Quarterly Report — Form 10-Q Filing Table of Contents
Document/ExhibitDescriptionPagesSize 1: 10-Q Form 10-Q for the Period Ended June 30, 2008 HTML 388K
2: EX-3.1 Amended and Restated Articles of Incorporation, as HTML 33K
Currently in Effect
3: EX-31.1 Certification of Stephen Cochennet Pursuant to HTML 15K
Section 302 of the Sarbanes-Oxley Act of
2002
4: EX-31.2 Certification of Dierdre Jones Pursuant to Section HTML 15K
302 of the Sarbanes-Oxley Act of 2002
5: EX-32.1 Certification of Stephen Cochennet Pursuant to HTML 9K
Section 906 of the Sarbanes-Oxley Act of
2002
6: EX-32.2 Certification of Dierdre Jones Pursuant to Section HTML 9K
906 of the Sarbanes-Oxley Act of 2002
10-Q — Form 10-Q for the Period Ended June 30, 2008
(Exact
name of registrant as specified in its charter)
Nevada
88-0422242
(State
or other jurisdiction of incorporation or organization)
(I.R.S.
Employer Identification No.)
7300
W. 110th,
7th
Floor
Overland
Park, Kansas
66210
(Address
of principal executive offices)
(Zip
Code)
(913)
693-4600
(Registrant’s
telephone number, including area code)
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90
days. Yes x No
¨
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer,”“accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filer ¨
Accelerated filer ¨
Non-accelerated
filer ¨ (Do
not check if a smaller reporting company) Smaller reporting
company x
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange
Act). Yes ¨ No
x
The
number of shares of Common Stock, $0.001 par value, outstanding on August 13,2008, was 4,443,467 shares.
ENERJEX
RESOURCES, INC.
FORM
10-Q
TABLE
OF CONTENTS
Page
PART
I FINANCIAL
STATEMENTS
Item
1. Financial
Statements
1
Consolidated Balance
Sheets
1
Consolidated Statements of
Operations
2
Consolidated Statements of Cash
Flows
3
Notes to Consolidated Financial
Statements
4
Forward-Looking
Statements
9
Item
2. Management’s
Discussion and Analysis of FinancialCondition and Results of
Operations
10
Item
3.
Quantitative and Qualitative Disclosures about MarketRisk
20
Item
4T.
Controls and Procedures
20
PART
II OTHER
INFORMATION
Item
1.
Legal Proceedings
20
Item
1A. Risk
Factors
21
Item
2.
Unregistered Sales of Equity Securities and Use of
Proceeds
39
Item
3. Defaults
Upon Senior Securities
40
Item
4.
Submission of Matters to a Vote of Security Holders
Adjustments
to reconcile net (loss) to cash provided by
(used
in) operating activities:
Accounts
receivable
(803,333
)
(141,426
)
Deposits
and prepaid expenses
(202,109
)
(25,780
)
Accounts
payable
1,185,685
144,743
Accrued
liabilities
223,267
(58,251
)
Deferred
payment from Euramerica for development
(251,951
)
-
Cash
provided by (used in) operating activities
351,045
(379,330
)
Cash
flows from investing activities
Purchase
of fixed assets
(58,626
)
(13,841
)
Additions
to oil & gas properties
(948,937
)
(1,586,601
)
Sale
of oil & gas properties
300,000
-
Cash
used in investing activities
(707,563
)
(1,600,442
)
Cash
flows from financing activities
Proceeds
from sales of common stock
-
4,313,757
Notes
payable, net
-
(350,000
)
Borrowings
from long-term debt
523,442
4,033,165
Payments
on long-term debt
(73,567
)
-
Payments
received on notes receivable
-
23,100
Cash
provided by financing activities
449,875
8,020,022
Increase
(decrease) in cash and cash equivalents
93,357
6,040,250
Cash
and cash equivalents, beginning
951,004
99,493
Cash
and cash equivalents, end
$
1,044,361
$
6,139,743
Supplemental
disclosures:
Interest
paid
$
39,073
$
75,935
Income
taxes paid
$
-
$
-
Non-cash
transactions:
Share-based
payments issued for services
$
-
$
2,018,655
Asset
retirement obligation
$
84,400
$
102,000
See
Notes to Consolidated Financial Statements.
3
EnerJex
Resources, Inc.
Notes
to Consolidated Financial Statements
Note
1 – Basis of Presentation
The
unaudited consolidated financial statements have been prepared in accordance
with United States generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q and reflect all
adjustments which, in the opinion of management, are necessary for a fair
presentation. All such adjustments are of a normal recurring
nature. The results of operations for the interim period are not
necessarily indicative of the results to be expected for a full
year. Certain amounts in the prior year statements have been
reclassified to conform to the current year presentations. The
statements should be read in conjunction with the financial statements and
footnotes thereto included in our Form 10-K for the fiscal year ended March 31,2008.
Our
consolidated financial statements include the accounts of our wholly-owned
subsidiaries, EnerJex Kansas, Inc. and DD Energy, Inc. All intercompany
transactions and accounts have been eliminated in consolidation.
Effective
on July 25, 2008, we implemented a one-for-five reverse split of our issued and
outstanding common stock (See Note 7). All share and per share data in these
consolidated financial statements and related notes hereto have been
retroactively adjusted to account for the effect of the reverse stock split for
all periods presented. The reverse split did not affect the
authorized shares and par value per share.
Note
2 – Common Stock
Stock transactions in fiscal
2009:
On
May 15, 2008, we issued 2,182 shares of common stock to a Director and chairman
of our Audit Committee for services over the next year. We recorded director
compensation in the amount of $13,000.
A
summary of stock options and warrants is as follows:
Our
asset retirement obligations relate to the abandonment of oil and natural gas
wells. The amounts recognized are based on numerous estimates and assumptions,
including future retirement costs, inflation rates and credit adjusted risk-free
interest rates. The following shows the changes in asset retirement
obligations:
On
April 11, 2007, we entered into a Securities Purchase Agreement, Registration
Rights Agreements, Senior Secured Debentures, a Pledge and Security Agreement, a
Secured Guaranty, and other related agreements (the “Financing Agreements”) with
the “Buyers” of a new series of senior secured debentures (the “Debentures”).
Under the terms of the Financing Agreements, we agreed to sell Debentures for a
total purchase price of $9.0 million. In connection with the purchase, we agreed
to issue to the Buyers a total of 1,800,000 shares. The first closing occurred
on April 12, 2007 with a total of $6.3 million in Debentures being sold and the
remaining $2.7 million closing on June 21, 2007.
The
Debentures have a three-year term, maturing on March 31, 2010, and bear interest
at a rate equal to 10% per annum. Interest is payable quarterly in arrears on
the first day of each succeeding quarter. We may pay interest in either cash or
registered shares of our common stock. The Debentures have no prepayment penalty
so long as we maintain an effective registration statement with the Securities
Exchange Commission and provided we give six (6) business days prior notice of
redemption to the Buyers.
Effective
July 7, 2008, we redeemed an aggregate principal amount of $6.3 million of the
Debentures and amended the $2.7 million of aggregate principal amount of the
remaining Debentures to, among other things, permit the indebtedness under our
new credit facility, subordinate the security interests of the debentures to the
new credit facility, provide for the redemption of the remaining Debentures with
the net proceeds from our next debt or equity offering and eliminate the
covenant to maintain certain production thresholds (See Note 7).
Pursuant
to the terms of the Registration Rights Agreement, as amended, between us and
one of the Buyers, we are obligated to maintain an effective registration
statement for 1,000,000 of the shares issued under the Financing Agreements. If
we fail to obtain and maintain effectiveness of the registration statement
before October 22, 2008, we will be obligated to pay cash to the Buyer equal to
1.5% of the aggregate purchase price allocable to such Buyer’s securities
($2,500,000) included in the registration statement for each 30 day period
following such effectiveness failure or maintenance failure. These payments are
capped at 10% of the Buyer’s original purchase price under the
Debentures.
5
The
proceeds from the Debentures were allocated to the long-term debt and the stock
issued based on the fair market value of each item that we calculated to be $9.0
million for each item. Since each of the instruments had a value
equal to 50% of the total, we allocated $4.5 million to stock and $4.5 million
to the note. The loan discount costs of $4.5 million will accrete as
interest based on the interest method over the period of issue to
maturity. The amount of interest accreted for the period ended June30, 2008 was $342,826 and for the period ended June 30, 2007 was
$175,766. The remaining amount of interest to accrete in future
periods is $3,067,376 as of June 30, 2008.
We
incurred debt issue costs totaling $466,835. The debt issue costs are
initially recorded as assets and are amortized to expense on a straight-line
basis over the life of the loan. The amount expensed in the three
month period ended June 30, 2008 was $39,298. The remaining debt issue costs
will be expensed in the following fiscal years: March 31, 2009 -$117,893 and
March 31, 2010 -$157,191.
We
obtained a note payable to a bank of $1,735,000 maturing in October 2011 with an
interest rate of 8.5% that is collateralized by some of our oil and gas leases
and assets.
We
financed the purchase of vehicles through a bank. The notes are for
seven years and the weighted average interest is 6.99% per
annum. Vehicles collateralize these notes.
Long-term
debt consists of the following at June 30, 2008:
Long-term
debentures
$
9,000,000
Unaccreted
discount
(3,067,376
)
Total
5,932,624
Note
payable to bank
2,001,116
Vehicle
notes payable
103,664
Total
long-term debt
8,037,404
Less
current portion
517,284
Long-term
debt
$
7,520,120
On
August 3, 2006, we sold a $25,000 convertible note that has an interest rate of
6% and matures August 2, 2010. The note is convertible at any time at
the option of the note holder into shares of our common stock at a conversion
rate of $10.00 per share.
6
Note
5 - Oil and Gas Properties
On
April 9, 2007, we entered into a “Joint Exploration Agreement” with a
shareholder, MorMeg, LLC, whereby we agreed to advance $4.0 million to a joint
operating account for further development of MorMeg’s Black Oaks leaseholds in
exchange for a 95% working interest in the Black Oaks Project. We will maintain
our 95% working interest until payout, at which time the MorMeg 5% carried
working interest will be converted to a 30% working interest and our working
interest becomes 70%. Payout is generally the point in time when the total
cumulative revenue from the project equals all of the project’s development
expenditures and costs associated with funding. We have until November 30, 2008
to contribute additional capital toward the Black Oaks Project development. If
we elect not to contribute further capital to the Black Oaks Project prior to
the project’s full development while it is economically viable to do so, or if
there is more than a thirty day delay in project activities due to lack of
capital, MorMeg has the option to cease further joint development and we will
receive an undivided interest in the Black Oaks Project. The undivided interest
will be the proportionate amount equal to the amount that our investment bears
to our investment plus $2.0 million, with MorMeg receiving an undivided interest
in what remains.
On
April 18, 2007, we entered into a “Purchase and Sale Agreement” with MorMeg to
acquire the lease interests of certain producing properties for cash in the
amount of $400,000.
In
August of 2007, we entered into a development agreement with Euramerica to
further the development and expansion of the Gas City Project, which included
6,600 acres, whereby Euramerica contributed $524,000 in capital toward the
project. Euramerica was granted an option to purchase this project for $1.2
million with a requirement to invest an additional $2.0 million for project
development by August 31, 2008. We are the operator of the project at a cost
plus 17.5% basis. We received $300,000 in the year ended March 31, 2008 (and an
additional $300,000 in the quarter ended June 30, 2008) of the $1.2 million
purchase price. We also received $250,000 of the $2.0 million development funds
in the year ended March 31, 2008 (and an additional $250,000 in the quarter
ended June 30, 2008). We recorded a reduction of $300,000 to our oil & gas
properties using full-cost accounting subject to amortization in the year ended
March 31, 2008 and will further reduce this account when we receive the
remaining $600,000 in proceeds in fiscal 2009. Upon payment of the
entire purchase price, Euramerica will be assigned a 95% working interest, and
we will retain a 5% carried working interest before payout. When the project
reaches payout, our 5% carried working interest will increase to a 25% working
interest, and Euramerica will have a 75% working interest.
On
September 14, 2007, we entered into a purchase agreement for the acquisition of
nearly a 100% working interest in leaseholds located in three counties in
eastern Kansas for a cash purchase price of $800,000.
On
September 27, 2007, we entered into a purchase and sale agreement with
shareholders to acquire oil leases in eastern Kansas for a purchase price of
$2.7 million.
Note
6 - Commitments and Contingencies
On
March 6, 2008, we entered into an agreement with Shell whereby we agreed to an
18-month fixed-price delivery contract with Shell for 130 BOPD at a fixed price
per barrel of $96.90, less transportation costs. This contract is for the
physical delivery of oil under our normal sales. This represented
approximately 60% of our total oil production on a net revenue basis at that
time and represents approximately $6.8 million in gross revenue before the
deduction of transportation costs over the 18-month period. In addition, we
agreed to sell all of our remaining oil production at current spot market
pricing beginning April 1, 2008 through September 30, 2009 to
Shell.
7
Note
7 - Subsequent Events
On
July 2, 2008, we granted 122,000 options to purchase shares of our common
stock to our non-employee directors as compensation for their service as
directors in fiscal 2009. The options are exercisable until July 1, 2011 at
a per share price of $6.25.
On
July 3, 2008, we entered a new three-year $50 million senior secured credit
facility with Texas Capital Bank, N. A. with an initial borrowing base of $10.75
million based on our current proved oil and natural gas reserves. We used
our initial borrowing under this facility of $10.75 million to redeem an
aggregate principal amount of $6.3 million of our 10% debentures, assign
approximately $2.0 million of our existing indebtedness with another bank to
this facility, repay $965,000 of seller-financed notes, pay the transaction
costs, fees and expenses of this new facility and expand our current development
projects, including the completion of 31 new oil wells that have been drilled
since May of 2008.
As
of July 3, 2008, we entered into an ISDA master agreement and a costless collar
with BP Corporation North America Inc. for 130 barrels of oil per day with a
price floor of $132.50 per barrel and a price ceiling of $155.70 per barrel for
NYMEX West Texas Intermediate for the period of October 1, 2009 until March31, 2011.
On
July 7, 2008, we amended the $2.7 million of aggregate principal amount of our
10% debentures that remain outstanding to, among other things, permit the
indebtedness under our new credit facility, subordinate the security interests
of the debentures to the new credit facility, provide for the redemption of the
remaining debentures with the net proceeds from our next debt or equity
offering, eliminate the covenant to maintain certain production
thresholds.
Effective
July 25, 2008, we implemented a one-for-five reverse stock split of our issued
and outstanding common stock. The number of authorized shares of
common stock and preferred stock was not affected and remains at 100,000,000 and
10,000,000, respectively, but the number of shares of common stock outstanding
was reduced from 22,214,166 to 4,443,467. The aggregate par value of
the issued common stock was reduced by reclassifying a portion of the par value
amount of the outstanding common shares from common stock to additional paid-in
capital for all periods presented. In addition, all per share and
share amounts, including stock options and warrants, have been retroactively
restated in the accompanying consolidated financial statements and notes to
consolidated financial statements for all periods presented to reflect the
reverse stock split.
On
August 1, 2008, we entered into an employment agreement with and granted C.
Stephen Cochennet, our chief executive officer, an option to purchase 75,000
shares of our common stock at $6.25 per share. 30,000 of the options vested
immediately and expire on July 31, 2011. The remaining 45,000 options vest based
on the following schedule: 10,000 options shall vest on July 1, 2009; 15,000
options shall vest on July 1, 2010; and 20,000 options shall vest on July 1,2011. The options will be exercisable for a three year term following the
vesting date.
On
August 1, 2008, we entered into an employment agreement with and granted
Dierdre P. Jones, our chief financial officer, an option to purchase
40,000 shares of our common stock at $6.25 per share for a period of three
years expiring on July 22, 2011.
This
report contains forward-looking statements. These forward-looking statements are
subject to a number of risks and uncertainties, many of which are beyond our
control. All statements, other than statements of historical fact, contained in
this report, including statements regarding future events, our future financial
performance, business strategy and plans and objectives of management for future
operations, are forward-looking statements. We have attempted to identify
forward-looking statements by terminology including “anticipates,”“believes,”“can,”“continue,”“could,”“estimates,”“expects,”“intends,”“may,”“plans,”“potential,”“predicts,”“should” or “will” or the negative of these terms or
other comparable terminology. Although we do not make forward-looking statements
unless we believe we have a reasonable basis for doing so, we cannot guarantee
their accuracy. These statements are only predictions and involve known and
unknown risks, uncertainties and other factors, including the risks outlined
under “Risk Factors” or elsewhere in this report, which may cause our or our
industry’s actual results, levels of activity, performance or achievements to be
materially different from any future results, levels of activity, performance or
achievements expressed or implied by these forward-looking statements. Moreover,
we operate in a very competitive and rapidly changing environment. New risks
emerge from time to time and it is not possible for us to predict all risk
factors, nor can we address the impact of all factors on our business or the
extent to which any factor, or combination of factors, may cause our actual
results to differ materially from those contained in any forward-looking
statements. The factors impacting these risks and uncertainties include, but are
not limited to:
·
estimated
quantities and quality of oil and natural gas
reserves;
·
fluctuations
in the price of oil and natural
gas;
·
inability
to efficiently manage our
operations;
·
the
inability of management to effectively implement our strategies and
business plans;
·
potential
default under our secured obligations or material debt
agreements;
·
approval
of certain parts of our operations by state
regulators;
·
inability
to hire or retain sufficient qualified operating field
personnel;
·
inability
to attract and obtain additional development
capital;
·
increases
in interest rates or our cost of
borrowing;
·
deterioration
in general or regional (especially Eastern Kansas) economic
conditions;
·
adverse
state or federal legislation or regulation that increases the costs of
compliance, or adverse findings by a regulator with respect to existing
operations;
·
the
occurrence of natural disasters, unforeseen weather conditions, or other
events or circumstances that could impact our operations or could impact
the operations of companies or contractors we depend upon in our
operations;
·
inability
to acquire mineral leases at a favorable economic value that will allow us
to expand our development efforts;
·
inability
to achieve future sales levels or other operating
results;
·
adverse
state or federal legislation or regulation that increases the costs of
compliance, or adverse findings by a regulator with respect to existing
operations; and
·
changes
in U.S. GAAP or in the legal, regulatory and legislative environments in
the markets in which we operate.
9
You
should not place undue reliance on any forward-looking statement, each of which
applies only as of the date of this report. Except as required by law, we
undertake no obligation to update or revise publicly any of the forward-looking
statements after the date of this report to conform our statements to actual
results or changed expectations. For a detailed description of these and other
factors that could cause actual results to differ materially from those
expressed in any forward-looking statement, please see “Risk Factors” in this
document and in our Annual Report on Form 10-K for the year ended March 31,2008.
All references in this report to “we,”“us,”“our,”“company” and “EnerJex” refer to EnerJex Resources, Inc. and our
wholly-owned operating subsidiaries, EnerJex Kansas, Inc. and DD Energy, Inc.,
unless the context requires otherwise. We report our financial information on
the basis of a March 31 fiscal year end.
Item
2. Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
The
following discussion of our financial condition and results of operations should
be read in conjunction with our financial statements and the related notes to
our financial statements included elsewhere in this report. In addition to
historical financial information, the following discussion and analysis contains
forward-looking statements that involve risks, uncertainties and assumptions.
Our actual results and timing of selected events may differ materially from
those anticipated in these forward-looking statements as a result of many
factors, including those discussed under ITEM 1A. Risk Factors and elsewhere in
this report.
Overview
Our
principal strategy is to focus on the acquisition of oil and natural gas mineral
leases that have existing production and cash flow. Once acquired, we implement
an accelerated development program utilizing capital resources, a regional
operating focus, an experienced management and technical team, and enhanced
recovery technologies to attempt to increase production and increase returns for
our stockholders. Our oil and natural gas acquisition and development activities
are currently focused in Eastern Kansas.
During
fiscal 2008 and the first quarter of fiscal 2009, we deployed approximately
$10.8 million in capital resources to acquire and develop five operating
projects and drill 132 new wells (90 producing wells and 42 water injection
wells). As of June 30, 2008, our production was 271
BOPD.
We
have several other projects that are in various stages of discussions, and we
are continually evaluating oil and natural gas opportunities in Eastern Kansas.
We plan to continue to bring multiple potential acquisitions to various
financial partners for evaluation and funding options. It is our vision to grow
the business in a disciplined and well-planned manner.
10
In
addition to raising additional capital, we may take on working interest
participants that will contribute to the capital costs of drilling and
completion and then share in revenues derived from production. This economic
strategy will allow us to utilize our own financial assets toward the growth of
our leased acreage holdings, pursue the acquisition of strategic oil and natural
gas producing properties or companies and generally expand our existing
operations while further diversifying risk.
We
began generating revenues from the sale of oil during the fiscal year ended
March 31, 2008. We expect our production to continue to increase, both through
development of wells and through our acquisition strategy. Our future financial
results will continue to depend on: (i) our ability to source and screen
potential projects; (ii) our ability to discover commercial quantities of
natural gas and oil; (iii) the market price for oil and natural gas; and (iv)
our ability to fully implement our exploration, workover and development
program, which is in part dependent on the availability of capital resources.
There can be no assurance that we will be successful in any of these respects,
that the prices of oil and natural gas prevailing at the time of production will
be at a level allowing for profitable production, or that we will be able to
obtain additional funding at terms favorable to us to increase our currently
limited capital resources. The board of directors has implemented a crude oil
and natural gas hedging strategy that will allow management to hedge up to 80%
of our net production to mitigate a majority of our exposure to changing oil
prices in the intermediate term.
Recent
Developments
In June of 2008, we received our second
payment of $300,000 from Euramerica related to its option exercise for the Gas
City Project. To date, Euramerica has paid $600,000 of the $1.2 million purchase
price and $500,000 of the $2.0 million development funds. Upon payment of the
entire purchase price, Euramerica will be assigned a 95% working interest, and
we will retain a 5% carried working interest before payout. When the project
reaches payout, our 5% carried working interest will increase to a 25% working
interest and Euramerica will have a 75% working interest.
On
July 3, 2008, we entered into a new three-year $50 million senior secured credit
facility with Texas Capital Bank, N. A. with an initial borrowing base of $10.75
million based on our current proved oil and natural gas reserves. We used
our initial borrowing under this facility of $10.75 million to redeem an
aggregate principal amount of $6.3 million of our 10% debentures, assign
approximately $2.0 million of our existing indebtedness with another bank to
this facility, repay $965,000 of seller-financed notes, pay the transaction
costs, fees and expenses of this new facility and expand our current development
projects, including the completion of 31 new oil wells that have been drilled
since May of 2008.
As
of July 3, 2008, we entered into an ISDA master agreement and a costless collar
with BP Corporation North America Inc., or BP, for 130 barrels of oil per day
with a price floor of $132.50 per barrel and a price ceiling of $155.70 per
barrel for NYMEX West Texas Intermediate for the period of October 1, 2009
until March 31, 2011.
11
On
July 7, 2008, we amended the $2.7 million of aggregate principal amount of our
10% debentures that remain outstanding to, among other things, permit the
indebtedness under our new credit facility, subordinate the security interests
of the debentures to the new credit facility, provide for the redemption of the
remaining debentures with the net proceeds from our next debt or equity offering
and eliminate the covenant to maintain certain production
thresholds.
On
August 1, 2008, we executed three-year employment agreements with C. Stephen
Cochennet, our chief executive officer, and Dierdre P. Jones, our chief
financial officer. Copies of the employment agreements were filed as Exhibits to
our Form 8-K filed on August 1, 2008.
Results
of Operations for the Three Months Ended June 30, 2008 and 2007
compared.
During
the three months ended June 30, 2007, we were in the early stage of developing
properties in Kansas and begun minimal production or revenues from our
properties. Our operations as of June 30, 2007 were limited to technical
evaluation of these properties, the design of development plans to exploit the
oil and natural gas resources on those properties, as well as seeking financing
opportunities to acquire additional oil and natural gas properties. Therefore
comparisons between the three months ended June 30, 2008 to the three months
ended June 30, 2007 are not indicative of our future results of
operations.
Oil
and natural gas revenues for the three months ended June 30, 2008 were
$1,690,086 compared to revenues of $146,203 in the three months ended June 30,2007. The increase in revenues is primarily the result of the sale of oil from
leases acquired beginning in April of 2007 and developed thereafter. The average
price per barrel of oil sold net of transformation costs, during the three
months ended June 30, 2008 was $100.51 compared to $58.77 during the three
months ended June 30, 2007. The average price per Mcf for natural gas
sales during the three months ended June 30, 2008 was $8.61, compared to $6.00
during the three months ended June 30, 2007.
Direct
operating costs for the three months ended June 30, 2008 were $714,534 compared
to $59,042 for the three months ended June 30, 2007. The increase over the prior
period reflects the operating costs on the oil leases acquired during the period
beginning in April 2007. Direct costs include pumping, gauging, pulling, certain
contract labor costs, and other non-capitalized expenses.
Depreciation, Depletion and
Amortization
Depreciation,
depletion and amortization for the three months ended June 30, 2008 was
$370,190, compared to $14,245 for the three months ended June 30, 2007. The
increase was primarily a result of the depletion of oil reserves commensurate
with our increase in production.
Professional
Fees
Professional
fees for the three months ended June 30, 2008 were $143,678 compared to $874,505
for the three months ended June 30, 2007. The decrease in professional fees was
largely the result of $773,659 in non-cash equity-based payments made by issuing
stock options to directors and an outside consultant in the prior year. No such
payments were made in the current period.
Salaries
Salaries
for the three months ended June 30, 2008 were $217,487 compared to $1,122,190
for the three months ended June 30, 2007. Non-cash equity-based payments made by
issuing stock options to our management in the prior year were $1,028,262 as
compared to $43,551 in the current period, resulting in a
decrease.
Administrative Expense
Administrative
expense for the three months ended June 30, 2008 was $219,487, compared to
$129,937 in the three months ended June 30, 2007. The administrative expense
increased as a result of the addition of employees, office space, and corporate
activity related to growth in operations.
13
Interest
Expense
Interest
expense for the three months ended June 30, 2008 was $274,386 as compared to
$69,742 for the three months ended June 30, 2007 and was primarily related to
our debentures. Interest income of $46,021 in the period ended June30, 2007 offset the interest expense in that same period as the income was
earned on proceeds from debentures. We had minimal interest income
for the period ended June 30, 2008.
Loan Costs
Loan
costs for the three months ended June 30, 2008 were $382,124 as compared to
$2,336,597 for the three months ended June 30, 2007. In the prior period,
we recorded $2,126,271 in loan penalty expense, which was directly attributable
to the accretion of the potential expense related to the issuance of threshold
shares under our $9.0 million debenture financing. The loan penalty
expense was reversed in a subsequent quarter based on our determination that
production levels were sufficient to meet required threshold levels. We also had
loan fee expense of $39,298 and $34,560, and loan interest accretion of $342,826
and $175,766, respectively, for the periods ending June 30, 2008 and 2007, all
related to our debentures. The amount of interest accreted is based on the
interest method over the period of issue to maturity.
Liquidity
and Capital Resources
Liquidity
is a measure of a company’s ability to meet potential cash requirements. We have
historically met our capital requirements through debt financing, revenues from
operations and the issuance of equity securities. In the future, we anticipate
we will be able to provide some of the necessary liquidity we need by the
revenues generated from our net interests in our oil and natural gas production,
and sales of reserves in our existing properties, however, if we do not generate
sufficient sales revenues we will continue to finance our operations through
equity and/or debt financings.
We
actively manage our exposure to commodity price fluctuations by executing
derivative transactions to hedge the change in prices of our production, thereby
mitigating our exposure to price declines, but these transactions will also
limit our earnings potential in periods of rising commodity prices. There also
is a risk that we will be required to post collateral to secure our hedging
activities and this could limit our available funds for our business
activities.
We
have utilized a costless collar with BP beginning October 1, 2009 through March31, 2011 to set minimum and maximum prices on a financially settled collar on a
set number of barrels of oil per day. We have also utilized a price swap
contract with Shell for a portion of our production, and agreed to sell Shell
the remainder of our current oil production at current spot market pricing,
beginning April 1, 2008 through September of 2009. The key risks associated with
these contracts are summarized in “Item 1A. Risk Factors”.
The following table summarizes total current assets, total current
liabilities and working capital at June 30, 2008 as compared to June 30,2007.
On
July 3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a three-year
$50 million senior secured revolving credit facility (the “Credit Facility”)
with Texas Capital Bank, N.A. Borrowings under the Credit Facility
will be subject to a borrowing base limitation based on the Company’s current
proved oil and gas reserves. The initial borrowing base is set at $10.75 million
and will be subject to semi-annual redeterminations, with the first
redetermination to be October 1, 2008. The Credit Facility will be secured by a
lien on substantially all assets of the Company and its subsidiaries. The Credit
Facility has a term of three years, and all principal amounts, together with all
accrued and unpaid interest, will be due and payable in full on July 3,2011. The Credit Facility also provides for the issuance of
letters-of-credit up to a $750,000 sub-limit under the borrowing base and up to
an additional $2.25 million limit not subject to the borrowing base to support
the Company’s hedging program. Borrowings under the Credit Facility of $10.75
million were made on July 7, 2008.
Proceeds
from the initial extension of credit under the Credit Facility were used: (1) to
redeem our 10% debentures in an aggregate principal amount of $6.3 million plus
accrued interest (the “April Debentures”), (2) for Texas Capital Bank’s
acquisition of the Company’s approximately $2.0 million indebtedness to
Cornerstone Bank, (3) for complete repayment of promissory notes issued to the
sellers in connection with the Company’s purchase of the DD Energy project in an
aggregate principal amount of $965,000 plus accrued interest, (4) to pay
transaction costs, fees and expenses related to the new facility, and (5) to
expand our current development projects, including the completion of 31 new oil
wells that have been drilled since May of 2008. Future borrowings may
be used for the acquisition, development and exploration of oil and gas
properties, capital expenditures and general corporate purposes.
Advances
under the Credit Facility will be in the form of either base rate loans or
Eurodollar loans. The interest rate on the base rate loans fluctuates based upon
the higher of (1) the lender’s “prime rate” and (2) the Federal Funds rate plus
0.50%, plus, in either case, a margin of between 0.0% and 0.5% depending on the
percent of the borrowing base utilized at the time of the credit extension. The
interest rate on the Eurodollar loans fluctuates based upon the applicable Libor
rate, plus a margin of 2.25% to 2.75% depending on the percent of the borrowing
base utilized at the time of the credit extensionon. Eurodollar loans of one,
two, three and six months may be selected by the Company. A commitment fee of
0.375% on the unused portion of the borrowing base will accrue, and be payable
quarterly in arrears.
15
The
Credit Facility includes usual and customary affirmative covenants for credit
facilities of this type and size, as well as customary negative covenants,
including, among others, limitations on liens, mergers, asset sales or
dispositions, payments of dividends, incurrence of additional indebtedness, and
investments. The Credit Facility also requires the Company, at the end of each
fiscal quarter beginning with the quarter ending September 30, 2008, to maintain
a minimum current assets to current liabilities ratio and a minimum ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
interest expense and at the end of each fiscal quarter beginning with the
quarter ended June 30, 2008 to maintain a minimum ratio of EBITDA to senior
funded debt.
Additionally,
Texas Capital Bank, N.A. and the holders of the debentures entered into a
Subordination Agreement whereby the debentures issued on June 21, 2007 will be
subordinated to the Credit Facility.
Debenture
Financing.
On
April 11, 2007, we completed a $9.0 million private placement of senior secured
debentures. In accordance with the terms of the debentures, we received $6.3
million (before expenses and placement fees) at the first closing and an
additional $2.7 million (before closing fees and expenses) at the second closing
on June 21, 2007. In connection with the sale of the debentures, we issued the
lenders 1,800,000 shares of common stock. On July 7, 2008, we redeemed $6.3
million aggregate principal amount of our debentures.
The
debentures mature on March 31, 2010, absent earlier redemption by us, and carry
an interest rate of 10%. Interest on the debentures began accruing on April 11,2007 and is payable quarterly in arrears on the first day of each succeeding
quarter during the term of the debentures, beginning on or about May 11, 2007
and ending on the maturity date of March 31, 2010. We may, under certain
conditions specified in the debentures, pay interest payments in shares of our
registered common stock. Additionally, on the maturity date, we are required to
pay the amount equal to the principal, as well as all accrued but unpaid
interest.
In
connection with the Credit Facility, we entered into an agreement amending the
Securities Purchase Agreement, Registration Rights Agreement, the Pledge and
Security Agreement and the Senior Secured Debentures issued on June 21, 2007
(the “Debenture Agreements”), with the holders (the “Buyers”) of the debentures
issued on June 21, 2007 (the “June Debentures”). Pursuant to this agreement, we,
among other things, (i) redeemed the April Debentures, (ii) agreed to use the
net proceeds from the Company’s next debt or equity offering to redeem the June
Debentures, (iii) agreed to update the registration statement to sell our common
stock owned by one of the Buyers, (iv) amended certain terms of the Debenture
Agreements in recognition of the indebtedness under the new Credit Facility, and
(v) amended the Securities Purchase Agreement and Registration Rights Agreement
to remove the covenant to issue and register additional shares of common stock
in the event that our oil production does not meet certain thresholds over
time.
16
Satisfaction
of our cash obligations for the next 12 months.
A
critical component of our operating plan is the ability to obtain additional
capital through additional equity and/or debt financing and working interest
participants. While our operations are generating sufficient cash revenues to
meet our monthly expenses, we still have negative working capital. In the event
we cannot obtain additional capital to pursue our strategic plan, however, this
would materially impact our ability to continue our aggressive growth. However,
there is no assurance we would be able to obtain such financing on commercially
reasonable terms, if at all.
We
intend to implement and successfully execute our business and marketing
strategy, continue to develop and upgrade technology and products, respond to
competitive developments, and attract, retain and motivate qualified personnel.
There can be no assurance that we will be successful in addressing such risks,
and the failure to do so can have a material adverse effect on our business
prospects, financial condition and results of operations.
Summary of product research and
development.
We
do not anticipate performing any significant product research and development
until such time as we can raise adequate working capital to sustain our
operations.
Expected purchase or sale of any
significant equipment.
We
anticipate that we will purchase the necessary production and field service
equipment required to produce oil and natural gas during our normal course of
operations over the next twelve months. We estimate this amount to be
approximately $3.0 million.
Significant changes in the number of
employees.
As
of June 30, 2008, we had 19 full time employees, an increase from 9 full time
employees at our fiscal year ended March 31, 2008. We hired a number
of former independent field contractors to help secure a more stable work base.
We have not experienced a material increase in expenses from this initiative, as
most of these individuals were already included in our current operating and
capital expenses as independent contractors. As drilling and
production activities increase, we intend to hire additional technical,
operational and administrative personnel as appropriate. We are using and will
continue to use the services of independent consultants and contractors to
perform various professional services, particularly in the area of land
services, reservoir engineering, drilling, water hauling, pipeline construction,
well design, well-site monitoring and surveillance, permitting and environmental
assessment. We believe that this use of third-party service providers may
enhance our ability to contain general and administrative expenses.
Off-Balance Sheet
Arrangements
We
do not have any off-balance sheet arrangements that have or are reasonably
likely to have a current or future effect on our financial condition, changes in
financial condition, revenues or expenses, results of operations, liquidity,
capital expenditures or capital resources that is material to
investors.
17
Critical
Accounting Policies and Estimates
Our
critical accounting estimates include our oil and gas properties, asset
retirement obligations and the value of share-based payments.
Oil and Gas
Properties:
The
accounting for our business is subject to special accounting rules that are
unique to the gas and oil industry. There are two allowable methods of
accounting for oil and gas business activities: the successful efforts method
and the full-cost method. We follow the full-cost method of accounting under
which all costs associated with property acquisition, exploration and
development activities are capitalized. We also capitalize internal costs that
can be directly identified with our acquisition, exploration and development
activities and do not include any costs related to production, general corporate
overhead or similar activities.
Under
the full-cost method, capitalized costs are amortized on a composite
unit-of-production method based on proved gas and oil reserves. Depreciation,
depletion and amortization expense is also based on the amount of estimated
reserves. If we maintain the same level of production year over year, the
depreciation, depletion and amortization expense may be significantly different
if our estimate of remaining reserves changes significantly. Proceeds from the
sale of properties are accounted for as reductions of capitalized costs unless
such sales involve a significant change in the relationship between costs and
the value of proved reserves or the underlying value of unproved properties, in
which case a gain or loss is recognized. The costs of unproved properties are
excluded from amortization until the properties are evaluated. We review all of
our unevaluated properties quarterly to determine whether or not and to what
extent proved reserves have been assigned to the properties, and otherwise if
impairment has occurred. Unevaluated properties are assessed individually when
individual costs are significant.
We
review the carrying value of our gas and oil properties under the full-cost
accounting rules of the SEC on a quarterly basis. This quarterly review is
referred to as a ceiling test. Under the ceiling test, capitalized costs, less
accumulated amortization and related deferred income taxes, may not exceed an
amount equal to the sum of the present value of estimated future net revenues
(adjusted for cash flow hedges) less estimated future expenditures to be
incurred in developing and producing the proved reserves, less any related
income tax effects. In calculating future net revenues, current prices and costs
used are those as of the end of the appropriate quarterly period. Such prices
are utilized except where different prices are fixed and determinable from
applicable contracts for the remaining term of those contracts, including the
effects of derivatives qualifying as cash flow hedges. Two primary factors
impacting this test are reserve levels and current prices, and their associated
impact on the present value of estimated future net revenues. Revisions to
estimates of gas and oil reserves and/or an increase or decrease in prices can
have a material impact on the present value of estimated future net revenues.
Any excess of the net book value, less deferred income taxes, is generally
written off as an expense. Under SEC regulations, the excess above the ceiling
is not expensed (or is reduced) if, subsequent to the end of the period, but
prior to the release of the financial statements, gas and oil prices increase
sufficiently such that an excess above the ceiling would have been eliminated
(or reduced) if the increased prices were used in the calculations.
18
The
process of estimating gas and oil reserves is very complex, requiring
significant decisions in the evaluation of available geological, geophysical,
engineering and economic data. The data for a given property may also change
substantially over time as a result of numerous factors, including additional
development activity, evolving production history and a continual reassessment
of the viability of production under changing economic conditions. As a result,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the subjective
decisions and variances in available data for various properties increase the
likelihood of significant changes in these estimates.
Approximately
100% of our proved reserves were evaluated by an independent petroleum engineer
as of our fiscal year ended March 31, 2008. All reserve estimates are prepared
based upon a review of production histories and other geologic, economic,
ownership and engineering data.
Asset
Retirement Obligations:
The
asset retirement obligation relates to the plug and abandonment costs when our
wells are no longer useful. We determine the value of the liability by obtaining
quotes for this service and estimate the increase we will face in the future. We
then discount the future value based on an intrinsic interest rate that is
appropriate for us. If costs rise more than what we have expected there could be
additional charges in the future, however, we monitor the costs of the abandoned
wells and we will adjust this liability if necessary.
Share-Based
Payments:
The
value we assign to the options and warrants that we issue is based on the fair
market value as calculated by the Black-Scholes pricing model. To perform a
calculation of the value of our options and warrants, we determine an estimate
of the volatility of our stock. We need to estimate volatility
because there has not been enough trading of our stock to determine an
appropriate measure of volatility. We believe our estimate of volatility is
reasonable, and we review the assumptions used to determine this whenever we
issue a new equity instruments. If we have a material error in our
estimate of the volatility of our stock, our expenses could be understated or
overstated.
Recent
Accounting Pronouncements
In March of 2008, the FASB issued SFAS
No. 161 (“FAS 161”)., “Disclosures about Derivative Instruments and Hedging
Activities” FAS 161 is intended to improve financial reporting about derivative
instruments and hedging activities by requiring enhanced disclosures to enable
investors to better understand their effects on the entity’s financial position,
financial performance, and cash flows. The provisions of FAS 161 are effective
for fiscal years and interim periods beginning after November 15, 2008. We are
currently evaluating the impact of the provisions of FAS 161.
19
Effects
of Inflation and Pricing
The
oil and natural gas industry is very cyclical and the demand for goods and
services of oil field companies, suppliers and others associated with the
industry puts extreme pressure on the economic stability and pricing structure
within the industry. Material changes in prices impact revenue stream, estimates
of future reserves, borrowing base calculations of bank loans and value of
properties in purchase and sale transactions. Material changes in prices can
impact the value of oil and natural gas companies and their ability to raise
capital, borrow money and retain personnel. We anticipate the increased business
costs will continue while the commodity prices for oil and natural gas, and the
demand for services related to production and exploration, both remain high
(from a historical context) in the near term.
Item
3. Quantitative
and Qualitative Disclosures about Market Risk.
Not
applicable.
Item
4T. Controls and Procedures.
Our
Chief Executive Officer, C. Stephen Cochennet, and Chief Financial Officer,
Dierdre P. Jones, evaluated the effectiveness of our disclosure controls and
procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of
1934, as amended) as of the end of the period covered by this
Report. Based on the evaluation, Mr. Cochennet and Ms. Jones
concluded that our disclosure controls and procedures are effective in timely
alerting them to material information relating to us (including our consolidated
subsidiaries) required to be included in our periodic SEC filings.
There
were no changes in our internal control over financial reporting that occurred
during our most recent fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
PART
II--OTHER INFORMATION
Item
1. Legal Proceedings.
We
may become involved in various routine legal proceedings incidental to our
business. However, to our knowledge as of the date of this report, there are no
material pending legal proceedings to which we are a party or to which any of
our property is subject.
20
Item
1A. Risk Factors.
Risks Associated with Our
Business
We have sustained
losses, which raises doubt as to our ability to successfully develop profitable
business operations.
Our
prospects must be considered in light of the risks, expenses and difficulties
frequently encountered in establishing and maintaining a business in the oil and
natural gas industries. There is nothing conclusive at this time on which to
base an assumption that our business operations will prove to be successful or
that we will be able to operate profitably. Our future operating results will
depend on many factors, including:
·
the
future prices of natural gas and
oil;
·
our
ability to raise adequate working
capital;
·
success
of our development and exploration
efforts;
·
demand
for natural gas and oil;
·
the
level of our competition;
·
our
ability to attract and maintain key management, employees and
operators;
·
transportation
and processing fees on our
facilities;
·
fuel
conservation measures;
·
alternate
fuel requirements;
·
government
regulation and taxation;
·
technical
advances in fuel economy and energy generation devices;
and
·
our
ability to efficiently explore, develop and produce sufficient quantities
of marketable natural gas or oil in a highly competitive and speculative
environment while maintaining quality and controlling
costs.
To
achieve profitable operations, we must, alone or with others, successfully
execute on the factors stated above, along with continually developing ways to
enhance our production efforts. Despite our best efforts, we may not be
successful in our development efforts or obtain required regulatory approvals.
There is a possibility that some of our wells may never produce natural gas or
oil in sustainable or economic quantities.
Natural gas and
oil prices are volatile. This volatility may occur in the future, causing
negative change in cash flows which may result in our inability to cover our
operating or capital expenditures.
Our
future revenues, profitability, future growth and the carrying value of our
properties is anticipated to depend substantially on the prices we may realize
for our natural gas and oil production. Our realized prices may also affect the
amount of cash flow available for operating or capital expenditures and our
ability to borrow and raise additional capital.
21
Natural
gas and oil prices are subject to wide fluctuations in response to relatively
minor changes in or perceptions regarding supply and demand. Historically, the
markets for natural gas and oil have been volatile, and they are likely to
continue to be volatile in the future. Among the factors that can cause this
volatility are:
·
worldwide
or regional demand for energy, which is affected by economic
conditions;
·
the
domestic and foreign supply of natural gas and
oil;
·
weather
conditions;
·
natural
disasters;
·
acts
of terrorism;
·
domestic
and foreign governmental regulations and
taxation;
·
political
and economic conditions in oil and natural gas producing countries,
including those in the Middle East and South
America;
·
impact
of the U.S. dollar exchange rates on oil and natural gas
prices;
·
the
availability of refining capacity;
·
actions
of the Organization of Petroleum Exporting Countries, or OPEC, and other
state controlled oil companies relating to oil price and production
controls; and
·
the
price and availability of other
fuels.
It is impossible to predict natural gas
and oil price movements with certainty. Lower natural gas and oil prices may not
only decrease our future revenues on a per unit basis but also may reduce the
amount of natural gas and oil that we can produce economically. A substantial or
extended decline in natural gas and oil prices may materially and adversely
affect our future business enough to force us to cease our business operations.
In addition, our reserves, financial condition, results of operations, liquidity
and ability to finance and execute planned capital expenditures will also suffer
in such a price decline. Further, natural gas and oil prices do not necessarily
move together.
Approximately
54%
of our total proved reserves as of March 31, 2008 consist of undeveloped and
developed non-producing reserves, and those reserves may not ultimately be
developed or produced.
As
of March 31, 2008, approximately 36% of our total proved reserves were
undeveloped and approximately 18% were developed non-producing. We plan to
develop and produce all of our proved reserves, but ultimately some of these
reserves may not be developed or produced. Furthermore, not all of our
undeveloped or developed non-producing reserves may be ultimately produced in
the time periods we have planned, at the costs we have budgeted, or at
all.
Because we face
uncertainties in estimating proven recoverable reserves, you should not place
undue reliance on such reserve information.
Our
reserve estimates and the future net cash flows attributable to those reserves
are prepared by McCune Engineering, our independent petroleum and geological
engineer. There are numerous uncertainties inherent in estimating quantities of
proved reserves and cash flows from such reserves, including factors beyond our
control and the control of McCune Engineering. Reserve engineering is a
subjective process of estimating underground accumulations of natural gas and
oil that can be economically extracted, which cannot be measured in an exact
manner. The accuracy of an estimate of quantities of reserves, or of cash flows
attributable to these reserves, is a function of the available data, assumptions
regarding future natural gas and oil prices, expenditures for future development
and exploitation activities, and engineering and geological interpretation and
judgment. Reserves and future cash flows may also be subject to material
downward or upward revisions based upon production history, development and
exploitation activities and natural gas and oil prices. Actual future
production, revenue, taxes, development expenditures, operating expenses,
quantities of recoverable reserves and value of cash flows from those reserves
may vary significantly from the assumptions and estimates in our reserve
reports. Any significant variance from these assumptions to actual figures could
greatly affect our estimates of reserves, the economically recoverable
quantities of natural gas and oil attributable to any particular group of
properties, the classification of reserves based on risk of recovery, and
estimates of the future net cash flows. In addition, reserve engineers may make
different estimates of reserves and cash flows based on the same available data.
The estimated quantities of proved reserves and the discounted present value of
future net cash flows attributable to those reserves included in this report
were prepared by McCune Engineering in accordance with rules of the Securities
and Exchange Commission, or SEC, and are not intended to represent the fair
market value of such reserves.
22
The
present value of future net cash flows from our proved reserves is not
necessarily the same as the current market value of our estimated reserves. We
base the estimated discounted future net cash flows from our proved reserves on
prices and costs. However, actual future net cash flows from our natural gas and
oil properties also will be affected by factors such as:
·
Geological
conditions;
·
Assumptions
governing future oil and natural gas
prices;
·
Amount
and timing of actual production;
·
Availability
of funds;
·
Future
operating and development costs;
·
Actual
prices we receive for natural gas and
oil;
·
Supply
and demand for our natural gas and
oil;
·
Changes
in government regulations and taxation;
and
·
Capital
costs of drilling new wells.
The
timing of both our production and our incurrence of expenses in connection with
the development and production of our properties will affect the timing of
actual future net cash flows from proved reserves, and thus their actual present
value. In addition, the 10% discount factor we use when calculating discounted
future net cash flows may not be the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with our
business or the natural gas and oil industry in general.
The
SEC permits natural gas and oil companies, in their public filings, to disclose
only proved reserves that a company has demonstrated by actual production or
conclusive formation tests to be economically and legally producible under
existing economic and operating conditions. The SEC’s guidelines strictly
prohibit us from including “probable reserves” and “possible reserves” in such
filings. We also caution you that the SEC views such “probable” and “possible”
reserve estimates as inherently unreliable and these estimates may be seen as
misleading to investors unless the reader is an expert in the natural gas and
oil industry. Unless you have such expertise, you should not place undue
reliance on these estimates. Potential investors should also be aware that such
“probable” and “possible” reserve estimates will not be contained in any
“resale” or other registration statement filed by us that offers or sells shares
on behalf of purchasers of our common stock and may have an impact on the
valuation of the resale of the shares. Except as required by applicable law, we
undertake no duty to update this information and do not intend to update this
information.
23
The differential
between the New York Mercantile Exchange, or NYMEX, or other benchmark price of
oil and natural gas and the wellhead price we receive could have a material
adverse effect on our results of operations, financial condition and cash
flows.
The
prices that we receive for our oil and natural gas production sometimes trade at
a discount to the relevant benchmark prices, such as NYMEX, that are used for
calculating hedge positions. The difference between the benchmark price and the
price we receive is called a differential. We cannot accurately predict oil and
natural gas differentials. In recent years for example, production increases
from competing Canadian and Rocky Mountain producers, in conjunction with
limited refining and pipeline capacity from the Rocky Mountain area, have
gradually widened this differential. Increases in the differential between the
benchmark price for oil and natural gas and the wellhead price we receive could
have a material adverse effect on our results of operations, financial condition
and cash flows by decreasing the proceeds we receive for our oil and natural gas
production in comparison to what we would receive if not for the
differential.
The natural gas
and oil business involves numerous uncertainties and operating risks that can
prevent us from realizing profits and can cause substantial
losses.
Our
development, exploitation and exploration activities may be unsuccessful for
many reasons, including weather, cost overruns, equipment shortages and
mechanical difficulties. Moreover, the successful drilling of a natural gas and
oil well does not ensure a profit on investment. A variety of factors, both
geological and market-related, can cause a well to become uneconomical or only
marginally economical. In addition to their cost, unsuccessful wells can hurt
our efforts to replace reserves.
The
natural gas and oil business involves a variety of operating risks,
including:
·
unexpected
operational events and/or
conditions;
·
unusual
or unexpected geological
formations;
·
reductions
in natural gas and oil prices;
·
limitations
in the market for oil and natural
gas;
·
adverse
weather conditions;
·
facility
or equipment malfunctions;
·
title
problems;
·
natural
gas and oil quality issues;
·
pipe,
casing, cement or pipeline
failures;
·
natural
disasters;
·
fires,
explosions, blowouts, surface cratering, pollution and other risks or
accidents;
·
environmental
hazards, such as natural gas leaks, oil spills, pipeline ruptures and
discharges of toxic gases;
·
compliance
with environmental and other governmental requirements;
and
·
uncontrollable
flows of oil, natural gas or well
fluids.
24
If
we experience any of these problems, it could affect well bores, gathering
systems and processing facilities, which could adversely affect our ability to
conduct operations. We could also incur substantial losses as a result
of:
·
injury
or loss of life;
·
severe
damage to and destruction of property, natural resources and
equipment;
·
pollution
and other environmental damage;
·
clean-up
responsibilities;
·
regulatory
investigation and penalties;
·
suspension
of our operations; and
·
repairs
to resume operations.
Because
we use third-party drilling contractors to drill our wells, we may not realize
the full benefit of worker compensation laws in dealing with their employees.
Our insurance does not protect us against all operational risks. We do not carry
business interruption insurance at levels that would provide enough funds for us
to continue operating without access to other funds. For some risks, we may not
obtain insurance if we believe the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks
generally are not fully insurable. If a significant accident or other event
occurs and is not fully covered by insurance, it could impact our operations
enough to force us to cease our operations.
Drilling wells is
speculative, often involving significant costs that may be more than our
estimates, and may not result in any addition to our production or reserves. Any
material inaccuracies in drilling costs, estimates or underlying assumptions
will materially affect our business.
Developing
and exploring for natural gas and oil involves a high degree of operational and
financial risk, which precludes definitive statements as to the time required
and costs involved in reaching certain objectives. The budgeted costs of
drilling, completing and operating wells are often exceeded and can increase
significantly when drilling costs rise due to a tightening in the supply of
various types of oilfield equipment and related services. Drilling may be
unsuccessful for many reasons, including geological conditions, weather, cost
overruns, equipment shortages and mechanical difficulties. Moreover, the
successful drilling of a natural gas or oil well does not ensure a profit on
investment. Exploratory wells bear a much greater risk of loss than development
wells. However, approximately 83% of our wells drilled through June 30, 2008
have been development wells. A variety of factors, both geological and
market-related, can cause a well to become uneconomical or only marginally
economic. Our initial drilling and development sites, and any potential
additional sites that may be developed, require significant additional
exploration and development, regulatory approval and commitments of resources
prior to commercial development. If our actual drilling and development costs
are significantly more than our estimated costs, we may not be able to continue
our business operations as proposed and would be forced to modify our plan of
operation.
25
Development
of our reserves, when established, may not occur as scheduled and the actual
results may not be as anticipated. Drilling activity and access to capital may
result in downward adjustments in reserves or higher than anticipated costs. Our
estimates will be based on various assumptions, including assumptions over which
we have control and assumptions required by the SEC relating to natural gas and
oil prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. We have control over our operations that affect, among
other things, acquisitions and dispositions of properties, availability of
funds, use of applicable technologies, hydrocarbon recovery efficiency, drainage
volume and production decline rates that are part of these estimates and
assumptions and any variance in our operations that affects these items within
our control may have a material effect on reserves. The process of
estimating our natural gas and oil reserves is anticipated to be extremely
complex, and will require significant decisions and assumptions in the
evaluation of available geological, geophysical, engineering and economic data
for each reservoir. Our estimates may not be reliable enough to allow us to be
successful in our intended business operations. Our actual production, revenues,
taxes, development expenditures and operating expenses will likely vary from
those anticipated. These variances may be material.
Unless we replace
our oil and natural gas reserves, our reserves and production will decline,
which would adversely affect our cash flows and income.
Unless
we conduct successful development, exploitation and exploration activities or
acquire properties containing proved reserves, our proved reserves will decline
as those reserves are produced. Producing oil and natural gas reservoirs
generally are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Our future oil and natural gas
reserves and production, and, therefore our cash flow and income, are highly
dependent on our success in efficiently developing and exploiting our current
reserves and economically finding or acquiring additional recoverable reserves.
We may be unable to make such acquisitions because we are:
·
unable
to identify attractive acquisition candidates or negotiate acceptable
purchase contracts with them;
·
unable
to obtain financing for these acquisitions on economically acceptable
terms; or
·
outbid
by competitors.
If
we are unable to develop, exploit, find or acquire additional reserves to
replace our current and future production, our cash flow and income will decline
as production declines, until our existing properties would be incapable of
sustaining commercial production.
26
A significant
portion of our potential future reserves and our business plan depend upon
secondary recovery techniques to establish production. There are significant
risks associated with such techniques.
We
anticipate that a significant portion of our future reserves and our business
plan will be associated with secondary recovery projects that are either in the
initial stage of implementation or are scheduled for implementation. We
anticipate that secondary recovery will affect our reserves and our business
plan, and the exact project initiation dates and, by the very nature of
waterflood operations, the exact completion dates of such projects are
uncertain. In addition, the reserves and our business plan associated with these
secondary recovery projects, as with any reserves, are estimates only, as the
success of any development project, including these waterflood projects, cannot
be ascertained in advance. If we are not successful in developing a significant
portion of our reserves associated with secondary recovery methods, then the
project may be uneconomic or generate less cash flow and reserves than we had
estimated prior to investing the capital. Risks associated with secondary
recovery techniques include, but are not limited to, the following:
·
higher
than projected operating costs;
·
lower-than-expected
production;
·
longer
response times;
·
higher
costs associated with obtaining
capital;
·
unusual
or unexpected geological
formations;
·
fluctuations
in natural gas and oil prices;
·
regulatory
changes;
·
shortages
of equipment; and
·
lack
of technical expertise.
If
any of these risks occur, it could adversely affect our financial condition or
results of operations.
Any acquisitions
we complete are subject to considerable risk.
Even
when we make acquisitions that we believe are good for our business, any
acquisition involves potential risks, including, among other
things:
·
the
validity of our assumptions about reserves, future production, revenues
and costs, including synergies;
·
an
inability to integrate successfully the businesses we
acquire;
·
a
decrease in our liquidity by using our available cash or borrowing
capacity to finance acquisitions;
·
a
significant increase in our interest expense or financial leverage if we
incur additional debt to finance
acquisitions;
·
the
assumption of unknown liabilities, losses or costs for which we are not
indemnified or for which our indemnity is
inadequate;
·
the
diversion of management’s attention from other business
concerns;
·
an
inability to hire, train or retain qualified personnel to manage the
acquired properties or assets;
·
the
incurrence of other significant charges, such as impairment of goodwill or
other intangible assets, asset devaluation or restructuring
charges;
·
unforeseen
difficulties encountered in operating in new geographic or geological
areas; and
·
customer
or key employee losses at the acquired
businesses.
27
Our decision to
acquire a property will depend in part on the evaluation of data obtained from
production reports and engineering studies, geophysical and geological analyses
and seismic and other information, the results of which are often incomplete or
inconclusive.
Our
reviews of acquired properties can be inherently incomplete because it is not
always feasible to perform an in-depth review of the individual properties
involved in each acquisition. Even a detailed review of records and properties
may not necessarily reveal existing or potential problems, nor will it permit a
buyer to become sufficiently familiar with the properties to assess fully their
deficiencies and potential. Inspections may not always be performed on every
well, and environmental problems, such as ground water contamination, plugging
or orphaned well liability are not necessarily observable even when an
inspection is undertaken.
We must obtain
governmental permits and approvals for drilling operations, which can result in
delays in our operations, be a costly and time consuming process, and result in
restrictions on our operations.
Regulatory
authorities exercise considerable discretion in the timing and scope of permit
issuances in the region in which we operate. Compliance with the requirements
imposed by these authorities can be costly and time consuming and may result in
delays in the commencement or continuation of our exploration or production
operations and/or fines. Regulatory or legal actions in the future may
materially interfere with our operations or otherwise have a material adverse
effect on us. In addition, we are often required to prepare and present to
federal, state or local authorities data pertaining to the effect or impact that
a proposed project may have on the environment, threatened and endangered
species, and cultural and archaeological artifacts. Accordingly, the permits we
need may not be issued, or if issued, may not be issued in a timely fashion, or
may involve requirements that restrict our ability to conduct our operations or
to do so profitably.
Due to our lack
of geographic diversification, adverse developments in our operating areas would
materially affect our business.
We
currently only lease and operate oil and natural gas properties located in
Eastern Kansas. As a result of this concentration, we may be disproportionately
exposed to the impact of delays or interruptions of production from these
properties caused by significant governmental regulation, transportation
capacity constraints, curtailment of production, natural disasters, adverse
weather conditions or other events which impact this area.
28
We depend on a
small number of customers for all, or a substantial amount of our sales. If
these customers reduce the volumes of oil and natural gas they purchase from us,
our revenue and cash available for distribution will decline to the extent we
are not able to find new customers for our production.
We
have contracted with Shell for the sale of all of our oil through September 2009
and will likely contract for the sale of our natural gas with one, or a small
number, of buyers. It is not likely that there will be a large pool of available
purchasers. If a key purchaser were to reduce the volume of oil or natural gas
it purchases from us, our revenue and cash available for operations will decline
to the extent we are not able to find new customers to purchase our production
at equivalent prices.
We are not the
operator of some of our properties and we have limited control over the
activities on those properties.
We
are not the operator on our Black Oaks Project. We have only limited ability to
influence or control the operation or future development of the Black Oaks
Project or the amount of capital expenditures that we can fund with respect to
it. In the case of the Black Oaks Project, our dependence on the operator, Haas
Petroleum, limits our ability to influence or control the operation or future
development of the project. Such limitations could materially adversely affect
the realization of our targeted returns on capital related to exploration,
drilling or production activities and lead to unexpected future
costs.
We may suffer
losses or incur liability for events for which we or the operator of a property
have chosen not to obtain insurance.
Our
operations are subject to hazards and risks inherent in producing and
transporting natural gas and oil, such as fires, natural disasters, explosions,
pipeline ruptures, spills, and acts of terrorism, all of which can result in the
loss of hydrocarbons, environmental pollution, personal injury claims and other
damage to our and others’ properties. As protection against operating hazards,
we maintain insurance coverage against some, but not all, potential losses. In
addition, pollution and environmental risks generally are not fully insurable.
As a result of market conditions, existing insurance policies may not be renewed
and other desirable insurance may not be available on commercially reasonable
terms, if at all. The occurrence of an event that is not covered, or not fully
covered, by insurance could have a material adverse effect on our business,
financial condition and results of operations.
Our hedging
activities could result in financial losses or could reduce our available funds
or income and therefore adversely affect our financial
position.
To
achieve more predictable cash flow and to reduce our exposure to adverse
fluctuations in the prices of oil and natural gas, we have entered into
derivative arrangements from April 1, 2008 until March 31, 2011, for 130 barrels
of oil per day that could result in both realized and unrealized hedging losses.
As of June 30, 2008 we had not incurred any such losses. The extent of our
commodity price exposure is related largely to the effectiveness and scope of
our derivative activities. For example, the derivative instruments we may
utilize may be based on posted market prices, which may differ significantly
from the actual crude oil, natural gas and NGL prices we realize in our
operations.
29
Our
actual future production may be significantly higher or lower than we estimate
at the time we enter into derivative transactions for such period. If the actual
amount is higher than we estimate, we will have greater commodity price exposure
than we intended. If the actual amount is lower than the nominal amount that is
subject to our derivative financial instruments, we might be forced to satisfy
all or a portion of our derivative transactions without the benefit of the cash
flow from our sale or purchase of the underlying physical commodity, resulting
in a substantial diminution of our liquidity. As a result of these factors, our
derivative activities may not be as effective as we intend in reducing the
volatility of our cash flows, and in certain circumstances may actually increase
the volatility of our cash flows. In addition, our derivative activities are
subject to the risks that a counterparty, such as Shell or BP, may not perform
its obligation under the applicable derivative instrument. Moreover, unless we
execute an intercreditor agreement with Shell or BP, there is a risk that we
will be required to post collateral to secure our hedging activities and this
could limit the funds available to us for our business activities. If oil
exceeds $210 a barrel before the intercreditor agreement is in place, and we are
unable to post the collateral, there is a risk that our hedged positions could
be liquidated and we could incur significant losses.
Our business
depends in part on gathering and transportation facilities owned by others. Any
limitation in the availability of those facilities could interfere with our
ability to market our oil and natural gas production and could harm our
business.
The
marketability of our oil and natural gas production will depend in a very large
part on the availability, proximity and capacity of pipelines, oil and natural
gas gathering systems and processing facilities. The amount of oil and natural
gas that can be produced and sold is subject to curtailment in certain
circumstances, such as pipeline interruptions due to scheduled and unscheduled
maintenance, excessive pressure, physical damage or lack of available capacity
on such systems. The curtailments arising from these and similar circumstances
may last from a few days to several months. In many cases, we will be provided
only with limited, if any, notice as to when these circumstances will arise and
their duration. Any significant curtailment in gathering system or pipeline
capacity could significantly reduce our ability to market our oil and natural
gas production and harm our business.
The high cost of
drilling rigs, equipment, supplies, personnel and other services could adversely
affect our ability to execute on a timely basis our development, exploitation
and exploration plans within our budget.
Shortages
or an increase in cost of drilling rigs, equipment, supplies or personnel could
delay or interrupt our operations, which could impact our financial condition
and results of operations. Drilling activity in the geographic areas in which we
conduct drilling activities may increase, which would lead to increases in
associated costs, including those related to drilling rigs, equipment, supplies
and personnel and the services and products of other vendors to the industry.
Increased drilling activity in these areas may also decrease the availability of
rigs. Although Haas Petroleum has agreed to provide two drilling rigs to the
Black Oaks Project, we do not have any contracts for drilling rigs and drilling
rigs may not be readily available when we need them. Drilling and other costs
may increase further and necessary equipment and services may not be available
to us at economical prices.
30
Our exposure to
possible leasehold defects and potential title failure could materially
adversely impact our ability to conduct drilling operations.
We
obtain the right and access to properties for drilling by obtaining oil and
natural gas leases either directly from the hydrocarbon owner, or through a
third party that owns the lease. The leases may be taken or assigned to us
without title insurance. There is a risk of title failure with respect to such
leases, and such title failures could materially adversely impact our business
by causing us to be unable to access properties to conduct drilling
operations.
Our reserves are
subject to the risk of depletion because many of our leases are in mature fields
that have produced large quantities of oil and natural gas to
date.
Our
operations are located in established fields in Eastern Kansas. As a result,
many of our leases are in, or directly offset, areas that have produced large
quantities of oil and natural gas to date. The degree of depletion for each of
our projects ranges from approximately 0% to 78%. As such, our
reserves may be partially or completely depleted by offsetting wells or
previously drilled wells, which could significantly harm our
business.
Our lease
ownership may be diluted due to financing strategies we may employ in the future
due to our lack of capital.
To
accelerate our development efforts we plan to take on working interest partners
who will contribute to the costs of drilling and completion and then share in
revenues derived from production. In addition, we may in the future, due to a
lack of capital or other strategic reasons, establish joint venture partnerships
or farm out all or part of our development efforts. These economic strategies
may have a dilutive effect on our lease ownership and could significantly reduce
our operating revenues.
We are subject to
complex laws and regulations, including environmental regulations, which can
adversely affect the cost, manner or feasibility of doing
business.
Development,
production and sale of natural gas and oil in the United States are subject to
extensive laws and regulations, including environmental laws and regulations. We
may be required to make large expenditures to comply with environmental and
other governmental regulations. Matters subject to regulation include, but are
not limited to:
·
location
and density of wells;
·
the
handling of drilling fluids and obtaining discharge permits for drilling
operations;
·
accounting
for and payment of royalties on production from state, federal and Indian
lands;
·
bonds
for ownership, development and production of natural gas and oil
properties;
·
transportation
of natural gas and oil by
pipelines;
·
operation
of wells and reports concerning operations;
and
·
taxation.
31
Under these laws and regulations, we
could be liable for personal injuries, property damage, oil spills, discharge of
hazardous materials, remediation and clean-up costs and other environmental
damages. Failure to comply with these laws and regulations also may result in
the suspension or termination of our operations and subject us to
administrative, civil and criminal penalties. Moreover, these laws and
regulations could change in ways that substantially increase our costs.
Accordingly, any of these liabilities, penalties, suspensions, terminations or
regulatory changes could materially adversely affect our financial condition and
results of operations enough to possibly force us to cease our business
operations.
Our operations
may expose us to significant costs and liabilities with respect to
environmental, operational safety and other matters.
We
may incur significant costs and liabilities as a result of environmental and
safety requirements applicable to our oil and natural gas exploration and
production activities. We may also be exposed to the risk of costs associated
with Kansas Corporation Commission requirements to plug orphaned and abandoned
wells on our oil and natural gas leases from wells previously drilled by third
parties. In addition, we may indemnify sellers or lessors of oil and natural gas
properties for environmental liabilities they or their predecessors may have
created. These costs and liabilities could arise under a wide range of federal,
state and local environmental and safety laws and regulations, including
regulations and enforcement policies, which have tended to become increasingly
strict over time. Failure to comply with these laws and regulations may result
in the assessment of administrative, civil and criminal penalties, imposition of
cleanup and site restoration costs, liens and to a lesser extent, issuance of
injunctions to limit or cease operations. In addition, claims for damages to
persons or property may result from environmental and other impacts of our
operations.
Strict,
joint and several liability may be imposed under certain environmental laws,
which could cause us to become liable for the conduct of others or for
consequences of our own actions that were in compliance with all applicable laws
at the time those actions were taken. New laws, regulations or enforcement
policies could be more stringent and impose unforeseen liabilities or
significantly increase compliance costs. If we are not able to recover the
resulting costs through insurance or increased revenues, our ability to operate
effectively could be adversely affected.
Our facilities
and activities could be subject to regulation by the Federal Energy Regulatory
Commission or the Department of Transportation, which could take actions that
could result in a material adverse effect on our financial
condition.
Although
it is anticipated that our natural gas gathering systems will be exempt from
FERC and DOT regulation, any revisions to this understanding may affect our
rights, liabilities, and access to midstream or interstate natural gas
transportation, which could have a material adverse effect on our operations and
financial condition. In addition, the cost of compliance with any revisions to
FERC or DOT rules, regulations or requirements could be substantial and could
adversely affect our ability to operate in an economic manner. Additional FERC
and DOT rules and legislation pertaining to matters that could affect our
operations are considered and adopted from time to time. We cannot predict what
effect, if any, such regulatory changes and legislation might have on our
operations, but we could be required to incur additional capital expenditures
and increased costs.
32
Although
our natural gas sales activities are not currently projected to be subject to
rate regulation by FERC, if FERC finds that in connection with making sales in
the future, we (i) failed to comply with any applicable FERC administered
statutes, rules, regulations or orders, (ii) engaged in certain fraudulent acts,
or (iii) engaged in market manipulation, we could be subject to substantial
penalties and fines of up to $1.0 million per day per violation.
We operate in a
highly competitive environment and our competitors may have greater resources
than us.
The
natural gas and oil industry is intensely competitive and we compete with other
companies, many of which are larger and have greater financial, technological,
human and other resources. Many of these companies not only explore for and
produce crude oil and natural gas but also carry on refining operations and
market petroleum and other products on a regional, national or worldwide basis.
Such companies may be able to pay more for productive natural gas and oil
properties and exploratory prospects or define, evaluate, bid for and purchase a
greater number of properties and prospects than our financial or human resources
permit. In addition, such companies may have a greater ability to continue
exploration activities during periods of low oil and natural gas market prices.
Our ability to acquire additional properties and to discover reserves in the
future will be dependent upon our ability to evaluate and select suitable
properties and to consummate transactions in a highly competitive environment.
If we are unable to compete, our operating results and financial position may be
adversely affected.
We may incur
substantial write-downs of the carrying value of our natural gas and oil
properties, which would adversely impact our earnings.
We
review the carrying value of our natural gas and oil properties under the
full-cost accounting rules of the SEC on a quarterly basis. This quarterly
review is referred to as a ceiling test. Under the ceiling test, capitalized
costs, less accumulated amortization and related deferred income taxes, may not
exceed an amount equal to the sum of the present value of estimated future net
revenues (adjusted for cash flow hedges) less estimated future expenditures to
be incurred in developing and producing the proved reserves, less any related
income tax effects. In calculating future net revenues, current prices and costs
used are those as of the end of the appropriate quarterly period. Such prices
are utilized except where different prices are fixed and determinable from
applicable contracts for the remaining term of those contracts, including the
effects of derivatives qualifying as cash flow hedges. Two primary factors
impacting this test are reserve levels and current prices, and their associated
impact on the present value of estimated future net revenues. Revisions to
estimates of natural gas and oil reserves and/or an increase or decrease in
prices can have a material impact on the present value of estimated future net
revenues. Any excess of the net book value, less deferred income taxes, is
generally written off as an expense. Under SEC regulations, the excess above the
ceiling is not expensed (or is reduced) if, subsequent to the end of the period,
but prior to the release of the financial statements, natural gas and oil prices
increase sufficiently such that an excess above the ceiling would have been
eliminated (or reduced) if the increased prices were used in the
calculations.
33
We
have recorded a total of $742,040 in impairments on our oil and natural gas
properties based on the ceiling test under the full-cost method in the years
ended March 31, 2007 and 2006. There was no impairment for the fiscal year ended
March 31, 2008 or in the three months ended June 30, 2008.
We will need
additional capital in the future to finance our planned growth, which we may not
be able to raise or may only be available on terms unfavorable to us or our
stockholders, which may result in our inability to fund our working capital
requirements and harm our operational results.
We
have and expect to continue to have substantial capital expenditure and working
capital needs. We will need to rely on cash flow from operations and borrowings
under our credit facility or raise additional cash to fund our operations, pay
outstanding long-term debt, fund our anticipated reserve replacement needs and
implement our growth strategy, or respond to competitive pressures and/or
perceived opportunities, such as investment, acquisition, exploration, workover
and development activities.
If
low natural gas and oil prices, operating difficulties or other factors, many of
which are beyond our control, cause our revenues or cash flows from operations
to decrease, we may be limited in our ability to spend the capital necessary to
complete our development, production exploitation and exploration programs. If
our resources or cash flows do not satisfy our operational needs, we will
require additional financing, in addition to anticipated cash generated from our
operations, to fund our planned growth. Additional financing might not be
available on terms favorable to us, or at all. If adequate funds were not
available or were not available on acceptable terms, our ability to fund our
operations, take advantage of unanticipated opportunities, develop or enhance
our business or otherwise respond to competitive pressures would be
significantly limited. In such a capital restricted situation, we may curtail
our acquisition, drilling, development, and exploration activities or be forced
to sell some of our assets on an untimely or unfavorable basis.
If
we raise additional funds through the issuance of equity or convertible debt
securities, the percentage ownership of our stockholders would be reduced, and
these newly issued securities might have rights, preferences or privileges
senior to those of existing stockholders.
Our success
depends on our key management and professional personnel, including C. Stephen
Cochennet, the loss of whom would harm our ability to execute our business
plan.
Our
success depends heavily upon the continued contributions of C. Stephen
Cochennet, whose knowledge, leadership and technical expertise would be
difficult to replace, and on our ability to retain and attract experienced
engineers, geoscientists and other technical and professional staff. We have
entered into an employment agreement with Mr. Cochennet, and we maintain $1.0
million in key person insurance on Mr. Cochennet. However, if we were to lose
his services, our ability to execute our business plan would be harmed and we
may be forced to significantly alter our operations until such time as we could
hire a suitable replacement for Mr. Cochennet.
34
Risks Associated with our
Debt Financing
Until we repay
the full amount of our outstanding debentures and credit facility, we may
continue to have substantial indebtedness, which is secured by substantially all
of our assets.
On
July 7, 2008, $2.7 million in debentures and approximately $12.75 million of
bank loans and letters of credit were outstanding. In the event that we default
with respect to the debentures or other secured debt, the lenders may enforce
their rights as a secured party and we may lose all or a portion of our assets
or be forced to materially reduce our business activities.
Our substantial
indebtedness could make it more difficult for us to fulfill our obligations
under our new credit facility and our debentures and, therefore, adversely
affect our business.
On
July 3, 2008, we entered into a three-year, senior secured revolving credit
facility providing for aggregate borrowings of up to $50 million. As
of July 7, 2008, we had total indebtedness of $13.6 million, including $10.8
million of initial borrowings under the credit facility and $2.7 million of
remaining debentures. In addition, we have issued letters of credit under the
new facility totaling $2.0 million. Our substantial indebtedness, and the
related interest expense, could have important consequences to us,
including:
·
limiting
our ability to borrow additional amounts for working capital, capital
expenditures, debt service requirements, execution of our business
strategy, or other general corporate
purposes;
·
limiting
our ability to use operating cash flow in other areas of our business
because we must dedicate a substantial portion of these funds to service
our indebtedness;
·
increasing
our vulnerability to general adverse economic and industry
conditions;
·
placing
us at a competitive disadvantage as compared to our competitors that have
less leverage;
·
limiting
our ability to capitalize on business opportunities and to react to
competitive pressures and changes in government
regulation;
·
limiting
our ability to, or increasing the cost of, refinancing our
indebtedness; and
·
limiting
our ability to enter into marketing, hedging, optimization and trading
transactions by reducing the number of counterparties with whom we can
enter into such transactions as well as the volume of those
transactions.
The covenants in
our new credit facility and debentures impose significant operating and
financial restrictions on us.
The
new credit facility and our debentures impose significant operating and
financial restrictions on us. These restrictions limit our ability and the
ability of our subsidiaries, among other things, to:
35
·
incur
additional indebtedness and provide additional
guarantees;
·
pay
dividends and make other restricted
payments;
·
create
or permit certain liens;
·
use
the proceeds from the sales of our oil and natural gas
properties;
·
engage
in certain transactions with affiliates;
and
·
consolidate,
merge, sell or transfer all or substantially all of our assets or the
assets of our subsidiaries.
The
new credit facility and our debentures also contain various affirmative
covenants with which we are required to comply. Although we currently expect to
comply with these covenants, we may be unable to comply with some or all of them
in the future. If we do not comply with these covenants and are unable to obtain
waivers from our lenders, we would be unable to make additional borrowings under
these facilities, our indebtedness under these agreements would be in default
and could be accelerated by our lenders. In addition, it could cause
a cross-default under our other indebtedness, including our debentures. If our
indebtedness is accelerated, we may not be able to repay our indebtedness or
borrow sufficient funds to refinance it. In addition, if we incur additional
indebtedness in the future, we may be subject to additional covenants, which may
be more restrictive than those to which we are currently
subject.
Risks Associated with our
Common Stock
Our common stock
is traded on an illiquid market, making it difficult for investors to sell their
shares.
Our
common stock trades on the Over-the-Counter Bulletin Board under the symbol
“ENRJ,” but trading has been minimal. Therefore, the market for our common stock
is limited. The trading price of our common stock could be subject to wide
fluctuations. Investors may not be able to purchase additional shares or sell
their shares within the time frame or at a price they desire.
The price of our
common stock may be volatile and you may not be able to resell your shares at a
favorable price.
Regardless
of whether an active trading market for our common stock develops, the market
price of our common stock may be volatile and you may not be able to resell your
shares at or above the price you paid for such shares. The following factors
could affect our stock price:
36
·
our
operating and financial performance and
prospects;
·
quarterly
variations in the rate of growth of our financial indicators, such as net
income per share, net income and
revenues;
·
changes
in revenue or earnings estimates or publication of research reports by
analysts about us or the exploration and production
industry;
·
potentially
limited liquidity;
·
actual
or anticipated variations in our reserve estimates and quarterly operating
results;
·
changes
in natural gas and oil prices;
·
sales
of our common stock by significant stockholders and future issuances of
our common stock;
·
increases
in our cost of capital;
·
changes
in applicable laws or regulations, court rulings and enforcement and legal
actions;
·
commencement
of or involvement in litigation;
·
changes
in market valuations of similar
companies;
·
additions
or departures of key management
personnel;
·
general
market conditions, including fluctuations in and the occurrence of events
or trends affecting the price of natural gas and oil;
and
·
domestic
and international economic, legal and regulatory factors unrelated to our
performance.
Our articles of
incorporation, bylaws and Nevada Law contain
provisions that could discourage an acquisition or change of control of
us.
Our
articles of incorporation authorize our board of directors to issue preferred
stock and common stock without stockholder approval. If our board of directors
elects to issue preferred stock, it could be more difficult for a third party to
acquire control of us. In addition, provisions of the articles of incorporation
and bylaws could also make it more difficult for a third party to acquire
control of us. In addition, Nevada’s “Combination with Interested Stockholders’
Statute” and its “Control Share Acquisition Statute” may have the effect in the
future of delaying or making it more difficult to effect a change in control of
us.
These
statutory anti-takeover measures may have certain negative consequences,
including an effect on the ability of our stockholders or other individuals to
(i) change the composition of the incumbent board of directors; (ii) benefit
from certain transactions which are opposed by the incumbent board of directors;
and (iii) make a tender offer or attempt to gain control of us, even if such
attempt were beneficial to us and our stockholders. Since such measures may also
discourage the accumulations of large blocks of our common stock by purchasers
whose objective is to seek control of us or have such common stock repurchased
by us or other persons at a premium, these measures could also depress the
market price of our common stock. Accordingly, our stockholders may be deprived
of certain opportunities to realize the “control premium” associated with
take-over attempts.
We have no plans
to pay dividends on our common stock. You may not receive funds without selling
your stock.
We
do not anticipate paying any cash dividends on our common stock in the
foreseeable future. We currently intend to retain future earnings, if any, to
finance the expansion of our business. Our future dividend policy is within the
discretion of our board of directors and will depend upon various factors,
including our business, financial condition, results of operations, capital
requirements, investment opportunities and restrictions imposed by our
debentures and credit facility.
37
We may issue
shares of preferred stock with greater rights than our common
stock.
Although
we have no current plans, arrangements, understandings or agreements to issue
any preferred stock, our articles of incorporation authorizes our board of
directors to issue one or more series of preferred stock and set the terms of
the preferred stock without seeking any further approval from our stockholders.
Any preferred stock that is issued may rank ahead of our common stock, with
respect to dividends, liquidation rights and voting rights, among other
things.
We have
derivative securities currently outstanding. Exercise of these derivatives will
cause dilution to existing and new stockholders.
As
of June 30, 2008, we had options and warrants to purchase approximately 533,500
shares of common stock outstanding in addition to 2,500 shares issuable upon
conversion of a convertible note. The exercise of our outstanding options and
warrants, and the conversion of the note, will cause additional shares of common
stock to be issued, resulting in dilution to our existing common
stockholders.
Because
our common stock may be deemed a low-priced “Penny” stock, an investment in our
common stock should be considered high risk and subject to marketability
restrictions.
Our
common stock may be deemed to be a penny stock, as defined in Rule 3a51-1 under
the Securities Exchange Act, which may make it more difficult for investors to
liquidate their investment even if and when a market develops for the common
stock. Until the trading price of the common stock consistently trades above
$5.00 per share, if ever, trading in the common stock may be subject to the
penny stock rules of the Securities Exchange Act specified in rules 15g-1
through 15g-10. Those rules require broker-dealers, before effecting
transactions in any penny stock, to:
·
Deliver
to the customer, and obtain a written receipt for, a disclosure
document;
·
Disclose
certain price information about the
stock;
·
Disclose
the amount of compensation received by the broker-dealer or any associated
person of the broker-dealer;
·
Send
monthly statements to customers with market and price information about
the penny stock; and
·
In
some circumstances, approve the purchaser’s account under certain
standards and deliver written statements to the customer with information
specified in the rules.
Consequently,
the penny stock rules may restrict the ability or willingness of broker-dealers
to sell the common stock and may affect the ability of holders to sell their
common stock in the secondary market and the price at which such holders can
sell any such securities. These additional procedures could also limit
our ability to raise additional capital in the future.
38
If
we fail to remain current on our reporting requirements, we could be removed
from the OTC Bulletin Board, which would limit the ability of broker-dealers to
sell our securities and the ability of stockholders to sell their securities in
the secondary market.
Companies
trading on the OTC Bulletin Board, such as us, must be reporting issuers under
Section 12 of the Securities Exchange Act of 1934, as amended, and must be
current in their reports under Section 13, in order to maintain price quotation
privileges on the OTC Bulletin Board. More specifically, FINRA has enacted
Rule 6530, which determines eligibility of issuers quoted on the OTC Bulletin
Board by requiring an issuer to be current in its filings with the
Commission. Pursuant to Rule 6530(e), if we file our reports late with the
Commission three times in a two-year period or our securities are removed from
the OTC Bulletin Board for failure to timely file twice in a two-year period
then we will be ineligible for quotation on the OTC Bulletin
Board. As a result, the market liquidity for our securities could be
severely adversely affected by limiting the ability of broker-dealers to sell
our securities and the ability of stockholders to sell their securities in the
secondary market.
FINRA
sales practice requirements may limit a stockholder's ability to buy and sell
our stock.
In addition to the “penny stock” rules
described above, FINRA has adopted rules that require that in recommending an
investment to a customer, a broker-dealer must have reasonable grounds for
believing that the investment is suitable for that customer. Prior to
recommending speculative low priced securities to their non-institutional
customers, broker-dealers must make reasonable efforts to obtain information
about the customer's financial status, tax status, investment objectives and
other information. Under interpretations of these rules, the FINRA believes that
there is a high probability that speculative low priced securities will not be
suitable for at least some customers. The FINRA requirements make it more
difficult for broker-dealers to recommend that their customers buy our common
stock, which may limit your ability to buy and sell our stock and have an
adverse effect on the market for our shares.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds.
Reverse Stock
Split
Effective
July 25, 2008, we implemented a one-for-five reverse stock split of our issued
and outstanding common stock. The number of authorized shares of
common stock and preferred stock was not affected and remains at 100,000,000 and
10,000,000, respectively, but the number of shares of common stock outstanding
was reduced from 22,214,166 to 4,443,467. All per share and share
amounts, including stock options and warrants, have been retroactively restated
in this report.
Issuances During the
Quarter
On May 15, 2008, we issued 2,182 shares
to Daran G. Dammeyer for serving as the chairman of our audit committee. We
believe that the issuance of shares of common stock was exempt from the
registration and prospectus delivery requirements of the Securities Act of 1933
by virtue of Section 4(2).
39
Subsequent
Issuances
On July 2, 2008, we granted
122,000 options to purchase shares of our common stock to our non-employee
directors as compensation for their service as directors in fiscal 2009. The
options are exercisable until July 1, 2011 at a per share price of $6.25.
We believe that the option grants were exempt from the registration and
prospectus delivery requirements of the Securities Act of 1933 by virtue of
Section 4(2).
On
August 1, 2008, we granted C. Stephen Cochennet, our chief executive officer, an
option to purchase 75,000 shares of our common stock at 6.25 per share. 30,000
of the options vested immediately and expire on July 31, 2011. The remaining
45,000 options vest based on the following schedule: 10,000 options shall vest
on July 1, 2009; 15,000 options shall vest on July 1, 2010; and 20,000 options
shall vest on July 1, 2011. The options will be exercisable for a three year
term following the vesting date. We believe that the grant of the options was
exempt from the registration and prospectus delivery requirements of the
Securities Act of 1933 by virtue of Section 4(2).
On August 1, 2008, we granted Dierdre
P. Jones, its chief financial officer, an option to purchase 40,000 shares
of our common stock at $6.25 per share for a period of three years expiring on
July 31, 2011. We believe that the issuance of the shares was exempt from
the registration and prospectus delivery requirements of the Securities Act of
1933 by virtue of Section 4(2).
Issuer
Purchases of Equity Securities
We did not repurchase any of our equity
securities during the quarter ended June 30, 2008.
Item
3. Defaults Upon Senior Securities.
None.
Item
4. Submission of Matters to a Vote of Security Holders.
We held a special meeting of our
stockholders on May 27, 2008. The sole business conducted at the meeting was to
approve a proposal to grant discretionary authority to our board of directors to
enact a reverse stock split on a 1-for-5 basis at any time over the twelve
months following approval of the proposal.
Each
share of our common stock was entitled to one vote. Only stockholders
of record at the close of business on April 15, 2008, were entitled to
vote. The number of outstanding shares at the time was 22,203,256
held by approximately 1,148 stockholders. The required quorum of stockholders
was present at this meeting with 13,150,458 shares (approximately 60%)
represented in person or by proxy.
40
Votes
on the approval of granting discretionary authority to our board to enact the
reverse stock split were as follows:
For
Against
Withheld
13,150,431
27
0
The reverse stock split was implemented
on July 25, 2008.
Promissory
Note to Texas Capital Bank, N.A. dated July 3, 2008 (incorporated by
reference to Exhibit 10.34 to the Form 10-K filed on July 10,2008)
10.3
Amended
and Restated Mortgage, Security Agreement, Financing Statement and
Assignment of Production and Revenues with Texas Capital Bank, N.A. dated
July 3, 2008 (incorporated by reference to Exhibit 10.35 to the Form 10-K
filed on July 10, 2008)
10.4
Security
Agreement with Texas Capital Bank, N.A. dated July 3, 2008 (incorporated
by reference to Exhibit 10.36 to the Form 10-K filed on July 10,2008)
10.5
Letter
Agreement with Debenture Holders dated July 3, 2008 (incorporated by
reference to Exhibit 10.37 to the Form 10-K filed on July 10,2008)
10.6†
C.
Stephen Cochennet Employment Agreement dated August 1, 2008 (incorporated
by reference to Exhibit 10.1 to the Form 8-K filed on August 1,2008)
10.7†
Dierdre
P. Jones Employment Agreement dated August 1, 2008 (incorporated by
reference to Exhibit 10.2 to the Form 8-K filed on August 1,2008)
31.1
Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002
31.2
Certification
of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002
32.1
Certification
of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
32.2
Certification
of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
† Indicates
management contract or compensatory plan or arrangement.
41
SIGNATURES
In accordance with the requirements of
the Exchange Act, the registrant caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
