notwithstanding the foregoing, Prospects drilled to the Clinton/Medina geological formation, the
Mississippian and/or Upper Devonian Sandstone reservoirs, the Marcellus Shale reservoir, the
Mississippian carbonate or Devonian Shale reservoirs, or any other formation or reservoir shall not
be enlarged or contracted if the Prospect was limited to the drilling or spacing unit because the
well was being drilled to Proved Reserves in the geological formation and the drilling or spacing
unit protected against drainage.
4.03(d)(2). Transfer of Less than the Managing General Partner’s and its Affiliates’ Entire
Interest. A sale, transfer or a conveyance to the Partnership of less than all of the ownership of
the Managing General Partner or an Affiliate (excluding another Program in which the interest of
the Managing General Partner or its Affiliates is substantially similar to or less than their
interest in the Partnership) in any Prospect shall not be made unless:
the interest retained by the Managing General Partner or the Affiliate is a
proportionate Working Interest;
(ii)
the respective obligations of the Managing General Partner or its Affiliates
and the Partnership are substantially the same after the sale of the interest by the
Managing General Partner or its Affiliates; and
(iii)
the Managing General Partner’s interest in revenues does not exceed the amount
proportionate to its retained Working Interest.
This section does not prevent the Managing General Partner or its Affiliates from subsequently
dealing with their retained interest as they may choose with unaffiliated parties or Affiliated
partnerships.
4.03(d)(3). Limitations on Sale of Undeveloped and Developed Leases to the Managing General
Partner. Other than another Program managed by the Managing General Partner and its Affiliates as
set forth in §§4.03(d)(5) and 4.03(d)(9), the Managing General Partner and its Affiliates shall not
receive a Farmout or purchase any undeveloped Leases from the Partnership other than at the higher
of Cost or fair market value.
The Managing General Partner and its Affiliates, other than an Affiliated Income Program, shall not
purchase any producing natural gas or oil property from the Partnership unless:
(i)
the sale is in connection with the liquidation of the Partnership; or
(ii)
the Managing General Partner’s well supervision fees under the Drilling and
Operating Agreement for the well have exceeded the net revenues of the well, determined
without regard to the Managing General Partner’s well supervision fees for the well,
for a period of at least three consecutive months.
Under both (i) and (ii) above, the sale must be at fair market value supported by an appraisal of
an Independent Expert selected by the Managing General Partner.
4.03(d)(4). Limitations on Activities of the Managing General Partner and its Affiliates on Leases
Acquired by the Partnership. During a period of five years after the Offering Termination Date of
the Partnership, if the Managing General Partner or any of its Affiliates (excluding another
Program in which the interest of the Managing General Partner or its Affiliates is substantially
similar to or less than their interest in the Partnership) proposes to acquire an interest from an
unaffiliated person in a Prospect in which the Partnership possesses an interest or in a Prospect
in which the Partnership’s interest has been terminated without compensation within one year
preceding the proposed acquisition, then the following conditions shall apply:
(i)
if the Managing General Partner or the Affiliate (excluding another Program in
which the interest of the Managing General Partner or its Affiliates is substantially
similar to or less than their interest in the Partnership) does not currently own
property in the Prospect separately from the Partnership, then neither the Managing
General Partner nor the Affiliate shall be permitted to purchase an interest in the
Prospect; and
(ii)
if the Managing General Partner or the Affiliate (excluding another Program in
which the interest of the Managing General Partner or its Affiliates is substantially
similar to or less than their interest in the Partnership) currently owns a
proportionate interest in the Prospect separately from the Partnership, then the
interest to be acquired shall be divided between the Partnership and the Managing
General Partner or the Affiliate in the same proportion as is the other property in the
Prospect. Provided, however, if cash or financing is not available to the Partnership
to enable it to complete a purchase of the additional interest to which it is entitled,
then neither the Managing General Partner nor the Affiliate shall be permitted to
purchase any additional interest in the Prospect.
4.03(d)(5). Transfer of Leases Between Affiliated Limited Partnerships. The transfer of an
undeveloped Lease from the Partnership to another drilling Program sponsored or managed by the
Managing General Partner or its Affiliates must be made at fair market value if the undeveloped
Lease has been held by the Partnership for more than two years. Otherwise, if the Managing General
Partner deems it to be in the best interest of the Partnership, the transfer may be made at Cost.
An Affiliated Income Program may purchase a producing natural gas and oil property from the
Partnership at any time at:
(i)
fair market value as supported by an appraisal from an Independent Expert if
the property has been held by the Partnership for more than six months or the
Partnership has made significant expenditures have been made in connection with the
property; or
(ii)
Cost, as adjusted for intervening operations, if the Managing General Partner
deems it to be in the best interest of the Partnership.
However, these prohibitions shall not apply to joint ventures or Farmouts among Affiliated
partnerships, provided that:
(i)
the respective obligations and revenue sharing of all parties to the
transaction are substantially the same; and
(ii)
the compensation arrangement or any other interest or right of either the
Managing General Partner or its Affiliates is the same in each Affiliated partnership
or if different, the aggregate compensation of the Managing General Partner or the
Affiliate is reduced to reflect the lower compensation arrangement.
4.03(d)(6). Sale of All Assets. The sale of all or substantially all of the assets of the
Partnership, including without limitation, Leases, wells, equipment and production therefrom, shall
be made only with the consent of Participants whose Units equal a majority of the total Units.
4.03(d)(7). Services.
4.03(d)(7)(a). Competitive Rates. The Managing General Partner and any Affiliate shall not render
to the Partnership any oil field, equipage, or other services nor sell or lease to the Partnership
any equipment or related supplies unless:
(i)
the person is engaged, independently of the Partnership and as an ordinary and
ongoing business, in the business of rendering the services or selling or leasing the
equipment and supplies to a substantial extent to other persons in the natural gas and
oil industry in addition to the partnerships in which the Managing General Partner or
an Affiliate has an interest; and
(ii)
the compensation, price, or rental therefor is competitive with the
compensation, price, or rental of other persons in the area engaged in the business of
rendering comparable services or selling or leasing comparable equipment and supplies
which could reasonably be made available to the Partnership.
If the person is not engaged in such a business, then the compensation, price or rental shall be
the Cost of the services, equipment or supplies to the person or the competitive rate which could
be obtained in the area, whichever is less.
4.03(d)(7)(b). If Not Disclosed in the Prospectus or This Agreement, Then Services by the Managing
General Partner Must be Described in a Separate Contract and Cancelable. Any services for which
the Managing General Partner or an Affiliate is to receive compensation, other than those described
in this Agreement or the Prospectus, shall be set forth in a written contract which precisely
describes the services to be rendered and all compensation to be paid. These contracts shall be
cancelable without penalty on 60 days written notice by Participants whose Units equal a majority
of the total Units.
4.03(d)(8). Loans.
4.03(d)(8)(a). No Loans from the Partnership. No loans or advances shall be made by the
Partnership to the Managing General Partner or its Affiliates.
4.03(d)(8)(b). Loans to the Partnership. Neither the Managing General Partner nor any Affiliate
shall loan money to the Partnership if the interest to be charged exceeds either:
(i)
the Managing General Partner’s or the Affiliate’s interest cost; or
that which would be charged to the Partnership, without reference to the
Managing General Partner’s or the Affiliate’s financial abilities or guarantees, by
unrelated lenders, on comparable loans for the same purpose.
Neither the Managing General Partner nor any Affiliate shall receive points or other financing
charges or fees, regardless of the amount, although the actual amount of the charges incurred by
them from third-party lenders may be reimbursed to the Managing General Partner or the Affiliate.
4.03(d)(9). Farmouts. The Managing General Partner shall not enter into a Farmout to avoid its
paying its share of costs related to drilling a well on an undeveloped Lease. The Partnership
shall not Farmout an undeveloped Lease or well activity to the Managing General Partner or its
Affiliates except as set forth in §4.03(d)(3). Notwithstanding, this restriction shall not apply
to Farmouts between the Partnership and another partnership managed by the Managing General Partner
or its Affiliates, either separately or jointly, provided that the respective obligations and
revenue sharing of all parties to the transactions are substantially the same and the compensation
arrangement or any other interest or right of the Managing General Partner or its Affiliates is the
same in each partnership, or, if different, the aggregate compensation of the Managing General
Partner and its Affiliates is reduced to reflect the lower compensation agreement.
The Partnership may Farmout an undeveloped lease or well activity only if the Managing General
Partner, exercising the standard of a prudent operator, determines that:
(i)
the Partnership lacks the funds to complete the oil and gas operations on the
Lease or well and cannot obtain suitable financing;
(ii)
drilling on the Lease or the intended well activity would concentrate excessive
funds in one location, creating undue risks to the Partnership;
(iii)
the Leases or well activity have been downgraded by events occurring after
assignment to the Partnership so that development of the Leases or well activity would
not be desirable; or
(iv)
the best interests of the Partnership would be served.
If the Partnership Farmouts a Lease or well activity, the Managing General Partner must retain on
behalf of the Partnership the economic interests and concessions as a reasonably prudent oil and
gas operator would or could retain under the circumstances prevailing at the time, consistent with
industry practices.
If the Partnership acquires an undeveloped Lease pursuant to a Farmout or joint venture from an
Affiliated partnership, the Managing General Partner’s and its Affiliates’ aggregate compensation
associated with the property and any direct and indirect ownership interest in the property may not
exceed the lower of the compensation and ownership interest in the Managing General Partner and/or
its Affiliates could receive if the property were separately owned or retained by either the
Partnership or the Affiliated partnership.
4.03(d)(10). No Compensating Balances. Neither the Managing General Partner nor any Affiliate
shall use the Partnership’s funds as compensating balances for its own benefit.
4.03(d)(11). Future Production. Neither the Managing General Partner nor any Affiliate shall
commit the future production of a well developed by the Partnership exclusively for its own
benefit.
4.03(d)(12). Marketing Arrangements. Subject to §4.06(c), all benefits from marketing
arrangements or other relationships affecting the property of the Managing General Partner or its
Affiliates, including its Affiliated partnerships and the Partnership shall be fairly and equitably
apportioned according to the respective interests of each in the property. In this regard, the
benefits and liabilities of the hedging agreements shall be equitably allocated by Atlas America
and/or Atlas Energy Resources, LLC and the Managing General Partner to the Partnership and the
other partnerships sponsored by the Managing General Partner and its Affiliates pro rata based on
actual production, consistent with past practice, and the Partnership and the other partnerships
sponsored by the Managing General Partner and its Affiliates shall be severally liable for their
respective allocated share thereof, but shall not be jointly and severally liable for the entire
amount of the liabilities under the hedging
agreements. Additionally, Atlas America and/or Atlas
Energy Resources, LLC shall not be liable for any such liabilities, or be entitled to any such
benefits, to the extent they are so allocated. Atlas America has transferred ownership of the
Managing General Partner to Atlas Energy Resources, LLC and it is anticipated that Atlas Energy
Resources, LLC, rather than Atlas America, will enter into future hedging agreements.
The Managing General Partner shall treat all wells in a geographic area equally concerning to whom
and at what price the Partnership’s natural gas and oil will be sold and to whom and at what price
the natural gas and oil of other natural gas and oil Programs which the Managing General Partner
has sponsored or will sponsor will be sold. For example, each seller of natural gas and oil in a
given area will be paid a weighted average selling price for all natural gas and oil sold in that
geographic area. The Managing General Partner, in its sole discretion, shall determine what
constitutes a geographic area.
4.03(d)(13). Advance Payments. Advance payments by the Partnership to the Managing General
Partner and its Affiliates are prohibited except when advance payments are required to secure the
tax benefits of prepaid Intangible Drilling Costs for a business purpose as set forth in the
Drilling and Operating Agreement.
4.03(d)(14). No Rebates. No rebates or give-ups may be received by the Managing General Partner
or any Affiliate nor may the Managing General Partner or any Affiliate participate in any
reciprocal business arrangements that would circumvent the provisions of this section.
4.03(d)(15). Participation in Other Partnerships. If the Partnership participates in other
partnerships or joint ventures (multi-tier arrangements), then the terms of any of these
arrangements shall not result in the circumvention of any of the requirements or prohibitions
contained in this Agreement, including the following:
(i)
there shall be no duplication or increase in Organization and Offering Costs,
the Managing General Partner’s compensation, Partnership expenses or other fees and
costs;
(ii)
there shall be no substantive alteration in the fiduciary and contractual
relationship between the Managing General Partner and the Participants; and
(iii)
there shall be no diminishment in the voting rights of the Participants.
4.03(d)(16). Roll-Up Limitations.
4.03(d)(16)(a). Requirement for Appraisal and Its Assumptions. In connection with a proposed
Roll-Up, an appraisal of all Partnership assets shall be obtained from a competent Independent
Expert. If the appraisal will be included in a prospectus used to offer securities of a Roll-Up
Entity, then the appraisal shall be filed with the SEC and the Administrator as an exhibit to the
registration statement for the offering. Thus, an issuer using the appraisal shall be subject to
liability for violation of Section 11 of the Securities Act of 1933 and comparable provisions under
state law for any material misrepresentations or material omissions in the appraisal.
Partnership assets shall be appraised on a consistent basis. The appraisal shall be based on all
relevant information, including current reserve estimates prepared as set forth in §4.03(b)(3), and
shall indicate the value of the Partnership’s assets as of a date immediately before the
announcement of the proposed Roll-Up transaction. The appraisal shall assume an orderly
liquidation of the Partnership’s assets over a 12-month period.
The terms of the engagement of the Independent Expert shall clearly state that the engagement is
for the benefit of the Partnership and the Participants. A summary of the independent appraisal,
indicating all material assumptions underlying the appraisal, shall be included in a report to the
Participants in connection with a proposed Roll-Up.
4.03(d)(16)(b). Rights of Participants Who Vote Against Proposal. In connection with a proposed
Roll-Up, Participants who vote “no” on the proposal shall be offered the choice of:
(i)
accepting the securities of the Roll-Up Entity offered in the proposed Roll-Up;
or
remaining as Participants in the Partnership and preserving their
Units in the Partnership on the same terms and conditions as existed previously;
or
(b)
receiving cash in an amount equal to the Participants’ pro rata
share of the appraised value of the net assets of the Partnership based on their
respective number of Units.
4.03(d)(16)(c). No Roll-Up If Diminishment of Voting Rights. The Partnership shall not
participate in any proposed Roll-Up which, if approved, would result in the diminishment of any
Participant’s voting rights under the Roll-Up Entity’s chartering agreement. In no event shall the
democracy rights of Participants in the Roll-Up Entity be less than those provided for under
§§4.03(c)(1) and 4.03(c)(2). If the Roll-Up Entity is a corporation, then the democracy rights of
Participants shall correspond to the democracy rights provided for in this Agreement to the
greatest extent possible.
4.03(d)(16)(d). No Roll-Up If Accumulation of Shares Would be Impeded. The Partnership shall not
participate in any proposed Roll-Up transaction which includes provisions that would operate to
materially impede or frustrate the accumulation of shares by any purchaser of the securities of the
Roll-Up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-Up
Entity. The Partnership shall not participate in any proposed Roll-Up transaction which would
limit the ability of a Participant to exercise the voting rights of its securities of the Roll-Up
Entity on the basis of the number of Units held by that Participant.
4.03(d)(16)(e). No Roll-Up If Access to Records Would Be Limited. The Partnership shall not
participate in a Roll-Up in which Participants’ rights of access to the records of the Roll-Up
Entity would be less than those provided for under §§4.03(b)(5), 4.03(b)(6) and 4.03(b)(7).
4.03(d)(16)(f). Cost of Roll-Up. The Partnership shall not participate in any proposed Roll-Up
transaction in which any of the costs of the transaction would be borne by the Partnership if
Participants whose Units equal a majority of the total Units do not vote to approve the proposed
Roll-Up.
4.03(d)(16)(g). Roll-Up Approval. The Partnership shall not participate in a Roll-Up transaction
unless the Roll-Up transaction is approved by Participants whose Units equal a majority of the
total Units.
4.03(d)(17). Disclosure of Binding Agreements. Any agreement or arrangement which binds the
Partnership must be disclosed in the Prospectus.
4.03(d)(18). Transactions Must Be Fair and Reasonable. Neither the Managing General Partner nor
any Affiliate shall sell, transfer, or convey any property to or purchase any property from the
Partnership, directly or indirectly, except under transactions that are fair and reasonable, nor
take any action with respect to the assets or property of the Partnership which does not primarily
benefit the Partnership.
4.04. Designation, Compensation and Removal of Managing General Partner and Removal of Operator.
4.04(a). Managing General Partner.
4.04(a)(1). Term of Service. Except as otherwise provided in this Agreement, Atlas shall serve as
the Managing General Partner of the Partnership until either it:
(i)
is removed pursuant to §4.04(a)(3); or
(ii)
withdraws pursuant to §4.04(a)(3)(f).
4.04(a)(2). Compensation of Managing General Partner. In addition to the compensation set forth
in §§4.01(a)(4) and 4.02(d)(1), the Managing General Partner shall receive the compensation set
forth in §§4.04(a)(2)(b) through 4.04(a)(2)(g).
4.04(a)(2)(a). Charges Must Be Necessary and Reasonable. Charges by the Managing General Partner
for goods and services must be fully supportable as to:
(i)
the necessity of the goods and services; and
(ii)
the reasonableness of the amount charged.
All actual and necessary expenses incurred by the Partnership may be paid out of the Partnership’s
subscription proceeds and revenues.
4.04(a)(2)(b). Direct Costs. The Managing General Partner and its Affiliates shall be reimbursed
for all Direct Costs. Direct Costs, however, shall be billed directly to and paid by the
Partnership to the extent practicable.
4.04(a)(2)(c). Administrative Costs. The Managing General Partner shall receive a nonaccountable,
fixed payment reimbursement for its Administrative Costs of $75 per well per month. The
nonaccountable, fixed payment reimbursement of $75 per well per month shall be subject to the
following:
(i)
it shall not be increased in amount during the term of the Partnership;
(ii)
it shall be proportionately reduced to the extent the Partnership acquires less
than 100% of the Working Interest in the well;
(iii)
it shall be the entire payment to reimburse the Managing General Partner for
the Partnership’s Administrative Costs; and
(iv)
it shall not be received for plugged or abandoned wells.
4.04(a)(2)(d). Gas Gathering. The Managing General Partner, not acting as a Partner, shall be
responsible for gathering and transporting the natural gas produced by the Partnership to
interstate pipeline systems, local distribution companies, and/or end-users in the area (the
“gathering services”). In providing the gathering services, the Managing General Partner may use
the gathering system owned by Atlas Pipeline Partners, as described in the Prospectus, and
gathering systems owned by independent third-parties and/or Affiliates of Atlas America other than
Atlas Pipeline Partners.
The Partnership shall pay a gathering fee directly to the Managing General Partner at competitive
rates for the gathering services. The gathering fee paid by the Partnership to the Managing
General Partner may be increased from time-to-time by the Managing General Partner, in its sole
discretion, but may not increase beyond competitive rates as determined by the Managing General
Partner. Currently, the Managing General Partner has determined that the competitive rate is an
amount equal to 13% of the gross sales price received by the Partnership for its natural gas in
each of its primary or secondary areas as described in the Prospectus. Gross sales price means the
price that is actually received, adjusted to take into account proceeds received or payments made
pursuant to hedging arrangements. The payment of a competitive fee to the Managing General Partner
for its gathering services shall be subject to the following conditions:
(i)
If the Partnership’s natural gas production is gathered and transported through
the gathering system owned by Atlas Pipeline Partners, then the Managing General
Partner shall apply its gathering fee towards the related gathering fee obligation of
Atlas America, Inc., Resource Energy, LLC, and Viking Resources LLC (the “Atlas
Entities”) under their agreement with Atlas Pipeline Partners as described in the
Prospectus.
(ii)
If a third-party gathering system is used by the Partnership, then the Managing
General Partner shall pay all of the gathering fee it receives from the Partnership to
the third-party gathering the natural gas. The Managing General Partner shall not
retain the excess of any gathering fees it receives from the Partnership over the
payments it makes to third-party gas gatherers. If the third-party’s gathering system
charges more than an amount equal to 13% of the gross sales price, then the Managing
General Partner’s gathering fee charged to the Partnership shall be the actual
transportation and compression fees charged by the third-party gathering system with
respect to the Partnership’s natural gas in the area.
If both a third-party gathering system and the Atlas Pipeline Partners
gathering system (or a gas gathering system owned by an affiliate of Atlas America
other than Atlas Pipeline Partners) are used by the Partnership, then the Managing
General Partner shall receive an amount equal to 13% of the gross sales price plus the
amount charged by the third-party gathering system. For purposes of illustration, but
not limitation, the Partnership will deliver natural gas produced from certain wells
drilled by the Partnership in the Upper Devonian Sandstone Reservoirs in the McKean
County, Pennsylvania area into a gathering system, a segment of which will be provided
by Atlas Pipeline Partners and a segment of which will be provided by a third-party.
The Managing General Partner shall receive a gathering fee composed of $.35 per mcf for
transportation and compression, which may be increased from time-to-time, that the
Managing General Partner shall pay to the third-party gathering the natural gas, and a
gathering fee equal to 13% of the gross sales price of the natural gas.
With respect to the Knox project and natural gas produced from the Mississippian and Devonian Shale
Reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee as described in the
Prospectus, if the Coalfield Pipeline does not have sufficient capacity to compress and transport
the natural gas produced from the Partnership’s wells as determined by Atlas America, then Atlas
America or an Affiliate other than Atlas Pipeline Partners may construct an additional gathering
system and/or enhancements to the Coalfield Pipeline. On completion of the construction, Atlas
America will transfer its ownership in the additional gathering system and/or enhancements to the
owners of Coalfield Pipeline, which will then pay Atlas America an amount equal to $.12 per mcf of
natural gas transported through the newly constructed and/or enhanced gathering system. Coalfield
Pipeline will pay this amount of $.12 per mcf to Atlas America from its gathering and compression
fees charged to the Partnership.
4.04(a)(2)(e). Dealer-Manager Fee. Subject to §3.03(a)(1), the Dealer-Manager shall receive on
each Unit sold to investors:
(i)
a 2.5% Dealer-Manager fee;
(ii)
a 7% Sales Commission; and
(iii)
an up to .5% reimbursement of the Selling Agents’ bona fide due diligence
expenses.
4.04(a)(2)(f). Drilling and Operating Agreement. The Managing General Partner and its Affiliates
shall receive compensation as set forth in the Drilling and Operating Agreement.
4.04(a)(2)(g). Other Transactions. The Managing General Partner and its Affiliates may enter into
transactions pursuant to §4.03(d)(7) with the Partnership and shall be entitled to compensation
under that section.
4.04(a)(3). Removal of Managing General Partner.
4.04(a)(3)(a). Majority Vote Required to Remove the Managing General Partner. The Managing
General Partner may be removed at any time on 60 days’ advance written notice to the outgoing
Managing General Partner by the affirmative vote of Participants whose Units equal a majority of
the total Units.
If the Participants vote to remove the Managing General Partner from the Partnership, then
Participants must elect by an affirmative vote of Participants whose Units equal a majority of the
total Units either to:
(i)
dissolve, wind-up, and terminate the Partnership; or
(ii)
continue as a successor limited partnership under all the terms of this
Partnership Agreement as provided in §7.01(c).
If the Participants elect to continue as a successor limited partnership, then the Managing General
Partner shall not be removed until a substituted Managing General Partner has been selected by an
affirmative vote of Participants whose Units equal a majority of the total Units and installed as
such.
4.04(a)(3)(b). Valuation of Managing General Partner’s Interest in the Partnership. If the
Managing General Partner is removed, then its interest in the Partnership shall be determined by
appraisal by a qualified Independent Expert. The Independent Expert shall be selected by mutual
agreement between the removed Managing General Partner and the incoming Managing General Partner.
The appraisal shall take into account an appropriate discount, to reflect the risk of recovering
natural gas and oil reserves, which shall not be less than that used to calculate the presentment
price in the most recent presentment offer under §6.03, if any.
The cost of the appraisal shall be borne equally by the removed Managing General Partner and the
Partnership.
4.04(a)(3)(c). Incoming Managing General Partner’s Option to Purchase. The incoming Managing
General Partner shall have the option to purchase 20% of the removed Managing General Partner’s
interest in the Partnership as Managing General Partner, but not as a Participant, for the value
determined by the Independent Expert.
4.04(a)(3)(d). Method of Payment. The method of payment for the removed Managing General
Partner’s interest must be fair and protect the solvency and liquidity of the Partnership. The
method of payment shall be as follows:
(i)
when the termination is voluntary, the method of payment shall be a
non-interest bearing unsecured promissory note with principal payable, if at all, from
distributions which the Managing General Partner otherwise would have received under
this Agreement had the Managing General Partner not been terminated; and
(ii)
when the termination is involuntary, the method of payment shall be an interest
bearing unsecured promissory note coming due in no less than five years with equal
installments each year. The interest rate shall be that charged on comparable loans.
4.04(a)(3)(e). Termination of Contracts. At the time of its removal, the removed Managing General
Partner shall cause, to the extent it is legally possible to do so, its successor to be transferred
or assigned all of its rights, obligations and interests as Managing General Partner of the
Partnership in contracts entered into by it on behalf of the Partnership. In any event, the
removed Managing General Partner shall cause all of its rights, obligations and interests as
Managing General Partner of the Partnership in any such contract to terminate at the time of its
removal.
Notwithstanding any other provision in this Agreement, the Partnership or the successor Managing
General Partner shall not:
(i)
be a party to any natural gas supply agreement that the Managing General
Partner or its Affiliates enters into with a third-party;
(ii)
have any rights pursuant to such natural gas supply agreement; or
(iii)
receive any interest in the Managing General Partner’s and its Affiliates’
pipeline or gathering system or compression facilities.
4.04(a)(3)(f). The Managing General Partner’s Right to Voluntarily Withdraw. At any time
beginning 10 years after the Offering Termination Date and the Partnership’s primary drilling
activities, the Managing General Partner may voluntarily withdraw as Managing General Partner on
giving 120 days’ written notice of withdrawal to the Participants. If the Managing General Partner
withdraws, then the following conditions shall apply:
(i)
the Managing General Partner’s interest in the Partnership shall be determined
as described in §4.04(a)(3)(b) above with respect to removal; and
(ii)
the interest shall be distributed to the Managing General Partner as described
in §4.04(a)(3)(d)(i) above.
Any successor Managing General Partner shall have the option to purchase 20% of the withdrawing
Managing General Partner’s interest in the Partnership at the value determined as described above
with respect to removal.
4.04(a)(3)(g). Right of Managing General Partner to Hypothecate Its Interests. The Managing
General Partner shall have the authority without the consent of the Participants and without
affecting the allocation of costs and revenues received or incurred under this Agreement, to
hypothecate, pledge, or otherwise encumber, on any terms it chooses for its own general purposes,
either:
(i)
its Partnership interest; or
(ii)
an undivided interest in the assets of the Partnership equal to or less than
its respective interest as Managing General Partner in the revenues of the Partnership.
All repayments of these borrowings and costs, interest or other charges related to the borrowings
shall be borne and paid separately by the Managing General Partner. In no event shall the
repayments, costs, interest, or other charges related to the borrowing be charged to the account of
the Participants.
4.04(a)(3)(h). The Managing General Partner’s Right to Withdraw Property Interest. The Managing
General Partner shall have the right to withdraw a property interest held by the Partnership in the
form of a Working Interest in the Partnership’s Wells equal to or less than its respective interest
as Managing General Partner in the revenues of the Partnership if:
(i)
the withdrawal is necessary to satisfy the bona fide request of its creditors;
or
(ii)
the withdrawal is approved by Participants whose Units equal a majority of the
total Units.
If the Managing General Partner withdraws a property interest from the Partnership as described
above, then the Managing General Partner shall:
(i)
pay the expenses of withdrawing; and
(ii)
fully indemnify the Partnership against any additional expenses which may
result from the withdrawal of its property interest, including insuring that a greater
amount of Direct Costs or Administrative Costs is not allocated to the Participants.
4.04(a)(4). Removal of Operator. The Operator may be removed and a new Operator may be
substituted at any time on 60 days advance written notice to the outgoing Operator by the Managing
General Partner acting on behalf of the Partnership on the affirmative vote of Participants whose
Units equal a majority of the total Units.
The Operator shall not be removed until a substituted Operator has been selected by an affirmative
vote of Participants whose Units equal a majority of the total Units and installed as such.
4.05. Indemnification and Exoneration.
4.05(a)(1). Standards for the Managing General Partner Not Incurring Liability to the Partnership
or Participants. The Managing General Partner, the Operator, and their Affiliates shall not have
any liability whatsoever to the Partnership, or to any Participant for any loss suffered by the
Partnership or the Participants which arises out of any action or inaction of the Managing General
Partner, the Operator, or their Affiliates if:
(i)
the Managing General Partner, the Operator, and their Affiliates determined in
good faith that the course of conduct was in the best interest of the Partnership;
(ii)
the Managing General Partner, the Operator, and their Affiliates were acting on
behalf of, or performing services for, the Partnership; and
(iii)
the course of conduct did not constitute negligence or misconduct of the
Managing General Partner, the Operator, or their Affiliates.
4.05(a)(2). Standards for Managing General Partner Indemnification. The Managing General Partner,
the Operator, and their Affiliates shall be indemnified by the Partnership against any losses,
judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in
connection with the Partnership, provided that:
(i)
the Managing General Partner, the Operator, and their Affiliates determined in
good faith that the course of conduct which caused the loss or liability was in the
best interest of the Partnership;
(ii)
the Managing General Partner, the Operator, and their Affiliates were acting on
behalf of, or performing services for, the Partnership; and
(iii)
the course of conduct was not the result of negligence or misconduct of the
Managing General Partner, the Operator, or their Affiliates.
Provided, however, payments arising from such indemnification or agreement to hold harmless are
recoverable only out of the following:
(i)
the Partnership’s tangible net assets, which include its revenues; and
(ii)
any insurance proceeds from the types of insurance for which the Managing
General Partner, the Operator and their Affiliates may be indemnified under this
Agreement.
4.05(a)(3). Standards for Securities Law Indemnification. Notwithstanding anything to the
contrary contained in this section, the Managing General Partner, the Operator, and their
Affiliates and any person acting as a broker/dealer with respect to the offer or sale of the Units,
shall not be indemnified for any losses, liabilities or expenses arising from or out of an alleged
violation of federal or state securities laws by such party unless:
(i)
there has been a successful adjudication on the merits of each count involving
alleged securities law violations as to the particular indemnitee;
(ii)
the claims have been dismissed with prejudice on the merits by a court of
competent jurisdiction as to the particular indemnitee; or
(iii)
a court of competent jurisdiction approves a settlement of the claims against
a particular indemnitee and finds that indemnification of the settlement and the
related costs should be made, and the court considering the request for indemnification
has been advised of the position of the SEC, the Massachusetts Securities Division, and
any state securities regulatory authority in which plaintiffs claim they were offered
or sold Units with respect to the issue of indemnification for violation of securities
laws.
4.05(a)(4). Standards for Advancement of Funds to the Managing General Partner and Insurance. The
advancement of Partnership funds to the Managing General Partner, the Operator, or their Affiliates
for legal expenses and other costs incurred as a result of any legal action for which
indemnification is being sought from the Partnership is permissible only if the Partnership has
adequate funds available and the following conditions are satisfied:
(i)
the legal action relates to acts or omissions with respect to the performance
of duties or services on behalf of the Partnership;
(ii)
the legal action is initiated by a third-party who is not a Participant, or the
legal action is initiated by a Participant and a court of competent jurisdiction
specifically approves the advancement; and
(iii)
the Managing General Partner or its Affiliates undertake to repay the advanced
funds to the Partnership, together with the applicable legal rate of interest thereon,
in cases in which such party is found not to be entitled to indemnification.
The Partnership shall not bear the cost of that portion of insurance which insures the Managing
General Partner, the Operator, or their Affiliates for any liability for which they could not be
indemnified pursuant to §§4.05(a)(1) and 4.05(a)(2).
4.05(b). Liability of Partners. Under the Delaware Revised Uniform Limited Partnership Act, the
Investor General Partners are liable jointly and severally for all liabilities and obligations of
the Partnership. Notwithstanding the foregoing, as among themselves, the Investor General Partners
agree that each shall be solely and individually responsible only for his pro rata share of the
liabilities and obligations of the Partnership based on his respective number of Units.
In addition, the Managing General Partner agrees to use its corporate assets to indemnify each of
the Investor General Partners against all Partnership related liabilities which exceed the Investor
General Partner’s interest in the undistributed net assets of the Partnership and insurance
proceeds, if any. Further, the Managing General Partner agrees to indemnify each Investor General
Partner against any personal liability as a result of the unauthorized acts of another Investor
General Partner.
If the Managing General Partner provides indemnification, then each Investor General Partner who
has been indemnified shall transfer and subrogate his rights for contribution from or against any
other Investor General Partner to the Managing General Partner.
4.05(c). Order of Payment of Claims. Claims shall be paid as follows:
(i)
first, out of any insurance proceeds;
(ii)
second, out of Partnership assets and revenues; and
(iii)
last, by the Managing General Partner as provided in §§3.05(b)(2) and (3) and
4.05(b).
No Limited Partner shall be required to reimburse the Managing General Partner, the Operator, their
Affiliates, or the Investor General Partners for any liability in excess of his agreed Capital
Contribution, except:
(i)
for a liability resulting from the Limited Partner’s unauthorized participation
in management of the Partnership; or
(ii)
from some other breach by the Limited Partner of this Agreement.
4.05(d). Authorized Transactions Are Not Deemed to Be a Breach. No transaction entered into or
action taken by the Partnership, or by the Managing General Partner, the Operator, or their
Affiliates, which is authorized by this Agreement shall be deemed a breach of any obligation owed
by the Managing General Partner, the Operator, or their Affiliates to the Partnership or the
Participants.
4.06. Other Activities.
4.06(a). The Managing General Partner May Pursue Other Natural Gas and Oil Activities for Its Own
Account. The Managing General Partner, the Operator, and their Affiliates are now engaged, and
will engage in the future, for their own account and for the account of others, including other
investors, in all aspects of the natural gas and oil business. This includes without limitation,
the evaluation, acquisition, and sale of producing and nonproducing Leases, and the exploration for
and production of natural gas, oil and other minerals.
The Managing General Partner is required to devote only so much of its time to the Partnership as
it determines in its sole discretion, but consistent with its fiduciary duties, is necessary to
manage the affairs of the Partnership. Except as expressly provided to the contrary in this
Agreement, and subject to fiduciary duties, the Managing General Partner, the Operator, and their
Affiliates may do the following:
(i)
continue their activities, or initiate further such activities, individually,
jointly with others, or as a part of any other limited or general partnership, tax
partnership, joint venture, or other entity or activity to which they are or may become
a party, in any locale and in the same fields, areas of operation or prospects in which
the Partnership may likewise be active;
(ii)
reserve partial interests in Leases being assigned to the Partnership or any
other interests not expressly prohibited by this Agreement;
deal with the Partnership as independent parties or through any other entity
in which they may be interested;
(iv)
conduct business with the Partnership as set forth in this Agreement; and
(v)
participate in such other investor operations, as investors or otherwise.
The Managing General Partner and its Affiliates shall not be required to permit the Partnership or
the Participants to participate in or share in any profits or other benefits from any of the other
operations in which the Managing General Partner and its Affiliates may be interested as permitted
under this section. However, except as otherwise provided in this Agreement, the Managing General
Partner and its Affiliates may pursue business opportunities that are consistent with the
Partnership’s investment objectives for their own account only after they have determined that the
opportunity either:
(i)
cannot be pursued by the Partnership because of insufficient funds; or
(ii)
it is not appropriate for the Partnership under the existing circumstances.
4.06(b). Managing General Partner May Manage Multiple Partnerships. The Managing General Partner
or its Affiliates may manage multiple Programs simultaneously.
4.06(c). Partnership Has No Interest in Natural Gas Contracts or Pipelines and Gathering Systems.
Notwithstanding any other provision in this Agreement, the Partnership shall not:
(i)
be a party to any natural gas supply agreement that the Managing General
Partner, the Operator, or their Affiliates enter into with a third-party or have any
rights pursuant to such natural gas supply agreement; or
(ii)
receive any interest in the Managing General Partner’s, the Operator’s, and
their Affiliates’ pipeline or gathering system or compression facilities.
ARTICLE V
PARTICIPATION IN COSTS AND REVENUES,
CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS
5.01. Participation in Costs and Revenues. Except as otherwise provided in this Agreement, costs
and revenues of the Partnership shall be charged and credited to the Managing General Partner and
the Participants as set forth in this section and its subsections.
5.01(a). Costs. Costs shall be charged as set forth below.
5.01(a)(1). Organization and Offering Costs. Organization and Offering Costs shall be charged
100% to the Managing General Partner. For purposes of sharing in revenues under §5.01(b)(4), the
Managing General Partner shall be credited with Organization and Offering Costs paid by it and for
services provided by it as Organization Costs up to an amount equal to 15% of the Partnership’s
subscription proceeds. Any Organization and Offering Costs paid and/or provided in services by
the Managing General Partner in excess of this amount shall not be credited towards the Managing
General Partner’s required Capital Contribution or revenue share set forth in §5.01(b)(4). The
Managing General Partner’s credit for services provided to the Partnership as Organization Costs
shall be determined based on generally accepted accounting principles.
5.01(a)(2). Intangible Drilling Costs. Ninety percent (90%) of the Partnership’s subscription
proceeds received from the Participants shall be used to pay 100% of the Intangible Drilling Costs.
5.01(a)(3). Tangible Costs. Ten percent (10%) of the Partnership’s subscription proceeds received
from the Participants shall be used by the Partnership to pay Tangible Costs. All remaining
Tangible Costs in excess of an amount equal to 10% of the Partnership’s subscription proceeds shall
be charged 100% to the Managing General Partner.
5.01(a)(4). Operating Costs, Direct Costs, Administrative Costs and All Other Costs. Operating
Costs, Direct Costs, Administrative Costs, and all other Partnership costs not specifically
allocated shall be charged to the parties in the same ratio as the related production revenues are
being credited.
5.01(a)(5). Allocation of Intangible Drilling Costs and Tangible Costs at Partnership Closings.
Intangible Drilling Costs and the Participants’ share of Tangible Costs of a well or wells to be
drilled and completed with the proceeds of a Partnership closing shall be charged 100% to the
Participants who are admitted to the Partnership in that closing and shall not be reallocated to
take into account other Partnership closings.
Although the subscription proceeds received by the Partnership in each closing may be used to pay
the costs of drilling different wells, 90% of each Participant’s subscription proceeds shall be
applied to Intangible Drilling Costs and 10% of each Participant’s subscription proceeds shall be
applied to Tangible Costs regardless of when the Participant subscribes for his Units or is
admitted to the Partnership.
5.01(a)(6). Lease Costs. The Leases shall be contributed to the Partnership by the Managing
General Partner as set forth in §4.01(a)(4).
5.01(b). Revenues. Revenues shall be credited as set forth below.
5.01(b)(1). Allocation of Revenues on Disposition of Property. If the parties’ Capital Accounts
are adjusted to reflect the simulated depletion of a natural gas or oil property of the
Partnership, then the portion of the total amount realized by the Partnership on the taxable
disposition of the property that represents recovery of its simulated tax basis in the property
shall be allocated to the parties in the same proportion as the aggregate adjusted tax basis of the
property was allocated to the parties or their predecessors in interest. If the parties’ Capital
Accounts are adjusted to reflect the actual depletion of a natural gas or oil property of the
Partnership, then the portion of the total amount realized by the Partnership on the taxable
disposition of the property that equals the parties’ aggregate remaining adjusted tax basis in the
property shall be allocated to the parties in proportion to their respective remaining adjusted tax
bases in the property. Thereafter, any excess shall be allocated to the Managing General Partner
in an amount equal to the difference between the fair market value of the Lease at the time it was
contributed to the Partnership and its simulated or actual adjusted tax basis at that time.
Finally, any excess shall be credited as provided in §5.01(b)(4), below.
In the event of the Partnership’s sale of developed natural gas and oil properties with equipment
on the properties, the Managing General Partner may make any reasonable allocation of the sales
proceeds between the equipment and the Leases.
5.01(b)(2). Interest. Interest earned on each Participant’s subscription proceeds under
§3.05(b)(1) shall be credited to the accounts of the respective subscribers who paid the
subscription proceeds to the Partnership. The interest shall be paid to the Participants not later
than the Partnership’s first cash distribution from operations.
After the Offering Termination Date and until proceeds from the offering are invested in the
Partnership’s natural gas and oil operations, any interest income from temporary investments shall
be allocated pro rata to the Participants providing the subscription proceeds.
All other interest income, including interest earned on the deposit of production revenues, shall
be credited as provided in §5.01(b)(4), below.
5.01(b)(3). Sale or Disposition of Equipment. Proceeds from the sale or disposition of equipment
shall be credited to the parties charged with the costs of the equipment in the ratio in which the
costs were charged.
5.01(b)(4). Other Revenues. Subject to §5.01(b)(4)(a), the Managing General Partner and the
Participants shall share in all other Partnership revenues in the same percentage as their
respective Capital Contribution bears to the Partnership’s total Capital Contributions, except that
the Managing General Partner shall receive an additional 7% of Partnership revenues. However, the
Managing General Partner’s total revenue share shall not exceed 40% of Partnership revenues. For
example, if the Managing General Partner contributes 25% of the Partnership’s total Capital
Contributions and the Participants contribute 75% of the Partnership’s total Capital Contributions,
then the Managing General Partner would receive 32% of the Partnership
revenues and the
Participants would receive 68% of the Partnership revenues. On the other hand, if the Managing
General Partner contributes 35% of the Partnership’s total Capital Contributions and the
Participants contribute
65% of the Partnership’s total Capital Contributions, then the Managing General Partner would
receive 40% of the Partnership revenues, not 42%, because its revenue share cannot exceed 40% of
Partnership revenues, and the Participants would receive 60% of Partnership revenues.
5.01(b)(4)(a). Subordination. The Managing General Partner shall subordinate up to 50% of its
share of Partnership Net Production Revenues to the receipt by Participants of cash distributions
from the Partnership equal to $1,000 per Unit (which is 10% of $10,000 per Unit) regardless of the
actual subscription price they paid for their Units, in each of the Partnership’s first five
12-month periods of operations as set forth below. In this regard:
(i)
the aggregate 60-month subordination period shall begin with the first cash
distribution from operations to the Participants;
(ii)
subsequent subordination distributions, if any, shall be determined and made at the
time of each subsequent distribution of revenues to the Participants; and
(iii)
the Managing General Partner shall not subordinate more than 50% of its share of
Partnership Net Production Revenues in any 12-month subordination period.
The Managing General Partner’s subordination obligation shall be determined by:
(i)
carrying forward to subsequent 12-month subordination periods the amount, if
any, by which cumulative cash distributions to Participants, including any
subordination payments, are less than:
(a)
$1,000 per Unit (10% of $10,000 per Unit) in the first 12-month
period;
(b)
$2,000 per Unit (20% of $10,000 per Unit) in the second 12-month
period;
(c)
$3,000 per Unit (30% of $10,000 per Unit) in the third 12-month
period; or
(d)
$4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month
period (no carry forward is required if the Participant’s cumulative cash
distributions are less than $5,000 per Unit (50% of $10,000 per Unit) in the
fifth 12-month period, because the Managing General Partner’s subordination
obligation terminates on the expiration of the fifth 12-month period); and
(ii)
reimbursing the Managing General Partner for any previous subordination
payments to the extent cumulative cash distributions to Participants, including any
subordination payments, would exceed:
(a)
$1,000 per Unit (10% of $10,000 per Unit) in the first 12-month
period;
(b)
$2,000 per Unit (20% of $10,000 per Unit) in the second 12-month
period;
(c)
$3,000 per Unit (30% of $10,000 per Unit) in the third 12-month
period;
(d)
$4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month
period; or
(e)
$5,000 per Unit (50% of $10,000 per Unit) in the fifth 12-month
period.
The Managing General Partner’s subordination obligation also shall be subject to the following
conditions:
(i)
the subordination obligation may be prorated in the Managing General Partner’s
discretion (e.g. in the case of a monthly distribution, the Managing General Partner
shall not have any subordination obligation if the cumulative monthly distributions to
Participants equal $83.33 per Unit (8.333% of $1,000 per Unit) or more, assuming there
are no subordination distributions owed for any preceding period);
the Managing General Partner shall not be required to return Partnership
distributions previously received by it, even though a subordination obligation arises
after the distributions;
(iii)
subject to the foregoing provisions of this section, only Partnership revenues
in the current distribution period shall be debited or credited to the Managing General
Partner as may be necessary to provide, to the extent possible, subordination
distributions to the Participants and reimbursements to the Managing General Partner;
(iv)
no subordination distributions to the Participants or reimbursements to the
Managing General Partner shall be made after the expiration of the fifth 12-month
subordination period; and
(v)
subordination payments to the Participants shall be subject to any lien or
priority granted by the Managing General Partner and/or its Affiliates to its lenders
pursuant to agreements either entered into by the Managing General Partner and/or its
Affiliates before the subordination obligation arose or entered into or renewed by the
Managing General Partner and/or its Affiliates after the subordination obligation
arose.
5.01(b)(5). Commingling of Revenues From All Partnership Wells. The revenues from all Partnership
wells shall be commingled, so regardless of when a Participant subscribes for Units or is admitted
to the Partnership, he will share in the Partnership’s revenues from all of its wells on the same
basis as the other Participants.
5.01(c). Allocations.
5.01(c)(1). Allocations among Participants. Except as provided otherwise in this Agreement, costs
(other than Intangible Drilling Costs and Tangible Costs) and revenues charged or credited to the
Participants as a group, which includes all revenue credited to the Participants under §5.01(b)(4),
shall be allocated among the Participants, including the Managing General Partner to the extent of
any optional subscription for Units under §3.03(b)(1), in the ratio of their respective Units based
on $10,000 per Unit regardless of the actual subscription price paid by a Participant for his
Units.
Intangible Drilling Costs and Tangible Costs charged to the Participants as a group shall be
allocated among the Participants, including the Managing General Partner to the extent of any
optional subscription for Units under §3.03(b)(1), in the ratio of the subscription amount
designated on their respective Subscription Agreements rather than the number of their respective
Units.
5.01(c)(2). Costs and Revenues Not Directly Allocable to a Partnership Well. Costs and revenues
not directly allocable to a particular Partnership Well or additional operation shall be allocated
among the Partnership Wells or additional operations in any manner the Managing General Partner in
its reasonable discretion, shall select, and shall then be charged or credited in the same manner
as costs or revenues directly applicable to the Partnership Well or additional operation are being
charged or credited.
5.01(c)(3). Managing General Partner’s Discretion in Making Allocations For Federal Income Tax
Purposes. In determining the proper method of allocating charges or credits among the parties,
allocating any item of income, gain, loss, deduction or credit pursuant to new laws or new IRS or
judicial interpretations of existing law, allocating any other item that is not otherwise
specifically allocated in this Agreement or is subsequently determined by the Managing General
Partner to be clearly inconsistent with a party’s economic interest in the Partnership, or making
any other allocations under this Agreement, the Managing General Partner may adopt any method of
allocation that it selects, in its sole discretion, after consultation with the Partnership’s legal
counsel or accountants. Any new allocation provisions shall be made in a manner that is consistent
with the parties’ economic interests in the Partnership and will result in the most favorable
aggregate consequences to the Participants that are, as nearly as possible, consistent with the
original allocations described in this Agreement.
5.02. Capital Accounts and Allocations Thereto.
5.02(a). Capital Accounts for Each Party to this Agreement. A single, separate Capital Account
shall be established for each party, regardless of the number of interests owned by the party, the
class of the interests and the time or manner in which the interests were acquired.
5.02(b)(1). General Standard. Except as otherwise provided in this Agreement, the Capital Account
of each party shall be determined and maintained in accordance with Treas. Reg. §1.704-l(b)(2)(iv)
and shall be increased by:
(i)
the amount of money contributed by him to the Partnership;
(ii)
the fair market value of property contributed by him to the Partnership,
without regard to §7701(g) of the Code, net of liabilities secured by the contributed
property that the Partnership is considered to assume or take subject to under §752 of
the Code; and
(iii)
allocations to him of Partnership income and gain, or items thereof, including
income and gain exempt from tax and income and gain described in Treas. Reg.
§1.704-l(b)(2)(iv)(g), but excluding income and gain described in Treas. Reg.
§1.704-l(b)(4)(i);
and shall be decreased by:
(iv)
the amount of money distributed to him by the Partnership;
(v)
the fair market value of property distributed to him by the Partnership,
without regard to §7701(g) of the Code, net of liabilities secured by the distributed
property that he is considered to assume or take subject to under §752 of the Code;
(vi)
allocations to him of Partnership expenditures described in §705(a)(2)(B) of
the Code; and
(vii)
allocations to him of Partnership loss and deduction, or items thereof,
including loss and deduction described in Treas. Reg. §1.704-l(b)(2)(iv)(g), but
excluding items described in (vi) above, and loss or deduction described in Treas. Reg.
§1.704-l(b)(4)(i) or (iii).
5.02(b)(2). Exception. If Treas. Reg. §1.704-l(b)(2)(iv) fails to provide guidance, Capital
Account adjustments shall be made in a manner that:
(i)
maintains equality between the aggregate governing Capital Accounts of the
parties and the amount of Partnership capital reflected on the Partnership’s balance
sheet, as computed for book purposes;
(ii)
is consistent with the underlying economic arrangement of the parties; and
(iii)
is based, wherever practicable, on federal tax accounting principles.
5.02(c). Payments to the Managing General Partner. The Capital Account of the Managing General
Partner shall be reduced by payments to it pursuant to §4.04(a)(2) only to the extent of the
Managing General Partner’s distributive share of any Partnership deduction, loss, or other downward
Capital Account adjustment resulting from the payments. Also, in the event, and to the extent,
that the Managing General Partner is treated under the Code as having been transferred an interest
in the Partnership in connection with the performance of services for the Partnership (whether
before or after the formation of the Partnership):
(i)
any resulting compensation income shall be allocated 100% to the Managing
General Partner;
(ii)
any associated increase in Capital Accounts shall be credited 100% to the
Managing General Partner; and
(iii)
any associated deduction to which the Partnership is entitled shall be
allocated 100% to the Managing General Partner.
5.02(d). Discretion of Managing General Partner in the Method of Maintaining Capital Accounts.
Notwithstanding any other provisions of this Agreement, the method of maintaining Capital Accounts
may be changed from time to time, in the
discretion of the Managing General Partner, to take into
consideration §704 and other provisions of the Code and the related rules, regulations and
interpretations as may exist from time to time.
5.02(e). Revaluations of Property. In the discretion of the Managing General Partner the Capital
Accounts of the parties may be increased or decreased to reflect a revaluation of Partnership
property, including intangible assets such as goodwill, on a property-by-property basis except as
otherwise permitted under §704(c) of the Code and the regulations thereunder, on the Partnership’s
books, in accordance with Treas. Reg. §1.704-l(b)(2)(iv)(f).
5.02(f). Amount of Book Items. In cases where §704(c) of the Code or §5.02(e) applies, Capital
Accounts shall be adjusted in accordance with Treas. Reg. §1.704-l(b)(2)(iv)(g) for allocations of
depreciation, depletion, amortization and gain and loss, as computed for book purposes, with
respect to the property.
5.03. Allocation of Income, Deductions and Credits.
5.03(a). In General.
5.03(a)(1). Deductions Are Allocated to Party Charged with Expenditure. To the extent permitted
by law and except as otherwise provided in this Agreement, all deductions and credits, including,
but not limited to, intangible drilling and development costs and depreciation, shall be allocated
to the party who has been charged with the expenditure giving rise to the deductions and credits;
and to the extent permitted by law, these parties shall be entitled to the deductions and credits
in computing taxable income or tax liabilities to the exclusion of any other party. Also, any
Partnership deductions that would be nonrecourse deductions if they were not attributable to a loan
made or guaranteed by the Managing General Partner or its Affiliates shall be allocated to the
Managing General Partner to the extent required by law.
5.03(a)(2). Income and Gain Allocated in Accordance With Revenues. Except as otherwise provided
in this Agreement, all items of income and gain, including gain on disposition of assets, shall be
allocated in accordance with the related revenue allocations set forth in §5.01(b) and its
subsections.
5.03(b). Tax Basis of Each Property. Subject to §704(c) of the Code, the tax basis of each oil
and gas property for computation of cost depletion and gain or loss on disposition shall be
allocated and reallocated when necessary based on the capital interest in the Partnership as to the
property and the capital interest in the Partnership for this purpose as to each property shall be
considered to be owned by the parties in the ratio in which the expenditure giving rise to the tax
basis of the property has been charged as of the end of the year.
5.03(c). Gain or Loss on Oil and Gas Properties. Each party shall separately compute its gain or
loss on the disposition of each natural gas and oil property in accordance with the provisions of
§613A(c)(7)(D) of the Code, and the calculation of the gain or loss shall consider the party’s
adjusted basis in his property interest computed as provided in §5.03(b) and the party’s allocable
share of the amount realized from the disposition of the property.
5.03(d). Gain on Depreciable Property. Gain from each sale or other disposition of depreciable
property shall be allocated to each party whose share of the proceeds from the sale or other
disposition exceeds its contribution to the adjusted basis of the property in the ratio that the
excess bears to the sum of the excesses of all parties having an excess.
5.03(e). Loss on Depreciable Property. Loss from each sale, abandonment or other disposition of
depreciable property shall be allocated to each party whose contribution to the adjusted basis of
the property exceeds its share of the proceeds from
the sale, abandonment or other disposition in the proportion that the excess bears to the sum of
the excesses of all parties having an excess.
5.03(f). Allocation If Recapture Treated As Ordinary Income. Any recapture treated as an increase
in ordinary income by reason of §§1245, 1250 or 1254 of the Code shall be allocated to the parties
in the amounts in which the recaptured items were previously allocated to them; provided that to
the extent recapture allocated to any party is in excess of the party’s gain from the disposition
of the property, the excess shall be allocated to the other parties but only to the extent of the
other parties’ gain from the disposition of the property.
5.03(g). Tax Credits. If a Partnership expenditure, whether or not deductible, that gives rise to
a tax credit in a Partnership taxable year also gives rise to valid allocations of Partnership loss
or deduction, or other downward Capital Account adjustments, for the year, then the parties’
interests in the Partnership with respect to the credit, or the cost giving rise thereto, shall be
in the same proportion as the parties’ respective distributive shares of the loss or deduction, and
adjustments. If Partnership receipts, whether or not taxable, that give rise to a tax credit,
including a marginal well production credit under §45I of the Code, in a Partnership taxable year
also give rise to valid allocations of Partnership income or gain, or other upward Capital Account
adjustments, for the year, then the parties’ interests in the Partnership with respect to the
credit, or the Partnership’s receipts or production of natural gas and oil production giving rise
thereto, shall be in the same proportion as the parties’ respective shares of the Partnership’s
production revenues from the sales of its natural gas and oil production as provided in
§5.01(b)(4).
5.03(h). Deficit Capital Accounts and Qualified Income Offset. Notwithstanding any provision of
this Agreement to the contrary, an allocation of loss or deduction which would result in a party
having a deficit Capital Account balance as of the end of the taxable year to which the allocation
relates, if charged to the party, to the extent the Participant is not required to restore the
deficit to the Partnership, taking into account:
(i)
adjustments that, as of the end of the year, reasonably are expected to be made
to the party’s Capital Account for depletion allowances with respect to the
Partnership’s natural gas and oil properties;
(ii)
allocations of loss and deduction that, as of the end of the year, reasonably
are expected to be made to the party under §§704(e)(2) and 706(d) of the Code and
Treas. Reg. §1.751-1(b)(2)(ii); and
(iii)
distributions that, as of the end of the year, reasonably are expected to be
made to the party to the extent they exceed offsetting increases to the party’s Capital
Account, assuming for this purpose that the fair market value of Partnership property
equals its adjusted tax basis, that reasonably are expected to occur during or prior to
the Partnership taxable years in which the distributions reasonably are expected to be
made;
shall be charged to the Managing General Partner. Further, the Managing General Partner shall be
credited with an additional amount of Partnership income or gain equal to the amount of the loss or
deduction as quickly as possible to the extent that the chargeback does not cause or increase
deficit balances in the parties’ Capital Accounts which are not required to be restored to the
Partnership.
Notwithstanding any provision of this Agreement to the contrary, if a party unexpectedly receives
an adjustment, allocation, or distribution described in (i), (ii), or (iii) above, or any other
distribution, which causes or increases a deficit balance in the party’s Capital Account which is
not required to be restored to the Partnership, the party shall be allocated items of income and
gain, consisting of a pro rata portion of each item of Partnership income, including gross income
and gain for the year, in an amount and manner sufficient to eliminate the deficit balance as
quickly as possible.
5.03(i). Minimum Gain Chargeback. To the extent there is a net decrease during a Partnership
taxable year in the minimum gain attributable to a Partner nonrecourse debt, then any Partner with
a share of the minimum gain attributable to the debt at the beginning of the year shall be
allocated items of Partnership income and gain in accordance with Treas. Reg. §1.704-2(i).
5.03(j). Partners’ Allocable Shares. Except as otherwise provided in this Agreement, each party’s
allocable share of Partnership income, gain, loss, deductions and credits shall be determined by
using any method prescribed or permitted by the Secretary of the Treasury by regulations or other
guidelines and selected by the Managing General Partner which takes into account the varying
interests of the parties in the Partnership during the taxable year. In the absence of those
regulations or guidelines, except as otherwise provided in this Agreement, the allocable share
shall be based on actual income, gain, loss, deductions and credits economically accrued each day
during the taxable year in proportion to each party’s varying interest in the Partnership on each
day during the taxable year.
5.03(k). Contingent Income. Subject to §5.04(d), if it is determined that any taxable income
results to any party by reason of its entitlement to a share of capital of the Partnership, or a
share of profits or revenues of the Partnership before the profit or revenue has been realized by
the Partnership, the resulting deduction, as well as any resulting gain, shall not enter into
Partnership net income or loss, but shall be separately allocated to that party.
5.04(a). Election to Deduct Intangible Costs. The Partnership’s federal income tax return shall
be made in accordance with an election under the option granted by the Code to deduct intangible
drilling and development costs.
5.04(b). No Election Out of Subchapter K. No election shall be made by the Partnership, any
Partner, or the Operator for the Partnership to be excluded from the application of the partnership
provisions of the Code, including Subchapter K of Chapter 1 of Subtitle A of the Code.
5.04(c). §754 Election. In the event of the transfer of an interest in the Partnership, or on the
death of an individual party hereto, or in the event of the distribution of property to any party,
the Managing General Partner may choose for the Partnership to file an election in accordance with
the applicable Treasury Regulations to cause the basis of the Partnership’s assets to be adjusted
for federal income tax purposes as provided by §§734 and 743 of the Code.
5.04(d). §83 Election. The Partnership, the Managing General Partner and each Participant hereby
agree to be legally bound by the provisions of this §5.04(d) and further agree that, in the
Managing General Partner’s sole discretion, the Partnership and all of its Partners may elect a
safe harbor under which the fair market value of a Partnership interest that is transferred in
connection with the performance of services is treated as being equal to the liquidation value of
that interest for transfers on or after the date final regulations providing the safe harbor are
published in the Federal Register. If the Managing General Partner determines that the Partnership
and all of its Partners will elect the safe harbor, which determination may be made solely in the
best interests of the Managing General Partner, the Partnership, the Managing General Partner and
each Participant further agree that:
(i)
the Partnership shall be authorized and directed to elect the safe harbor;
(ii)
the Partnership and each of its Partners (including any Person to whom a
Partnership interest is transferred in connection with the performance of services)
shall comply with all requirements of the safe harbor with respect to all Partnership
interests transferred in connection with the performance of services while the election
remains effective; and
(iii)
the Managing General Partner, in its sole discretion, may cause the
Partnership to terminate the safe harbor election, which determination may be made in
the sole interests of the Managing General Partner.
5.05. Distributions.
5.05(a). In General.
5.05(a)(1). Monthly Review of Accounts. The Managing General Partner shall review the accounts of
the Partnership at least monthly to determine whether cash distributions are appropriate and the
amount to be distributed, if any.
5.05(a)(2). Distributions. The Partnership shall distribute funds to the Managing General Partner
and the Participants allocated to their respective accounts that the Managing General Partner deems
unnecessary for the Partnership to retain.
5.05(a)(3). No Borrowings. In no event shall funds be advanced or borrowed by the Partnership for
distributions to the Managing General Partner and the Participants if the amount of the
distributions would exceed the Partnership’s accrued and received revenues for the previous four
quarters, less paid and accrued Operating Costs with respect to the revenues. The determination of
revenues and costs shall be made in accordance with generally accepted accounting principles,
consistently applied.
5.05(a)(4). Distributions to the Managing General Partner. Cash distributions from the
Partnership to the Managing General Partner shall only be made as follows:
(i)
in conjunction with distributions to Participants; and
out of funds properly allocated to the Managing General Partner’s account.
5.05(a)(5). Reserve. At any time after one year from the date each Partnership Well is placed
into production, the Managing General Partner shall have the right to deduct each month from the
Partnership’s net sales proceeds from the sale of the natural gas and oil production from each of
its productive wells up to $200 per well for the purpose of establishing a fund to cover the
estimated costs of plugging and abandoning the well. All of these funds shall be deposited in a
separate interest bearing account for the benefit of the Partnership, and the total amount so
retained and deposited shall not exceed the Managing General Partner’s reasonable estimate of the
costs to plug and abandon the well.
5.05(b). Distribution of Uncommitted Subscription Proceeds. Any subscription proceeds not
expended or committed for expenditure, as evidenced by a written agreement, by the Partnership
within 12 months of the Offering Termination Date, except necessary operating capital, shall be
distributed to the Participants in the ratio that the subscription amount designated on each
Participant’s Subscription Agreement bears to the total subscription amounts designated on all of
the Participants’ Subscription Agreements, as a return of capital. The Managing General Partner
shall reimburse the Participants for the selling or other offering expenses, if any, allocable to
the return of capital.
For purposes of this subsection, “committed for expenditure” shall mean contracted for, actually
earmarked for or allocated by the Managing General Partner to the Partnership’s drilling
operations, and “necessary operating capital” shall mean those funds which, in the opinion of the
Managing General Partner, should remain on hand to assure continuing operation of the Partnership.
5.05(c). Distributions on Winding Up. On the winding up of the Partnership distributions shall be
made as provided in §7.02.
5.05(d). Interest and Return of Capital. No party shall under any circumstances be entitled to
any interest on amounts retained by the Partnership. Each Participant shall look only to his share
of distributions, if any, from the Partnership for a return of his Capital Contribution.
ARTICLE VI
TRANSFER OF UNITS
6.01. Transferability of Units. A Participant’s transfer of a portion or all his Units, or any
interest in his Units, is subject to all of the provisions of this Article VI. For purposes of
this Article VI, the term “transfer” shall include any sale, exchange, gift, assignment, pledge,
mortgage, hypothecation, redemption or other form of transfer of a Unit, or any interest in a Unit,
by a Participant (which may include the Managing General Partner or its Affiliates, if they
purchase Units) or by operation of law, including any transfers of Units which a Participant
presents to the Managing General Partner for purchase under §6.03.
6.01(a). Rights of Assignee. Unless a transferee of a Participant’s Unit becomes a substitute
Participant with respect to that Unit in accordance with the provisions of §6.02(a)(3)(a), he shall
not be entitled to any of the rights granted to a Participant under this Agreement, other than the
right to receive all or part of the share of the profits, losses, income, gains, deductions,
credits and depletion allowances, or items thereof, and cash distributions or returns of capital to
which his transferor would otherwise be entitled under this Agreement.
6.01(b). Conversion of Investor General Partner Units to Limited Partner Units.
6.01(b)(1). Automatic Conversion. After all of the Partnership Wells have been drilled and
completed, as determined by the Managing General Partner, the Managing General Partner shall file
an amended certificate of limited partnership with the Secretary of State of the State of Delaware
for the purpose of converting the Investor General Partner Units to Limited Partner Units. In this
regard, a well shall be deemed to be completed when production equipment is installed on a well,
even though the well may not yet be connected to a pipeline for production of natural gas.
6.01(b)(2). Investor General Partners Shall Have Contingent Liability. On conversion the Investor
General Partners shall be Limited Partners entitled to limited liability; however, they shall
remain liable to the Partnership for any additional Capital
Contribution required for their
proportionate share of any Partnership obligation or liability arising before the conversion of
their Units as provided in §3.05(b)(2).
6.01(b)(3). Conversion Shall Not Affect Allocations. The conversion shall not affect the
allocation to any Participant of any item of Partnership income, gain, loss, deduction or credit or
other item of special tax significance other than Partnership liabilities, if any. Further, the
conversion shall not affect any Participant’s interest in the Partnership’s natural gas and oil
properties and unrealized receivables.
6.01(b)(4). Right to Convert if Reduction of Insurance. Notwithstanding the foregoing, the
Managing General Partner shall notify all Participants at least 30 days before the effective date
of any material adverse change in the Partnership’s insurance coverage. If the insurance coverage
is to be materially reduced, then the Investor General Partners shall have the right to convert
their Units into Limited Partner Units before the reduction by giving written notice to the
Managing General Partner.
6.02. Special Restrictions on Transfers of Units by Participants.
6.02(a). In General. Transfers of Units by Participants are subject to the following general
conditions:
(i)
except as provided by operation of law:
(a)
only whole Units may be transferred unless the Participant owns
less than a whole Unit, in which case his entire fractional interest must be
transferred; and
(b)
Units may not be transferred to a person who is under the age of
18 or incompetent (unless an attorney-in-fact, guardian, custodian or
conservator has been appointed to handle the affairs of that person) without the
Managing General Partner’s consent;
(ii)
the costs and expenses associated with the transfer must be paid by the assignor Participant;
(iii)
the transfer documents must be in a form satisfactory to the Managing General Partner; and
(iv)
the terms of the transfer must not contravene those of this Agreement.
Transfers of Units by Participants are subject to the following additional restrictions set forth
in §§6.02(a)(1) and 6.02(a)(2).
6.02(a)(1). Tax Law Restrictions. Subject to transfers permitted by §6.03 and transfers by
operation of law, no transfer of a Unit by a Participant shall be made which, in the opinion of
counsel to the Partnership, would result in the Partnership being either:
(i)
terminated for tax purposes under §708 of the Code; or
(ii)
treated as a “publicly-traded” partnership for purposes of §469(k) of the Code.
6.02(a)(2). Securities Laws Restriction. Subject to transfers permitted by §6.03 and transfers by
operation of law, no Unit shall be transferred by a Participant unless there is either:
(i)
an effective registration of the Unit under the Securities Act of 1933, as
amended, and qualification under applicable state securities laws; or
(ii)
an opinion of counsel acceptable to the Managing General Partner that the
registration and qualification of the Unit is not required, unless this requirement is
waived by the Managing General Partner.
Transfers of Units by Participants are also subject to any conditions contained in the Subscription
Agreement and Exhibit (B) to the Prospectus.
6.02(a)(3)(a). Procedure to Become Substitute Participant. Subject to §§6.02(a)(1) and
6.02(a)(2), a transferee of a Participant’s Unit shall become a substitute Participant entitled to
all the rights of a Participant if, and only if:
(i)
the transferor gives the transferee the right;
(ii)
the transferee pays to the Partnership all costs and expenses incurred by the
Partnership in connection with the substitution; and
(iii)
the transferee executes and delivers the instruments necessary to establish
that a legal transfer has taken place and to confirm the agreement of the transferee to
be bound by all of the terms of this Agreement, in a form acceptable to the Managing
General Partner.
6.02(a)(3)(b). Rights of Substitute Participant. A substitute Participant shall be entitled to
all of the rights attributable to full ownership of the assigned Units including the right to vote.
6.02(b). Effect of Transfer.
6.02(b)(1). Amendment of Records. The Partnership shall amend its records at least once each
calendar quarter to effect the substitution of substitute Participants.
Any transfer of a Unit by a Participant which is permitted under this Article VI, when the
transferee does not become a substitute Participant, shall be effective as follows:
(i)
midnight of the last day of the calendar month in which it is made; or
(ii)
at the Managing General Partner’s election, 7:00 A.M. of the following day.
6.02(b)(2). A Transfer of Units Does Not Relieve the Transferor of Certain Costs. No transfer of
a Unit by a Participant, including a transfer of less than all of a Participant’s Units or the
transfer of a Participant’s Units to more than one party, shall relieve the transferor of its
responsibility for its proportionate part of any expenses, obligations and liabilities under this
Agreement related to the Units so transferred, whether arising before or after the transfer.
6.02(b)(3). A Transfer of Units Does Not Require A Partnership Accounting. No transfer of a Unit
by a Participant shall require an accounting of the Partnership. Also, no transfer of a Unit shall
grant rights under this Agreement, including the exercise of any elections, as between the
transferring Participant and the Partnership, the Managing General Partner and the
remaining Participants to more than one Person unanimously designated by the transferee(s) of the
Unit, and, if he has retained an interest in the transferred Unit, the transferor of the Unit.
6.02(b)(4). Required Notice to Managing General Partner of Transfer of Units. Until the Managing
General Partner receives from the transferring Participant a written notice in a form acceptable to
the Managing General Partner that designates the transferee(s) of a Unit, the Managing General
Partner shall continue to account only to the Person to whom it was furnishing notices pursuant to
§8.01 and its subsections before the purported transfer of the Unit. This party shall continue to
exercise all rights under this Agreement applicable to the Units owned by the purported transferor
of the Unit.
6.03. Presentment.
6.03(a). In General. Participants shall have the right to present their Units to the Managing
General Partner for purchase subject to the conditions and limitations set forth in this §6.03. A
Participant, however, is not obligated to present his Units for purchase.
The Managing General Partner shall not be obligated to purchase more than 5% of the total
outstanding Units in any calendar year and this 5% limit may not be waived. The Managing General
Partner shall not purchase less than one Unit unless the
lesser amount represents the Participant’s
entire interest in the Partnership, however, the Managing General Partner may waive this
limitation.
A Participant may present his Units in writing to the Managing General Partner every year beginning
with the fifth calendar year after the Offering Termination Date subject to the following
conditions:
(i)
the presentment request must be made by the Participant within 120 days of the
reserve report described in §4.03(b)(3);
(ii)
in accordance with Treas. Reg. §1.7704-1(f), the purchase may not be made until
at least 60 calendar days after the Participant notifies the Partnership in writing of
the Participant’s intention to exercise the presentment right; and
(iii)
the purchase shall not be considered effective until the presentment price has
been paid to the Participant in cash to the Participant.
6.03(b). Requirement for Independent Petroleum Consultant. The amount of the presentment price
attributable to Partnership reserves shall be determined based on the last reserve report of the
Partnership prepared by the Managing General Partner and reviewed by an Independent Expert. The
Managing General Partner shall estimate the present worth of future net revenues attributable to
the Partnership’s interest in the Proved Reserves as described in §4.03(b)(3)(ii). The calculation
of the presentment price shall be made as set forth in §6.03(c).
6.03(c). Calculation of Presentment Price. The presentment price shall be based on the
Partnership’s net assets and liabilities and shall be allocated pro rata to each Participant in the
ratio that his number of Units bears to the total number of Units. Subject to the foregoing, the
presentment price shall include the sum of the following Partnership items:
(i)
an amount based on 70% of the present worth of future net revenues from the
Proved Reserves determined as described in §6.03(b);
(ii)
cash on hand;
(iii)
prepaid expenses and accounts receivable less a reasonable amount for doubtful
accounts; and
(iv)
the estimated market value of all assets that are not separately specified
above, determined in accordance with standard industry valuation procedures.
There shall be deducted from the foregoing sum the following Partnership items:
(i)
an amount equal to all debts, obligations, and other liabilities, including
accrued expenses; and
(ii)
any distributions made to the Participants between the date of the presentment
request and the date the presentment price is paid to the selling Participant.
However, if any amount of those cash distributions to the Participant by the
Partnership was derived from the sale of natural gas, oil or other mineral production,
or of a producing property owned by the Partnership, after the date of the presentment
request, for purposes of determining the reduction of the presentment price the amount
of those cash distributions shall be discounted using the same rate used to take into
account the risk factors employed to determine the present worth of the Partnership’s
Proved Reserves.
6.03(d). Further Adjustment May Be Allowed. The presentment price may be further adjusted by the
Managing General Partner for estimated changes therein from the date of the report to the date of
payment of the presentment price to the Selling Participant because of the following:
(i)
the production or sales of, or additions to, reserves and lease and well
equipment, sale or abandonment of Leases, and similar matters occurring before the date
of the presentment request; and
any of the following occurring before payment of the presentment price to the
selling Participant:
(a)
changes in well performance;
(b)
increases or decreases in the market price of natural gas, oil or
other minerals;
(c)
revisions to regulations relating to the importing of
hydrocarbons;
(d)
changes in income, ad valorem, and other tax laws, such as
material variations in the provisions for depletion; and
(e)
similar matters.
6.03(e). Selection by Lot. If less than all of the Units presented at any time are to be
purchased, then the Participants whose Units are to be purchased will be selected by lot.
The Managing General Partner’s obligation to purchase Units presented may be discharged for its
benefit by a third-party or an Affiliate. The Units of the selling Participant shall be
transferred to the party who pays for it. A selling Participant shall be required to deliver an
executed assignment of his Units, in a form satisfactory to the Managing General Partner, together
with any other documentation as the Managing General Partner may reasonably request.
6.03(f). No Obligation of the Managing General Partner to Establish a Reserve. The Managing
General Partner shall have no obligation to establish any reserve to satisfy the presentment
feature under this section.
6.03(g). Suspension of Presentment Feature. The Managing General Partner may suspend this
presentment feature by so notifying Participants at any time if it determines in its sole
discretion that it:
(i)
does not have sufficient cash flow; or
(ii)
is unable to borrow funds for this purpose on terms it deems reasonable.
In addition, the presentment feature may be conditioned, in the Managing General Partner’s sole
discretion, on the Managing General Partner’s receipt of an opinion of counsel that the transfers
will not cause the Partnership to be treated as a “publicly traded partnership” under the Code.
The Managing General Partner shall hold the purchased Units for its own account and not for resale.
6.04. Redemption of Units from Non-Citizen Assignees. If the Partnership, the Managing General
Partner or any of its Affiliates become subject to federal, state or local laws or regulations
that, in the reasonable determination of the Managing General Partner, create a substantial risk of
cancellation or forfeiture of any property that they have an interest in because of the
nationality, citizenship or other related status of any Participant or assignee of a Participant’s
Units, the Partnership may redeem, on 30 days’ advance notice to the Participant, the Participant’s
Units or the Units held by the assignee of a Participant, at a reasonable redemption price per Unit
as determined by the Managing General Partner in its sole discretion.
ARTICLE VII
DURATION, DISSOLUTION, AND WINDING UP
7.01. Duration.
7.01(a). Fifty Year Term. The Partnership shall continue in existence for a term of 50 years from
the effective date of this Agreement unless sooner terminated as set forth below.
7.01(b). Termination. The Partnership shall terminate following the occurrence of:
any event that causes the dissolution of a limited partnership under the
Delaware Revised Uniform Limited Partnership Act.
7.01(c). Continuance of Partnership Except on Final Terminating Event. Other than the occurrence
of a Final Terminating Event, the Partnership or any successor limited partnership shall not be
wound up, but shall be continued by the parties and their respective successors as a successor
limited partnership under all of the terms of this Agreement. The successor limited partnership
shall succeed to all of the assets of the Partnership. As used throughout this Agreement, the term
“Partnership” shall include the successor limited partnership and the parties to the successor
limited partnership.
7.02. Dissolution and Winding Up.
7.02(a). Final Terminating Event. On the occurrence of a Final Terminating Event the affairs of
the Partnership shall be wound up and there shall be distributed to each of the parties its
Distribution Interest in the remaining Partnership assets.
7.02(b). Time of Liquidating Distribution. To the extent practicable and in accordance with sound
business practices in the judgment of the Managing General Partner, liquidating distributions shall
be made by:
(i)
the end of the taxable year in which liquidation occurs, determined without
regard to §706(c)(2)(A) of the Code; or
(ii)
if later, within 90 days after the date of the liquidation.
Notwithstanding, the following amounts are not required to be distributed within the foregoing time
periods so long as the withheld amounts are distributed as soon as practical:
(i)
amounts withheld for reserves reasonably required for liabilities of the
Partnership; and
(ii)
installment obligations owed to the Partnership.
7.02(c). In-Kind Distributions. The Managing General Partner shall not be obligated to offer
in-kind property distributions to the Participants, but may do so, in its discretion. Any in-kind
property distributions to the Participants shall be made to a liquidating trust or similar entity
for the benefit of the Participants, unless at the time of the distribution:
(i)
the Managing General Partner offers the individual Participants the election of
receiving in-kind property distributions and the Participants accept the offer after
being advised of the risks associated with direct ownership; or
(ii)
there are alternative arrangements in place which assure the Participants that
they will not, at any time, be responsible for the operation or disposition of
Partnership properties.
If the Managing General Partner has not received a Participant’s consent within 30 days after the
Managing General Partner mailed the request for consent, then it shall be presumed that the
Participant has refused to give his consent.
7.02(d). Sale If No Consent. Any Partnership asset which would otherwise be distributed in-kind
to a Participant, except for the failure or refusal of the Participant to give his written consent
to the distribution, may instead be sold by the Managing General Partner at the best price
reasonably obtainable from an independent third-party, who is not an Affiliate of the Managing
General Partner, or to the Managing General Partner itself or its Affiliates, including an
Affiliated Income Program, at fair market value as determined by an Independent Expert selected by
the Managing General Partner.
ARTICLE VIII
MISCELLANEOUS PROVISIONS
8.01. Notices.
8.01(a). Method. Any notice required under this Agreement shall be:
given by mail or delivered by an overnight delivery company (although one-day
delivery is not required) addressed to the party to receive the notice at the address
designated in §1.03.
If there is a transfer of Units under this Agreement, no notice to the transferee shall be
required, nor shall the transferee have any rights under this Agreement, until notice of the
transfer has been given to the Managing General Partner.
Any transfer of Units under this Agreement shall not increase the Managing General Partner’s or the
Partnership’s duty to give notice. If there is a transfer of Units under this Agreement to more
than one party, then notice to any owner of any interest in the Units shall be notice to all of the
owners of the Units.
8.01(b). Change in Address. The address of any party to this Agreement may be changed by notice
as follows:
(i)
to the Participants, if there is a change of address by the Managing General
Partner; or
(ii)
to the Managing General Partner, if there is a change of address by a
Participant.
8.01(c). Time Notice Deemed Given. If the notice is given by the Managing General Partner, then
the notice shall be considered given, and any applicable time shall run, from the date the notice
is placed in the mail or delivered to the overnight delivery company.
If the notice is given by any Participant, then the notice shall be considered given and any
applicable time shall run from the date the notice is received.
8.01(d). Effectiveness of Notice. Any notice to a party other than the Managing General Partner,
including a notice requiring concurrence or nonconcurrence, shall be effective, and any failure to
respond binding, irrespective of the following:
(i)
whether or not the notice is actually received; or
(ii)
any disability or death on the part of the noticee, even if the disability or
death is known to the party giving the notice.
8.01(e). Failure to Respond. Except pursuant to §7.02(c) or when this Agreement expressly
requires affirmative approval of a Participant, any Participant who fails to respond in writing
within the time specified to a request by the Managing General Partner as set forth below, for
approval of, or concurrence in, a proposed action shall be conclusively deemed to have approved the
action. Except pursuant to §7.02(c), when this Agreement expressly requires affirmative approval
of a Participant, the Managing General Partner shall send a first request and the time period for
the Participant’s written response shall not be less than 15 business days from the date of mailing
of the request. If the Participant does not respond in writing to the first request, then the
Managing General Partner shall send a second request. If the Participant does not respond in
writing to the second request within seven calendar days from the date of mailing the second
request, then the Participant shall be conclusively deemed to have approved the action.
8.02. Time. Time is of the essence of each part of this Agreement.
8.03. Applicable Law. The terms and provisions of this Agreement shall be construed under the
laws of the State of Delaware, other than its conflict of law provisions, however, this section
shall not be deemed to limit causes of action for alleged violations of federal or state securities
law to the laws of the State of Delaware. Neither this Agreement nor the Subscription Agreement
shall require mandatory venue or mandatory arbitration of any or all claims by Participants against
the Sponsor.
8.04. Agreement in Counterparts. This Agreement may be executed in counterpart and shall be
binding on all of the parties executing this or similar agreements from and after the date of
execution by each party.
8.05(a). Procedure for Amendment. No changes in this Agreement shall be binding unless:
(i)
proposed in writing by the Managing General Partner, and adopted with the
consent of Participants whose Units equal a majority of the total Units; or
(ii)
proposed in writing by Participants whose Units equal 10% or more of the total
Units and approved by an affirmative vote of Participants whose Units equal a majority
of the total Units.
8.05(b). Circumstances Under Which the Managing General Partner Alone May Amend. The Managing
General Partner is authorized to amend this Agreement and its exhibits without the consent of
Participants in any way deemed necessary or desirable by it to do any or all of the following:
(i)
add, or substitute in the case of an assigning party, additional Participants;
(ii)
enhance the tax benefits of the Partnership to the parties and amend the
allocation provisions of this Agreement as provided in §5.01(c)(3);
(iii)
satisfy any requirements, conditions, guidelines, options, or elections
contained in any opinion, directive, order, ruling, or regulation of the SEC, the IRS,
or any other federal or state agency, or in any federal or state statute, compliance
with which it deems to be in the best interest of the Partnership; or
(iv)
cure any ambiguity, correct or supplement any provision of this Agreement that
may be inconsistent with any other provision of this Agreement, or add any provision to
this Agreement with respect to matters, events or issues arising under this Agreement
that is not inconsistent with the other provisions of this Agreement.
Notwithstanding the foregoing, no amendment materially and adversely affecting the interests or
rights of Participants shall be made without the consent of the Participants whose interests or
rights will be so affected.
8.06. Additional Partners. Each Participant consents to the admission to the Partnership of
additional Participants as the Managing General Partner, in its discretion, chooses to admit.
8.07. Legal Effect. This Agreement shall be binding on and inure to the benefit of the parties,
their heirs, devisees, personal representatives, successors and assigns, and shall run with the
interests subject to this Agreement. The terms “Partnership,”“Limited Partner,”“Investor General
Partner,”“Participant,”“Partner,”“Managing General Partner,”“Operator,” or “parties” shall
equally apply to any successor limited partnership, and any heir, devisee, personal representative,
successor or assign of a party.
IN WITNESS WHEREOF, the parties hereto set
their hands as of the day of , 2007.
EXHIBIT (I-A)
MANAGING GENERAL PARTNER SIGNATURE PAGE
Attached to and made a part of the AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED
PARTNERSHIP of ATLAS RESOURCES PUBLIC #16-2007(A) L.P.
The undersigned agrees:
1.
to serve as the Managing General Partner of ATLAS RESOURCES PUBLIC #16-2007(A)
L.P. (the “Partnership”), and hereby executes, swears to, and agrees to all the terms
of the Partnership Agreement;
2.
to pay the required subscription of the Managing General Partner under §3.04(a)
of the Partnership Agreement; and
3.
to subscribe to the Partnership as follows:
(a)
$ [] Unit(s)] under Section 3.03(b)(1)
of the Partnership Agreement as a Limited Partner; or
(b)
$ [] Unit(s)] under Section 3.03(b)(1)
of the Partnership Agreement as an Investor General Partner.
I, the undersigned, hereby offer to purchase Units of Atlas Resources Public #16-2007(A) L.P. in
the amount set forth on the Signature Page of this Subscription Agreement and on the terms
described in the current Prospectus for Atlas Resources Public #16-2007 Program, as supplemented or
amended from time to time. I acknowledge and agree that my execution of this Subscription
Agreement also constitutes my execution of the Agreement of Limited Partnership (the “Partnership
Agreement”) the form of which is attached as Exhibit (A) to the Prospectus and I agree to be bound
by all of the terms and conditions of the Partnership Agreement if my subscription is accepted by
Atlas Resources, LLC, the Managing General Partner. I understand and agree that I may not assign
this offer, nor may it be withdrawn after it has been accepted by the Managing General Partner. I
hereby irrevocably constitute and appoint the Managing General Partner, and its duly authorized
agents, my agent and attorney-in-fact, in my name, place and stead, to make, execute, acknowledge,
swear to, file, record and deliver the Agreement of Limited Partnership and any certificates
related thereto. I (other than Massachusetts residents) further understand that following the
Signature Page there are certain representations, warranties and covenants which I must make before
the Managing General Partner will accept my subscription.
SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT
I, the undersigned, agree to purchase ___Units at $10,000 per Unit in ATLAS RESOURCES PUBLIC
#16-2007(A) L.P. (the “Partnership”) as (check one):
Subscription Amount
o
INVESTOR GENERAL PARTNER
$
o
LIMITED PARTNER
(# Units)
Instructions
Make your check payable to: “National City Bank of Cleveland, Ohio, Escrow Agent, Atlas Resources
Public #16-2007(A) L.P.”
Minimum Subscription: one Unit ($10,000). Additional Subscriptions in $1,000 increments. If you
are an individual investor you must personally sign this Signature Page and provide the information
requested below. Wire instructions available upon request.
Subscriber (All investors must personally sign this Signature Page.)
NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP: Name
(Enclose supporting documents.) If a partnership, corporation or trust, then the members,
stockholders or beneficiaries thereof are citizens of .
Tax I. D. No.:
Address of Record (Do not use P.O. Box)
Print Name
X
Signature
Tax I. D. No.:
See the attached “Distributions Not to Address of Record
Form” for electronic and alternate address information.
Farmer (2/3 or more of my gross income in 2006 or 2005 is from farming)
TO BE COMPLETED BY REGISTERED REPRESENTATIVE (For Commission and Other Purposes)
I hereby represent that I have discharged my affirmative obligations under Rule 2810(b)(2)(B) and
(b)(3)(D) of the NASD’s Conduct Rules and specifically have obtained information from the
above-named subscriber concerning his/her age, net worth, annual income, federal income tax
bracket, investment objectives, investment portfolio, and other financial information and have
determined that an investment in the Partnership is suitable for such subscriber, that such
subscriber is or will be in a financial position to realize the benefits of this investment, and
that such subscriber has a fair market net worth sufficient to sustain the risks for this
investment. I have also informed the subscriber of all pertinent facts relating to the liquidity
and marketability of an investment in the Partnership, of the risks of unlimited liability
regarding an investment as an Investor General Partner, and of the passive loss limitations for tax
purposes of an investment as a Limited Partner.
Name of Registered Representative and CRD Number
Name of Broker/Dealer
Signature of Registered Representative
Broker/Dealer CRD Number
Registered Representative Office Address:
Broker/Dealer Facsimile Number:
Broker/Dealer E-mail Address:
Phone Number:
Facsimile Number:
E-mail Address:
Company Name (if other than Broker/Dealer Name)
NOTICE TO BROKER-DEALER:
Send Subscription Documents completed and signed with check MADE PAYABLE TO: “National
City Bank of Cleveland, Ohio, Escrow Agent, Atlas Resources Public #16-2007(A) L.P.”to:
In order to induce the Managing General Partner to accept this subscription, I hereby
represent, warrant, covenant and agree as follows:
Notice: Residents of Massachusetts should not complete or initial this page. Instead,
residents of Massachusetts should read the statements below and treat them as notices to the
Massachusetts investor of the information set forth in those statements.
Investor’s
Co-Investor’s
Initials
Initials
___
___
I have received the Prospectus.
___
___
I (other than if I am a Minnesota or Maine resident) recognize and understand that before this
offering there has been no public market for the Units and it is unlikely that after the offering
there will be any such market, the transferability of the Units is restricted, and in case of
emergency or other change in circumstances I cannot expect to be able to readily liquidate my
investment in the Units.
___
___
I am purchasing the Units for my own account, for investment purposes and not for the account of
others, and with no present intention of reselling them.
___
___
If an individual, I am a citizen of the United States of America and at least twenty-one years of
age.
___
___
If an individual, I am a foreign investor, and at least twenty-one years of age.
___
___
If a partnership, corporation or trust, then I am at least twenty-one years of age and empowered
and duly authorized under a governing document, trust instrument, charter, certificate of
incorporation, by-law provision or the like to enter into this Subscription Agreement and to
perform the transactions contemplated by the Prospectus, including its exhibits.
___
___
I am a foreign corporation, partnership, trust or other entity, and empowered and duly authorized
under a governing document, trust instrument, charter, certificate of incorporation, by-law
provision or the like to enter into this Subscription Agreement and to perform the transactions
contemplated by the Prospectus, including its exhibits.
___
___
I (other than if I am a Minnesota or Maine resident) understand that if I am an Investor General
Partner, then I will have unlimited joint and several liability for Partnership obligations and
liabilities including amounts in excess of my subscription to the extent the obligations and
liabilities exceed the Partnership’s insurance proceeds, the Partnership’s assets, and
indemnification by the Managing General Partner. Also, the insurance may be inadequate to cover
these liabilities and there is no insurance coverage for certain claims.
___
___
I (other than if I am a Minnesota or Maine resident) understand that if I am a Limited Partner,
then I may only use my Partnership losses to the extent of my net passive income from passive
activities in the year, with any excess losses being deferred.
___
___
I (other than if I am a Minnesota or Maine resident) understand that no state or federal
governmental authority has made any finding or determination relating to the fairness for public
investment of the Units and no state or federal governmental authority has recommended or
endorsed or will recommend or endorse the Units.
___
___
I (other than if I am a Minnesota or Maine resident) understand that the Selling Agent or
registered representative is required to inform me and the other potential investors of all
pertinent facts relating to the Units, including the following: the risks involved in the
offering, including the speculative nature of the investment and the speculative nature of
drilling for natural gas and oil; the financial hazards involved in the offering, including the
risk of losing my entire investment; the lack of liquidity of my investment; the restrictions on
transferability of my Units; the background of the Managing General Partner and the Operator; the
tax
consequences of my investment; and the unlimited joint and several
liability of the Investor General Partners.
To meet the suitability requirements for an investment in your state, please check and initial
either (a), (b), (c) or (d) depending on your state of residence and whether you are buying limited
partner units or investor general partner units. Also, initial (e) if you are a fiduciary and you
meet the requirement.
Investor’s
Co-Investor’s
Initials
Initials
___
___
(a) If I purchase limited
partner units and I am a resident of :
then I must have either: a minimum net worth of $225,000,
exclusive of home, home furnishings, and automobiles, or a minimum
net worth of $60,000, exclusive of home, home furnishings, and
automobiles, and had during the last tax year or estimate that I
will have during the current tax year “taxable income” as defined
in Section 63 of the Internal Revenue Code of at least $60,000,
without regard to an investment in the partnership. In addition,
if I am a resident of Pennsylvania, then I must not make an
investment in a partnership which is in excess of 10% of my net
worth, exclusive of home, home furnishings and automobiles.
Finally, if I am a resident of Kansas, it is recommended by the
Office of the Kansas Securities Commissioner that I should limit
my investment in the partnership and substantially similar
programs to no more than 10% of my liquid net worth, excluding
home, furnishings and automobiles. Liquid net worth is
that portion of your net worth (total assets minus total
liabilities) that is comprised of cash, cash equivalents and
readily marketable securities. Readily marketable securities may
include investments in an IRA or other retirement plan that can be
liquidated within a short time, less any income tax penalties that
may apply for early distribution.
___
___
(b)
If I purchase limited partner units and I am a resident of:
•Alaska,
•California,
•Iowa,
•Kentucky,
•Massachusetts,
•Michigan,
•New Hampshire,
•New Jersey,
•North Carolina, or
•Ohio,
then I represent that I am aware of and meet
that state’s qualifications and suitability
standards set forth in Exhibit (B) to the
Prospectus.
If I purchase investor general
partner units and I am a resident of:
•Colorado,
•Connecticut,
•Delaware,
•District of Columbia,
•Florida,
•Georgia,
•Hawaii,
•Idaho,
•Illinois,
•Louisiana,
•Maryland,
•Montana,
•Nebraska,
•Nevada,
•New York,
•North Dakota,
•Rhode Island,
•South Carolina,
•Utah,
•Virginia,
•West Virginia,
•Wisconsin, or
•Wyoming,
then I must have either: a net worth of at least $225,000,
exclusive of home, furnishings and automobiles, or a net worth,
exclusive of home, furnishings and automobiles, of at least
$60,000, and had during the last tax year, or estimate that I will
have during the current tax year, “taxable income” as defined in
Section 63 of the Code of at least $60,000, without regard to an
investment in the Partnership.
___
___
(d)
If I purchase investor general partner units and I am a resident of:
•Alaska,
•Alabama,
•Arizona,
•Arkansas,
•California,
•Indiana,
•Iowa,
•Kansas,
•Kentucky,
•Maine,
•Massachusetts,
•Michigan,
•Minnesota,
•Mississippi,
•Missouri,
•New Hampshire,
•New Jersey,
•New Mexico,
•North Carolina,
•Ohio,
•Oklahoma,
•Oregon,
•Pennsylvania,
•South Dakota,
•Tennessee,
•Texas,
•Vermont or
•Washington,
then I represent that I am aware of and meet that state’s
qualifications and suitability standards set forth in Exhibit (B)
to the Prospectus.
___
___
(e)
If I am a fiduciary, then I am purchasing for a person or entity having the
appropriate income and/or net worth specified in (a), (b), (c) or (d) above.
The above representations do not constitute a waiver of any rights that I may have under the Acts
administered by the SEC or by any state regulatory agency administering statutes bearing on the
sale of securities.
Instructions
to Investor
You are required to execute your own Subscription Agreement and the Managing General Partner will
not accept any Subscription Agreement that has been executed by someone other than you unless the
person has been given your legal power of attorney to sign on your behalf, and you meet all of the
conditions in the Prospectus and this Subscription Agreement. In the case of sales to fiduciary
accounts, the minimum standards set forth in the Prospectus and this Subscription Agreement must be
met by the beneficiary, the fiduciary account, or by the donor or grantor who directly or
indirectly supplies the funds to purchase the Partnership Units if the donor or grantor is the
fiduciary.
Your execution of the Subscription Agreement constitutes your binding offer to buy Units in the
Partnership. Once you subscribe you may withdraw your subscription only by providing the Managing
General Partner with written notice of your withdrawal before your subscription is accepted by the
Managing General Partner. The Managing General Partner has the discretion to refuse to accept your
subscription without liability to you. Subscriptions will be accepted or rejected by the
Partnership within 30 days of their receipt. If your subscription is rejected, then all of your
funds will be returned to you immediately. If your subscription is accepted before the first
closing, then you will be admitted as a Participant not later than 15 days after the release from
escrow of the investors’ funds to the Partnership. If your subscription is accepted after the
first closing, then you will be admitted into the Partnership not later than the last day of the
calendar month in which your subscription was accepted by the Partnership.
The Managing General Partner will not complete a sale of Units to you and send you a confirmation
of purchase until at least five business days after the date you receive a final Prospectus.
NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from various
requirements of Title 10 of the California Administrative Code. These deviations include, but are
not limited to the following: the definition of Prospect in the Prospectus, unlike Rule
260.140.127.2(b) and Rule 260.140.121(1), does not require enlarging or contracting the size of the
area on the basis of geological data in all cases. If I am a resident of California, I acknowledge
the receipt of California Rule 260.141.11 set forth in Exhibit (B) to the Prospectus.
Taxpayer Identification Number Certification – Check the first box below, unless you are a
foreign investor or you are investing as a U.S. grantor trust.
Note: If there is a change in circumstances which makes any of the information provided by you
in your certification below incorrect, then you are under a continuing obligation so long as
you own units in the partnership to notify the partnership and furnish the partnership a new
certificate within thirty (30) days of the change.
o
Under penalties of perjury, I certify that:
(1)
the number provided in my Subscription Agreement is my correct “TIN”
(i.e., social security number or employer identification number);
(2)
I am not subject to backup withholding because (a) I am exempt from
backup withholding under §3406(g)(1) of the Internal Revenue Code and the related
regulations, or (b) I have not been notified by the Internal Revenue Service (IRS)
that I am subject to backup withholding as a result of failure to report all
interest or dividends, or (c) the IRS has notified me that I am no longer subject to
backup withholding; and
(3)
I am a U.S. person (which includes U.S. citizens, resident aliens,
entities or associations formed in the U.S. or under U.S. law, and U.S. estates and
trusts.)
(Note: You must cross out item 2 above if you have been notified by the IRS that you are
currently subject to backup withholding because you have failed to report all interest and
dividends on your tax return.)
o
Foreign Partner. I am at least 21 years of age, and I have provided the partnership with
the appropriate Form W-8 certification or, if a joint account, each joint account owner
has provided the partnership the appropriate Form W-8 certification, and if any one of
the joint account owners has not established foreign status, that joint account owner has
provided the partnership with a certified TIN.
o
U.S. Grantor Trusts. Under penalties of perjury, I certify that:
(1)
the trust designated as the investor on the Subscription Agreement is a
United States grantor trust which I can amend or revoke during my lifetime;
(2)
under subpart E of subchapter J of the Internal Revenue Code (check onlyone of the boxes below):
o
(a) 100% of the trust is treated as owned by me;
o
(b) the trust is treated as owned in equal shares by me and my
spouse; or
o
(c) ___% of the trust is treated as owned by
______, and the remainder is treated as owned ___% by me
and ___% by my spouse); and
(3)
each grantor or other owner of any portion of the trust has provided the
partnership with the appropriate Form W-8 or Form W-9 certification.
Note: If you check the box in (2)(c), you must insert the information called for by the blanks.
The Internal Revenue Service does not require your consent to any provision of this document
other than the certifications required to avoid backup withholding.
Assignment of Well Locations; Representations and Indemnification Associated with the Assignment of the Lease; Designation of
Additional Well Locations; Outside Activities Are Not Restricted
1
2.
Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations
2
3.
Operator — Responsibilities in General; Covenants; Term
3
4.
Operator’s Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry Hole Determination; Excess Funds and Cost
Overruns – Intangible Drilling Costs; Excess Funds and Cost Overruns – Tangible Costs
5
5.
Title Examination of Well Locations; Developer’s Acceptance and Liability; Additional Well Locations
8
6.
Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price
Determinations; Plugging and Abandonment
8
7.
Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for Sale
Proceeds; Records and Reports; Additional Information
10
8.
Operator’s Lien; Right to Collect From Oil or Gas Purchaser
12
9.
Successors and Assigns; Transfers; Appointment of Agent
THIS AGREEMENT made this day of , 200, by and between ATLAS RESOURCES,
LLC, a Pennsylvania limited liability company (hereinafter referred to as “Atlas” or “Operator”),
and
ATLAS RESOURCES PUBLIC #16-2007(A) L.P. [Atlas Resources Public #16-2007(B) L.P.], a Delaware
limited partnership, (hereinafter referred to as the “Developer”).
WITNESSETH THAT:
WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the “Leases”) described on Exhibit A
attached to and made a part of this Agreement, has certain rights to develop the
() initial well locations (the “Initial Well Locations”) identified on the maps attached to
and made a part of this Agreement as Exhibits A-l through A- ;
WHEREAS, the Developer, subject to the terms and conditions of this Agreement, desires to acquire
certain of the Operator’s rights to develop the Initial Well Locations and to provide for the
development on the terms and conditions set forth in this Agreement of additional well locations
(“Additional Well Locations”) that the parties may from time to time designate; and
WHEREAS, the Operator is in the oil and gas exploration and development business, and the Developer
desires that Operator, as its independent contractor, perform certain services in connection with
its efforts to develop the aforesaid Initial and Additional Well Locations (collectively the “Well
Locations”) and to operate the wells completed on the Well Locations, on the terms and conditions
set forth in this Agreement;
NOW THEREFORE, in consideration of the mutual covenants herein contained and subject to the terms
and conditions hereinafter set forth, the parties hereto, intending to be legally bound, hereby
agree as follows:
1.
Assignment of Well Locations; Representations and Indemnification Associated with the
Assignment of the Lease; Designation of Additional Well Locations; Outside Activities Are Not
Restricted.
(a)
Assignment of Well Locations. The Operator shall execute an assignment of an
undivided percentage of Working Interest in the Well Location acreage for each well to
the Developer as shown on Exhibit A attached hereto, which assignment shall be limited
to a depth from the surface to the deepest depth penetrated at the cessation of
drilling operations.
The assignment shall be substantially in the form of Exhibit B attached to and made a
part of this Agreement. The amount of acreage included in each Initial Well Location
and the configuration of the Initial Well Location are indicated on the maps attached
to this Agreement as Exhibits A-l through A-. The amount of acreage included
in each Additional Well Location and the configuration of the Additional Well
Location shall be indicated on the maps to be attached as exhibits to the applicable
addendum to this Agreement as provided in sub-section (c) below.
(b)
Representations and Indemnification Associated with the Assignment of the
Lease. The Operator represents and warrants to the Developer that:
(i)
the Operator is the lawful owner of the Lease and rights and
interest under the Lease and of the personal property on the Lease or used in
connection with the Lease;
(ii)
the Operator has good right and authority to sell and convey the rights, interest, and property;
(iii)
the rights, interest, and property are free and clear from all liens and encumbrances; and
(iv)
all rentals and royalties due and payable under the Lease have been duly paid.
These representations and warranties shall also be included in each recorded
assignment of the acreage included in each Initial Well Location and Additional Well
Location designated pursuant to sub-section (c) below, substantially in the form of
Exhibit B attached to and made a part of this Agreement.
The Operator agrees to indemnify, protect and hold the Developer and its successors
and assigns harmless from and against all costs (including but not limited to
reasonable attorneys’ fees), liabilities, claims, penalties, losses, suits, actions,
causes of action, judgments or decrees resulting from the breach of any of the above
representations and warranties. It is understood and agreed that, except as
specifically set forth above, the Operator makes no warranty or representation,
express or implied, as to its title or the title of the lessors in and to the lands
or oil and gas interests covered by said Leases.
(c)
Designation of Additional Well Locations. If the parties hereto desire to
designate Additional Well Locations to be developed in accordance with the terms and
conditions of this Agreement, then the parties shall execute an addendum substantially
in the form of Exhibit C attached to and made a part of this Agreement specifying:
(i)
the undivided percentage of Working Interest and the Oil and Gas
Leases to be included as Leases under this Agreement;
(ii)
the amount and configuration of acreage included in each
Additional Well Location on maps attached as exhibits to the addendum; and
(iii)
their agreement that the Additional Well Locations shall be
developed in accordance with the terms and conditions of this Agreement.
(d)
Outside Activities Are Not Restricted. It is understood and agreed that the
assignment of rights under the Leases and the oil and gas development activities
contemplated by this Agreement relate only to the Initial Well Locations and the
Additional Well Locations. Nothing contained in this Agreement shall be interpreted to
restrict in any manner the right of each of the parties to conduct without the
participation of the other party any additional activities relating to exploration,
development, drilling, production, or delivery of oil and gas on lands adjacent to or
in the immediate vicinity of the Well Locations or elsewhere.
2.
Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations.
(a)
Drilling of Wells. Operator, as Developer’s independent contractor, agrees to
drill, complete (or plug) and operate () oil and gas wells on the
() Initial Well Locations in accordance with the terms and
conditions of this Agreement. Developer, as a minimum commitment, agrees to
participate in and pay the Operator’s charges for drilling and completing (or plugging)
the wells and any extra costs pursuant to Section 4 in proportion to the share of the
Working Interest owned by the Developer in the wells with respect to all initial wells.
It is understood and agreed that, subject to sub-section (e) below, Developer does not
reserve the right to decline participation in the drilling of any of the initial wells
to be drilled under this Agreement.
(b)
Timing. Operator shall begin drilling the first well within thirty (30) days
after the date of this Agreement, and shall begin drilling each of the other initial
wells for which payment is made pursuant to Section 4(b) before the close of the
90th day after the close of the calendar year in which this Agreement is
entered into by Operator and the Developer. Subject to the foregoing time limits,
Operator shall determine the timing of and the order of drilling the Initial Well
Locations.
(c)
Depth. All of the wells to be drilled under this Agreement shall be:
(i)
drilled and completed (or plugged) in accordance with the
generally accepted and customary oil and gas field practices and techniques then
prevailing in the geographical area of the Well Locations; and
drilled to a depth sufficient to test thoroughly the objective
formation or the deepest assigned depth, whichever is less.
(d)
Interest of Developer. Except as otherwise provided in this Agreement, all
costs, expenses, and liabilities incurred in connection with the drilling and other
operations and activities contemplated by this Agreement shall be borne and paid, and
all wells, gathering lines of up to approximately 2,500 feet on each Well Location in
connection with a natural gas well, equipment, materials, and facilities acquired,
constructed or installed under this Agreement shall be owned, by the Developer in
proportion to the share of the Working Interest owned by the Developer in the wells.
Subject to the payment of lessor’s royalties and other royalties and overriding
royalties, if any, production of oil and gas from the wells to be drilled under this
Agreement shall be owned by the Developer in proportion to the share of the Working
Interest owned by the Developer in the wells.
(e)
Right to Substitute Well Locations. Notwithstanding the provisions of
sub-section (a) above, if the Operator or Developer determines in good faith, with
respect to any Well Location, before operations begin under this Agreement on the Well
Location, that it would not be in the best interest of the parties to drill a well on
the Well Location, then the party making the determination shall notify the other party
of its determination and the basis for its determination and, unless otherwise
instructed by Developer, the well shall not be drilled. This determination may be based
on:
(i)
the production or failure of production of any other wells that
may have been recently drilled in the immediate area of the Well Location;
(ii)
newly discovered title defects; or
(iii)
any other evidence with respect to the Well Location as may have
been obtained.
If the well is not drilled, then Operator shall promptly propose a new well location
(including all information for the Well Location as Developer may reasonably request)
to be substituted for the original Well Location. Developer shall then have seven
(7) business days to either reject or accept the proposed new well location. If the
new well location is rejected, then Operator shall promptly propose another
substitute well location pursuant to the provisions of this sub-section.
Once the Developer accepts a substitute well location or does not reject it within
the seven (7) day period, this Agreement shall terminate as to the original Well
Location and the substitute well location shall become subject to the terms and
conditions of this Agreement.
3.
Operator — Responsibilities in General; Covenants; Term.
(a)
Operator — Responsibilities in General. Atlas shall be the Operator of the
wells and Well Locations subject to this Agreement and, as the Developer’s independent
contractor, shall, in addition to its other obligations under this Agreement do the
following:
(i)
arrange for drilling and completing (or plugging) the wells and,
if a gas well, installing the necessary gas gathering line systems and
connection facilities;
(ii)
make the technical decisions required in drilling, testing,
completing (or plugging), and operating the wells;
(iii)
manage and conduct all field operations in connection with the
drilling, testing, completing (or plugging), equipping, operating, and producing
the wells;
(iv)
maintain all wells, equipment, gathering lines if a gas well, and
facilities in good working order during their useful lives; and
perform the necessary administrative and accounting functions.
In performing the work contemplated by this Agreement, Operator is an independent
contractor with authority to control and direct the performance of the details of the
work.
(b)
Covenants. Operator covenants and agrees that under this Agreement:
(i)
it shall perform and carry on (or cause to be performed and
carried on) its duties and obligations in a good, prudent, diligent, and
workmanlike manner using technically sound, acceptable oil and gas field
practices then prevailing in the geographical area of the Well Locations;
(ii)
all drilling and other operations conducted by, for and under the
control of Operator shall conform in all respects to federal, state and local
laws, statutes, ordinances, regulations, and requirements;
(iii)
unless otherwise agreed in writing by the Developer, all work
performed pursuant to a written estimate shall conform to the technical
specifications set forth in the written estimate and all equipment and materials
installed or incorporated in the wells and facilities shall be new or used and
of good quality;
(iv)
in the course of conducting operations, it shall comply with all
terms and conditions, other than any minimum drilling commitments, of the Leases
(and any related assignments, amendments, subleases, modifications and
supplements);
(v)
it shall keep the Well Locations and all wells, equipment and
facilities located on the Well Locations free and clear of all labor, materials
and other types of liens or encumbrances arising out of operations;
(vi)
it shall file all reports and obtain all permits and bonds
required to be filed with or obtained from any governmental authority or agency
in connection with the drilling or other operations and activities; and
(vii)
it will provide competent and experienced personnel to supervise
drilling, completing (or plugging), and operating the wells and use the services
of competent and experienced service companies to provide any third party
services necessary or appropriate in order to perform its duties.
(c)
Term. Atlas shall serve as Operator under this Agreement until the earliest
of:
(i)
the termination of this Agreement pursuant to Section 13;
(ii)
the termination of Atlas as Operator by the Developer at any time
in the Developer’s discretion, with or without cause on sixty (60) days’ advance
written notice to the Operator; or
(iii)
the resignation of Atlas as Operator under this Agreement which
may occur on ninety (90) days’ written notice to the Developer at any time after
five (5) years from the date of this Agreement, it being expressly understood
and agreed that Atlas shall have no right to resign as Operator before the
expiration of the five-year period.
Any successor Operator shall be selected by the Developer. Nothing contained in this
sub-section shall relieve or release Atlas or the Developer from any liability or
obligation under this Agreement that accrued or occurred before Atlas’ removal or
resignation as Operator under this Agreement. On any change in Operator under this
provision, the then present Operator shall deliver to the successor Operator
possession of all records, equipment, materials and appurtenances used or obtained
for use in connection with operations under this Agreement and owned by the
Developer.
Operator’s Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry
Hole Determination; Excess Funds and Cost Overruns-Intangible Drilling Costs; Excess Funds and
Cost Overruns-Tangible Costs.
(a)
Operator’s Charges for Drilling and Completing Wells. Each oil and gas well
that is drilled and completed under this Agreement shall be drilled and completed for
an amount equal to the sum of the following items: (i) the Cost of permits, supplies,
materials, equipment, and all other items used in the drilling and completion of a well
provided by third-parties, or if the foregoing items are provided by Affiliates of the
Developer’s Managing General Partner, then those items shall be charged at competitive
rates; (ii) fees for third-party services; (iii) fees for services provided by the
Developer’s Managing General Partner’s Affiliates, which shall be charged at
competitive rates; (iv) an administration and oversight fee of $15,000 per well,
which shall be charged to the Developer’s investors as part of each well’s Intangible
Drilling Costs, as that term is defined below and the portion of Tangible Costs, as
that term is defined below, paid by the Developer’s investors; and (v) a mark-up in
an amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above, for the
Developer’s Managing General Partner’s services as general drilling contractor as
Operator under this Agreement. “Cost” shall mean the price paid by Operator in an
arm’s-length transaction. Additionally, if the Developer’s Managing General Partner
drills a well for the Developer that the Managing General Partner determines is not
an average well in the area because of the well’s depth, complexity associated with
either drilling or completion activity or as otherwise determined by the Managing
General Partner, the administration and oversight fee of $15,000 per well described
in §4.02(d)(1)(iv) of the Developer’s Partnership Agreement may be increased to a
competitive rate as determined by the Managing General Partner.
The estimated price for drilling and completing each of the wells shall be set forth
in an Authority for Expenditure (“AFE”) that shall be attached to this Agreement as
an Exhibit, and shall cover all ordinary costs which may be incurred in drilling and
completing (or plugging) each well. This includes without limitation, site
preparation, permits and bonds, roadways, surface damages, power at the site, water,
Operator’s compensation as set forth above, rights-of-way, drilling rigs, equipment
and materials, costs of title examinations, logging, cementing, fracturing, casing,
meters (other than utility purchase meters), connection facilities, salt water
collection tanks, separators, siphon string, rabbit, tubing, an average of 2,500 feet
of gathering line per well in connection with each gas well, and geological,
geophysical and engineering services.
(b)
Payment. The Developer shall pay to Operator, in proportion to the share of
the Working Interest owned by the Developer in the wells, one hundred percent (100%) of
the estimated Intangible Drilling Costs and Tangible Costs, as those terms are defined
below, for drilling and completing all initial wells on execution of this Agreement.
Notwithstanding the foregoing, Atlas’ payments for its share of the estimated Tangible
Costs, as that term is defined below, of drilling and completing all initial wells as
the Managing General Partner of the Developer shall be paid within five (5) business
days of notice from Operator that the costs have been incurred. The Developer’s
payment shall be nonrefundable in all events in order to enable Operator to do the
following:
(i)
commence site preparation for the initial wells;
(ii)
obtain suitable subcontractors for drilling and completing or
plugging the initial wells at currently prevailing prices; and
(iii)
insure the availability of equipment and materials.
For purposes of this Agreement, “Intangible Drilling Costs” shall mean those
expenditures associated with property acquisition and the drilling and completion of
oil and gas wells that under present law are generally accepted as fully deductible
currently for federal income tax purposes. This includes:
all expenditures made with respect to any well before the
establishment of production in commercial quantities for wages, fuel, repairs,
hauling, supplies and other costs and expenses incident to and necessary for the
drilling of the well and the preparation of the well for the production of oil
or gas, that are currently deductible pursuant to Section 263(c) of the Internal
Revenue Code of 1986, as amended (the “Code”), and Treasury Reg. Section
1.612-4, which are generally termed “intangible drilling and development costs”;
(ii)
the expense of plugging and abandoning any well before a
completion attempt; and
(iii)
the costs (other than Tangible Costs and Lease acquisition
costs) to re-enter and deepen an existing well, complete the well to deeper
formations or reservoirs, or plug and abandon the well if it is nonproductive
from the targeted deeper formations or reservoirs.
“Tangible Costs” shall mean those costs associated with property acquisition and the
drilling and completion of oil and gas wells that are generally accepted as capital
expenditures pursuant to the provisions of the Code. This includes:
(i)
all costs of equipment, parts and items of hardware used in
drilling and completing (or plugging) a well;
(ii)
the costs (other than Intangible Drilling Costs and Lease
acquisition costs) to re-enter and deepen an existing well, complete the well to
deeper formations or reservoirs, or plug and abandon the well if it is
nonproductive from the targeted deeper formations or reservoirs; and
(iii)
those items necessary to deliver acceptable oil and gas
production to purchasers to the extent installed downstream from the wellhead of
any well, which are required to be capitalized under the Code and its
regulations.
With respect to each additional well drilled on the Additional Well Locations, if
any, the Developer shall pay to Operator, in proportion to the share of the Working
Interest owned by the Developer in the wells, one hundred percent (100%) of the
estimated Intangible Drilling Costs and Tangible Costs for drilling and completing
the well on execution of the applicable addendum pursuant to Section l(c) above.
Notwithstanding the foregoing, Atlas’ payments for its share of the estimated
Tangible Costs of drilling and completing all additional wells as the Managing
General Partner of the Developer shall be paid within five (5) business days of
notice from Operator that the costs have been incurred. The Developer’s payment
shall be nonrefundable in all events in order to enable Operator to do the following:
(i)
commence site preparation for the additional wells;
(ii)
obtain suitable subcontractors for drilling and completing the
additional wells at currently prevailing prices; and
(iii)
insure the availability of equipment and materials.
Developer shall pay, in proportion to the share of the Working Interest owned by the
Developer in the wells, any extra costs incurred for each well pursuant to
sub-section (a) above within ten (10) business days of its receipt of Operator’s
statement for the extra costs.
(c)
Completion Determination. Operator shall determine whether or not to run the
production casing for an attempted completion or to plug and abandon any well drilled
under this Agreement. However, a well shall be completed only if Operator has made a
good faith determination that there is a reasonable possibility of obtaining commercial
quantities of oil and/or gas.
Dry Hole Determination. If Operator determines at any time during the drilling
or attempted completion of any well drilled under this Agreement, in accordance with
the generally accepted and customary oil and gas field practices and techniques then
prevailing in the geographic area of the Well Location that the well should not be
completed, then it shall promptly and properly plug and abandon the well.
(e)
Excess Funds and Cost Overruns-Intangible Drilling Costs. Any estimated
Intangible Drilling Costs (which are the Intangible Drilling Costs set forth on the
AFE) prepaid by Developer with respect to any well that exceed Operator’s price
specified in sub-section (a) above for the Intangible Drilling Costs of the well shall
be retained by Operator and shall be applied, in proportion to the share of the Working
Interest owned by the Developer in the wells, to:
(i)
the Intangible Drilling Costs of an additional well or wells to
be drilled on the Additional Well Locations; or
(ii)
any cost overruns owed by the Developer to Operator for
Intangible Drilling Costs on one or more of the other wells on the Well
Locations.
Conversely, if Operator’s price specified in sub-section (a) above for the Intangible
Drilling Costs of any well exceeds the estimated Intangible Drilling Costs (which are
the Intangible Drilling Costs set forth on the AFE) prepaid by Developer for the
well, then:
(i)
Developer shall pay the additional price to Operator within ten
(10) business days after notice from Operator that the additional amount is due
and owing; or
(ii)
Developer and Operator may agree to delete or reduce Developer’s
Working Interest in one or more wells to be drilled under this Agreement that
have not yet been spudded to provide funds to pay the additional amounts owed by
Developer to Operator. If doing so results in any excess prepaid Intangible
Drilling Costs, then these funds shall be applied, in proportion to the share of
the Working Interest owned by the Developer in the wells, to:
(a)
the Intangible Drilling Costs of an additional well
or wells to be drilled on the Additional Well Locations; or
(b)
any cost overruns owed by the Developer to Operator
for Intangible Drilling Costs of one or more of the other wells on the
Well Locations.
The Exhibits to this Agreement with respect to the affected wells shall be amended as
appropriate.
(f)
Excess Funds and Cost Overruns – Tangible Costs. Any estimated Tangible Costs
(which are the Tangible Costs set forth on the AFE) prepaid by Developer with respect
to any well that exceed Operator’s price specified in sub-section (a) above for the
Tangible Costs of the well shall be retained by Operator and shall be applied, in
proportion to the share of the Working Interest owned by the Developer in the wells,
to:
(i)
the Developer’s Participants’ share of the Tangible Costs for an
additional well or wells to be drilled on the Additional Well Locations; or
(ii)
any cost overruns owed by the Developer to Operator for the
Developer’s Participants’ share of the Tangible Costs of one or more of the
other wells on the Well Locations.
Conversely, if Operator’s price specified in sub-section (a) above for the
Developer’s Participants’ share of Tangible Costs of any well exceeds the estimated
Tangible Costs (which are the Tangible Costs set forth on the AFE) prepaid by
Developer for the Developer’s Participants’ share of the Tangible Costs for the well,
then:
Developer shall pay the additional price to Operator within ten
(10) business days after notice from Operator that the additional price is due
and owing; or
(ii)
Developer and Operator may agree to delete or reduce Developer’s
Working Interest in one or more wells to be drilled under this Agreement that
have not yet been spudded to provide funds to pay the additional amounts owed by
Developer to Operator. If doing so results in any excess prepaid Tangible
Costs, then these funds shall be applied, in proportion to the share of the
Working Interest owed by the Developer in the wells, to:
(a)
the Developer’s Participants’ share of the Tangible
Costs of an additional well or wells to be drilled on the Additional Well
Locations; or
(b)
any cost overruns owed by the Developer to Operator
for the Developer’s Participants’ share of the Tangible Costs of one or
more of the other wells on the Well Locations.
(iii)
The Developer’s Participants’ share of the Tangible Costs of all
of the wells drilled under this Agreement and any additional wells to be drilled
on the Additional Well Locations under any Addendum to this Agreement shall be
ten percent (10%) of the total price prepaid by Developer to Operator pursuant
to Section 4(b) of this Agreement or any Addendum hereto. The Developer’s
Participants’ share of the Tangible Costs of any one well drilled under this
Agreement shall be determined subject to the preceding sentence, taking into
account the Developer’s share of all of the Tangible Costs of all of the wells
to be drilled under this Agreement and any Addendum hereto.
The Exhibits to this Agreement with respect to the affected wells shall be amended as
appropriate.
5.
Title Examination of Well Locations, Developer’s Acceptance and Liability; Additional Well
Locations.
(a)
Title Examination of Well Locations, Developer’s Acceptance and Liability. The
Developer acknowledges that Operator has furnished Developer with the title opinions
identified on Exhibit A, and other documents and information that Developer or its
counsel has requested in order to determine the adequacy of the title to the Initial
Well Locations and leased premises subject to this Agreement. The Developer accepts
the title to the Initial Well Locations and leased premises and acknowledges and agrees
that, except for any loss, expense, cost, or liability caused by the breach of any of
the warranties and representations made by the Operator in Section l(b), any loss,
expense, cost or liability whatsoever caused by or related to any defect or failure of
the title shall be the sole responsibility of and shall be borne entirely by the
Developer.
(b)
Additional Well Locations. Before beginning drilling of any well on any
Additional Well Location, Operator shall conduct, or cause to be conducted, a title
examination of the Additional Well Location, in order to obtain appropriate abstracts,
opinions and certificates and other information necessary to determine the adequacy of
title to both the applicable Lease and the fee title of the lessor to the premises
covered by the Lease. The results of the title examination and such other information
as is necessary to determine the adequacy of title for drilling purposes shall be
submitted to the Developer for its review and acceptance. No drilling on the
Additional Well Locations shall begin until the title has been accepted in writing by
the Developer. After any title has been accepted by the Developer, any loss, expense,
cost, or liability whatsoever, caused by or related to any defect or failure of the
title shall be the sole responsibility of and shall be borne entirely by the Developer,
unless such loss, expense, cost, or liability was caused by the breach of any of the
warranties and representations made by the Operator in Section l(b).
Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs;
Pipelines; Price Determinations; Plugging and Abandonment.
(a)
Operations Subsequent to Completion of the Wells. Beginning with the month in
which a well drilled under this Agreement begins to produce, Operator shall be entitled
to an operating fee of $362 per month for each well being operated under this
Agreement, which operating fee shall be proportionately reduced, on a well-by-well
basis to the extent the Developer owns less than 100% of the Working Interest in a
well. This fee shall be in lieu of any direct charges by Operator for its services or
the provision by Operator of its equipment for normal superintendence and maintenance
of the wells and related pipelines and facilities.
The operating fees shall cover all normal, regularly recurring operating expenses for
the production, delivery and sale of natural gas, including without limitation:
(i)
well tending, routine maintenance and adjustment;
(ii)
reading meters, recording production, pumping, maintaining appropriate books and records;
(iii)
preparing reports to the Developer and government agencies; and
(iv)
collecting and disbursing revenues.
The operating fees shall not cover costs and expenses related to the following:
(i)
the production and sale of oil;
(ii)
the collection and disposal of salt water or other liquids produced by the wells;
(iii)
the rebuilding of access roads; and
(iv)
the purchase of equipment, materials or third party services;
which, subject to the provisions of sub-section (c) of this Section 6, shall be
invoiced by Operator to the Developer on a monthly basis, and shall be paid by the
Developer within ten (10) business days after notice
from Operator that the additional amounts are due and owing in proportion to the
share of the Working Interest owned by the Developer in the wells.
Any well that is temporarily abandoned or shut-in continuously for an entire calendar
month shall not be considered a producing well for purposes of determining the number
of wells in the month subject to the operating fee.
(b)
Fee Adjustments. The monthly operating fee set forth in sub-section (a) above
may be adjusted by Operator annually, as of the first day of January (the “Adjustment
Date”) of each year, beginning January 1, 2008. This adjustment, if any, shall not
exceed the percentage increase in the average weekly earnings of “Crude Petroleum,
Natural Gas, and Natural Gas Liquids” workers, as published by the U.S. Department of
Labor, Bureau of Labor Statistics, and shown in Employment and Earnings Publication,
Monthly Establishment Data, Hours and Earning Statistical Table C-2, Index Average
Weekly Earnings of “Crude Petroleum, Natural Gas, and Natural Gas Liquids” workers, SIC
Code #131-2, or any successor index thereto, since January l, 2006, in the case of the
first adjustment, and since the previous Adjustment Date, in the case of each
subsequent adjustment.
In addition, the monthly operating fee set forth in sub-section (a) above for any
given well or wells being operated under this Agreement may be increased beyond the
annual adjustment described in the prior paragraph without advance notice to the
Developer, from time-to-time to the competitive rate in the area where the well(s)
are situated, as determined by the Operator in its sole discretion.
Extraordinary Costs. Without the prior written consent of the Developer,
pursuant to a written estimate submitted by Operator, Operator shall not undertake any
single project or incur any extraordinary cost with respect to any well being produced
under this Agreement that is reasonably estimated to result in an expenditure of more
than $5,000, unless the project or extraordinary cost is necessary for the following:
(i)
to safeguard persons or property; or
(ii)
to protect the well or related facilities in the event of a
sudden emergency.
In no event, however, shall the Developer be required to pay for any project or
extraordinary cost arising from the negligence or misconduct of Operator, its agents,
servants, employees, subcontractors, licensees, or invitees.
All extraordinary costs incurred and the cost of projects undertaken under this
section with respect to a well being produced under this Agreement shall be billed to
the Developer at the invoice cost of third-party services performed or materials
purchased together with a reasonable charge by Operator for any services performed
directly by it, in proportion to the share of the Working Interest owned by the
Developer in the wells. Operator shall have the right to require the Developer to
pay in advance all or a portion of the estimated costs of a project undertaken under
this section, before undertaking the project, in proportion to the share of the
Working Interest owned by the Developer in the well or wells.
(d)
Pipelines. Developer shall have no interest in the pipeline gathering system,
which gathering system shall remain the sole property of Operator or its Affiliates and
shall be maintained at their sole cost and expense.
(e)
Price Determinations. Notwithstanding anything in this Agreement to the
contrary, the Developer shall pay all costs in proportion to the share of the Working
Interest owned by the Developer in the wells with respect to obtaining price
determinations under and otherwise complying with the Natural Gas Policy Act of 1978
and the implementing state regulations. This responsibility shall include, without
limitation, preparing, filing, and executing all applications, affidavits, interim
collection notices, reports and other documents necessary or appropriate to obtain
price certification, to effect sales of natural gas, or otherwise to comply with the
Act and the implementing state regulations.
Operator agrees to furnish the information and render the assistance as the Developer
may reasonably request in order to comply with the Act and the implementing state
regulations without charge for services performed by its employees.
(f)
Plugging and Abandonment. The Developer shall have the right to direct
Operator to plug and abandon any well that has been completed under this Agreement as a
producer. In addition, Operator shall not plug and abandon any well that has been
drilled and completed as a producer under this Agreement before obtaining the written
consent of the Developer. However, if the Operator determines that any well drilled
and completed under this Agreement as a producer shall be plugged and abandoned in
accordance with the generally accepted and customary oil and gas field practices and
techniques then prevailing in the geographic area of the well location, and makes a
written request to the Developer for authority to plug and abandon the well and the
Developer fails to respond in writing to the request within forty-five (45) days
following the date of the request, then the Developer shall be deemed to have consented
to the plugging and abandonment of the well.
All costs and expenses related to plugging and abandoning wells that have been
drilled and completed under this Agreement as producing wells shall be borne and paid
by the Developer in proportion to the share of the Working Interest owned by the
Developer in the wells. Also, at any time after one (1) year from the date each well
drilled and completed under this Agreement is placed into production, Operator shall
have the right to deduct each month from the proceeds of the sale of the production
from the well up to $200, in proportion to the share of the Working Interest owned by
the Developer in the well, for the purpose of establishing a fund to cover the
Operator’s estimate of the Developer’s share of the costs of eventually
plugging and
abandoning the well. All of these funds shall be deposited by Operator in a separate
interest bearing escrow account for the account of the Developer, and the total
amount so retained and deposited shall not exceed Operator’s reasonable estimate of
Developer’s share of the costs of eventually plugging and abandoning the well.
7.
Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate
Account for Sale Proceeds; Records and Reports; Additional Information.
(a)
Billing and Payment Procedure with Respect to Operation of Wells. Operator
shall promptly and timely pay and discharge on behalf of the Developer, in proportion
to the share of the Working Interest owned by the Developer in the wells, the
following:
(i)
all expenses and liabilities payable and incurred by reason of
its operation of the wells in accordance with this Agreement , such as severance
taxes, royalties, overriding royalties, operating fees, and pipeline gathering
charges; and
(ii)
any third-party invoices received by Operator with respect to the
Developer’s share of the costs and expenses incurred in connection with the
operation of the wells.
Operator, however, shall not be required to pay and discharge any of the above costs
and expenses that are being contested in good faith by Operator.
Operator shall:
(i)
deduct the foregoing costs and expenses from the Developer’s
share of the proceeds of the oil and/or gas sold from the wells; and
(ii)
keep an accurate record of the Developer’s account, showing
expenses incurred and charges and credits made and received with respect to each
well.
If the Developer’s share of the proceeds of the oil and/or gas sold from the wells is
insufficient to pay the costs and expenses, then Operator shall promptly and timely
pay and discharge the costs and expenses described above, in proportion to the share
of the Working Interest owned by the Developer in the wells, and prepare and submit
an invoice to the Developer each month for those costs and expenses. The invoice
shall be accompanied by the form of statement specified in sub-section (b) below, and
shall be paid by the Developer within ten (10) business days of its receipt.
(b)
Disbursements. Operator shall disburse to the Developer, on a monthly basis,
the Developer’s share of the proceeds received from the sale of oil and/or gas sold
from the wells operated under this Agreement, less:
(i)
the amounts charged to the Developer under sub-section (a); and
(ii)
the amount, if any, withheld by Operator for future plugging
costs pursuant to sub-section (f) of Section 6.
Each disbursement made and/or invoice submitted to the Developer pursuant to
sub-section (a) above shall be accompanied by a statement from the Operator itemizing
with respect to each well:
(i)
the total production of oil and/or gas since the date of the last
disbursement or invoice billing period, as the case may be, and the Developer’s
share of the production;
(ii)
the total proceeds received from any sale of the production, and
the Developer’s share of the proceeds;
the costs and expenses deducted from the proceeds and/or being
billed to the Developer pursuant to sub-section (a) above;
(iv)
the amount withheld for future plugging costs; and
(v)
any other information as Developer may reasonably request,
including without limitation copies of all third-party invoices listed on the
statement for the period.
(c)
Separate Account for Sale Proceeds. Operator agrees to deposit all proceeds
from the sale of oil and/or gas sold from the wells operated under this Agreement in a
separate checking account maintained by Operator. This account shall be used solely
for the purpose of collecting and disbursing funds constituting proceeds from the sale
of production under this Agreement.
(d)
Records and Reports. In addition to the statements required under sub-section
(b) above, Operator, within seventy-five (75) days after the completion of each well
drilled, shall furnish the Developer with a detailed statement itemizing with respect
to the well the total costs and charges under Section 4(a) and the Developer’s share of
the costs and charges, and any other information as is necessary to enable the
Developer:
(i)
to allocate any extra costs incurred with respect to the well
between Tangible Costs and Intangible Drilling Costs; and
(ii)
to determine the amount of the investment tax credit or marginal
well production tax credit, if applicable.
(e)
Additional Information. Operator shall promptly furnish the Developer with any
additional information as it may reasonably request, including without limitation
geological, technical, and financial information, in the form as may reasonably be
requested, pertaining to any phase of the operations and activities governed by this
Agreement. The Developer and its authorized employees, agents and consultants,
including independent accountants shall, at Developer’s sole cost and expense:
(i)
on at least ten (10) days’ written notice to Operator have access
during normal business hours to all of Operator’s records pertaining to
operations under this Agreement, including without limitation, the right to
audit the books of account of Operator relating to all receipts, costs, charges,
expenses and disbursements and information regarding the separate account
required under sub-section (c); and
(ii)
have access, at its sole risk, to any wells drilled by Operator
under this Agreement at all times to inspect and observe any machinery,
equipment and operations.
8.
Operator’s Lien; Right to Collect From Oil or Gas Purchaser.
(a)
Operator’s Lien. To secure the payment of all sums due from Developer to
Operator under this Agreement, the Developer grants Operator a first and preferred lien
on and security interest in the following:
(i)
the Developer’s interest in the Leases covered by this Agreement;
(ii)
the Developer’s interest in oil and gas produced under this
Agreement and its share of the proceeds from the sale of the oil and gas; and
(iii)
the Developer’s interest in materials and equipment under this
Agreement.
(b)
Right to Collect From Oil or Gas Purchaser. If the Developer fails to timely
pay any amount owing under this Agreement by it to the Operator, then Operator, without
prejudice to other existing remedies,
may collect and retain from any purchaser or
purchasers of oil or gas the Developer’s share of the proceeds from the sale of the oil
and gas until the amount owed by the Developer, plus twelve percent (12%) interest on a
per annum basis, and any additional costs (including without limitation actual
attorneys’ fees and costs) resulting from the delinquency, has been paid. Each
purchaser of oil or gas shall be entitled to rely on Operator’s written statement
concerning the amount of any default.
9.
Successors and Assigns; Transfers; Appointment of Agent.
(a)
Successors and Assigns. This Agreement shall be binding on and inure to the
benefit of the undersigned parties and their respective successors and permitted
assigns. However, without the prior written consent of the Developer, the Operator may
not assign, transfer, pledge, mortgage, hypothecate, sell or otherwise dispose of any
of its interest in this Agreement, or any of its rights or obligations under this
Agreement. Notwithstanding, this consent shall not be required in connection with:
(i)
the assignment of work to be performed for Operator to
subcontractors, it being understood and agreed, however, that any assignment to
Operator’s subcontractors shall not in any manner relieve or release Operator
from any of its obligations and responsibilities under this Agreement;
(ii)
any lien, assignment, security interest, pledge or mortgage
arising under Operator’s present or future financing arrangements; or
(iii)
the liquidation, merger, consolidation, or other corporate
reorganization or sale of substantially all of the assets of Operator.
Further, in order to maintain uniformity of ownership in the wells, production,
equipment, and leasehold interests covered by this Agreement, and notwithstanding any
other provision of this Agreement to the contrary, the Developer shall not, without
the prior written consent of Operator, sell, assign, transfer, encumber, mortgage or
otherwise dispose of any of its interest in the wells, production, equipment or
leasehold interests covered by this Agreement unless the disposition encompasses
either:
(i)
the entire interest of the Developer in all wells, production,
equipment and leasehold interests subject to this Agreement; or
(ii)
an equal undivided interest in all such wells, production,
equipment, and leasehold interests.
(b)
Transfers. Subject to the provisions of sub-section (a) above, any sale,
encumbrance, transfer or other disposition made by the Developer of its interests in
the wells, production, equipment, and/or leasehold interests covered by this Agreement
shall be made:
(i)
expressly subject to this Agreement;
(ii)
without prejudice to the rights of the Operator; and
(iii)
in accordance with and subject to the provisions of the Leases
covering the Well Locations.
(c)
Appointment of Agent. If at any time the interest of the Developer is divided
among or owned by co-owners, Operator may, in its discretion, require the co-owners to
appoint a single trustee or agent with full authority to do the following:
(i)
receive notices, reports and distributions of the proceeds from
production;
(ii)
approve expenditures;
(iii)
receive billings for and approve and pay all costs, expenses and
liabilities incurred under this Agreement;
exercise any rights granted to the co-owners under this
Agreement;
(v)
grant any approvals or authorizations required or contemplated by
this Agreement;
(vi)
sign, execute, certify, acknowledge, file and/or record any
agreements, contracts, instruments, reports, or documents whatsoever in
connection with this Agreement or the activities contemplated by this Agreement;
and
(vii)
deal generally with, and with power to bind, the co-owners with
respect to all activities and operations contemplated by this Agreement.
However, all the co-owners shall continue to have the right to enter into and execute
all contracts or agreements for their respective shares of the oil and gas produced
from the wells drilled under this Agreement in accordance with sub-section (c) of
Section 11.
Operator’s Insurance. Operator shall obtain and maintain at its own expense so
long as it is Operator under this Agreement all required Workmen’s Compensation
Insurance and comprehensive general public liability insurance in amounts and coverage
not less than $1,000,000 per person per occurrence for personal injury or death and
$1,000,000 for property damage per occurrence, which shall include coverage for
blow-outs, and total liability coverage of not less than $10,000,000.
Subject to the above limits, the Operator’s general public liability insurance shall
be in all respects comparable to that generally maintained in the industry with
respect to services of the type to be rendered and activities of the type to be
conducted under this Agreement. Operator’s general public liability insurance shall,
if permitted by Operator’s insurance carrier:
(i)
name the Developer as an additional insured party; and
(ii)
provide that at least thirty (30) days’ prior notice of
cancellation and any other adverse material change in the policy shall be given
to the Developer.
However, the Developer shall reimburse Operator for the additional cost, if any, of
including it as an additional insured party under the Operator’s insurance.
Current copies of all policies or certificates of the Operator’s insurance coverage
shall be delivered to the Developer on request. It is understood and agreed that
Operator’s insurance coverage may not adequately protect the interests of the
Developer and that the Developer shall carry at its expense the excess or additional
general public liability, property damage, and other insurance, if any, as the
Developer deems appropriate.
(b)
Subcontractors’ Insurance. Operator shall require all of its subcontractors to
carry all required Workmen’s Compensation Insurance and to maintain such other
insurance, if any, as Operator in its discretion may require.
(c)
Operator’s Liability. Operator’s liability to the Developer as Operator under
this Agreement shall be limited to, and Operator shall indemnify the Developer and hold
it harmless from, claims, penalties, liabilities, obligations, charges, losses, costs,
damages, or expenses (including but not limited to reasonable attorneys’ fees) as
provided in Section 4.05 of the Developer’s Partnership Agreement.
11.
Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind.
(a)
Internal Revenue Code Election. With respect to this Agreement, each of the
parties elects under Section 761(a) of the Internal Revenue Code of 1986, as amended,
to be excluded from the provisions of
Subchapter K of Chapter 1 of Subtitle A of the
Internal Revenue Code of 1986, as amended. If the income tax laws of the state or
states in which the property covered by this Agreement is located contain, or may
subsequently contain, a similar election, each of the parties agrees that the election
shall be exercised.
Beginning with the first taxable year of operations under this Agreement, each party
agrees that the deemed election provided by Section 1.761-2(b)(2)(ii) of the
Regulations under the Internal Revenue Code of 1986, as amended, will apply; and no
party will file an application under Section 1.761-2 (b)(3)(i) of the Regulations to
revoke the election. Each party agrees to execute the documents and make the filings
with the appropriate governmental authorities as may be necessary to effect the
election.
(b)
Relationship of Parties. It is not the intention of the parties to create, nor
shall this Agreement be construed as creating, a mining or other partnership or
association or to render the parties liable as partners or joint venturers for any
purpose. Operator shall be deemed to be an independent contractor and shall perform
its obligations as set forth in this Agreement.
(c)
Right to Take Production in Kind. Subject to the provisions of Section 8
above, the Developer shall have the exclusive right to sell or dispose of its
proportionate share of all oil and gas produced from the wells to be drilled under this
Agreement, exclusive of production:
(i)
that may be used in development and producing operations;
(ii)
unavoidably lost; and
(iii)
used to fulfill any free gas obligations under the terms of the
applicable Lease or Leases.
Operator shall not have any right to sell or otherwise dispose of the oil and gas.
The Developer shall have the exclusive right to execute all contracts relating to the
sale or disposition of its proportionate share of the production from the wells
drilled under this Agreement.
Developer shall have no interest in any gas supply agreements of Operator, except the
right to receive Developer’s share of the proceeds received from the sale of any gas
or oil from wells developed under this Agreement. The Developer agrees to designate
Operator or Operator’s designated bank agent as the Developer’s collection agent in
any contracts. On request, Operator shall assist Developer in arranging the sale or
disposition of Developer’s oil and gas under this Agreement and shall promptly
provide the Developer with all relevant information that comes to Operator’s
attention regarding opportunities for selling production.
If Developer fails to take in kind or separately dispose of its proportionate share
of the oil and gas produced under this Agreement, then Operator shall have the right,
subject to the revocation at will by the Developer, but not the obligation, to
purchase the oil and gas or sell it to others at any time and from time to time, for
the account of the Developer at the best price obtainable in the area for the
production. Notwithstanding, Operator shall have no liability to Developer should
Operator fail to market the production.
Any such purchase or sale by Operator shall be subject always to the right of the
Developer to exercise at any time its right to take in-kind, or separately dispose
of, its share of oil and gas not previously delivered to a purchaser. Any purchase
or sale by Operator of the Developer’s share of oil and gas under this Agreement
shall be only for reasonable periods of time as are consistent with the minimum needs
of the oil and gas industry under the particular circumstances, but in no event for a
period in excess of one (1) year.
12.
Effect of Force Majeure; Definition of Force Majeure; Limitation.
(a)
Effect of Force Majeure. If Operator is rendered unable, wholly or in part, by
force majeure (as defined below) to carry out any of its obligations under this
Agreement, including but not limited to beginning the drilling of one or more wells by
the applicable times set forth in Section 2(b), or any
Addendum to this Agreement, the
obligations of the Operator, so far as it is affected by the force majeure, shall be
suspended during but no longer than, the continuance of the force majeure. The
Operator shall give to the Developer prompt written notice of the force majeure with
reasonably full particulars concerning it. Operator shall use all reasonable diligence
to remove the force majeure as quickly as possible to the extent the same is within its
reasonable control.
(b)
Definition of Force Majeure. The term “force majeure” shall mean an act of
God, strike, lockout, or other industrial disturbance, act of the public enemy, war,
terrorist acts, blockade, public riot, lightning, fire, storm, flood, explosion,
governmental restraint, unavailability of drilling rigs, equipment or materials, plant
shut-downs, curtailments by oil and gas purchasers and any other causes whether of the
kind specifically enumerated above or otherwise, which directly preclude Operator’s
performance under this Agreement and is not reasonably within the control of the
Operator including, but not limited to, the inability of Operator to begin the drilling
of the wells subject to this Agreement by the applicable times set forth in Section
2(b) or in any Addendum to this Agreement due to decisions of third-party operators to
delay drilling the wells, poor weather conditions, inability to obtain drilling
permits, access right to the drilling site or title problems.
(c)
Limitation. The requirement that any force majeure shall be remedied with all
reasonable dispatch shall not require the settlement of strikes, lockouts, or other
labor difficulty affecting the Operator contrary to its wishes. The method of handling
these difficulties shall be entirely within the discretion of the Operator.
13.
Term.
This Agreement shall become effective when executed by Operator and the Developer. Except
as provided in sub-section (c) of Section 3, this Agreement shall continue and remain in
full force and effect for the productive lives of each wells being operated under this
Agreement.
14.
Governing Law; Invalidity.
(a)
Governing Law. This Agreement shall be governed by, construed and interpreted
in accordance with the laws of the Commonwealth of Pennsylvania, excluding its conflict
of law provisions.
(b)
Invalidity. The invalidity or unenforceability of any particular provision of
this Agreement shall not affect the other provisions of this Agreement, and this
Agreement shall be construed in all respects as if the invalid or unenforceable
provision were omitted.
15.
Integration; Written Amendment.
(a)
Integration. This Agreement, including the Exhibits to this Agreement,
constitutes and represents the entire understanding and agreement of the parties with
respect to the subject matter of this Agreement and supersedes all prior negotiations,
understandings, agreements, and representations relating to the subject matter of this
Agreement.
(b)
Written Amendment. No change, waiver, modification, or amendment of this
Agreement shall be binding or of any effect unless in writing duly signed by the party
against which the change, waiver, modification, or amendment is sought to be enforced.
16.
Waiver of Default or Breach.
No waiver by any party to any default of or breach by any other party under this Agreement
shall operate as a waiver of any future default or breach, whether of like or different
character or nature.
Unless otherwise provided in this Agreement, all notices, statements, requests, or demands
that are required or contemplated by this Agreement shall be in writing and shall be
hand-delivered or sent by registered or certified mail, postage prepaid, to the following
addresses until a party’s address is changed by certified or registered letter so addressed
to the other party:
If to Developer, to:
Atlas Resources Public #16-2007(A) L.P.
[Atlas Resources Public #16-2007(B) L.P.]
c/o Atlas Resources, LLC
311 Rouser Road Moon Township, Pennsylvania15108
Notices that are served by registered or certified mail on the parties in the manner
provided above shall be deemed sufficiently served or given for all purposes under this
Agreement at the time the notice is hand-delivered or mailed in any post office or branch
post office regularly maintained by the United States Postal Service or any successor. All
payments shall be hand-delivered or sent by United States mail, postage prepaid to the
addresses set forth above until a party’s address is changed by certified or registered
letter so addressed to the other party.
18.
Interpretation.
The titles of the Sections in this Agreement are for convenience of reference only and shall
not control or affect the meaning or construction of any of the terms and provisions of this
Agreement. As used in this Agreement, the plural shall include the singular and the
singular shall include the plural whenever appropriate.
19.
Counterparts.
The parties may execute this Agreement in any number of separate counterparts, each of
which, when executed and delivered by the parties, shall have the force and effect of an
original; but all counterparts of this Agreement shall be deemed to constitute one and the
same instrument.
IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and
year first above written.
[To be completed as information becomes available]
1.
WELL LOCATION
(a)
Oil and Gas Lease from
dated
and recorded in Deed Book Volume ,
Page in
the Recorder’s Office of County, , covering approximately acres
in
Township,
County,
.
(b)
The portion of the leasehold estate constituting the No. Well Location is described
on the map attached hereto as Exhibit A-l.
(c)
Title Opinion of ,
, ,
, dated , 200___.
(d)
The Developer’s interest in the leasehold estate constituting this Well
Location is an undivided % Working Interest to those oil and gas
rights from the surface to the deepest depth penetrated at the cessation of drilling
activities (which is feet), subject to the landowner’s royalty interest and
overriding royalty interests.
THAT the undersigned
(hereinafter called “Assignor”), for and in consideration of One Dollar and other valuable
consideration ($1.00 ovc), the receipt whereof is hereby acknowledged, does hereby sell, assign,
transfer and set over unto
(hereinafter called “Assignee”), an undivided
in,
and to, the oil and gas lease described as follows:
together with the rights incident thereto and the personal property thereto, appurtenant thereto,
or used, or obtained, in connection therewith.
And for the same consideration, the assignor covenants with the said assignee and his or its
heirs, successors, or assigns that assignor is the lawful owner of said lease and rights and
interest thereunder and of the personal property thereon or used in connection therewith; that the
undersigned has good right and authority to sell and convey the same; and that said rights,
interest and property are free and clear from all liens and encumbrances, and that all rentals and
royalties due and payable thereunder have been duly paid.
In
Witness Whereof, the undersigned owner and assignor ha signed and sealed
this instrument the
day of , 200.
County and
State, on this day personally appeared who
acknowledged to me that
he did sign the foregoing instrument and that the same is
free act and deed.
In testimony whereof, I have hereunto set my hand and official seal, at
,
this day of , A.D., 200.
Notary Public
CORPORATION ACKNOWLEDGMENT
STATE OF
BEFORE ME, a Notary Public, in and for said
COUNTY OF
County and State, on this day personally appeared known to me to be the person and officer
whose name is subscribed to the foregoing instrument and acknowledged that the same was the act of
the said , a corporation, and that he executed the
same as the act of such corporation for the purposes and consideration therein expressed, and in
the capacity therein stated.
In testimony whereof, I have hereunto set my hand and official seal, at
, this day of , A.D., 200.
THIS ADDENDUM NO. made and entered into this day of ,
200, by and between ATLAS RESOURCES, LLC, a Pennsylvania limited liability company (hereinafter
referred to as “Operator”),
and
ATLAS RESOURCES PUBLIC #16-2007(A) L.P. [ATLAS RESOURCES PUBLIC #16-2007(B) L.P.], a Delaware
limited partnership, (hereinafter referred to as the Developer).
WITNESSETH THAT:
WHEREAS, Operator and the Developer have entered into a Drilling and Operating Agreement dated
, 200, (the “Agreement”), which relates to the drilling and operating of
()wells on the () Initial Well Locations identified
on the maps attached as Exhibits A-l through A- to the Agreement, and provides for the
development on the terms and conditions set forth in the Agreement of Additional Well Locations as
the parties may from time to time designate; and
WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer presently desire to
designate Additional Well Locations described below to be developed in accordance
with the terms and conditions of the Agreement.
NOW, THEREFORE, in consideration of the mutual covenants contained in this Addendum and intending
to be legally bound, the parties agree as follows:
1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes Operator to
drill, complete (or plug) and operate, on the terms and conditions set forth in the Agreement and
this Addendum No. , additional wells on the Additional
Well Locations described on Exhibit A to this Addendum and on the maps attached to this Addendum as
Exhibits A- through A-.
2. Operator, as Developer’s independent contractor, agrees to drill, complete (or plug) and
operate the additional wells on the Additional Well Locations in accordance with the terms and
conditions of the Agreement and further agrees to begin drilling the first additional well within
thirty (30) days after the date of this Addendum and to begin drilling all of the additional wells
before the close of the 90th day after the close of the calendar year in which the
Agreement was entered into by Operator and the Developer, or, if this Addendum is dated after that
90 day period, to begin drilling the first additional well within thirty (30) days after the date
of this Addendum and to drill and complete (or plug) all of the remaining additional wells by the
end of the calendar year in which this Addendum is dated.
3. Developer acknowledges that:
(a)
Operator has furnished Developer with the title opinions identified on Exhibit
A to this Addendum; and
(b)
such other documents and information which Developer or its counsel has
requested in order to determine the adequacy of the title to the above Additional Well
Locations.
The Developer accepts the title to the Additional Well Locations and leased premises in accordance
with the provisions of Section 5 of the Agreement.
4. The drilling and operation of the additional wells on the Additional Well Locations shall
be in accordance with and subject to the terms and conditions set forth in the Agreement as
supplemented by this Addendum No.
SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS
If you are a resident of one of the following states, then you must meet that state’s qualification
and suitability standards as set forth below.
Special Suitability Requirements If You Are Buying Limited Partner Units.
I.
If you are a resident of Alaska and you subscribe for limited
partner units, then you must meet either of the following special
suitability requirements:
•
a net worth of not less than $65,000, exclusive of your
principal automobile, principal residence and home furnishings, and
an annual gross income of not less than $65,000; or
•
a net worth of not less than $150,000, exclusive of your
principal automobile, principal residence, and home furnishings.
II.
If you are a resident of California or New Jersey and you purchase limited partners units,
then you must meet any one of the following special suitability requirements:
•
a net worth of not less than $250,000, exclusive of home, home furnishings and
automobiles, and expect to have gross income in the current year of $65,000 or more; or
•
a net worth of not less than $500,000, exclusive of home, home furnishings and automobiles; or
•
a net worth of not less than $1 million; or
•
expected gross income in the current tax year of not less than $200,000.
III.
If you are a resident of Kentucky and you subscribe for limited partner units, then you must meet either of the
following special suitability requirements:
•
a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles; or
•
a net worth of not less than $70,000, exclusive of home, home furnishings, and
automobiles, and annual income of $70,000 or more without regard to an investment in
the partnership.
Additionally, if you are a resident of Kentucky, then you must not make an investment in a
partnership which is in excess of 10% of your liquid net worth.
IV.
If you are a resident of Michigan or North Carolina and you purchase limited partner units, then you must meet either
one of the following special suitability requirements:
•
a net worth of not less than $225,000, exclusive of home, home furnishings and automobiles; or
•
a net worth of not less than $60,000, exclusive of home, home furnishings and
automobiles, and estimated current year taxable income as defined in Section 63 of the
Internal Revenue Code of $60,000 or more without regard to an investment in the
partnership.
In addition, if you are a resident of Michigan, then you must not make an investment in the
partnership in excess of 10% of your net worth, exclusive of home, home furnishings and
automobiles.
V.
If you are a resident of New Hampshire and you purchase limited partner units, then you must meet either one of the
following special suitability requirements:
•
a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles, or
•
a net worth of not less than $125,000, exclusive of home, home furnishings, and
automobiles, and $50,000 of taxable income.
VI.
If you are a resident of Ohio, Iowa or Massachusetts, and you subscribe for limited partner
units, then you must meet, without regard to your investment in a partnership, either of the
following special suitability requirements:
•
a net worth of not less than $330,000, exclusive of home, home furnishings, and
automobiles; or
a net worth of not less than $85,000, exclusive of home, home furnishings, and
automobiles, and an annual gross income during the current tax year of at least
$85,000.
Additionally, if you are a resident of Ohio you must not make an investment in a partnership
which would, after including your previous investments in prior Atlas Resources programs, if
any, and any other similar natural gas and oil drilling programs, exceed 10% of your net worth,
exclusive of home, home furnishings and automobiles.
Special Suitability Requirements If You Are Buying Investor General Partner Units.
I.
If you are a resident of Alaska and you subscribe for
investor general partner units, then you must meet either of the
following special suitability requirements:
•
a net worth of not less than $65,000, exclusive of your
principal automobile, principal residence and home furnishings, and
an annual gross income of not less than $65,000; or
•
a net worth of not less than $150,000, exclusive of your
principal automobile, principal residence and home furnishings.
II.
If you are a resident of California or New Jersey and you purchase investor general partner
units, then you must meet any one of the following special suitability requirements:
•
an individual or joint net worth with your spouse of not less than $250,000,
exclusive of home, home furnishings and automobiles, and expect to have annual gross
income in the current year of $120,000 or more; or
•
an individual or joint net worth with your spouse of not less than $500,000,
exclusive of home, home furnishings and automobiles; or
•
an individual or joint net worth with your spouse of not less than $1 million; or
•
a combined expected gross income in the current year of not less than $200,000.
III.
If you are a resident of any of the following states:
•
Alabama;
•
Maine;
•
Pennsylvania;
•
Arizona;
•
Minnesota;
•
Tennessee;
•
Arkansas;
•
North Carolina;
•
Texas; or
•
Indiana;
•
Oklahoma;
•
Washington
and you purchase investor general partner units, then you must meet
any one of the following special suitability requirements:
•
an individual or joint net worth with your spouse of $225,000 or more, without
regard to the investment in the partnership, exclusive of home, home furnishings and
automobiles, and a combined gross income of $100,000 or more for the current year and
for the two previous years; or
•
an individual or joint net worth with your spouse in excess of $1 million, inclusive
of home, home furnishings and automobiles; or
•
an individual or joint net worth with your spouse in excess of $500,000, exclusive
of home, home furnishings and automobiles; or
•
a combined “gross income” as defined in Section 61 of the Internal Revenue Code of
1986, as amended, in excess of $200,000 in the current year and the two previous years.
IV.
If you are a resident of any of the following states:
and you purchase investor general partner units, then you must meet any one of the
following special suitability requirements:
•
an individual or joint net worth with your spouse of $225,000 or more, without
regard to the investment in the partnership, exclusive of home, home furnishings and
automobiles, and a combined “taxable income” of $60,000 or more for the previous year
and expect to have a combined “taxable income” of $60,000 or more for the current year
and for the succeeding year; or
•
an individual or joint net worth with your spouse in excess of $1 million, inclusive
of home, home furnishings and automobiles; or
•
an individual or joint net worth with your spouse in excess of $500,000, exclusive
of home, home furnishings and automobiles; or
•
a combined “gross income” as defined in Section 61 of the Internal Revenue Code of
1986, as amended, in excess of $200,000 in the current year and the two previous years.
V.
If you are a resident of Kentucky and you subscribe for investor general partner units, then you must meet either of the
following special suitability requirements:
•
a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles; or
•
a net worth of not less than $70,000, exclusive of home, home furnishings, and
automobiles, and annual income of $70,000 or more without regard to an investment in
the partnership.
Additionally, if you are a resident of Kentucky, then you must not make an investment in a
partnership which is in excess of 10% of your liquid net worth.
VI.
In addition, if you are a resident of any of the following states:
•
Michigan; or
•Pennsylvania;
then you must not make an investment in the partnership in excess of 10% of your net
worth, exclusive of home, furnishings and automobiles.
Also, if you are a resident of Kansas, it is recommended by the Office of the Kansas Securities
Commissioner that you should limit your investment in the program and substantially similar
programs to no more than 10% of your liquid net worth. Liquid net worth is that portion of
your net worth (total assets minus total liabilities) that is comprised of cash, cash
equivalents and readily marketable securities. Readily marketable securities may include
investments in an IRA or other retirement plan that can be liquidated within a short time, less
any income tax penalties that may apply for early distribution.
VII.
If you are a resident of New Hampshire and you purchase investor general partner units, then
you must meet either one of the following special suitability requirements:
•
an individual or joint net worth with your spouse of not less than $250,000,
exclusive of home, home furnishings, and automobiles, or
an individual or joint net worth with your spouse of not less than $125,000,
exclusive of home, home furnishings, and automobiles, and $50,000 of taxable income.
VIII.
If you are a resident of Ohio, Iowa or Massachusetts and you subscribe for investor general
partner units, then you must meet, without regard to your investment in a partnership, either
of the following special suitability requirements:
•
an individual or joint net worth with your spouse of not less than $750,000,
exclusive of home, home furnishings, and automobiles; or
•
an individual or joint net worth with your spouse of not less than $330,000,
exclusive of home, home furnishings, and automobiles, and an annual gross income of at
least $150,000 for the current year and the two previous years.
Additionally, if you are a resident of Ohio, then you must not make an investment in a
partnership which would, after including your previous investments in prior Atlas Resources
programs, if any, and any other similar natural gas and oil drilling programs, exceed 10% of
your net worth, exclusive of home, home furnishings and automobiles. Additionally, if you are
a resident of Iowa, then you must not make an investment in a partnership which is in excess of
10% of your net worth, exclusive of home, home furnishings, and automobiles.
Special Representations of Subscribers in California, Iowa, North Carolina and Pennsylvania.
I.
If a resident of California, I am aware that:
IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST
THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT
OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED
IN THE COMMISSIONER’S RULES.
As a condition of qualification of the units for sale in the State of California, the following
rule is hereby delivered to each California purchaser.
California Administrative Code, Title 10, Ch. 3, Rule 260.141.11. Restriction on transfer.
(a)
The issuer of any security upon which a restriction on transfer has been imposed
pursuant to Section 260.141.10 or 260.534 shall cause a copy of this section to be
delivered to each issuee or transferee of such security at the time the certificate
evidencing the security is delivered to the issuee or transferee.
(b)
It is unlawful for the holder of any such security to consummate a sale or transfer
of such security, or any interest therein, without the prior written consent of the
Commissioner (until this condition is removed pursuant to Section 260.141.12 of these
rules), except:
(i)
to the issuer;
(ii)
pursuant to the order or process of any court;
(iii)
to any person described in Subdivision (i) of Section 25102 of the
Code or Section 260.105.14 of these rules;
(iv)
to the transferor’s ancestors, descendants or spouse, or any
custodian or trustee for the account of the transferor or the transferor’s
ancestors, descendants or spouse, or to a transferee by a trustee or custodian for
the account of the transferee or the transferee’s ancestors, descendants or
spouse;
(v)
to holders of securities of the same class of the same issuer;
by way of gift or donation inter vivos or on death;
(vii)
by or through a broker-dealer licensed under the Code (either acting
as such or as a finder) to a resident of a foreign state, territory or country who
is neither domiciled in this state to the knowledge of the broker-dealer, nor
actually present in this state if the sale of such securities is not in violation
of any securities law of the foreign state, territory or country concerned;
(viii)
to a broker-dealer licensed under the Code in a principal transaction, or as an
underwriter or member of an underwriting syndicate or selling group;
(ix)
if the interest sold or transferred is a pledge or other lien given
by the purchaser to the seller upon a sale of the security for which the
Commissioner’s written consent is obtained or under this rule not required;
(x)
by way of a sale qualified under Sections 25111, 25112, 25113 or
25121 of the Code, of the securities to be transferred, provided that no order
under Section 25140 or Subdivision (a) of Section 25143 is in effect with respect
to such qualification;
(xi)
by a corporation to a wholly-owned subsidiary of such corporation, or
by a wholly-owned subsidiary of a corporation to such corporation;
(xii)
by way of an exchange qualified under Section 25111, 25112 or 25113
of the Code, provided that no order under Section 25140 or Subdivision (a) of
Section 25143 is in effect with respect to such qualification;
(xiii)
between residents of foreign states, territories or countries who are neither
domiciled nor actually present in this state;
(xiv)
to the State Controller pursuant to the Unclaimed Property Law or to
the administrator of the unclaimed property law of another state;
(xv)
by the State Controller pursuant to the Unclaimed Property Law or by
the administrator of the unclaimed property law of another state if, in either
such case, such person (i) discloses to potential purchasers at the sale that
transfer of the securities is restricted under this rule, (ii) delivers to each
purchaser a copy of this rule, and (iii) advises the Commissioner of the name of
each purchaser;
(xvi)
by a trustee to a successor trustee when such transfer does not
involve a change in the beneficial ownership of the securities;
(xvii)
by way of an offer and sale of outstanding securities in an issuer transaction
that is subject to the qualification requirement of Section 25110 of the Code but
exempt from that qualification requirement by subdivision (f) of Section 25102;
provided that any such transfer is on the condition that any certificate evidencing the
security issued to such transferee shall contain the legend required by this section.
(c)
The certificates representing all such securities subject to such a restriction on
transfer, whether upon initial issuance or upon any transfer thereof, shall bear on their
face a legend, prominently stamped or printed thereon in capital letters of not less than
10-point size, reading as follows:
“IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST
THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF
THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE
COMMISSIONER’S RULES.”
If a resident of Iowa or North Carolina, I am aware that:
IN MAKING AN INVESTMENT DECISION INVESTORS MUST RELY ON THEIR OWN EXAMINATION OF THE
PERSON OR ENTITY CREATING THE SECURITIES AND THE TERMS OF THE OFFERING, INCLUDING THE
MERITS AND RISKS INVOLVED. THESE SECURITIES HAVE NOT BEEN RECOMMENDED BY ANY FEDERAL
OR STATE SECURITIES COMMISSION OR REGULATORY AUTHORITY. FURTHERMORE, THE FOREGOING
AUTHORITIES HAVE NOT CONFIRMED THE ACCURACY OR DETERMINED THE ADEQUACY OF THIS
DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
III.
PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than 10% of the maximum
closing amount allowed to a partnership in this offering, you are cautioned to carefully
evaluate the partnership’s ability to fully accomplish its stated objectives and inquire as to
the current dollar volume of partnership subscriptions. In addition, subscription proceeds
received by a partnership from Pennsylvania investors will be placed into a short-term escrow
(120 days or less) until subscriptions for at least 5% of the maximum offering proceeds have
been received by a partnership, which for Atlas Resources Public #16-2007(A) L.P. means that
subscriptions for at least $6.7 million have been received by the partnership from investors,
including Pennsylvania investors. If the appropriate minimum has not been met at the end of
each escrow period, the partnership must notify the Pennsylvania investors in writing by
certified mail or any other means whereby a receipt of delivery is obtained within 10 calendar
days after the end of each escrow period that they have a right to have their investment
returned to them. If an investor requests the return of such funds within 10 calendar days
after receipt of notification, the issuer must return such funds within 15 calendar days after
receipt of the investor’s request.
Instructions to Investor
You are required to execute your own Subscription Agreement and the Managing General Partner will
not accept any Subscription Agreement that has been executed by someone other than you unless the
person has been given your legal power of attorney to sign on your behalf, and you meet all of the
conditions in the Prospectus and this Subscription Agreement. In the case of sales to fiduciary
accounts, the minimum standards set forth in the Prospectus and this Subscription Agreement must be
met by the beneficiary, the fiduciary account, or by the donor or grantor who directly or
indirectly supplies the funds to purchase the Partnership Units if the donor or grantor is the
fiduciary.
Your execution of the Subscription Agreement constitutes your binding offer to buy Units in the
Partnership. Once you subscribe you may withdraw your subscription only by providing the Managing
General Partner with written notice of your withdrawal before your subscription is accepted by the
Managing General Partner. The Managing General Partner has the discretion to refuse to accept your
subscription without liability to you. Subscriptions will be accepted or rejected by the
Partnership within 30 days of their receipt. If your subscription is rejected, then all of your
funds will be returned to you immediately. If your subscription is accepted before the first
closing, then you will be admitted as a Participant not later than 15 days after the release from
escrow of the investors’ funds to the Partnership. If your subscription is accepted after the
first closing, then you will be admitted into the Partnership not later than the last day of the
calendar month in which your subscription was accepted by the Partnership.
The Managing General Partner will not complete a sale of Units to you and send you a confirmation
of purchase until at least five business days after the date you receive a final Prospectus.
NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from various
requirements of Title 10 of the California Administrative Code. These deviations include, but are
not limited to the following: the definition of Prospect in the Prospectus, unlike Rule
260.140.127.2(b) and Rule 260.140.121(1), does not require enlarging or contracting the size of the
area on the basis of geological data in all cases. If I am a resident of California, I acknowledge
the receipt of California Rule 260.141.11 set forth in Exhibit (B) to the Prospectus.
Management’s Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources
80
Proposed Activities
83
Competition, Markets and Regulation
100
Participation in Costs and Revenues
105
Conflicts of Interest
112
Fiduciary Responsibility of the Managing
General Partner
123
Federal Income Tax Consequences
125
Summary of Partnership Agreement
155
Summary of Drilling and Operating Agreement
158
Reports to Investors
158
Presentment Feature
160
Transferability of Units
161
Plan of Distribution
162
Sales Material
165
Legal Opinions
166
Experts
166
Litigation
167
Financial Information Concerning the Managing General Partner and Atlas Resources Public #16-2007(A) L.P.
167
Index to Financial Statements
167
EXHIBIT (A) — Form of Amended and Restated Certificate and Agreement of Limited Partnership
for Atlas Resources Public #16-2007(A) L.P. [Form of Amended and Restated Certificate and
Agreement of Limited Partnership for Atlas Resources Public #16-2007(B) L.P.]
EXHIBIT (I-A) — Form of Managing General Partner
Signature Page
EXHIBIT (I-B) — Form of Subscription Agreement
EXHIBIT (II) — Form of Drilling and Operating Agreement for Atlas Resources Public #16-2007(A)
L.P. [Atlas Resources Public #16-2007(B) L.P.]
EXHIBIT (B) — Special Suitability Requirements and
Disclosures to Investors
No one has been authorized to give any information or make any representations other than those
contained in this prospectus in connection with this offering. If given or made, you should not
rely on such information or representations as having been authorized by the managing general
partner. The delivery of this prospectus does not imply that its information is correct as of
any time after its date. This prospectus is not an offer to sell these securities in any state
to any person where the offer and sale is not permitted.
ATLAS RESOURCES
PUBLIC #16-2007 PROGRAM
PROSPECTUS
Until December 31, 2007, all dealers that effect transactions in these securities, whether or
not participating in this offering, may be required to deliver a prospectus. This is in addition to
the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to
their unsold allotments or subscriptions.
Item 13. Other Expenses of Issuance and Distribution.
The expenses to be incurred in connection with the issuance and distribution of the securities to
be registered, other than underwriting discounts, commissions and expense allowances, are estimated
to be as follows:
Accounting Fees and Expenses
$
40,000
*
Legal Fees (including Blue Sky) and Expenses
360,000
*
Printing
300,000
*
SEC Registration Fee
21,400
Blue Sky Filing Fees (excluding legal fees)
165,265
*
NASD Filing Fee
20,500
Miscellaneous
566,837
*
Total
$
1,474,002
*
*
Estimated
Item 14. Indemnification of Directors and Officers.
Title 15, Section 8945 of the Pennsylvania Consolidated Statutes provides for indemnification of
members and managers by a limited liability company subject to certain limitations.
Under Section 4.05 of the Amended and Restated Certificate and Agreement of Limited Partnership,
the Participants, within the limits of their Capital Contributions, and the Partnership, generally
agree to indemnify and exonerate the Managing General Partner, the Operator and their Affiliates
from claims of liability to any third party arising out of operations of the Partnership provided
that:
•
they determined in good faith that the course of conduct which caused the loss or
liability was in the best interest of the Partnership;
•
they were acting on behalf of or performing services for the Partnership; and
•
the course of conduct was not the result of their negligence or misconduct.
Section 11 of the Dealer-Manager Agreement provides for the indemnification of the Managing General
Partner, the Partnership and control persons under specified conditions by the Dealer-Manager
and/or Selling Agent.
Item 15. Recent Sales of Unregistered Securities.
None by the Registrant.
Atlas Resources, LLC (“Atlas”), an Affiliate of the Registrant, has made sales of unregistered and
registered securities within the last three years. See the section of the Prospectus captioned
“Prior Activities” regarding the sale of limited and general partner interests. In the opinion of
Atlas, the foregoing unregistered securities in each case have been and/or are being offered and
sold in compliance with exemptions from registration provided by the Securities Act of 1933, as
amended, including the exemptions provided by Section 4(2) of that Act and certain rules and
regulations promulgated thereunder. The securities in each case have been and/or are being offered
and sold to a limited number of persons who had the sophistication to understand the merits and
risks of the investment and who had the financial ability to bear such risks. The units of limited
and general partner interests were sold to persons who were Accredited Investors, as that term is
defined in Regulation D (17 CFR 230.501(a)), or who had, at the time of purchase, a net worth of at
least $225,000 (exclusive of home, furnishings and
automobiles) or a net worth (exclusive of home, furnishings and automobiles) of at least $125,000
and gross income of at least $75,000, or otherwise satisfied Atlas that the investment was
suitable.
Item 16. Exhibits and Financial Statement Schedules.
(a)
Exhibits
1
(a)
Proposed form of Dealer-Manager Agreement with Anthem Securities, Inc.
3
(a)
Certificate of Organization of Atlas Resources, LLC (1)
3
(b)
Operating Agreement of Atlas Resources, LLC (1)
4
(a)
Certificate of Limited Partnership for Atlas America Public #16-2007(A) L.P. (1)
4
(b)
Certificate of Limited Partnership for Atlas America Public #16-2007(B) L.P. (1)
4
(c)
Form of Amended and Restated Certificate and Agreement of Limited
Partnership for Atlas Resources Public #16-2007(A) L.P. [Form of Amended and
Restated Certificate and Agreement of Limited Partnership for Atlas Resources
Public #16-2007(B) L.P.] (See Exhibit (A) to Prospectus)
4
(d)
Amendment to the Certificate of Limited Partnership for Atlas America
Public #16-2007(A) L.P. (2)
4
(e)
Amendment to the Certificate of Limited Partnership for Atlas America
Public #16-2007(B) L.P. (2)
5
Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units (2)
8
Opinion of Kunzman & Bollinger, Inc. as to federal tax matters (2)
10
(a)
Escrow Agreement for Atlas Resources Public #16-2007(A) L.P.
10
(b)
Form of Drilling and Operating Agreement for Atlas Resources Public
#16-2007(A) L.P. [Atlas Resources Public #16-2007(B) L.P.] (See Exhibit (II) to the
Form of Limited Partnership Agreement, Exhibit (A) to Prospectus)
10
(c)
Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas
Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource
Energy, Inc. (1)
10
(d)
Guaranty dated August 12, 2003 between First Energy Corp. and Atlas
Resources, Inc. to Gas Purchase Agreement dated March 31, 1999 between Northeast
Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and
Resource Energy, Inc. (1)
10
(e)
Master Natural Gas Gathering Agreement dated February 2, 2000 among
Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas
America, Inc., Resource Energy, Inc., and Viking Resources Corporation (1)
10
(f)
Omnibus Agreement dated February 2, 2000 among Atlas America, Inc.,
Resource Energy, Inc., and Viking Resources Corporation, and Atlas Pipeline
Operating Partnership, L.P., and Atlas Pipeline Partners, L.P. (1)
10
(g)
Natural Gas Gathering Agreement dated January 1, 2002 among Atlas
Pipeline Partners, L.P., and Atlas Pipeline Operating Partnership, L.P. and Atlas
Resources, Inc., and Atlas Energy Group, Inc. and Atlas Noble Corporation, and
Resource Energy Inc., and Viking Resources Corporation (1)
Base Contract for Sale and Purchase of Natural Gas dated November 13,2002 Between UGI Energy Services, Inc. and Viking Resources Corp. (1)
10(h)(1)
First Amendment to Base Contract for Sale and Purchase of Natural Gas (2)
10(h)(2)
Second Amendment to Base Contract for Sale and Purchase of Natural Gas (2)
10(h)(3)
Third Amendment to Base Contract for Sale and Purchase of Natural Gas (2)
10
(i)
Guaranty dated June 1, 2004 between UGI Corporation and Viking Resources Corp. (1)
10
(j)
Guaranty as of December 7, 2004 between FirstEnergy Corp. and Atlas Resources, Inc. (1)
10
(k)
Confirmation of Gas Purchase and Sales Agreement dated November 17,2004 between Atlas Resources, Inc. et. al. and First Energy Solutions Corp. for the
period from April 1, 2006 through March 31, 2007 production/calendar periods (1)
10
(l)
Transaction Confirmation dated December 14, 2004 between Atlas
America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK (1)
10
(m)
Drilling and Operating Agreement Dated September 15, 2004 by and
between Atlas America, Inc. and Knox Energy, LLC (1)
10
(n)
Guaranty dated January 1, 2005 between UGI Corporation and Viking Resources Corp. (1)
10
(o)
Escrow Agreement for Atlas Resources Public #16-2007(B) L.P.
10
(p)
Amendment among Atlas Pipeline Partners, L.P. and Atlas Pipeline
Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., Viking
Resources Corporation, Atlas Noble Corp., and Atlas Resources, Inc. to the Master
Natural Gas Gathering Agreement dated February 2, 2000 and the Natural Gas
Gathering Agreement dated January 1, 2002 (1)
10
(q)
Contribution, Conveyance and Assumption Agreement dated December 18,2006 among Atlas America, Inc., Atlas Energy Resources, LLC, and Atlas Energy
Operating Company, LLC (2)
10
(r)
Omnibus Agreement dated December 18, 2006 between Atlas Energy
Resources, LLC and Atlas America, Inc. (2)
10
(s)
Management Agreement dated December 18, 2006 among Atlas Energy
Resources, LLC, Atlas Energy Operating Company, LLC, and Atlas Energy Management,
Inc. (2)
10
(t)
Amendment and Joinder to Omnibus Agreement dated December 18, 2006,
among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P.,
Atlas America, Inc., Resource Energy, LLC, Viking Resources, LLC, Atlas Energy
Resources, LLC, and Atlas Energy Operating Company, LLC (2)
10
(u)
Amendment and Joinder to Gas Gathering Agreements dated December 18,2006, among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership,
L.P., Atlas America, Inc., Resource Energy, LLC, Viking Resources, LLC, Atlas
Noble, LLC, Atlas Resources, LLC, Atlas America, LLC, Atlas Energy Resources, LLC,
and Atlas Energy Operating Company, LLC (2)
10
(v)
Revolving Credit Agreement dated as of December 18, 2006 Among Atlas
Energy Operating Company, LLC, as Borrower; AER Pipeline Construction, Inc., AIC,
LLC, Atlas America, LLC, Atlas Energy Ohio, LLC, Atlas Energy Resources, LLC, Atlas
Noble, LLC, Atlas Resources, LLC,
REI-NY, LLC, Resource Energy, LLC, Resource Well Services, LLC, and Viking
Resources LLC as Guarantors; Wachovia Bank, National Association as
Administrative Agent and Issuing Bank; Bank Of America, N.A. and Compass Bank as
Co-Syndication Agents; Bank Of Oklahoma, N.A., U.S. Bank, National Association
and BNP Paribas as Co-Documentation Agents and the Lenders Signatory Hereto
$250,000,000 Senior Secured Revolving Credit Facility Wachovia Capital Markets,
LLC as Lead Arranger (2)
10
(w)
Continuing Guaranty Agreement dated December 18, 2006 by Atlas Energy
Resources, LLC in Favor of Wachovia Bank, National Association, as Administrative
Agent for the Lenders (2)
23
(a)
Consent of Independent Registered Public Accounting Firm
23
(b)
Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)
23
(c)
Consent of Wright & Company, Inc. (1)
23
(d)
Consent of United Energy Development Consultants, Inc.
All financial statement schedules are omitted because the information is not required, is not
material or is otherwise included in the financial statements or related notes thereto.
Item 17. Undertakings.
The undersigned registrant hereby undertakes:
(a) (1)
To file, during any period in which offers or sales are being made, a
post-effective amendment to this registration statement:
(i)
To include any prospectus required by section 10(a)(3) of the
Securities Act of 1933;
(ii)
To reflect in the prospectus any facts or events arising after
the effective date of the registration statement (or the most recent
post-effective amendment thereof) which, individually or in the aggregate,
represent a fundamental change in the information set forth in the registration
statement. Notwithstanding the foregoing, any increase or decrease in volume of
securities offered (if the total dollar value of securities offered would not
exceed that which was registered) and any deviation from the low or high end of
the estimated maximum offering range may be reflected in the form of prospectus
filed with the Commission pursuant to Rule 424(b) (§ 230.424(b) of this
chapter) if, in the aggregate, the changes in volume and price represent no more
than 20% change in the maximum aggregate offering price set forth in the
“Calculation of Registration Fee” table in the effective registration statement.
(iii)
To include any material information with respect to the plan
of distribution not previously disclosed in the registration statement or any
material change to such information in the registration statement;
Paragraphs (a)(1)(i) and (a)(1)(ii) of this section
do not apply if the registration statement is on Form S-8 (§
239.16b of this chapter), and the information required to be included
in a post-effective amendment by those paragraphs is contained in reports
filed with or furnished to the Commission by the registrant pursuant to
section 13 or section 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)) that are incorporated by
reference in the registration statement; and
(B)
Paragraphs (a)(1)(i), (a)(1)(ii) and (a)(1)(iii) of
this section do not apply if the registration statement is on Form S-3
(§ 239.13 of this chapter) or Form F-3 (§ 239.33 of this
chapter) and the information required to be included in a post-effective
amendment by those paragraphs is contained in reports filed with or
furnished to the Commission by the registrant pursuant to section 13 or
section 15(d) of the Securities Exchange Act of 1934 that are
incorporated by reference in the registration statement, or is contained
in a form of prospectus filed pursuant to Rule 424(b) (§
230.424(b) of this chapter) that is part of the registration
statement.
(C)
Provided further, however, that paragraphs
(a)(1)(i) and (a)(1)(ii) do not apply if the registration statement is
for an offering of asset-backed securities on Form S-1 (§ 239.11
of this chapter) or Form S-3 (§ 239.13 of this chapter), and the
information required to be included in a post-effective amendment is
provided pursuant to Item 1100(c) of Regulation AB (§
229.1100(c)).
(2)
That, for the purpose of determining any liability under the Securities Act of
1933, each such post-effective amendment shall be deemed to be a new registration
statement relating to the securities offered therein, and the offering of such
securities at that time shall be deemed to be the initial bona fide offering thereof.
(3)
To remove from registration by means of a post-effective amendment any of the
securities being registered which remain unsold at the termination of the offering.
(4)
If the registrant is a foreign private issuer, to file a post-effective
amendment to the registration statement to include any financial statements required by
“Item 8.A. of Form 20-F (17 CFR 249.220f)” at the start of any delayed offering
or throughout a continuous offering. Financial statements and information otherwise
required by Section 10(a)(3) of the Act need not be furnished, provided that the
registrant includes in the prospectus, by means of a post-effective amendment,
financial statements required pursuant to this paragraph (a)(4) and other information
necessary to ensure that all other information in the prospectus is at least as current
as the date of those financial statements. Notwithstanding the foregoing, with respect
to registration statements on Form F-3 (§ 239.33 of this chapter), a
post-effective amendment need not be filed to include financial statements and
information required by Section 10(a)(3) of the Act or § 210.3-19 of this
chapter if such financial statements and information are contained in periodic reports
filed with or furnished to the Commission by the registrant pursuant to section 13 or
section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference
in the Form F-3.
(5)
That, for the purpose of determining liability under the Securities Act of 1933
to any purchaser:
(i)
If the registrant is relying on Rule 430B (§ 230.430B of
this chapter):
(A)
Each prospectus filed by the registrant pursuant to
Rule 424(b)(3) (§ 230.424(b)(3) of this chapter) shall be deemed
to be part of the registration statement as of the date the filed
prospectus was deemed part of and included in the registration statement;
and
(B)
Each prospectus required to be filed pursuant to
Rule 424(b)(2), (b)(5), or (b)(7) (§ 230.424(b)(2),
(b)(5), or (b)(7) of this chapter) as part of a
registration statement in reliance on Rule 430B relating to an offering
made pursuant to Rule 415(a)(1)(i), (vii), or
(x) (§ 230.415(a)(1)(i), (vii), or (x) of this
chapter) for the purpose of providing the information required by
section 10(a) of the Securities Act of 1933 shall be deemed to be part
of and included in the registration statement as of the earlier of the
date such form of prospectus is first used after effectiveness or the
date of the first contract of sale of securities in the offering
described in the prospectus. As provided in Rule 430B, for liability
purposes of the issuer and any person that is at that date an
underwriter, such date shall be deemed to be a new effective date of
the registration statement relating to the securities in the
registration statement to which that prospectus relates, and the
offering of such securities at that time shall be deemed to be the
initial bona fide offering thereof. Provided, however, that no
statement made in a registration statement or prospectus that is part
of the registration statement or made in a document incorporated or
deemed incorporated by reference into the registration statement or
prospectus that is part of the registration statement will, as to a
purchaser with a time of contract of sale prior to such effective date,
supersede or modify any statement that was made in the registration
statement or prospectus that was part of the registration statement or
made in any such document immediately prior to such effective date; or
(ii)
If the registrant is subject to Rule 430C (§ 230.430C of
this chapter), each prospectus filed pursuant to Rule 424(b) as part of a
registration statement relating to an offering, other than registration
statements relying on Rule 430B or other than prospectuses filed in reliance on
Rule 430A (§ 230.430A of this chapter), shall be deemed to be part of
and included in the registration statement as of the date it is first used after
effectiveness. Provided, however, that no statement made in a registration
statement or prospectus that is part of the registration statement or made in a
document incorporated or deemed incorporated by reference into the registration
statement or prospectus that is part of the registration statement will, as to a
purchaser with a time of contract of sale prior to such first use, supersede or
modify any statement that was made in the registration statement or prospectus
that was part of the registration statement or made in any such document
immediately prior to such date of first use.
(6)
That, for the purpose of determining liability of the registrant under the
Securities Act of 1933 to any purchaser in the initial distribution of the securities:
The undersigned registrant hereby undertakes that in a primary offering of securities
of the undersigned registrant pursuant to this registration statement, regardless of
the underwriting method used to sell the securities to the purchaser, if the
securities are offered or sold to such purchaser by means of any of the following
communications, the undersigned registrant will be a seller to the purchaser and will
be considered to offer or sell such securities to such purchaser:
(i)
Any preliminary prospectus or prospectus of the undersigned
registrant relating to the offering required to be filed pursuant to Rule 424
(§ 230.424 of this chapter);
(ii)
Any free writing prospectus relating to the offering prepared by
or on behalf of the undersigned registrant or used or referred to by the
undersigned registrant;
(iii)
The portion of any other free writing prospectus relating to the
offering containing material information about the undersigned registrant or its
securities provided by or on behalf of the undersigned registrant; and
(iv)
Any other communication that is an offer in the offering made by
the undersigned registrant to the purchaser.
(b)
The undersigned registrant hereby undertakes that, for purposes of determining any liability
under the Securities Act of 1933, each filing of the registrant’s annual report pursuant to
section 13(a) or section 15(d) of the Securities
Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s
annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is
incorporated by reference in the registration statement shall be deemed to be a new
registration statement relating to the securities offered therein, and the offering of such
securities at that time shall be deemed to be the initial bona fide offering thereof.
(c)
The undersigned registrant hereby undertakes to supplement the prospectus, after the
expiration of the subscription period, to set forth the results of the subscription offer, the
transactions by the underwriters during the subscription period, the amount of unsubscribed
securities to be purchased by the underwriters, and the terms of any subsequent reoffering
thereof. If any public offering by the underwriters is to be made on terms differing from
those set forth on the cover page of the prospectus, a post-effective amendment will be filed
to set forth the terms of such offering.
(d)
The undersigned registrant hereby undertakes (1) to use its best efforts to distribute prior
to the opening of bids, to prospective bidders, underwriters, and dealers, a reasonable number
of copies of a prospectus which at that time meets the requirements of section 10(a) of the
Act, and relating to the securities offered at competitive bidding, as contained in the
registration statement, together with any supplements thereto, and (2) to file an amendment to
the registration statement reflecting the results of bidding, the terms of the reoffering and
related matters to the extent required by the applicable form, not later than the first use,
authorized by the issuer after the opening of bids, of a prospectus relating to the securities
offered at competitive bidding, unless no further public offering of such securities by the
issuer and no reoffering of such securities by the purchasers is proposed to be made.
(e)
The undersigned registrant hereby undertakes to deliver or cause to be delivered with the
prospectus, to each person to whom the prospectus is sent or given, the latest annual report
to security holders that is incorporated by reference in the prospectus and furnished pursuant
to and meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Securities Exchange Act
of 1934; and, where interim financial information required to be presented by Article 3 of
Regulation S-X are not set forth in the prospectus, to deliver, or cause to be delivered to
each person to whom the prospectus is sent or given, the latest quarterly report that is
specifically incorporated by reference in the prospectus to provide such interim financial
information.
(f)
The undersigned registrant hereby undertakes to provide to the underwriter at the closing
specified in the underwriting agreements certificates in such denominations and registered in
such names as required by the underwriter to permit prompt delivery to each purchaser.
(g) (1)
The undersigned registrant hereby undertakes as follows: that prior to any public
reoffering of the securities registered hereunder through use of a prospectus which is a part
of this registration statement, by any person or party who is deemed to be an underwriter
within the meaning of Rule 145(c), the issuer undertakes that such reoffering prospectus will
contain the information called for by the applicable registration form with respect to
reofferings by persons who may be deemed underwriters, in addition to the information called
for by the other Items of the applicable form.
(2)
The undersigned registrant hereby undertakes that every prospectus (i) that is
filed pursuant to paragraph (h) (1) immediately preceding, or (ii) that purports to
meet the requirements of section 10(a)(3) of the Act and is used in connection with an
offering of securities subject to Rule 415 (§ 230.415 of this chapter), will be
filed as a part of an amendment to the registration statement and will not be used
until such amendment is effective, and that, for purposes of determining any liability
under the Securities Act of 1933, each such post-effective amendment shall be deemed to
be a new registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona fide
offering thereof.
(h)
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be
permitted to directors, officers and controlling persons of the registrant pursuant to the
foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public policy as expressed
in the Act and is, therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the registrant of expenses incurred or
paid by a director, officer or
controlling person of the registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in connection with
the securities being registered, the registrant will, unless in the opinion of its counsel
the matter has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public policy as
expressed in the Act and will be governed by the final adjudication of such issue.
(i)
The undersigned registrant hereby undertakes that:
(1)
For purposes of determining any liability under the Securities Act of 1933, the
information omitted from the form of prospectus filed as part of this registration
statement in reliance upon Rule 430A and contained in a form of prospectus filed by the
registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall
be deemed to be part of this registration statement as of the time it was declared
effective.
(2)
For the purpose of determining any liability under the Securities Act of 1933,
each post-effective amendment that contains a form of prospectus shall be deemed to be
a new registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona fide
offering thereof.
(j)
The undersigned registrant hereby undertakes to file an application for the purpose of
determining the eligibility of the trustee to act under subsection (a) of section 310 of the
Trust Indenture Act (“Act”) in accordance with the rules and regulations prescribed by the
Commission under section 305(b)(2) of the Act.
(k)
The undersigned registrant hereby undertakes that, for purposes of determining any liability
under the Securities Act of 1933, each filing of the annual report pursuant to section 13(a)
or section 15(d) of the Securities Exchange Act of 1934 of a third party that is incorporated
by reference in the registration statement in accordance with Item 1100(c)(1) of Regulation AB
(17 CFR 229.1100(c)(1)) shall be deemed to be a new registration statement relating to
the securities offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.
(l)
The undersigned registrant hereby undertakes that, except as otherwise provided by Item 1105
of Regulation AB (17 CFR 229.1105), information provided in response to that Item
pursuant to Rule 312 of Regulation S-T (17 CFR 232.312) through the specified Internet
address in the prospectus is deemed to be a part of the prospectus included in the
registration statement. In addition, the undersigned registrant hereby undertakes to provide
to any person without charge, upon request, a copy of the information provided in response to
Item 1105 of Regulation AB pursuant to Rule 312 of Regulation S-T through the specified
Internet address as of the date of the prospectus included in the registration statement if a
subsequent update or change is made to the information.
Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly
caused this Pre-Effective Amendment No. 2 to the Registration Statement to be signed on its behalf
by the undersigned, thereunto duly authorized, in Moon Township, Pennsylvania on
February 23, 2007.
to the Registration Statement, has
been granted Power of Attorney and is
signing on behalf of the names shown
Jack L. Hollander, Senior Vice President -
Direct Participation Programs
below, in the capacities indicated.
In accordance with the requirements of the Securities Act of 1933, this Registration Statement has
been signed by the following persons in the capacities and on the dates indicated.
Signature
Title
Date
Freddie M. Kotek
President, Chief Executive Officer and Chairman of the
REGISTRATION STATEMENT
Under
THE SECURITIES ACT OF 1933
ATLAS RESOURCES PUBLIC #16-2007 PROGRAM
(Exact name of Registrant as Specified in its Charter)
Jack L. Hollander, Senior Vice President – Direct Participation Programs
Atlas Resources, LLC
311 Rouser Road, Moon Township, Pennsylvania15108
(412) 262-2830
(Name, Address and Telephone Number of Agent for Service)
Proposed form of Dealer-Manager Agreement with Anthem Securities, Inc.
3(a)
Certificate of Organization of Atlas Resources, LLC (1)
3(b)
Operating Agreement of Atlas Resources, LLC (1)
4(a)
Certificate of Limited Partnership for Atlas America Public #16-2007(A) L.P. (1)
4(b)
Certificate of Limited Partnership for Atlas America Public #16-2007(B) L.P. (1)
4(c)
Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas
Resources Public #16-2007(A) L.P. [Form of Amended and Restated Certificate and Agreement of
Limited Partnership for Atlas Resources Public #16-2007(B) L.P.] (See Exhibit (A) to Prospectus)
4(d)
Amendment to the Certificate of Limited Partnership for Atlas America Public #16-2007(A) L.P. (2)
4(e)
Amendment to the Certificate of Limited Partnership for Atlas America Public #16-2007(B) L.P. (2)
5
Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units (2)
8
Opinion of Kunzman & Bollinger, Inc. as to federal tax matters (2)
10(a)
Escrow Agreement for Atlas Resources Public #16-2007(A) L.P.
10(b)
Form of Drilling and Operating Agreement for Atlas Resources Public #16-2007(A) L.P. [Atlas
Resources Public #16-2007(B) L.P.] (See Exhibit (II) to the Form of Limited Partnership
Agreement, Exhibit (A) to Prospectus)
10(c)
Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and
Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. (1)
10(d)
Guaranty dated August 12, 2003 between First Energy Corp. and Atlas Resources, Inc. to Gas
Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas
Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. (1)
10(e)
Master Natural Gas Gathering Agreement dated February 2, 2000 among Atlas Pipeline Partners,
L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc.,
and Viking Resources Corporation (1)
10(f)
Omnibus Agreement dated February 2, 2000 among Atlas America, Inc., Resource Energy, Inc., and
Viking Resources Corporation, and Atlas Pipeline Operating Partnership, L.P., and Atlas Pipeline
Partners, L.P. (1)
10(g)
Natural Gas Gathering Agreement dated January 1, 2002 among Atlas Pipeline Partners, L.P., and
Atlas Pipeline Operating Partnership, L.P. and Atlas Resources, Inc., and Atlas Energy Group,
Inc. and Atlas Noble Corporation, and Resource Energy Inc., and Viking Resources Corporation (1)
10(h)
Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy
Services, Inc. and Viking Resources Corp. (1)
10(h)(1)
First Amendment to Base Contract for Sale and Purchase of Natural Gas (2)
10(h)(2)
Second Amendment to Base Contract for Sale and Purchase of Natural Gas (2)
10(h)(3)
Third Amendment to Base Contract for Sale and Purchase of Natural Gas (2)
10(i)
Guaranty dated June 1, 2004 between UGI Corporation and Viking Resources Corp. (1)
10(j)
Guaranty as of December 7, 2004 between FirstEnergy Corp. and Atlas Resources, Inc. (1)
10(k)
Confirmation of Gas Purchase and Sales Agreement dated November 17, 2004 between Atlas
Resources, Inc. et. al. and First Energy Solutions Corp. for the period from April 1, 2006
through March 31, 2007 production/calendar periods (1)
Transaction Confirmation dated December 14, 2004 between Atlas America, Inc. and UGI Energy
Services, Inc. d/b/a GASMARK (1)
10(m)
Drilling and Operating Agreement Dated September 15, 2004 by and between Atlas America, Inc. and
Knox Energy, LLC (1)
10(n)
Guaranty dated January 1, 2005 between UGI Corporation and Viking Resources Corp. (1)
10(o)
Escrow Agreement for Atlas Resources Public #16-2007(B) L.P.
10(p)
Amendment among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P.,
Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corp., and
Atlas Resources, Inc. to the Master Natural Gas Gathering Agreement dated February 2, 2000 and
the Natural Gas Gathering Agreement dated January 1, 2002 (1)
10(q)
Contribution, Conveyance and Assumption Agreement dated December 18, 2006 among Atlas America,
Inc., Atlas Energy Resources, LLC, and Atlas Energy Operating Company, LLC (2)
10(r)
Omnibus Agreement dated December 18, 2006 between Atlas Energy Resources, LLC and Atlas America,
Inc. (2)
10(s)
Management Agreement dated December 18, 2006 among Atlas Energy Resources, LLC, Atlas Energy
Operating Company, LLC, and Atlas Energy Management, Inc. (2)
10(t)
Amendment and Joinder to Omnibus Agreement dated December 18, 2006, among Atlas Pipeline
Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource
Energy, LLC, Viking Resources, LLC, Atlas Energy Resources, LLC, and Atlas Energy Operating
Company, LLC (2)
10(u)
Amendment and Joinder to Gas Gathering Agreements dated December 18, 2006, among Atlas Pipeline
Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource
Energy, LLC, Viking Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, Atlas America, LLC,
Atlas Energy Resources, LLC, and Atlas Energy Operating Company, LLC (2)
10(v)
Revolving Credit Agreement dated as of December 18, 2006 Among Atlas Energy Operating Company,
LLC, as Borrower; AER Pipeline Construction, Inc., AIC, LLC, Atlas America, LLC, Atlas Energy
Ohio, LLC, Atlas Energy Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, REI-NY, LLC,
Resource Energy, LLC, Resource Well Services, LLC, and Viking Resources LLC as Guarantors;
Wachovia Bank, National Association as Administrative Agent and Issuing Bank; Bank Of America,
N.A. and Compass Bank as Co-Syndication Agents; Bank Of Oklahoma, N.A., U.S. Bank, National
Association and BNP Paribas as Co-Documentation Agents and the Lenders Signatory Hereto
$250,000,000 Senior Secured Revolving Credit Facility Wachovia Capital Markets, LLC as Lead
Arranger (2)
10(w)
Continuing Guaranty Agreement dated December 18, 2006 by Atlas Energy Resources, LLC in Favor of
Wachovia Bank, National Association, as Administrative Agent for the Lenders (2)
23(a)
Consent of Independent Registered Public Accounting Firm
23(b)
Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)
23(c)
Consent of Wright & Company, Inc. (1)
23(d)
Consent of United Energy Development Consultants, Inc.