Filed On 12/15/06 5:09pm ET · SEC File 333-139424 · Accession Number 950129-6-10190
As Of Filer Filing As/For/On Docs:Pgs Issuer Agent
12/15/06 NorthernStar Natural Gas Inc S-1 3:139 Bowne of Houston...01/FA
Document/Exhibit Description Pages Size
1: S-1 Registration Statement (General Form) HTML 877K
2: EX-23.1 Consent of Malone & Bailey Llp HTML 5K
3: EX-23.2 Consent of Pannell Kerr Forster of Texas, P.C. HTML 5K
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- Alternative Formats (RTF, XML, et al.)
- Business
- Capitalization
- Certain Relationships and Related Transactions
- Consolidated Balance Sheet as of December 31, 2005
- Consolidated Balance Sheet at December 31, 2004 and December 31, 2005
- Consolidated Balance Sheets at September 30, 2006 and December 31, 2005 (unaudited)
- Consolidated Statement of Cash Flows from Inception (January 14, 2002) through December 31, 2005 and for the years ended December 31, 2003, 2004, and 2005
- Consolidated Statement of Cash Flows from Inception (May 17, 2005) through December 31, 2005
- Consolidated Statement of Changes in Members Equity from Inception (January 14, 2002) through December 31, 2005 and for the years ended December 31, 2003, 2004, and 2005
- Consolidated Statement of Changes in Members Equity from Inception (May 17, 2005) through December 31, 2005
- Consolidated Statement of Operations from Inception (January 14, 2002) through December 31, 2005 and for the years ended December 31, 2003, 2004, and 2005
- Consolidated Statement of Operations from Inception (May 17, 2005) through December 31, 2005
- Consolidated Statements of Cash Flows for the period nine months ended September 30, 2006 and the Cumulative period from Inception (May 17, 2005) through September 30, 2006 (unaudited)
- Consolidated Statements of Operations for the nine months ended September 30, 2006, and Cumulative Period from Inception (May 17, 2005) through September 30, 2006 (unaudited)
- Consolidated Statements of Stockholder s Equity at September 30, 2006 (unaudited)
- Description of Capital Stock
- Description of Senior Convertible Notes
- Dilution
- Dividend Policy
- Experts
- Forward-Looking Statements
- Index to Financial Statements
- Industry Overview
- Legal Matters
- Management
- Management s Discussion and Analysis of Financial Condition and Results of Operations
- Notes to Consolidated Financial Statements (unaudited)
- Notes to Financial Statements
- Principal Stockholders
- Report of Independent Registered Public Accounting Firm
- Risk Factors
- Selected Historical Financial Data
- Shares Eligible for Future Sale
- State and Federal Government Regulatory Matters
- Summary
- Table of Contents
- Underwriting
- Use of Proceeds
- Where You Can Find Additional Information
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| 1 | 1st Page
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| " | Table of Contents
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| " | Summary
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| " | Risk Factors
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| " | Forward-Looking Statements
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| " | Use of Proceeds
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| " | Dividend Policy
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| " | Capitalization
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| " | Dilution
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| " | Selected Historical Financial Data
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| " | Management s Discussion and Analysis of Financial Condition and Results of Operations
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| " | Industry Overview
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| " | Business
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| " | State and Federal Government Regulatory Matters
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| " | Management
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| " | Principal Stockholders
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| " | Certain Relationships and Related Transactions
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| " | Description of Capital Stock
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| " | Description of Senior Convertible Notes
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| " | Shares Eligible for Future Sale
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| " | Underwriting
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| " | Legal Matters
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| " | Experts
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| " | Where You Can Find Additional Information
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| " | Index to Financial Statements
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| " | Consolidated Balance Sheets at September 30, 2006 and December 31, 2005 (unaudited)
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| " | Consolidated Statements of Operations for the nine months ended September 30, 2006, and Cumulative Period from Inception (May 17, 2005) through September 30, 2006 (unaudited)
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| " | Consolidated Statements of Cash Flows for the period nine months ended September 30, 2006 and the Cumulative period from Inception (May 17, 2005) through September 30, 2006 (unaudited)
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| " | Consolidated Statements of Stockholder s Equity at September 30, 2006 (unaudited)
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| " | Notes to Consolidated Financial Statements (unaudited)
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| " | Report of Independent Registered Public Accounting Firm
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| " | Consolidated Balance Sheet as of December 31, 2005
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| " | Consolidated Statement of Operations from Inception (May 17, 2005) through December 31, 2005
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| " | Consolidated Statement of Changes in Members Equity from Inception (May 17, 2005) through December 31, 2005
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| " | Consolidated Statement of Cash Flows from Inception (May 17, 2005) through December 31, 2005
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| " | Notes to Financial Statements
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| " | Consolidated Balance Sheet at December 31, 2004 and December 31, 2005
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| " | Consolidated Statement of Operations from Inception (January 14, 2002) through December 31, 2005 and for the years ended December 31, 2003, 2004, and 2005
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| " | Consolidated Statement of Changes in Members Equity from Inception (January 14, 2002) through December 31, 2005 and for the years ended December 31, 2003, 2004, and 2005
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| " | Consolidated Statement of Cash Flows from Inception (January 14, 2002) through December 31, 2005 and for the years ended December 31, 2003, 2004, and 2005
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This is an EDGAR HTML document rendered as filed. [ Alternative Formats ]
Registration No. 333-
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
NORTHERNSTAR NATURAL GAS INC.
(Exact name of Registrant as specified in its charter)
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| Delaware
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5171
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20-4827373 |
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(Primary Standard Industrial
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(I.R.S. employer |
| incorporation or organization)
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Classification code number)
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identification no.) |
First City Tower
1001 Fannin, Suite 1700
Houston, TX 77002
Tel. (713) 599-4910
(Address, including zip code, and telephone number, including area
code, of registrant’s principal executive offices)
Jonathan L. Phillips, Esq.
General Counsel
First City Tower
1001 Fannin, Suite 1700
Houston, TX 77002
Tel. (713) 599-4910
(Name, address, including zip code and telephone number, including area code, of agent for service)
Please address a copy of all communications to:
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| Douglas A. Tanner, Esq.
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R. Joel Swanson, Esq. |
| Brett Goldblatt, Esq.
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Baker Botts L.L.P. |
| Milbank, Tweed, Hadley & McCloy LLP
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One Shell Plaza |
| 1 Chase Manhattan Plaza
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910 Louisiana |
| New York, New York 10005
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Houston, Texas 77002 |
| Tel. (212) 530-5000 |
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Approximate date of commencement of proposed sale to the public: As soon as practicable after
this Registration Statement becomes effective.
If any of the securities being registered on this Form are to be offered on a delayed or
continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.
o
If this Form is filed to register additional securities for an offering pursuant to Rule
462(b) under the Securities Act, check the following box and list the Securities Act registration
statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities
Act, check the following box and list the Securities Act registration statement number of the
earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities
Act, check the following box and list the Securities Act registration statement number of the
earlier effective registration statement for the same offering. o
If delivery of the prospectus is expected to be made pursuant to Rule 434, check the following
box. o
CALCULATION OF REGISTRATION FEE
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Title of each class of |
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Amount of |
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Securities to be registered |
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offering price (1) |
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Registration fee |
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Common Stock, $0.01 par value |
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125,000,000 |
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13,375 |
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Estimated solely for the purpose of computing the registration fee pursuant to Rule 457(o)
under the Securities Act. |
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary
to delay its effective date until the Registrant shall file a further amendment which specifically
states that this Registration Statement shall thereafter become effective in accordance with
Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.
The information in this prospectus is not complete and may be changed. We may not sell these
securities until the registration statement filed with the Securities and Exchange Commission is
effective. This prospectus is not an offer to sell these securities and it is not soliciting an
offer to buy these securities in any state where the offer or sale is not permitted.
P R O S P E C T U S
Shares
NorthernStar
Natural Gas Inc.
Common Stock
$
per
share
We are selling shares of our common stock. We have granted the
underwriters an option to purchase up to additional shares of common stock to cover
over-allotments.
This is the initial public offering of our common stock. We currently expect the initial
public offering price to be between $ and $ per share. We are applying to have the common
stock listed on The Nasdaq Global Market under the symbol “NSNG.”
Investing in our common stock involves risks. See “Risk Factors” beginning on page 10.
Neither the Securities and Exchange Commission nor any state securities commission has
approved or disapproved of these securities or determined if this prospectus is truthful or
complete. Any representation to the contrary is a criminal offense.
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Per Share |
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Total |
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Public Offering Price |
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Underwriting Discount |
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Proceeds to NorthernStar Natural Gas Inc. (before expenses) |
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The underwriters expect to deliver the shares to purchasers on or about , 2007.
Sole Book-Runner
Citigroup
, 2007
You should only rely on the information contained in this prospectus. We have not authorized anyone
to provide you any information other than the information contained in this prospectus. We are not,
and the underwriters are not, making any offer to sell these securities in any jurisdiction where
the offer or sale is not permitted. You should assume that the information contained in this
prospectus is accurate only as of the date of this prospectus regardless of the time of delivery of
this prospectus or any sale of the common stock.
Until , 2007 (25 days after the commencement of this offering), all dealers that effect
transactions in these securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when
acting as underwriters and with respect to their unsold allotments or subscriptions.
MARKET AND INDUSTRY DATA
This prospectus includes industry data and forecasts that we obtained from publicly available
information, industry publications, and surveys. Our forecasts are based upon management’s current
understanding of industry conditions and speak only as of the date of this prospectus unless the
context indicates otherwise. This information has not been independently verified by us and may not
be consistent with other third-party information. We believe that the information included in this
prospectus from industry surveys, publications and forecasts is reliable.
SUMMARY
The following summary highlights selected information from this prospectus. It does not
contain all the information that you should consider in making an investment decision and should be
read together with the more detailed information appearing elsewhere in this prospectus, including
“Risk Factors” and the consolidated financial statements and related notes. In this prospectus,
unless the context otherwise requires or as otherwise defined, the terms “we,” “us” and “our” refer
to NorthernStar Natural Gas Inc. and its consolidated subsidiaries and the terms “our projects” and
“our LNG terminal projects” refer to each of (i) Bradwood Landing LLC (Bradwood), (ii) Clearwater
Port Holdings LLC and Clearwater Port LLC (Clearwater), and (iii) Port Orion LLC (Orion)
individually or all three projects taken together as a group. Amounts in this prospectus are
expressed in U.S. dollars and all references in this prospectus to fiscal years made in connection
with our financial statements or operating results refer to our fiscal year ended on December 31 of
such year.
NorthernStar Natural Gas Inc. was founded in May 2005 to develop, own and operate liquefied
natural gas (LNG) receiving/importation terminals on the West Coast of the United States (West
Coast). We consolidated ownership of our LNG terminal projects in March 2006 to take advantage of
project portfolio diversification, economies of scale and greater access to capital.
The members of our senior management team have significant project development experience and
have been involved in the development of more than 50 energy infrastructure projects with an
aggregate cost of over $15 billion. They have been directly involved in either the development,
construction or operation of nine LNG terminal projects, including our three development projects.
Our LNG terminal projects, when complete, will provide direct access to major West Coast
natural gas demand centers. We intend to negotiate and sign terminal use agreements (TUAs) for all
or substantially all of the long-term base capacity of each LNG terminal with highly rated
creditworthy counterparties. We expect to provide offloading and regasification services under the
TUAs without taking ownership of LNG or natural gas. Each TUA is expected to have a 20-year term
and to generate a steady, predictable stream of contracted fee payments with no commodity price
risk. In addition, we may periodically sell capacity to third parties or purchase, regasify and
sell cargoes of LNG on a spot basis as opportunities arise when the terminals’ firm capacity is not
being utilized by our TUA customers, generating additional revenues to supplement those received
under the TUAs.
Our Industry
During the first nine months of 2006, the United States consumed an average of more than 60
billion cubic feet per day (Bcf/d) of natural gas. The U.S. natural gas market has higher
transaction volumes, more trading liquidity and more creditworthy counterparties than most other
natural gas markets. LNG only accounted for approximately 3% of total U.S. natural gas supply and
consumption in 2005. However, declining North American natural gas reserves coupled with steadily
increasing demand is creating a constrained supply of natural gas with a projected shortfall of 13
Bcf/d by 2015, according to the Energy Information Administration. The growing imbalance between
supply and demand has led to generally higher energy prices, resulting in an increase in the
announcement and development of LNG terminal projects in North America to tap the abundant proved
gas reserves located in remote locations around the world.
This imbalance is more pronounced on the West Coast, making it an attractive market into which
to sell LNG:
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The West Coast is a 9.0 Bcf/d natural gas market, representing approximately
15% of U.S. natural gas consumption in 2005. Natural gas trading volumes in the
key West Coast gas trading hubs have grown substantially over the past three
years and are among the most liquid and heavily-traded gas markets in the United
States. |
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The West Coast imports over 80% of its natural gas supply, primarily from
Canada, and is located at the end of a network of interstate natural gas
pipelines, making the market susceptible to supply disruptions. In addition, the
decline of production in Canada’s Western Canadian Sedimentary Basin coupled with |
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the 1.9% annual growth in Canadian consumption, driven by bitumen production and
integrated oil sands facilities, is expected to reduce Canadian exports to the
United States. |
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Major pipeline projects are in development to connect the U.S. Rockies natural
gas production with eastern pipelines including Kinder Morgan’s Rockies Express
and CenterPoint’s Mid-Continent Express which together is expected to transport
over 3 Bcf/d eastbound and further reduce available West Coast supply. |
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The Asia Pacific and Middle East regions have abundant natural gas reserves,
and according to Purvin and Gertz, LNG liquefaction capacity is projected to more
than double in these regions, from approximately 14.4 Bcf/d in 2005 to
approximately 36.3 Bcf/d in 2015. A significant portion of this incremental
capacity is presently not contracted and is available for export to West Coast
LNG Terminals. |
The primary functions of LNG terminals are offloading LNG from carriers and providing
regasification services to convert LNG back into natural gas suitable for transportation through
existing pipelines to end users. There are only five operational LNG terminals in the continental
United States, all of which are located on the East or Gulf Coasts of the United States. According
to the Federal Energy Regulatory Commission (FERC), five new LNG terminals are currently under
construction in North America, but only one of these is on the west coast of North America, located
on the Baja Peninsula in Mexico.
We believe that natural gas suppliers in the Asia Pacific and Middle East regions will have a
cost, including a 12% return on capital, to produce, liquefy, ship and deliver regasified LNG
through our LNG terminals to West Coast pipeline networks that will be $2.50-$4.70 per million
British thermal units (MMBtu). This will enable them to compete favorably with North American
domestic supplies of natural gas given current and projected natural gas market prices. On
December
5, 2006 the Henry Hub spot rate for natural gas was $7.32/MMBtu, and the average future
contracts
price on New York Mercantile Exchange (NYMEX) for first quarter 2011 deliveries, when we expect
Bradwood to begin operations, was approximately $8.02/MMBtu.
Our Projects
Our existing LNG terminal project portfolio consists of one project in Oregon/Washington and
two projects in Southern California.
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Our Bradwood project is designed as a land-based LNG terminal in a remote
location of Oregon on the Columbia River with deepwater channel access,
approximately 30 miles inland from the Pacific Ocean. We have entered into an
option agreement which allows us to purchase the property through August 2008.
Bradwood is engineered to have an initial sustainable base capacity of 1.0
billion cubic feet per day (Bcf/d), a peak capacity of 1.3 Bcf/d, and a
pre-engineered capability to expand the base capacity to 2.0 Bcf/d. Bradwood’s
location offers prospective customers, via a connecting pipeline discussed more
fully below in “Business —Bradwood,” convenient access to the region’s pipelines
serving a 9.0 Bcf/d market across Oregon, Washington, Idaho, Nevada and Northern
and Southern California. Bradwood is the only LNG terminal project in the Pacific
Northwest to have completed the Federal Energy Regulatory Commission (FERC)
prefiling process, and whose formal applications to the FERC have been accepted
into the application process under Sections 3 and 7 of the Natural Gas Act for
authorization to construct and operate an LNG receiving terminal and pipeline. We
are anticipating regulatory approvals by the FERC and remaining state and local
authorities in the third quarter of 2007. Based on this permitting timeline, we
anticipate the start of terminal construction in the fourth quarter of 2007, and
the commencement of commercial operations in the first quarter of 2011. |
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Our Clearwater project has contracted for the use of Platform Grace, an
existing oil and gas production platform located in federal waters approximately
13 miles offshore of Oxnard, California, which we intend to convert into an LNG
terminal. We have entered into an option agreement which allows us to purchase
the property through March 2012. The current owner will terminate oil and gas
production activities and permanently abandon production wells prior to our
taking possession of the platform. We plan to refurbish and reconfigure the
platform for regasification of LNG and to add two floating mooring |
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docks capable of accommodating large LNG carriers. Clearwater is engineered to have
a sustainable base capacity of 1.2 Bcf/d and a peak capacity of 1.4 Bcf/d. The
platform will be connected by a 13-mile offshore pipeline to the Southern
California Gas Co. (SoCalGas) pipeline network and storage infrastructure serving
the 4.0 Bcf/d Southern California market. SoCalGas will construct 65 miles of
pipeline to connect and to loop the existing system to receive 1.4 Bcf/d on a firm
basis. Clearwater signed a collectable work agreement with SoCalGas in 2004 to
initiate the engineering design of the pipeline and in August 2006 we entered into
a collectable system upgrade agreement with SoCalGas for the design and
construction of the required pipeline facilities. Clearwater filed its original
Deepwater Port (DWP) license application in February 2004, and, following our
purchase of this project in late March 2006, we submitted an amended and restated
application in June 2006 as a more comprehensive response to additional data
requests with direction from the relevant state and federal regulatory agencies.
Based upon new agency reviews, the U.S. Coast Guard and the California State Lands
Commission are expected to move forward with engagement of a contractor for the
preparation of our draft environmental reports. We are anticipating regulatory
approval in the second quarter of 2008, the commencement of construction in the
third quarter of 2008, and commencement of commercial operations in the second
quarter of 2010. |
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Our Orion project has a target location about 25 miles offshore of Carlsbad,
California with direct access to the Los Angeles and San Diego markets. Orion is
expected to be designed to include a concrete hull floating storage and
regasification unit with a sustainable base capacity of 1.2 Bcf/d, a peak
capacity of 1.5 Bcf/d. We intend to pursue the development of Orion in
conjunction with the approval process of our Clearwater project. |
Our three LNG terminal projects are designed to have an aggregate sustainable base capacity of
3.4 Bcf/d and expansion capability that could increase our base capacity to 4.4 Bcf/d.
We expect the proceeds of this offering to fund the equity portion of the construction of our
Bradwood LNG terminal project, to fund the continued development of our remaining initial projects,
to fund the development of LNG projects in addition to our initial projects
that we determine to have strong development potential, to pay the transaction costs related to
this offering and to fund working capital for general corporate purposes. We expect construction of
our LNG terminals to be funded by project financings supported by TUAs with highly rated
creditworthy parties. The aggregate construction cost for our Bradwood and Clearwater projects is
projected to be approximately $1.4 billion, excluding interest during construction and financing
fees. Through
September 30, 2006, we have incurred a total of approximately $20.8 million in
development costs for all three of our projects.
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NorthernStar Natural Gas Inc. |
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Bradwood |
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Clearwater |
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Orion |
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Columbia River, |
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13 miles offshore |
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Bradwood OR |
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Oxnard CA |
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Carlsbad CA |
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(dollars in millions) (capacity in Bcf/d) |
Base capacity |
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1.0 |
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Peak capacity |
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Expanded base capacity(1) |
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Target market(s) |
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OR, WA, ID, |
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CA, NV |
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S. CA |
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S. CA |
Market size |
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Primary permitting authority |
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Coast |
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Guard/CSLC |
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Expected primary permit |
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Third Quarter 2007 |
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Second Quarter 2008 |
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Expected commercial operations |
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First Quarter 2011 |
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Second Quarter 2010 |
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Not determined |
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$18 |
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$24 |
Estimated construction cost (1) (2) |
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Excludes development and construction cost of Bradwood base capacity expansion from 1.0 to
2.0 Bcf/d, excluding interest during construction and financing fees, of approximately $230
million. |
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Excluding interest during construction and financing fees. |
Our Competitive Strengths
We believe that our competitive strengths include the following:
Strategic project locations provide Pacific basin suppliers with access to attractive U.S.
West Coast markets. We have selected the locations of our LNG terminals because each offers (i)
access to attractive markets; (ii) reduced downstream transportation costs for our customers; (iii)
the opportunity for cost-effective development and construction, reducing unproductive capital
investments; and (iv) reduced development time for permitting and construction.
Significant barriers to entry based on advanced positioning in regulatory approval processes
and natural / existing infrastructure of LNG Terminal sites. We believe that Bradwood and
Clearwater, if completed on schedule, will be the first operating LNG terminals in their respective
markets. Bradwood is the only LNG project in the Pacific Northwest to
have completed the Federal Energy Regulatory Commission (FERC)
prefiling process under Section 3 of the Natural Gas Act for
authorization to construct and operate an LNG receiving terminal. We believe
Bradwood is approximately 6 to 12 months ahead of competing projects in the region reflecting the
current stage of its permitting activities. Its deepwater location does not require a costly
breakwater or significant dredging. Clearwater utilizes an existing platform and does not require
construction of LNG storage facilities, thus we believe that it can have a 24 to 30 months shorter
construction period compared to other offshore terminal designs.
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Portfolio of LNG Terminal projects provides economies of scale, market optionality and
increased likelihood for success. We believe that our portfolio of LNG terminal projects in Oregon
and California will be more attractive to potential TUA capacity holders than single project
entities because we can provide our terminal customers with flexibility to deliver LNG supply to
multiple receiving points connecting to several major pipelines and West Coast markets. Further, we
believe that simultaneously pursuing a portfolio of LNG terminals will provide economies of scale
at the development, TUA marketing, financing, construction and operating stages. We believe that we
will be able to leverage our knowledge and experience as we develop our projects to expedite the
permitting process and to increase the likelihood of success for each successive project.
Seasoned and incentivized management team with significant project development experience. The
members of our senior management team have significant project development experience, having been
involved in the development of more than 50 energy infrastructure projects with an aggregate
investment of over $15 billion. They have been directly involved in either the development,
construction or operation of nine LNG terminal projects worldwide including all three of the
existing projects currently being developed by us. Following the completion of this offering, our
senior management team will, directly or indirectly, control approximately % of our
outstanding common stock.
Our Strategy
Our strategy is to become a leading independent LNG terminal developer, owner and operator in
our targeted markets. These markets, including the West Coast, are those that we believe offer: (i)
attractive margins to potential LNG suppliers; (ii) fewer LNG terminal competitors; (iii) high
barriers to entry; and (iv) the potential to allow us to charge competitive rates with attractive
margins. We intend to implement this strategy through the following steps:
Target LNG Terminal Sites with Attractive Margins. We are presently developing LNG terminals
on the West Coast to help satisfy the region’s substantial existing and forecasted demand for
natural gas with LNG supplies from Asia Pacific, Middle East, and other potential LNG producers. We
believe these gas producers view the liquid, heavily-traded, creditworthy U.S. market as an
attractive alternative to other Pacific Basin LNG markets. We believe the barriers to entry caused
by the significant regulatory, environmental and public-concern hurdles in the West Coast market
will limit the number of LNG terminals built in this market. We believe that implementation of our
low cost, first-to-market strategy will give us a competitive advantage in securing TUAs with
attractive margins and highly rated creditworthy counterparties and in obtaining project financing
for construction of our LNG terminals.
Disciplined Project Development. The successful development and construction of LNG terminal
projects requires managing the complex interaction of legal requirements, regulatory processes,
technical knowledge, political environments, public policy and construction execution. Members of
our senior management team, who have developed more than 50 energy infrastructure projects with an
aggregate cost of over $15 billion, have formulated a disciplined project site feasibility and
pre-screening process to identify attractive terminal locations, and are adept at identifying
significant issues and challenges in completing our LNG terminals that require early resolution.
Once a site is selected, our senior management actively manages our project team of seasoned
professionals, who are supported by leading engineering, environmental, regulatory and legal firms.
Each project team strives to anticipate difficulties, define strategies and analyze the needs of
each constituent group and regulatory body so as to design the project to achieve as much
collaboration and widespread support as possible. By applying our disciplined project development
program, we believe that we will incur lower development and capital costs and more quickly
complete our projects. We believe that rapid and responsible development of low-cost LNG terminals
will greatly increase our likelihood of success.
Build Cost-Effective Terminals. Our disciplined project development strategy includes a
process for completing LNG terminals whose cost-effectiveness and location should allow us to
generate attractive margins from our TUAs. We have sited, and are designing and engineering our LNG
terminals to be cost-effective, reducing unproductive capital investments by: (i) locating our
projects in close proximity to major interstate gas transmission pipelines, thereby reducing
pipeline interconnection and construction costs, (ii) maximizing use of existing infrastructure
where possible, such as the existing platform for Clearwater and the existing onshore third-party
natural gas storage facilities in Southern California, and (iii) selecting sites that are
well-suited for LNG terminal operations such as Bradwood, whose deepwater location does not require
a costly breakwater or significant dredging.
Secure Long-Term Terminal Use Agreements. We intend to negotiate and sign firm capacity
20-year TUAs with highly rated creditworthy LNG suppliers, natural gas marketers, distribution
utilities or industrial consumers for all or
5
substantially all of our terminal base capacity. We expect that the terms of our standard TUA
will include an initial fee at the time of execution of the TUA, a fixed reservation charge for the
monthly throughput capacity, and a variable charge for each million British thermal units (MMBtu)
processed through the facility.
Lead Investor
MatlinPatterson Global Advisers LLC (MatlinPatterson), a global investment firm which manages
private equity funds which have raised $3.9 billion, is the lead investor in
our company.
MatlinPatterson (including its principals) has experience with a variety of companies with
involvement in energy and natural gas markets including: KGen Power Management LLC, NRG Energy,
Inc., Central Piedra Buena, S.A., Huntsman Corporation, and PT Medco Energi Internasional Tbk.
References to MatlinPatterson in this prospectus include, where appropriate, MatlinPatterson Global
Opportunities Partners II L.P. and MatlinPatterson Global Opportunities II (Cayman) L.P. and
certain
subsidiaries through which they have invested in
our Company.
Risk Factors
You should consider carefully the risks discussed under “Risk Factors” beginning on page 10.
These risks could materially and adversely impact our business, financial condition, operating
results, and cash flow, which could cause the trading price of our common stock to decline and
could result in a partial or total loss of your investment.
How You Can Contact Us
We are a Delaware corporation. Our principal executive offices are located at First City
Tower, 1001 Fannin, Suite 1700,
Houston,
TX 77002. Our telephone number is (
713) 599-4910. Our
website address is
http://www.northernstar-ng.com. The contents of our
website are not incorporated
by reference into this prospectus and you should not consider our
website part of this prospectus.
6
The Offering
| |
|
|
Issuer
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|
NorthernStar Natural Gas Inc. |
|
|
|
Common stock offered
|
|
shares (% of common stock to be outstanding after this offering) |
|
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|
Common stock to be
outstanding after
this offering
|
|
shares |
|
|
|
Use of proceeds
|
|
We expect to use approximately $ million to pay transaction fees pertaining
to this offering and other expenses. We expect to use approximately $ million for equity
financing for the construction of the Bradwood terminal project, the continued
development of our proposed LNG terminals, additional project development, and
working capital and general corporate purposes and approximately
$ million to pay transaction
fees pertaining to this offering and other expenses. |
|
|
|
Over-allotment option
|
|
We have granted the underwriters a 30-day option to purchase up to additional
shares of our common stock at the initial public offering price to cover
over-allotments. |
|
|
|
Dividend policy
|
|
We do not intend to declare or pay any dividends on our common stock in the
foreseeable future. |
|
|
|
Nasdaq Global Market
symbol
|
|
NSNG |
Except as otherwise indicated, the number of shares of common stock outstanding after this
offering as presented in this prospectus:
| |
• |
|
Excludes 4,100,611 shares of common stock issuable upon exercise of currently
outstanding options as of November 15, 2006 with an exercise price of $9.12. |
| |
| |
• |
|
Excludes shares of common stock issuable upon conversion of our Senior
Convertible Notes due 2013 (convertible notes), which totaled 11,346,552 shares
as of November 15, 2006, based upon an estimated conversion price of $9.12 per
share, including additional shares which will be issuable upon conversion as we
have elected to pay interest on these convertible notes in kind by increasing the
principal outstanding thereunder. Additional shares will be issuable upon
conversion should we elect to pay future interest due on the convertible notes in
kind. See “Description of Senior Convertible Notes” regarding the ultimate
determination of the conversion price. |
| |
| |
• |
|
Assumes no exercise of the underwriters’ over-allotment option. |
7
Summary Financial Data
The following table presents our selected consolidated historical financial information. The
consolidated statement of operations and balance sheet data for the period from inception (
May 17,
2005) through
December 31, 2005, and as of
December 31, 2005 are derived from our audited
consolidated financial statements and related notes included in this prospectus. The consolidated
statement of operations and balance sheet data for the nine months ended
September 30, 2006 are
derived from our unaudited consolidated financial statements included in this prospectus. The
consolidated statement of operations from the date of our inception through
September 30, 2006 is
derived from our audited and unaudited consolidated financial statements included in this
prospectus. In the opinion of management, the unaudited consolidated financial statements have been
prepared on the same basis as our audited consolidated financial statements and include all
adjustments, consisting of only normal recurring adjustments, necessary for a fair presentation of
the information set forth therein. As we are a recently formed development stage company with no
operating revenues, our historical results for any annual or interim period are not necessarily
indicative of results to be expected for a full year or for any future period as development
activities, and related costs have varied in the past and are anticipated to continue to vary in
the future. The net loss per share information is computed using the weighted average number of
units/common shares outstanding during the related period.
You should read this information together with “Capitalization,” “Management’s Discussion and
Analysis of Financial Condition and Results of Operations,” and our consolidated financial
statements and the related notes thereto included elsewhere in this prospectus.
| |
|
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|
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|
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|
|
|
| |
|
|
|
|
|
|
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Cumulative Period |
|
| |
|
|
|
|
|
|
|
|
|
from Inception (May |
|
| |
|
Inception |
|
|
|
|
|
|
17, 2005) |
|
| |
|
(May 17, 2005) |
|
|
Nine Months Ended |
|
|
through September |
|
| |
|
through |
|
|
September 30, 2006 |
|
|
30, 2006 |
|
| |
|
December 31, 2005 |
|
|
(Unaudited)(3) |
|
|
(Unaudited)(3) |
|
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Project prospecting |
|
|
— |
|
|
|
179,846 |
|
|
|
179,846 |
|
Project development |
|
|
7,712,256 |
|
|
|
13,107,813 |
|
|
|
20,820,069 |
|
Corporate general and administrative
costs |
|
|
887,288 |
|
|
|
27,315,410 |
|
|
|
28,202,698 |
|
|
|
|
|
|
|
|
|
|
|
Loss from operations |
|
|
(8,599,544 |
) |
|
|
(40,603,069 |
) |
|
|
(49,202,613 |
) |
|
|
|
|
|
|
|
|
|
|
Net other income/(expense) |
|
|
23,123 |
|
|
|
(2,231,705 |
) |
|
|
(2,208,582 |
) |
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(8,576,421 |
) |
|
$ |
(42,834,774 |
) |
|
$ |
(51,411,195 |
) |
|
|
|
|
|
|
|
|
|
|
Weighted average units/shares outstanding
basic and diluted (1) (2) |
|
|
130 |
|
|
|
27,356,833 |
|
|
|
27,330,969 |
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net loss per share |
|
$ |
(65,972.47 |
) |
|
$ |
(1.57 |
) |
|
$ |
(1.88 |
) |
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents(4) |
|
$ |
1,382,873 |
|
|
$ |
82,358,255 |
|
|
|
|
|
Working capital(4) |
|
|
310,593 |
|
|
|
77,884,362 |
|
|
|
|
|
Deferred financing costs(4) |
|
|
— |
|
|
|
6,624,940 |
|
|
|
|
|
Total assets(4) |
|
|
2,259,670 |
|
|
|
91,605,118 |
|
|
|
|
|
Debt and advances payable, including
current portion(4) |
|
|
— |
|
|
|
110,868,898 |
|
|
|
|
|
Members’/Stockholders’ equity (deficit) |
|
|
83,406 |
|
|
|
(25,584,335 |
) |
|
|
|
|
|
|
|
| (1) |
|
Amount does not include 4,100,611 shares of common stock issuable as of November 15, 2006,
upon the exercise of outstanding options exercisable at $9.12 per share or 11,346,552 shares
issuable, as of November 15, 2006, upon conversion of convertible notes based on an estimated
conversion price of $9.12 per share. Additional shares will be issuable upon conversion should
we elect to pay future interest due on the convertible notes in kind. See “Description of
Senior Convertible Notes” regarding the ultimate determination of the conversion price. |
8
| (2) |
|
As of December 31, 2005 the Company had units outstanding as a limited liability company and
was not subject to federal income tax. Amounts at September 30, 2006 reflect our
reorganization into a corporation on May 16, 2006 and the contemporaneous conversion of the
units into common shares, by issuing 210,000 shares for each unit exchanged. |
| |
| (3) |
|
Our financial results for the nine months ended September 30, 2006 reflect a net loss of
$42.8 million, or $1.57 per share (basic and diluted). The major factors contributing to our
loss per share at September 30, 2006 were $13.1 million in development costs for our projects,
$13.9 million in consulting fees relating to the acquisition of the project companies, and
$13.4 million in other general and administrative expenses. |
| |
| (4) |
|
As of September 30, 2006, we had cash of $82.3 million, working capital of $77.9 million,
unamortized deferred financing costs of $6.6 million, total assets of $91.6 million, and debt
and advances of $110.8 million provided primarily by or directly related to the issuance of
our convertible notes. |
9
RISK FACTORS
An investment in our common stock involves risk. You should carefully consider the risk
factors set forth below as well as the other information included in this prospectus before buying
shares of our common stock. Any of these risks may have a material adverse effect on our business,
financial condition, results of operation and cash flow, and may cause the trading price of our
common stock to decline. In that case, you may lose all or part of your investment. The risks
described below are not the only ones faced by us. Additional unknown risks or those we currently
deem immaterial may also impair our business operations.
Risk Factors Related to Us as a Recently Formed Development Stage Company Engaged in Project
Development
We are a recently formed development stage company engaged in project development with limited
operating history. If we are unable to successfully construct and commence operations of our LNG
terminals, our business will be materially and adversely affected and you could lose all or a
significant portion of your investment.
We are a recently formed company engaged in project development with limited operating
history. Although we have begun preliminary engineering work on each of our three liquefied natural
gas (LNG) terminal projects, we have not received any of the permits or approvals necessary to
start the construction of any of our planned LNG terminals. We are subject to significant business,
economic, regulatory and competitive uncertainties as well as the risks associated with any new
business, including the risk that we may not be able to develop, build or operate any of our
planned LNG terminals. If we do not successfully manage the development of our business or if we
experience delays in the implementation or completion of our business plan, our business could be
materially and adversely affected and you could lose all or a significant portion of your
investment.
We currently have no operating revenues and negative cash flow, and we may not be able to achieve
profitability and generate positive cash flow in the future.
We currently have no operating revenues. During 2005, we incurred combined net losses of $8.6
million and in the nine months ended
September 30, 2006, we incurred net losses of $42.8 million.
We will continue to incur losses and experience negative operating cash flow during the next
several years through the development and construction stages of the LNG terminal projects. We do
not anticipate that we will generate revenues until at least one of our planned LNG terminals is
completed, which we do not expect to occur until 2010 or later. In addition, following the
completion of our LNG terminals, we may continue to incur losses on our in-development projects
which reduce or exceed any profits generated by these operating projects.
In addition, we will continue to incur significant capital and operating expenditures while we
develop our planned LNG terminals. We do not anticipate that the advances we expect to receive from
customers for sales of regasification capacity at our planned LNG terminals will generate
sufficient funds to cover these expenditures. We expect to continue to have operating losses and
negative cash flow on a quarterly and annual basis over the next several years. Any delays in the
permitting and construction process could increase the level of our operating losses and extend the
period for which we will have operating losses and negative cash flow. Our ability to generate
positive operating cash flow and achieve profitability is dependent on our ability to successfully
complete our LNG terminal projects. If we do not generate positive operating cash flow, you could
lose all or a significant portion of your investment. Further, capital and operating expenditures
are not the only factors that may contribute to our net losses. For example, the interest expense
on our convertible notes of up to $7.0 million annually will contribute to our net losses. As a
result, even if we experience positive operating revenues and cash flow in the future, we may
continue to incur net losses.
The proceeds from this offering may not be sufficient to finish development of any of our LNG
terminal projects.
We currently estimate that the remaining development cost as of
September 30, 2006 for our
three LNG terminal projects will be approximately $62 million, and expect that certain of these
costs will be funded by the proceeds of this offering. However, we cannot assure you that our
development costs will not exceed the amount raised from this offering due to unforeseen
circumstances and delays in the permitting process. We will continue to incur significant
expenditures as long as we are developing our planned LNG terminals. In the event we cannot
complete development of an LNG terminal project, we will not be able to begin construction and may
not be able to obtain further development financing or construction financing
10
to complete the project. In such event our business would be materially and adversely affected
and you could lose all or a significant portion of your investment.
The proceeds from this offering are not sufficient to construct any of our proposed LNG terminals.
We must obtain separate and additional financing in order to construct our planned LNG terminals.
We
currently estimate that the aggregate cost of completing our Bradwood
and Clearwater LNG terminals will be
approximately $1.4 billion, excluding interest during
construction and financing fees and the cost of our Orion LNG
terminal has not yet been determined. In the event
third parties do not finance and construct certain pipelines connecting our LNG terminals to gas
distribution pipeline systems, we may need to expend materially greater amounts to complete such
pipelines. To fund construction, we will have to obtain additional debt financing, and, if
insufficient, additional equity financing by us and/or at our project subsidiary level. Our ability
to obtain financing will depend, in part, on factors beyond our control, such as capital market and
industry conditions at the time financing is sought. We cannot assure you that we will be able to
obtain the additional financing.
The terms of our outstanding convertible notes provide for additional shares to be issued upon
conversion if we sell shares of our common stock at a price that is less than the average trading
price of our common stock over the 10-day period prior to any such sale, which might further limit
our access to the capital markets.
In addition, our ability to obtain certain types of financing may depend on our ability to
obtain other types of financing. For example, project level debt financing is often contingent upon
a significant equity capital contribution from the project developer. As a result, even if we are
able to identify potential project level lenders, we may still have to raise additional capital for
us to fund the required equity capital contribution. Any project level debt financing will also
typically be conditioned upon our prior receipt of commitments for at least a portion of projected
LNG terminal regasification capacity under long-term terminal use agreements (TUAs), and our
ability to fund the projects will likely be subject to the achievement of additional milestones in
our project financing. If we fail to obtain financing at any point in the construction process, our
business would be materially and adversely affected and you could lose all or a significant portion
of your investment.
Even if we are able to obtain financing for the construction of our planned LNG terminals, the
terms of the financing may adversely affect our ability to operate our business.
In order to obtain further financing, we may have to accept terms that are disadvantageous to
us or that may have an adverse impact on our current or future business, operations or financial
condition. These terms may have the following results, among others:
| |
• |
|
borrowings or debt issuances by us or at the project level would result in
increased interest expense and add to our need for cash to service such debt and
may subject us or the project entity to certain restrictive covenants, including
covenants restricting our or the project entity’s ability to raise additional
capital or our ability or the ability of our project subsidiaries to make
distributions, and may require us to pledge our interest in the project
subsidiaries which could result in the loss of our equity interest in an LNG
terminal; |
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| |
• |
|
sales of equity interests in our project subsidiaries would reduce our
interest in future revenues once the LNG terminals commence operations; and |
| |
| |
• |
|
the prepayment of terminal use fees by, or business development loans from,
prospective customers would reduce future revenues once the LNG terminals
commence operations. |
Risks Related to the Development and Construction of LNG Terminals
Failure to obtain the necessary approvals and permits from governmental and regulatory agencies
could prevent us from constructing or operating one or more of our LNG terminals.
The design, construction and operation of LNG terminals and interconnecting pipelines and the
transportation of LNG and natural gas are all highly regulated activities. The approval of the
Federal Energy Regulatory Commission (FERC) under Section 3 of the Natural Gas Act of 1938, or the
NGA, as well as numerous other material governmental and regulatory
11
approvals and permits are required in order to license, site, construct and operate our
proposed LNG terminals. The Coast Guard has responsibility under the Deepwater Port Act of 1974, as
amended (DWPA), for approval of any offshore LNG terminals in federal waters. The DWPA approval
requires that the Secretary of Transportation seek the de facto approval of the governor of the
adjacent coastal state, California, prior to the licensing of a deepwater port. The governor of
California must approve or deny the DWPA license within 45 days of the last Federal DWPA hearing.
If the governor does not act within 45 days, approval will be presumed. In addition, a FERC
certificate of public convenience and necessity under Section 7 of the NGA, as well as numerous
other material governmental and regulatory approvals and permits, are required to construct, own,
and operate interstate pipelines connecting with an LNG terminal. Although we have formally filed
for the FERC authorization for Bradwood and filed the DWP license for Clearwater, we have not yet
obtained the required permits to construct and operate our proposed LNG terminals. We cannot assure
you of the outcome of the review and approval process and we cannot assure you that a filing will
ever be made with regard to Orion. If we are unable to obtain the necessary approvals and permits,
our business would be materially and adversely affected and you could lose all or a significant
portion of your investment. In addition, if we are unable to obtain the necessary approvals and
permits for our initial LNG terminal projects, we may use the proceeds from this offering to fund
the development of other projects, which may not yield results equivalent to those expected of such
LNG terminal projects and you could lose all or a significant portion of your investment.
Existing and future governmental regulation, taxation and price controls could seriously harm our
business.
Our LNG terminal projects will be subject to extensive federal, state and local laws and
regulations that regulate the release of materials into the environment or otherwise relate to the
protection of the environment. These laws and regulations may restrict or prohibit the types,
quantities and concentration of substances that can be released into the environment and impose
substantial liabilities on us for pollution or releases of hazardous substances. Failure to comply
with these rules and regulations may result in substantial penalties and harm our business. Present
and future legislation and regulations could cause additional expenditures, restrictions and delay
the commencement of our operations, to an extent which we cannot predict and which may require us
to substantially limit, delay or cease construction or operations in some circumstances. The
imposition of price controls on energy products could limit our markets or adversely affect our
ability to complete our projects.
Federal laws such as the Comprehensive Environmental Response, Compensation and Liability Act;
the Clean Air Act; the Clean Water Act; and the Coastal Zone Management Act and analogous state
laws have regularly imposed increasingly strict requirements for water and air pollution control,
hazardous and solid waste management and financial responsibility and remedial response
obligations. Existing environmental laws and regulations may be revised or new laws and regulations
may be adopted or become applicable to us. Revised or additional laws and regulations could result
in increased compliance costs or impose additional operating restrictions on us. The cost of
complying with existing and future environmental legislation could adversely affect our business
and you could lose all or a significant portion of your investment.
The completion of one or more of our LNG terminals is subject to a number of risks, which could
prevent construction at all or could cause cost overruns and delays in the completion of
construction.
Key factors that may affect the timing of, and our ability to complete, our LNG terminals
include:
| |
• |
|
the issuance of necessary permits, licenses and approvals from the FERC, the
Coast Guard and other governmental agencies as are required to construct and
operate the facilities; |
| |
| |
• |
|
the terms and availability of sufficient debt financing and equity financing,
both on our part and at the project level, for development and construction of
our LNG terminal projects; |
| |
| |
• |
|
our ability to enter into a satisfactory agreement with an engineering,
procurement and construction (EPC) contractor for each facility and to maintain
good relationships with these contractors, and the ability of these EPC
contractors to perform their obligations satisfactorily under EPC agreements and
to maintain their creditworthiness; |
| |
| |
• |
|
site development difficulties, including change orders, cost overruns,
construction delays and changes in the price of construction materials or labor; |
12
| |
• |
|
unanticipated changes in international and domestic market demand for natural
gas or the supply of LNG, which will depend, in part, on supplies of, and prices
for, alternative energy sources; |
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| |
• |
|
competition with other domestic and international LNG terminals; |
| |
| |
• |
|
commercial arrangements for pipelines and related equipment to transport
natural gas from each LNG terminal; |
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| |
• |
|
local and general economic conditions; |
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• |
|
catastrophes, such as accidents, fires, and product spills, as well as acts of terror or sabotage; |
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• |
|
resistance and challenges in the local community and governmental agencies,
including through litigation and regulatory challenges, to the development and
construction of LNG terminals; |
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| |
• |
|
labor disputes; and |
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| |
• |
|
weather conditions. |
Delays in the commencement of construction of any of our LNG terminals beyond the estimated
development period could also increase the cost of completion beyond the amounts currently
estimated in our capital budget, which could require us to obtain additional sources of financing
to fund our operations until our LNG terminals are completed, which could cause further delays and
impact the competitive position of our LNG terminal projects. Any delay in the completion of any of
our LNG terminals would also cause a delay in the receipt of revenues projected from operation of
the LNG terminals. Thus, any significant construction delay, whatever the cause, could adversely
affect our ability to complete construction of our LNG terminals in a timely manner, or at all,
which would materially and adversely affect our business and you could lose all or a significant
portion of your investment.
If sufficient LNG liquefaction capacity is not constructed, we may not be able to secure TUAs for
one or more of our LNG terminals.
There is currently a shortage of LNG liquefaction capacity globally. While there are numerous
LNG liquefaction facilities currently being constructed in the Asia Pacific and Middle East regions
to bring natural gas to market, commercial development of an LNG liquefaction facility can take
anywhere from three to 10 years and requires a substantial capital investment. If sufficient LNG
liquefaction capacity is not constructed, we may not be able to secure adequate TUAs for one or
more of our LNG terminals, which would materially and adversely affect our business and you could
lose all or a significant portion of your investment.
Failure of imported LNG to become a competitive source of energy in the United States could have a
detrimental effect on our ability to implement and complete our business plan.
In the United States, imported LNG has not been a major energy source. Historically, LNG, as
an energy source, competes directly with natural gas and through the use of improved exploration
technologies, additional sources of natural gas may be discovered in North America, which would
increase the available supply of natural gas at potentially lower costs than importing LNG. In
addition to natural gas, LNG also competes with other sources of energy, including liquid petroleum
gases such as propane and butane, coal and coal-derived synthetic gas, oil and refined oil
products, nuclear, hydroelectric, wind, biomass, and solar energy.
As a result, LNG may cease to be a competitive source of energy in the United States which
could prevent or limit our ability to secure TUAs. The failure of LNG to continue as a competitive
supply alternative to domestic natural gas, oil and other energy sources would materially and
adversely affect our business and you could lose all or a significant portion of your investment.
13
We are impacted by fluctuations in energy prices or the supply of LNG that could be particularly
harmful to the development of our LNG terminal business because of our early stage of development.
If the delivery cost of LNG is higher than the delivery cost of domestically produced natural
gas or natural gas derived from other sources, until such time as we enter into TUAs on
commercially favorable terms, our ability to attract customers to purchase our capacity may be
negatively impacted. In addition, in the event the supply of LNG is limited or restricted for any
reason, our ability to profitably operate an LNG terminal could be materially impacted. Revenues
generated by an LNG terminal depend on the volume of LNG processed and the price of the natural gas
produced, both of which can be affected by the price of natural gas and natural gas liquids. In
particular, our ability to obtain financing in the amounts we require and on commercially favorable
terms may be compromised because fluctuations in energy or LNG prices may cause uncertainty in the
market and cause lenders and other sources of funding to become wary of lending to or investing in
our industry. In addition, extreme gas price volatility may discourage interim commitments.
We face competition in developing LNG terminals from competitors with far greater resources.
Many other companies are or are considering building LNG terminals, including major oil and
gas companies such as ExxonMobil Corporation, ConocoPhillips, Royal Dutch/Shell Group and Chevron
Corporation. Other energy companies such as Cheniere Energy, Inc., Sempra Energy, Suez LNG North
America, McMoRan Exploration Co., AES Corporation, Excelerate Energy, LLC, BHP Billiton Limited and
Woodside Energy Inc. and other public and private companies have also proposed LNG receiving
facilities in North America, both onshore and offshore. Most of our competitors have longer
operating histories, greater name recognition, larger staff, and substantially greater financial,
technical and marketing resources than we do. The superior resources that these competitors have to
deploy increases the likelihood that they will successfully develop LNG terminals and could allow
them to complete their LNG terminals before we complete our LNG terminals. Among other things, our
competitors may not have to rely on external financing to the same extent we do, if at all. The
existence and timing of competing LNG terminal development projects may make our ability to obtain
financing for construction more difficult or more expensive. Because only a limited number of LNG
terminals are likely to be constructed in the United States and on the West Coast in particular, if
our competition is successful in developing and building their LNG terminals before we develop and
build our LNG terminals, it would materially and adversely affect our business and you could lose
all or a significant portion of your investment.
We may not be able to enter into enough long-term TUAs or obtain enough customers to implement and
complete our business plan.
Our ability to obtain project level financing for each LNG terminal is likely to be contingent
on our ability to enter into long-term TUAs covering a significant portion of our regasification
capacity in advance of the commencement of construction. We expect to securitize or pledge revenues
to be generated under the TUAs to obtain financing for our construction costs. We have not yet
entered into any TUAs. We may not be able to attract customers or enter into TUAs because we are a
recently formed development stage company with no operating history in the LNG terminal business.
In order to succeed, we must convince potential customers, among other things, that the LNG
terminals that we are developing will obtain and maintain required government approvals and that we
will be able to secure adequate financing for their construction and to construct them successfully
and on a timely basis. If these efforts are not successful, we may not be able to secure long-term
TUAs or financing for our LNG terminals and our business would materially and adversely affected
and you could lose all or a significant portion of your investment.
Potential for overcapacity in the LNG terminal market and other factors could adversely impact our
ability to enter into long-term TUAs and our ability to successfully operate our business.
Industry analysts have predicted that if all of the proposed LNG terminals in North America
that have been announced by developers were actually built, there would likely be substantial
excess capacity for such LNG terminals in the future. Accordingly, there is a substantial risk that
some projects may never be completed. Any perception in the marketplace that we may be unable to
complete our proposed LNG terminals could have a material adverse effect on our ability to obtain
construction financing and on the market price of our shares.
If the number of LNG terminals built outstrips demand for natural gas from those LNG
terminals, the excess capacity likely will prevent later market entrants from entering into
long-term TUAs with highly rated creditworthy customers and lead to a decrease in the prices that
LNG terminals will be able to obtain for uncommitted amounts of regasification services. Because we
anticipate that we will have significant debt service obligations, if we are unable to enter into
long-term TUAs
14
with highly rated creditworthy customers, any such price decreases would impact us more
severely than competitors that have greater financial resources. Accordingly, potential
overcapacity in the LNG terminal marketplace could have a material adverse effect on our ability to
enter into long-term TUAs with highly rated creditworthy customers and would materially and
adversely affect our business and you could lose all or a significant portion of your investment.
The construction of our proposed LNG terminals will be dependent on performance by, and our
relationship with, the EPC contractor that we engage at each facility.
We plan to enter into turnkey
contracts with one or more major EPC contractors for the
construction of our proposed LNG terminals. The success of our LNG terminal projects is highly
dependent on our ability to enter into acceptable
contracts with reputable EPC contractors and for
these contractors to perform their obligations under the
contracts, including completing the
projects on a timely basis. Nevertheless, we may not be able to enter into acceptable EPC
contracts
for the construction of our proposed LNG terminals. As a result, we may encounter unexpected delays
or problems in connection with the construction of any of our proposed LNG terminals. Moreover, any
EPC
contract could be terminated under certain circumstances prior to completion of construction.
If our relationship with any initial EPC contractor were to fail, we would be forced to engage a
substitute contractor, which would likely result in increased construction costs and a delay in
construction of our LNG terminals, which would materially and adversely affect our business and you
could lose all or a significant portion of your investment.
The cost of constructing our proposed LNG terminals will be dependent on several factors, including
change orders, cost overruns and commodity prices. As a result, if completed, the actual
construction cost of these facilities may be significantly higher than our current estimates,
excluding interest during construction and financing fees.
Although certain of our senior management have experience developing and constructing LNG
terminals, we have no prior experience in constructing LNG terminals. Prior to 2005, no LNG
terminal had been constructed in the continental United States in over 25 years. If we are able to
commence construction on our projects, we may decide or be forced to submit change orders to our
EPC contractor that could result in a longer construction period and higher construction costs and
greater financing costs. Similarly, we may encounter significant cost overruns during some phases
of the construction process. In addition, under any agreement with an EPC contractor, we may retain
the commodity price risk for construction materials. As a result, any significant change orders,
cost overruns or increases in the price of construction materials and labor would materially and
adversely affect our business and you could lose all or a significant portion of your investment.
We may not be able to hire or maintain the staff or contractors necessary to construct or operate
our LNG terminals, which may have a material adverse effect on our ability to implement our
business plan and our ability to generate revenues and profits.
As of
November 15, 2006, we had 23 employees and many contractors who are primarily focused on
the development of our proposed LNG terminals. Once we begin construction, we will need to hire
onsite employees to manage the construction of each facility and EPC contractors and other
contractors to construct the LNG terminals. Later, once we commence operations, we will need to
hire a full staff to operate each completed facility. Only our senior management has experience in
the construction or operation of LNG terminals, and, as a result, we will be forced to rely
significantly on the employees we hire to perform these functions. We currently estimate that 35 to
40 employees will be required to operate each LNG terminal. As our operations expand,
we will also have to expand our administrative staff. If we are unable to locate or attract as
employees individuals who can carry out these construction and operations roles, our business could
be materially and adversely affected.
We may invest in additional LNG terminal projects and/or change our operating and investment
strategy and make other LNG-related investments, including upstream and downstream opportunities,
which may entail greater risk.
We may consider acquisitions of additional LNG terminal projects. We cannot assure you that we
will be able to identify, acquire, continue to develop, or profitably manage additional LNG
terminal projects or that we will be able to successfully integrate any acquired LNG terminal
projects without substantial costs, delays, or other operational or financial problems.
Acquisitions involve a number of special risks, including failure of the acquired business to
achieve expected results, diversion of management’s attention, failure to retain key personnel of
the acquired business and risks associated with unanticipated events or liabilities. If we
experience any regulatory problems or negative publicity with regard to any LNG
15
terminal project, it could have a generally adverse effect on our reputation and harm our
local, regional, or national development initiatives. In addition, we cannot assure you that any
acquired projects will be completed or produce any revenues or earnings.
We may finance future acquisitions, if any, by using shares of our common stock for a
substantial portion of the consideration to be paid. If potential acquisition candidates are
unwilling to accept common stock as part of the consideration for the sale of their businesses, we
may be required to pay cash, if available, in order to complete any acquisitions. If we do not have
sufficient cash resources to make acquisitions, we may miss important corporate opportunities,
experience dilution, or otherwise be unable to execute our business strategy. Acquisitions using
our common stock will dilute the interests of all stockholders, and if the effective value of our
common stock declines due to dilution, your investment could be materially adversely affected.
We may also change our operating and investment strategy at any time without your consent,
which could result in our acquiring or investing in projects that are different from, and possibly
riskier than, the LNG terminal projects described in this prospectus, such as natural gas pipelines
and storage, marketing and trading, LNG shipping, oil and gas exploration, development and
transportation, securing foreign LNG supply arrangements and developing foreign natural gas
reserves that could be converted to LNG. We may not be successful in any future acquisitions of LNG
terminal projects or in pursuing any downstream or upstream LNG opportunities and, even if
successful, we could be exposed to greater and unanticipated risks. Any changes to our operating
and investment strategy could cause us to become a substantially different company, which could
adversely affect our business and financial condition.
If we begin conducting development, construction or operations of LNG terminals outside of the
United States due to any potential foreign acquisition or other opportunity our financial condition
and results of operations may be materially adversely affected by economic, political and
governmental conditions in the countries where we engage in business. Any disruptions caused by
these factors could harm our business, including the risks of war, expropriation or nationalization
of assets, renegotiation or nullification of existing
contracts, changing laws and policies
affecting trade, taxation and investment, fluctuating currency values and exchange rates and
overlap of tax structures.
Risks Related to Operating Our Business
We depend on key personnel, and the loss of any of these individuals could have a material adverse
effect on our business and operations.
Several of our executive officers, including Mr. Garrett, our Chief Executive Officer, Mr.
Soanes, our President, and Mr. Glessner, our Vice President, Engineering and Construction, have
been involved in the development of our LNG terminals prior to our founding and are familiar with
the development plans and issues. In addition, these individuals have extensive project development
experience in the energy sector, including with respect to LNG terminals. The loss of services of
one or more of these individuals could prevent or delay the development of our LNG terminals and
could have a material adverse effect on the success of our business.
Certain of our executive officers have the right to pursue other business interests which may
adversely affect our ability to achieve our strategic plan.
Mr. Garrett, Mr. Soanes and Mr. Phillips may only hold an ownership interest in, hold an
executive officer position with, have defined services with respect to and sit on the board of, one
or more biodiesel businesses without violation of their respective employment agreements if (1)
such activities do not materially interfere with the performance of duties under their employment
agreements and (2) such business or businesses do not enter into any line of business that competes
with the business of
the Company or its affiliates. Nevertheless, these other business interests
may demand their attention and reduce the amount of time they have available to devote to our
business, which may adversely affect our ability to implement our business plan successfully.
We expect to enter into TUAs that will be subject to termination by our capacity holders under
certain circumstances, and we expect to be generally dependent on the performance of those
counterparties under the TUAs.
We expect to enter into long-term TUAs under which payments received from our capacity holders
will be our principal source of operating income. Each TUA will contain various termination rights.
For example, these rights may include the right to terminate a TUA during the construction period
of a proposed LNG terminal for any reasonable determination that “substantial completion” of the
terminal will not occur prior to a future date or if we fail to reach certain milestones. It may
16
not be possible to replace a TUA on desirable terms, or at all, if a TUA is terminated. In
addition, we may be dependent on our capacity holders’ creditworthiness and their continued ability
and willingness to perform their obligations under our TUAs and may be subject to a concentration
of credit risk due to the minimal number of counterparties. If any of our capacity holders were to
fail to perform under its respective TUA, our revenues could be materially adversely affected, even
if we were to be ultimately successful in seeking damages from that counterparty for a breach of
the TUA. In addition, termination of a TUA and failure to obtain a replacement TUA may constitute
an event of default on our indebtedness, which could lead to foreclosure upon our facilities which
would materially and adversely affect our business and you could lose all or a significant portion
of your investment.
The inability of potential LNG customers to import LNG into the United States due to, among other
things, governmental regulation, potential instability in countries that supply natural gas or
other circumstances beyond our control could adversely affect our business and you could lose all
or a significant portion of your investment.
Upon completion of our LNG terminals, our business will be dependent upon the ability of our
customers to import LNG into the United States. Political instability in foreign countries that
supply LNG, or strained relations between those countries and the United States, may impede the
ability of LNG suppliers in those countries to export LNG to the United States. These foreign
suppliers may also be able to negotiate more favorable prices with other LNG customers around the
world than with customers in the United States, thereby reducing the supply of LNG available to be
imported into the U.S. market. In addition, the lack of sufficient LNG carriers available to
deliver the forecasted amount of LNG would impede our customers’ ability to import LNG into the
United States.
Furthermore, our customers may be able to suspend, terminate, or otherwise not perform
obligations under their
contracts upon the occurrence of events of force majeure, including but not
limited to strikes and other industrial or labor disturbances, terrorism, restraints of government,
civil disturbances, accidents or breakages of machinery, failure of suppliers, interruptions or
delays in transportation, or any natural disaster, all being circumstances out of our control.
Any significant impediment to our customers’ ability to import LNG into the United States or
their ability to suspend, terminate or otherwise not perform their obligations under their
contracts could adversely affect our business and you could lose all or a significant portion of
your investment.
Volatility in the demand for LNG regasification capacity may result in reduced operating revenues.
If we do not
contract for all of our base capacity through long-term TUAs, we will be forced
to sell our capacity on the spot market. Spot market sales are subject to cyclical swings in
prices, which could adversely affect our results of operations and the value of your investment.
Any resulting increases and decreases in the available supply of natural gas and volatility in
the demand for LNG receiving capacity could adversely affect our business and you could lose all or
a significant portion of your investment.
LNG terminals are subject to significant operating hazards and uninsured risks, one or more of
which may create significant liabilities for us.
The construction and operation of our proposed LNG terminals will be subject to the inherent
risks normally associated with these types of operations, including accidents, pollution, adverse
weather conditions and other hazards, each of which could result in damage to or destruction of our
facilities or damage to persons and property for which we could be liable. In addition, our
operations face possible risks associated with acts of aggression on our assets and the assets of
third parties on which our operations are dependent.
In accordance with customary industry practices, we intend to maintain insurance against some,
but not all, of these risks and losses. We may not be able to maintain adequate insurance in the
future at rates that we consider commercially reasonable. The occurrence of a significant event not
fully insured or indemnified against could have a material adverse effect on our business and
operations and, in the event of a partial or total loss, our ability to repair or replace the
damaged assets.
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The impact of natural disasters such as earthquakes, volcanic eruptions, tsunamis, hurricanes and
floods could have a material adverse effect on our business and operations.
The construction and operation of our proposed LNG terminals on the West Coast could be
materially adversely affected by earthquakes, volcanic eruptions, tsunamis, hurricanes, floods, and
other similar natural catastrophes.
Terrorist attacks or sustained military campaigns may adversely impact our business.
The terrorist attacks that took place in the United States on
September 11, 2001 were
unprecedented events that have created many long-lasting economic and political uncertainties, some
of which may materially adversely impact our business. The continued threat of terrorism and the
impact of military and other action will likely lead to continued volatility in prices for natural
gas and could affect the markets for the operations of LNG customers on which we will be dependent.
Furthermore, the U.S. government has issued public warnings indicating that pipelines and other
energy assets might be specific targets of terrorist organizations. The continuation of these
developments may subject our operations to increased risks and, depending on their ultimate
magnitude, could have a material adverse effect on our business, operations, financial condition,
and the value of your investment.
In addition, LNG and oil facilities, shipyards, carriers, pipelines, and oil and gas fields
and virtually all other energy-related facilities could be targets of future terrorist attacks. Any
such attacks could lead to, among other things, bodily injury or loss of life or other property
damage, increased operational costs, including insurance costs, and the inability to operate our
LNG terminals. Terrorist attacks, war or other events beyond our control that adversely affect the
distribution, production or transportation of LNG could reduce payments under our TUAs or entitle
our customers to terminate our TUAs, which could materially and adversely affect our business and
you could lose all or a significant portion of your investment.
Our bylaws do not prevent our directors from pursuing or acquiring corporate opportunities that may
be in competition with us and as a result may adversely affect our financial condition and results
of operations.
Our
bylaws provide that if one of our directors that is a member, manager, principal,
employee, or other representative or nominee of a large financial institution or investment fund,
or any affiliate thereof, who is a holder of our common stock, acquires knowledge of an investment
opportunity, such director will be deemed not to have violated its fiduciary duty to us and our
stockholders and such director will not be liable to us or our stockholders for breach of any
fiduciary duty by reason of the fact that the director (or the related financial institution or
investment fund) pursues or acquires the opportunity for itself or directs the opportunity to
another person or does not communicate information regarding the opportunity to us.
As a result, certain of our directors may pursue corporate opportunities directly competitive
with our business, rather than presenting corporate opportunities to us, which may materially and
adversely affect our financial condition and results of operations.
We may be required to repurchase all or a portion of our convertible notes in cash on May 17, 2009.
The holders of our convertible notes may require us to repurchase all or any portion of the
convertible notes on
May 17, 2009 in cash at a price equal to the conversion amount applicable to
the principal amount being redeemed plus interest accrued but not paid. Based on the amount of
convertible notes outstanding as of
November 15, 2006, if we were to be required to redeem all of
the convertible notes we would be required to make cash payments to convertible note holders in an
aggregate amount of up to $103.5 million plus interest accrued
through
May 17, 2009, unless all or a portion of the convertible notes are
converted by the holders or redeemed by us prior to such date. In addition, if we choose to pay
interest on the convertible notes in kind with additional convertible notes, our cash requirements
if we are required to repurchase the convertible notes will increase. If we do not have sufficient
cash to meet our repurchase obligations under the convertible notes we may suffer material harm to
our ability to operate our business or be required to obtain financing on less favorable terms than
would otherwise be available to us.
Risks Related to Our Common Stock
Our stock price may decline due to sales of shares by our other stockholders.
Sales of substantial amounts of our common stock, or the perception that these sales may
occur, may adversely affect the price of our common stock and impede our ability to raise capital
through the issuance of equity securities in the future. All shares sold in this offering are
freely transferable without restriction or further registration under the Securities Act, subject
to
18
restrictions that may be applicable to our affiliates, as that term is defined under Rule 144
under the Securities Act. In addition, our convertible notes are convertible into 11,346,552 shares
of our common stock based on our estimated conversion price of $9.12 per share. In addition,
substantially all of the shares held by our existing stockholders are subject to registration
rights, and we believe these rights will be exercised. A significant number of these shares may be
sold, which may decrease the price of shares of our common stock.
In connection with this offering, we and our executive officers, directors, substantially all
our stockholders, and all the holders of our convertible notes entered into 180-day lock-up
agreements. These lock-up agreements prohibit us and our executive officers, directors, and such
stockholders and holders of our convertible notes from selling or otherwise disposing of shares of
our common stock, except in limited circumstances. The terms of the lock-up agreements can be
waived, at any time, by the underwriters at their discretion, without prior notice or
pronouncement, to allow us or our executive officers, directors, stockholders, and holders of our
convertible notes to sell shares of our common stock. If the terms of the lock-up agreements are
waived, shares of our common stock will be available for sale in the public market sooner, which
could reduce the price of our common stock.
The public market for LNG focused companies may be very volatile.
The future market price for our shares may be very volatile. This price volatility may make it
more difficult for you to sell your shares when you want at prices you find attractive. The stock
market in general has experienced extreme price and volume fluctuations that often are unrelated or
disproportionate to the performance of
the company. Broad market factors and the investing public’s
negative perception of our business may reduce our stock price, regardless of our performance.
Market fluctuations and volatility, as well as general economic, market, and political conditions,
could reduce our market price. As a result, this may make it difficult or impossible for you to
sell our common stock for a positive return on your investment.
Some of the factors in addition to the risks described above that could negatively affect the
price of our common stock include:
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actual or anticipated variations in our quarterly operating results as well as
the operating results of similar companies; |
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delays or anticipated delays in development or construction of our proposed LNG terminals; |
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changes in our earnings estimates or publication of research reports about us or the LNG industry; |
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changes in financial estimates by us, by investors or by any financial
analysts who might cover our stock; |
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our ability to meet the performance expectations of financial analysts or investors; |
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the failure of securities analysts to cover our common stock after this offering; |
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the activities of competitors; |
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our quarterly or annual earnings or those of other companies in our industry; |
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announcements by us or our competitors of significant acquisitions, strategic
partnerships or divestitures; |
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changes in market valuations of similar companies; |
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adverse market reaction to any increased indebtedness we or our subsidiaries
incur in the future, or defaults or other non-performance on the terms of any
indebtedness; |
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future sales by us of our common stock, debt securities or other securities; |
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additions or departures of our key personnel; |
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actions by institutional holders; |
19
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speculation in the press or investment community; |
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the public’s reaction to our press releases, our other public announcements
and our filings with the Securities and Exchange Commission; |
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changes in accounting principles; |
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general market and economic conditions, including factors unrelated to our performance; and |
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the other factors described elsewhere in these “Risk Factors.” |
As a result of these factors, you may not be able to sell your shares at or above the initial
offering price. These broad market fluctuations and industry factors may materially reduce the
market price of our common stock, regardless of our operating performance.
If we fail to meet continued listing standards of Nasdaq, our common stock may be delisted which
would have a material adverse effect on the price of our common stock.
In order for our securities to be eligible for continued listing on Nasdaq, we must remain in
compliance with certain listing standards. Among other things, these standards require that we
remain current in our filings with the SEC and comply with certain provisions of the Sarbanes-Oxley
Act of 2002 (Sarbanes-Oxley Act). If we were to become noncompliant with Nasdaq’s continued listing
requirements, our common stock may be delisted which would have a material adverse affect on the
price of our common stock.
If we are delisted, our common stock may become subject to the “penny stock” rules of the
Securities and Exchange Commission, which would make transactions in our common stock cumbersome
and may reduce the value of an investment in our stock.
The Securities and Exchange Commission (SEC) has adopted Rule 3a51-1 which establishes the
definition of a “penny stock,” for the purposes relevant to us, as any equity security that is not
listed on a national securities exchange or registered national securities association’s automated
quotation system and has a market price of less than $5.00 per share, subject to certain
exceptions. For any transaction involving a penny stock, unless exempt, Rule 15g-9 require:
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that a broker or dealer approve a person’s account for transactions in penny
stocks; and |
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the broker or dealer receive from the investor a written agreement to the
transaction, setting forth the identity and quantity of the penny stock to be
purchased. |
In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:
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obtain financial information and investment experience and objectives of the person; and |
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make a reasonable determination that the transactions in penny stocks are
suitable for that person and the person has sufficient knowledge and experience
in financial matters to be capable of evaluating the risks of transactions in
penny stocks. |
The broker or dealer must also deliver, prior to any transaction in a penny stock, a
disclosure schedule prescribed by the Securities and Exchange Commission relating to the penny
stock market, which, in highlight form:
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sets forth the basis on which the broker or dealer made the suitability
determination; and |
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that the broker or dealer received a signed, written agreement from the
investor prior to the transaction. |
Generally, brokers may be less willing to execute transactions in securities subject to the
“penny stock” rules. This may make it more difficult for investors to dispose of our common stock
and cause a decline in the market value of our stock.
20
If securities analysts downgrade our common stock or cease coverage of us, the price of our common
stock could decline.
The trading market for our common stock will rely in part on the research and reports that
industry or financial analysts publish about us or our business. We do not control these analysts.
Furthermore, there are other well-established, publicly traded companies active in our industry,
which may mean that it is less likely that we will receive widespread analyst coverage. If one or
more of the analysts who do cover us downgrade our common stock, our common stock price would
likely decline rapidly. If one or more of these analysts cease coverage of us, we could lose
visibility in the market, which in turn could cause our common stock price to decline.
Certain provisions of our charter documents and agreements, as well as Delaware law, could
discourage, delay or prevent a merger or acquisition at a premium price and upon a change of
control, we may be required to redeem some or all of our convertible notes.
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permit us to issue, without any further vote or action by our stockholders,
shares of preferred stock in one or more series and, with respect to each
series, to fix the number of shares constituting the series and the designation
of the series, the voting powers (if any) of the shares of such series, and the
preferences and other special rights, if any, and any qualifications, limitations
or restrictions, of the shares of the series; and |
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limit our stockholders’ ability to call special meetings. |
The foregoing provisions may impose various impediments to the ability of a third party to
acquire control of us, even if a change in control would be beneficial to our existing
stockholders.
In addition, our convertible notes provide that, upon a change of control, holders may require
us to redeem all or a portion of their convertible notes at a price either 110% of the conversion
amount applicable to the principal amount being redeemed, in the case of a mandatory change of
control redemption, or 100% of the conversion amount applicable to the principal amount being
redeemed, in the case of an optional change of control redemption, plus any accrued and unpaid
interest.
If you purchase shares of common stock sold in this offering, you will experience immediate and
substantial dilution.
If you purchase shares of our common stock in this offering, you will experience immediate and
substantial dilution of pro forma net tangible book value per share because the price
that you pay will be substantially greater than the net tangible book value per share of the shares
you acquire, based on the net tangible book value per share as of
September 30, 2006. This dilution
is due in large part to the fact that our earlier investors paid substantially less than the
initial public offering price when they purchased their shares. You will experience additional
dilution upon the exercise of stock options by certain employees or certain directors to purchase
common stock under our equity incentive plan and conversion of our convertible notes.
We do not expect to pay dividends on our common stock in the foreseeable future.
We currently have no operating revenues and do not expect to pay dividends in the foreseeable
future. We presently anticipate that all earnings, if any, will be retained for the development of
our business. Any future dividends will be subject to the discretion of our board of directors and
will depend on, among other things, future earnings, our operating and financial condition, our
capital requirements, and general business conditions. Investors seeking cash interest and/or
dividends should not purchase our common stock.
The conversion price of our Senior Convertible Notes may be lowered if we issue shares of our
common stock at a price less than the existing conversion price, which could cause dilution to our
common stockholders.
Subject to certain exclusions, if we issue common stock at a price less than the existing
conversion price for our Senior Convertible Notes due 2013 (convertible notes), the conversion
price shall be adjusted downward to a price no less than $7.30 per share which would dilute our
common stock holders upon conversion. The conversion price will be adjusted for certain issuances
of our securities, stock splits, cash dividends, and stock dividends.
21
Our executive officers, directors and other five percent or greater stockholders and entities
affiliated with them own a large percentage of our company, and could influence matters requiring
approval by our stockholders.
Prior to the close of this offering, our executive officers, directors and other five percent
or greater stockholders and entities affiliated with them, acting together, will be able to
influence matters requiring approval by our stockholders, including the election of directors.
After the offering, assuming none of the holders of our convertible notes elect to convert their
convertible notes, MatlinPatterson will control approximately % of our outstanding
common stock and approximately % of our outstanding common stock if the over-allotment
option is exercised in full. In addition, MatlinPatterson holds $10 million in principal amount of
our convertible notes. Accordingly, MatlinPatterson will be in a position to control or influence
the outcome of matters requiring a stockholder vote, including the election of directors, adoption
of amendments to our
certificate of incorporation or
bylaws or approval of transactions involving a
change of control. The interests of MatlinPatterson may differ from yours, and MatlinPatterson may
vote its common stock in a manner that may adversely affect you. In addition, Section 203 of the
Delaware General Corporation Law (DGCL) provides for a three-year moratorium on certain business
combinations with interested stockholders (generally, persons who own, individually or with or
through other persons, 15% or more of the corporation’s outstanding voting stock). The DGCL,
however, permits a corporation to opt out of the restrictions imposed by Section 203. We plan to
opt out of Section 203 of the DGCL in the amended and restated
certificate of incorporation which
we plan to adopt prior to the completion of this offering. Accordingly, we will be able to engage
in business combinations with interested stockholders, such as MatlinPatterson.
The concentration of ownership of our shares of common stock may also have the effect of
delaying or preventing a change in control.
When we become a public company, we will incur increased costs that may place a strain on our
resources or divert our management’s attention from other business concerns.
When we become a public company, we will incur additional legal, accounting and other expenses
that we do not incur as a private company. The Exchange Act will require us to file annual,
quarterly and current reports with respect to our business and financial condition, which will
require us to incur substantial legal and accounting expenses. The Sarbanes-Oxley Act will require
us to maintain effective disclosure controls and procedures and internal controls for financial
reporting. In order to maintain and improve the effectiveness of our disclosure controls and
procedures and internal control over financial reporting, significant resources and management
oversight will be required. We expect the corporate governance rules and regulations of the SEC and
any exchange on which we may list will increase our legal and financial compliance costs and make
some activities more time consuming and costly. These requirements may place a strain on our
systems and resources and may divert our management’s attention from other business concerns, which
could have a material adverse effect on our business, financial condition and results of
operations. In addition, we are hiring and will continue to hire additional legal, accounting and
financial staff with appropriate public company experience and technical accounting knowledge,
which will increase our operating expenses in future periods.
We also expect these rules and regulations to make it more difficult and more expensive for us
to obtain director and officer liability insurance, and we may be required to accept reduced policy
limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As
a result, it may be more difficult for us to attract and retain qualified persons to serve on our
board of directors or as executive officers. We are currently evaluating and monitoring
developments with respect to these rules, and we cannot predict or estimate the amount of
additional costs we may incur or the timing of such costs.
We may be exposed to potential risks resulting from new requirements that we evaluate our internal
controls over financial reporting under Section 404 of the Sarbanes-Oxley Act of 2002.
Section 404 of the Sarbanes-Oxley Act requires that publicly reporting companies cause their
management to perform annual assessments of the effectiveness of their internal controls over
financial reporting and their independent auditors to prepare reports that address such
assessments. Once the registration statement for this offering has been declared effective by the
SEC, we are required to satisfy the requirements of Section 404 upon the filing of our second
annual report after becoming a public company.
We may not be able to assess our current internal controls and comply with these requirements
within the required timeframe. If we are able to proceed with a complete assessment in a timely
manner, we may identify deficiencies which we
22
may not be able to remediate, may identify deficiencies which will demand significant
resources to remediate, or may be unable to identify existing deficiencies at all. In addition, if
we fail to achieve and maintain the adequacy of our internal controls, we may not be able to
conclude on an ongoing basis that we have effective internal control over financial reporting in
accordance with Section 404 of the Sarbanes-Oxley Act. Moreover, effective internal controls,
particularly those related to revenue recognition, are necessary for us to produce reliable
financial reports and are important to helping prevent financial fraud. If we cannot provide
reliable financial reports or prevent fraud, our business and operating results could be harmed,
investors could lose confidence in our reported financial information and the trading price of the
common stock offered hereby could drop significantly. Our compliance with the Sarbanes-Oxley Act
may require significant expenses and management resources that would need to be diverted from our
other operations and could require a restructuring of our internal financial reporting. Any such
expenses, time reallocations or restructuring could have a material adverse effect on our
operations. The applicability of the Sarbanes-Oxley Act to us could make it more difficult and more
expensive for us to obtain director and officer liability insurance, and also make it more
difficult for us to attract and retain qualified individuals to serve on our board of directors
and, particularly, our audit committee, or to serve as executive officers.
We will retain broad discretion in using the net proceeds from this offering, and may not use the
proceeds effectively.
Although we expect to use a substantial portion of the net proceeds from this offering to fund
the development of our three active projects, the equity financing for the construction of our
Bradwood LNG project, the development of other LNG terminals in addition to our initial projects,
and general corporate purposes, our management will retain broad discretion to allocate the net
proceeds of this offering. The net proceeds may be applied in ways with which you and other
investors in the offering may not agree. Moreover, our management may use the proceeds for
corporate purposes that may not increase our market value or make us profitable. Management’s
failure to spend the proceeds effectively could have an adverse effect on our business and our
ability to complete development and construction of our proposed LNG terminals.
We may be or become a United States real property holding corporation. If we are or become such a
corporation, non-U.S. investors may be subject to U.S. federal income tax (including withholding
tax) on gains realized on disposition of our common stock, and U.S. investors selling our common
stock may be required to certify as to their status in order to avoid withholding.
A United States real property holding corporation is a corporation in which 50% or more of the
fair market value of its assets consist of United States real property. Whether we are or are
likely to become a United States real property holding corporation is subject to significant legal
and factual issues, but there is a significant risk that we are or may become such a corporation.
If we were a United States real property holding corporation, a non-U.S. holder of our common stock
would generally be subject to U.S. federal income tax on gains realized on a sale or other
disposition of our common stock. Certain non-U.S. holders of our common stock may be eligible for
an exception to the foregoing general rule if our common stock is regularly traded on an
established securities market during the calendar year in which the sale or disposition occurs. We
would be so treated if we were listed on Nasdaq and we satisfied certain requirements, including
requirements as to minimum volumes of trading. We cannot offer any assurance that our common stock
will be so traded at any point in time in the future.
If our common stock is not considered to be regularly traded on an established securities
market during the calendar year in which a sale or disposition occurs, the buyer or other
transferee of our common stock will generally be required to withhold tax at the rate of 10% on the
sales price or other amount realized, unless the transferor furnishes an affidavit certifying that
it is not a foreign person in the manner and form specified in applicable Treasury regulations.
23
FORWARD-LOOKING STATEMENTS
This prospectus includes “forward-looking statements,” as defined by federal securities laws,
with respect to our financial condition, results of operations, our industry, and business.
Forward-looking statements are those that do not relate solely to historical fact. They include,
but are not limited to, any statement that may predict, forecast, indicate or imply future results,
performance, achievements or events. Words such as, but not limited to, “will,” “may,” “should,”
“could,” “would,” “predicts,” “potential,” “continue,” “expects,” “anticipates,” “future,”
“intends,” “plans,” “believes,” “estimates,” and similar expressions or phrases, as well as
statements in future tense, identify forward-looking statements. All statements other than
statements of historical fact are, or may be deemed to be, forward-looking statements.
All forward-looking statements involve significant risks and uncertainties. Although we
believe the expectations and forecasts reflected in these and other forward-looking statements are
reasonable, we cannot assure you that they will prove to have been correct. The occurrence of the
events described, and the achievement of the expected results, depend on many events, many or all
of which are not predictable or within our control. Should one or more of these uncertainties or
management’s current assumptions regarding risks, among others, materialize, actual results may
vary materially from those estimated, anticipated or projected.
Factors that could cause actual results to differ materially from expected results are
described under “Risk Factors” and include:
| |
• |
|
the ability to commence or complete construction of each of our liquefied
natural gas (LNG) terminals by certain dates, or at all; |
| |
| |
• |
|
the volatility of natural gas and substitute commodity prices as well as other
commodities including steel, nickel, and concrete, and the market for
construction services; |
| |
| |
• |
|
the strength and financial resources of our competitors; |
| |
| |
• |
|
the preparation and receipt of the necessary permits and licenses to construct
and operate proposed LNG terminals by a certain date, or at all; |
| |
| |
• |
|
construction of our proposed LNG terminals, including the engagement of any
qualified engineering, procurement and construction (EPC) contractor, the
anticipated terms and provisions of any agreement with an EPC contractor, and
anticipated costs related thereto; |
| |
| |
• |
|
adverse effects of governmental and environmental regulation; |
| |
| |
• |
|
other factors affecting the energy industry generally or the LNG industry in particular; |
| |
| |
• |
|
our level of indebtedness; |
| |
| |
• |
|
financing transactions or arrangements, whether on our part or at the project level; |
| |
| |
• |
|
the substantial debt we expect to incur in connection with any future
construction of our LNG terminals and the restrictive covenants under such debt
to which we expect to be subject; |
| |
| |
• |
|
the availability of LNG supply and our ability to enter into and maintain
adequate terminal use agreements; |
| |
| |
• |
|
future levels of domestic or foreign natural gas production or consumption or
the future level of LNG imports into North America, regardless of the source, or
the transportation or other infrastructure or prices related to natural gas, LNG
or other hydrocarbon products; |
| |
| |
• |
|
whether proposed LNG terminals and pipelines, when completed, will have
certain characteristics, including amounts of regasification and storage
capacities, a number of storage tanks and docks, pipeline deliverability and a
number of pipeline interconnections; |
24
| |
• |
|
possible expansions of the currently projected size of any of our proposed LNG
terminals; business strategy, our business plans or any other plans, forecasts or
objectives; |
| |
| |
• |
|
changes in gas specifications in the pipeline systems to which our LNG terminals may connect to; |
| |
| |
• |
|
losses possible from future litigation; |
| |
| |
• |
|
our ability to attract and retain skilled employees; and |
| |
| |
• |
|
any other legal, regulatory, and other proceedings to which we may become subject. |
We urge you to carefully review and consider the disclosures made in this prospectus of the
risks and factors that may affect our business. See “Risk Factors” on page 10 of this prospectus
for examples of factors, risks and uncertainties that could cause actual outcomes and results to be
materially different from those projected or assumed in our forward-looking statements. Other
currently unknown or unpredictable factors could also harm our results. Consequently, there can be
no assurance that actual results or developments anticipated by us will be realized or, even if
substantially realized, that they will have the expected consequences to, or effects on, us.
Given these uncertainties, prospective investors are cautioned not to place undue reliance on
such forward-looking statements, which speak only as of the date of this prospectus unless the
context indicates otherwise. We undertake no obligation to update or revise any forward-looking
statements, either to reflect new developments, or for any other reason, except as required by law.
25
USE OF PROCEEDS
We expect to receive net proceeds of approximately $ million from the sale of
shares of common stock by us in this offering at an assumed initial public offering price of $ per share (the mid-point of the range set forth on the cover page of this prospectus), after
deducting estimated underwriting commissions and discounts and estimated expenses. Our estimates
assume an initial public offering price of $ per share of common stock and no exercise of
the underwriters’ option to purchase additional shares. An increase or decrease in the initial
public offering price of $ per share would cause the net proceeds from the offering, after
deducting underwriting discounts and fees and offering expenses payable by us, to increase or
decrease by $ million (or $ million assuming full exercise of the underwriters’
option to purchase additional shares).
We anticipate using the net proceeds to us from this offering as follows:
| |
• |
|
provide the equity financing for the construction of the Bradwood terminal project; |
| |
| |
• |
|
fund the continued development of our three active proposed liquefied natural gas (LNG) terminals; |
| |
| |
• |
|
fund possible additional LNG projects that we determine to have strong development potential; |
| |
| |
• |
|
pay transaction costs related to this offering, other expenses; and |
| |
| |
• |
|
fund working capital and for general corporate purposes. |
DIVIDEND POLICY
We are a recently formed development stage company without revenue generating capability and
have paid no dividends in the past. We do not anticipate paying cash dividends in the foreseeable
future. Any declaration and payment of dividends will be at the discretion of our board of
directors and will depend upon, among other things, our earnings, financial condition, capital
requirements, level of indebtedness, contractual restrictions with respect to the payment of
dividends, and other considerations that the Board deems relevant. Our board of directors’ ability
to declare a dividend is also subject to limits imposed by Delaware corporate law and by the
provisions of our Senior Convertible Notes due 2013. See “Description of Senior Convertible Notes.”
26
CAPITALIZATION
The following table sets forth our cash, cash equivalents, marketable securities, and
capitalization as of
September 30, 2006 on an actual basis and pro forma as adjusted basis after
giving effect to our receipt of the net proceeds from our sale of common stock in this offering.
This table should be read in conjunction with our financial statements and the notes thereto,
“Use of Proceeds,” “Dividend Policy,”
“Selected Historical Financial Data,” “Management’s
Discussion and Analysis of Financial Condition and Results of Operations,” and “Description of
Senior Convertible Notes” included elsewhere in this prospectus.
| |
|
|
|
|
|
|
|
|
| |
|
As of September 30, 2006 |
|
| |
|
(unaudited) |
|
| |
|
|
|
|
|
Pro Forma as |
|
| |
|
Actual |
|
|
Adjusted |
|
Cash, cash equivalents, and marketable securities (1) |
|
$ |
82,358,255 |
|
|
$ |
|
|
|
|
|
|
|
|
|
Total long term debt: |
|
|
|
|
|
|
|
|
Convertible notes (2) |
|
$ |
100,000,000 |
|
|
$ |
100,000,000 |
|
Term notes (3) |
|
|
2,205,009 |
|
|
|
2,205,009 |
|
Advance payable (4) |
|
|
6,000,000 |
|
|
|
6,000,000 |
|
|
|
|
|
|
|
|
Total long term debt: |
|
$ |
108,205,009 |
|
|
$ |
|
|
Stockholders’ Equity: |
|
|
|
|
|
|
|
|
Common stock ($0.01 par value; 150,000,000 shares
authorized, 27,441,935 outstanding) (5) |
|
|
274,419 |
|
|
|
|
|
Additional paid in capital |
|
|
35,738,700 |
|
|
|
|
|
Accumulated deficit |
|
|
(61,597,454 |
) |
|
|
261,592,454 |
|
|
|
|
|
|
|
|
Total stockholders’ equity |
|
|
(25,584,335 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total capitalization |
|
$ |
82,620,674 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
| (1) |
|
Includes the net proceeds to us from this offering, after deducting underwriting discounts
and estimated offering expenses payable by us of $ million. |
| |
| (2) |
|
On May 17, 2006 we issued $100.0 million of our Senior Convertible Notes due 2013
(convertible notes) and on November 15, 2006, accrued interest of $3.5 million was paid in
kind, increasing the principal balance outstanding. See “Description of Senior Convertible
Notes.” |
| |
| (3) |
|
Discounted non-interest bearing note payable to an entity controlled by Mr. Garrett and Mr.
Soanes. See “Certain Relationships and Related Transactions.” |
| |
| (4) |
|
This liability bears no interest and represents an obligation to repay an advance made to the
Clearwater project by an LNG supplier when the Clearwater terminal receives long-term
construction financing, achieves commercial operation, or a distribution is made by Clearwater
Holding. |
| |
| (5) |
|
Amount does not include 4,100,611 shares of common stock issuable as of November 15, 2006,
upon the exercise of outstanding options exercisable at $9.12 per share or 11,346,552 shares
issuable, as of November 15, 2006, upon conversion of our convertible notes based on an
estimated conversion price of $9.12 per share. Additional shares will be issuable upon
conversion should we elect to pay future interest on our convertible notes in kind. See
“Description of Capital Stock,” “Description of Senior Convertible Notes,” and “Certain
Relationships and Related Transactions.” |
27
DILUTION
Purchasers of the common stock in this offering will be immediately and substantially diluted
to the extent of the difference between the initial public offering price per share of our common
stock and the net tangible book value per share of our common stock immediately after completion of
this offering. Dilution results from the fact that the per share offering price of the common stock
is substantially in excess of the net tangible book value per share of our common stock immediately
following the completion of the offering. Net tangible book value represents the amount of our
total tangible assets reduced by our total liabilities. Tangible assets represent our total assets
less intangible assets. Net tangible book value per share represents our net tangible book value
divided by the number of shares of common stock outstanding. As of
September 30, 2006, our net
tangible deficit was $25.6 million or $0.93 per share.
The following table illustrates this substantial and immediate per share dilution to new investors:
| |
|
|
|
|
Assumed initial public offering price per share |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in net tangible deficit per share attributable to new investors
purchasing shares in this offering(1) |
|
|
|
|
|
|
|
|
|
Pro forma, as adjusted, net tangible deficit per share after this offering
Dilution of net tangible deficit per share to new investors |
|
$ |
|
|
|
|
|
| (1) |
|
After deducting estimated underwriting discount and other offering expenses to be paid by the Company. |
The following table presents as of
September 30, 2006 and on a pro forma basis after giving
effect to this offering, the total number of shares of common stock purchased from us, the total
consideration paid to us, assuming an initial public offering price of $ per share (before
deducting the estimated underwriting discounts and commissions and offering expenses payable by us
in this offering), and the average price per share paid by existing stockholders and by new
investors purchasing shares in this offering.
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Shares Purchased |
|
Total Consideration |
|
Average Price |
| |
|
Number (%) |
|
Amount (%) |
|
Per Share |
Existing Stockholders |
|
|
|
% |
|
|
|
% |
|
$ |
|
|
New Stockholders |
|
|
|
% |
|
|
|
% |
|
$ |
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
$ |
|
|
The foregoing table does not include the impact of the underwriters’ over-allotment option. If
the underwriters exercise their option to purchase additional shares of our common stock in full in
this offering, the as adjusted net tangible book value per share after this offering would be $
per share, the decrease in net tangible book value per share to existing stockholders would be
per share and the dilution to new investors purchasing shares in this offering would be per
share.
A $1.00 change in the assumed public offering price of $ per share of our common stock
would change our pro forma net tangible book value after giving effect to the offering by $
million, the pro forma net tangible book value per share of our common stock after giving effect to
this offering by $ and the dilution in pro forma net tangible book value per share of our
common stock to new investors by $ , assuming no change in the number of shares of common stock
offered by us as set forth on the cover page of this prospectus, and after deducting underwriting
discounts and commissions and other expenses of the offering. The pro forma information discussed
above is illustrative only. Our net tangible book value following completion of the offering is
subject to adjustment based upon the actual offering price of our common stock and other terms of
this offering at pricing.
28
The discussion and tables above exclude the following:
| |
• |
|
4,100,611 shares of common stock issuable upon the exercise of options
outstanding as of November 15, 2006 at an exercise price of $9.12 per share; the
consummation of this offering will not result in further vesting of such options; |
| |
| |
• |
|
11,346,552 shares of common stock issuable upon conversion of our Senior
Convertible Notes due 2013 (convertible notes), based on an estimated conversion
price of $9.12 per share, including additional shares, as of November 15, 2006,
which will be issuable upon conversion as we have elected to pay interest on
these convertible notes in kind by increasing the principal outstanding
thereunder. Additional shares will be issuable upon conversion should we elect to
pay future interest due on the convertible notes in kind. See “Description of
Senior Convertible Notes” regarding the ultimate determination of the conversion
price. |
29
SELECTED HISTORICAL FINANCIAL DATA
The following table presents our selected consolidated historical financial information. The
consolidated statement of operations and balance sheet data for the period from inception (
May 17,
2005) through
December 31, 2005 and as of
December 31, 2005 are derived from our audited
consolidated financial statements and related notes included in this prospectus. The consolidated
statement of operations and balance sheet data for the nine months ended
September 30, 2006 are
derived from our unaudited consolidated financial statements included in this prospectus. The
consolidated statement of operations from the date of our inception through
September 30, 2006 is
derived from our audited and unaudited consolidated financial statements included in this
prospectus. In the opinion of management, the unaudited consolidated financial statements have been
prepared on the same basis as our audited consolidated financial statements and include all
adjustments, consisting of only normal recurring adjustments, necessary for a fair presentation of
the information set forth therein. As we are a recently formed development stage company with no
operating revenues our historical results for any annual or interim period are not necessarily
indicative of results to be expected for a full year or for any future period as development
activities and related costs have varied in the past and are anticipated to continue to vary in the
future. The net loss per share information is computed using the weighted average number of
units/common shares outstanding during the related period.
You should read this information together with “Capitalization,” “Management’s Discussion and
Analysis of Financial Condition and Results of Operations,” and our consolidated financial
statements and the related notes thereto included elsewhere in this prospectus. Our historical
financial statements have been prepared in accordance with generally accepted accounting principles
in the United States.
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Cumulative Period |
|
| |
|
|
|
|
|
|
|
|
|
from Inception (May |
|
| |
|
Inception |
|
|
|
|
|
|
17, 2005) |
|
| |
|
(May 17, 2005) |
|
|
Nine Months Ended |
|
|
through |
|
| |
|
through |
|
|
September 30, 2006 |
|
|
September 30, 2006 |
|
| |
|
December 31, 2005 |
|
|
(Unaudited)(3) |
|
|
(Unaudited)(3) |
|
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Project prospecting |
|
|
— |
|
|
|
179,846 |
|
|
|
179,846 |
|
Project development |
|
|
7,712,256 |
|
|
|
13,107,813 |
|
|
|
20,820,069 |
|
Corporate general and administrative
costs |
|
|
887,288 |
|
|
|
27,315,410 |
|
|
|
28,202,698 |
|
|
|
|
|
|
|
|
|
|
|
Loss from operations |
|
|
(8,599,544 |
) |
|
|
(40,603,069 |
) |
|
|
(49,202,613 |
) |
|
|
|
|
|
|
|
|
|
|
Net other income/(expense) |
|
|
23,123 |
|
|
|
(2,231,705 |
) |
|
|
(2,208,582 |
) |
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(8,576,421 |
) |
|
$ |
(42,834,774 |
) |
|
$ |
(51,411,195 |
) |
|
|
|
|
|
|
|
|
|
|
Weighted average units/shares outstanding
basic and diluted (1) (2) |
|
|
130 |
|
|
|
27,356,833 |
|
|
|
27,330,969 |
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net loss per share |
|
$ |
(65,972.47 |
) |
|
$ |
(1.57 |
) |
|
$ |
(1.88 |
) |
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents(4) |
|
$ |
1,382,873 |
|
|
$ |
82,358,255 |
|
|
|
|
|
Working capital(4) |
|
|
310,593 |
|
|
|
77,884,362 |
|
|
|
|
|
Deferred financing costs(4) |
|
|
— |
|
|
|
6,624,940 |
|
|
|
|
|
Total assets(4) |
|
|
2,259,670 |
|
|
|
91,605,118 |
|
|
|
|
|
Debt and advances payable, including
current portion(4) |
|
|
— |
|
|
|
110,868,898 |
|
|
|
|
|
Members’/Stockholders’ equity (deficit) |
|
|
83,406 |
|
|
|
(25,584,335 |
) |
|
|
|
|
|
|
|
| (1) |
|
Amount does not include 4,100,611 shares of common stock issuable as of November 15, 2006,
upon the exercise of outstanding options exercisable at $9.12 per share or 11,346,552 shares
issuable, as of November 15, 2006, upon conversion of convertible notes based on an estimated
conversion price of $9.12 per share. Additional shares will be |
30
|
|
|
| |
|
issuable upon conversion should we elect to pay future interest due on the convertible notes in
kind. See “Description of Senior Convertible Notes” regarding the ultimate determination of the
conversion price. |
| |
| (2) |
|
As of December 31, 2005 the Company had units outstanding as a limited liability company and
was not subject to federal income tax. Amounts at September 30, 2006 reflect our
reorganization into a corporation on May 16, 2006 and the contemporaneous conversion of the
units into common shares, by issuing 210,000 shares for each unit exchanged. |
| |
| (3) |
|
Our financial results for the nine months ended September 30, 2006 reflect a net loss of
$42.8 million, or $1.57 per share (basic and diluted). The major factors contributing to our
loss per share at September 30, 2006 were $13.1 million in development costs for our projects,
$13.9 million in consulting fees relating to the acquisition of the project companies, and
$13.4 million in other general and administrative expenses. |
| |
| (4) |
|
As of September 30, 2006, we had cash of $82.3 million, working capital of $77.9 million,
unamortized deferred financing costs of $6.6 million, total assets of $91.6 million, and debt
and advances of $110.8 million provided primarily by or directly related to the issuance of
our convertible notes. |
31
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis in conjunction with the section
“Selected Historical Financial Data” and the financial statements and related notes included
elsewhere in this prospectus. This discussion contains forward-looking statements and reflects our
current views with respect to future events and financial performance. Our actual results may
differ materially from those anticipated in these forward-looking statements as a result of certain
factors such as those set forth under “Risk Factors” and elsewhere in this prospectus.
Background
Our business was founded by our Chief Executive Officer, Mr. Garrett, and our President, Mr.
Soanes, who have significant global project development experience and who, together with other
members of our senior management team, have been involved in the development of more than 50 energy
infrastructure projects with an aggregate investment of over $15 billion.
Commencing in May 2005, Mr. Garrett and Mr. Soanes, through an entity controlled by them,
formed a joint venture with certain affiliates of MatlinPatterson Global Advisors LLC
(MatlinPatterson). The joint venture was specifically formed to develop and eventually construct
the Bradwood LNG terminal project. Mr. Garrett and Mr. Soanes agreed to provide services to the
joint venture and not compete with the venture in the U.S. Pacific Northwest. MatlinPatterson
agreed to provide up to $14 million for the costs to develop the project.
The audited and unaudited financial statements of NorthernStar Natural Gas Inc. and
subsidiaries (formerly NorthernStar Natural Gas LLC), represent the original entity through which
MatlinPatterson made its investment in the joint venture and include the development stage
operating results of this business from inception,
May 17, 2005, through
December 31, 2005 and for
the period
January 1, 2006 through
September 30, 2006. The original joint venture was reorganized
by an exchange of membership units and the issuance of membership units to certain persons who
assisted in its formation and are among our current or former directors. This resulted in our
owning the entire Bradwood project. Under the provisions of FIN 46 R, Bradwood has been fully
consolidated in our financial statements as if it were a wholly-owned subsidiary since our founding
on
May 17, 2005. This exchange of equity interests is more fully discussed under
“—Results of
Operations” below.
Our Chief Executive Officer and our President were historically involved in the development of
our two other LNG projects, the assets of which we acquired during 2006. One of these acquisitions,
Clearwater, was formed in January 2002 by third parties and was managed by Mr. Garrett and Mr.
Soanes through a consulting arrangement. Clearwater utilizes Platform Grace, an existing offshore
oil and gas production platform located approximately 13 miles offshore of Oxnard, California. From
October 2003 through March 2006, Mr. Garrett and Mr. Soanes led the development efforts for this
project. On
March 27, 2006, we acquired the entity developing this project and it became a
wholly-owned subsidiary named Clearwater Port Holdings LLC. The financial results of Clearwater are
included in our consolidated financial statements subsequent to the acquisition date. Clearwater
was and is a development stage company.
Our Orion project was an acquisition of certain proprietary information related to a proposed
LNG terminal project that Mr. Garrett and Mr. Soanes began to develop along with other parties in
early 2002 in Southern California. In October 2002, the development entity managed by Mr. Garrett
and Mr. Soanes sold the rights to the project to an unrelated third party and was retained by the
purchaser as a project development adviser. The selling entity received consulting income during
the period that it served as a project development adviser. The purchaser actively pursued the
development of the project, including making expenditures for seismic studies, permit applications,
engineering, and pipeline routing and environmental studies; however, in September 2005 the
purchaser discontinued its development of the project and in accordance with the initial sales
agreement, all intellectual property and intangible rights related to the development of the
project reverted to the initial development entity. Mr. Garrett and Mr. Soanes, through this
entity, began evaluating a new project offshore of Southern California using some of the
intellectual property and intangible rights related to the prior project. The intellectual property
and intangible rights related to the new project were sold to Orion and Orion was acquired by us on
March 7, 2006. Orion’s financial results are included in our consolidated financial statements
after the acquisition date. These acquired intangible assets do not constitute a business and,
accordingly, no financial statements have been prepared.
32
General
Our company was founded in May 2005 to develop, own, and operate LNG receiving/importation
terminals on the West Coast of the United States (West Coast). We consolidated ownership of our LNG
terminal projects in March 2006 to take advantage of project portfolio diversification, economies
of scale, and greater access to capital.
Our three initial LNG terminal projects are as follows:
| |
• |
|
Bradwood is a land-based LNG terminal with docking facilities located on the south
bank of the Columbia River in Northwest Oregon; |
| |
| |
• |
|
Clearwater is an offshore LNG terminal located approximately 13 miles from Oxnard, California; and |
| |
| |
• |
|
Orion is an offshore LNG terminal located approximately 25 miles from Carlsbad, California. |
We were incorporated on
May 16, 2006, with previous members exchanging their membership units
in NorthernStar Natural Gas LLC for our shares of the common stock of NorthernStar Natural Gas Inc.
(NorthernStar) using an exchange ratio of 210,000 shares for each
membership unit of NorthernStar Natural Gas LLC. Our three
projects are held by our wholly-owned
subsidiaries.
To date, our activities have been limited to development activities related to our three LNG
terminal projects. Those projects, if completed according to plan, will provide direct access to
major West Coast natural gas demand centers. We intend to negotiate and sign terminal use
agreements (TUAs) for all or substantially all of the long-term base capacity of each LNG terminal
with highly rated creditworthy counterparties. We expect to provide offloading and regasification
services under the TUAs without taking ownership of LNG or natural gas. Each TUA is expected to
have a 20-year term and to generate a steady, predictable stream of contracted fee payments with no
commodity price risk. In addition, we may periodically sell capacity to third parties or purchase,
regasify, and sell cargoes of LNG on a spot basis as opportunities arise when the terminals’ firm
capacity is not being utilized by our TUA customers, generating additional revenues to supplement
those received under the TUAs.
We estimate the remaining aggregate costs from
September 30, 2006 to bring all three projects
to the end of the development stage to be approximately $62 million. We continue to pursue
necessary permits and approvals for construction of these projects and believe such permits and
approvals will be obtained and if pursued to their conclusion that all of the projects will be
economically viable to construct and operate. Our business success will depend to a significant
extent upon our ability to obtain the funding necessary to construct our LNG terminals, to bring
them into operation on a commercial basis and to finance the costs of staffing, operating and
expanding
our company during that process.
Our ability to obtain construction financing for our projects will depend on the final costs
of the project, the quality of our engineering, procurement and construction (EPC) contractor, the
terms of our
contract with such EPC contractor, and the economic viability of each LNG terminal
project to prospective lenders. We intend to negotiate our TUAs close to the time or following the
receipt of the permits necessary to initiate construction of the LNG terminals in order to maximize
our negotiating leverage with purchasers of our capacity. We will seek to enter into long-term TUAs
with highly rated creditworthy
“anchor tenants” for our planned regasification capacity. Our TUAs
may provide an advance payment for regasification capacity sold, which may provide additional
capital to help meet our ongoing liquidity needs. Furthermore, these TUAs are expected to serve as
collateral to facilitate project level debt financing that we intend to obtain with respect to the
construction of the related LNG terminal(s); however, we do not expect our LNG terminal projects to
become a source of material revenues until after commercial operations successfully commence.
Bradwood
Our Bradwood project is designed as a land-based LNG terminal engineered to have an initial
sustainable base capacity of 1.0 Bcf/d, peak capacity of 1.3 Bcf/d and a pre-engineered capability
to expand the base capacity to 2.0 Bcf/d. Bradwood is the only LNG terminal project in the Pacific
Northwest to have completed the Federal Energy Regulatory Commission (FERC) prefiling process under
Section 3 of the Natural Gas Act for authorization to construct and operate an LNG receiving
terminal. To commence construction of the project, we need to obtain all required permits from FERC
and certain other regulatory agencies and obtain the necessary financing. See “State and Federal
Government Regulatory Matters.” We are targeting regulatory approvals for the Bradwood project by
the FERC and state and local authorities in the third quarter of 2007 and the commencement of
commercial operations in the first quarter of 2011.
33
Clearwater
Our Clearwater project is an offshore, platform-based LNG terminal that is engineered to have
a sustainable base capacity of 1.2 Bcf/d and a peak capacity of 1.4 Bcf/d. The platform will be
connected through a 13-mile offshore pipeline to the Southern California Gas Co. pipeline network
and storage infrastructure serving the approximately 4.0 Bcf/d Southern California market. We filed
our original Deepwater Port (DWP) license application in February 2004, and, following our purchase
of this project, submitted an amended and restated application in June 2006 as a more comprehensive
response to additional data requests with direction from the U.S. Coast Guard, the California State
Lands Commission (CSLC), and other agencies. Based upon new agency reviews, the U.S. Coast Guard
and the CSLC will move forward with engagement of a contractor for the preparation of our draft
environmental reports. We are anticipating regulatory approval in the second quarter of 2008, the
commencement of construction in the third quarter of 2008, and the commencement of commercial
operations in the second quarter of 2010.
Orion
Our Orion project has advanced with a target location about 25 miles offshore of Carlsbad,
California with direct access to the Los Angeles and San Diego markets. Orion is expected to be
designed to include a concrete hull floating storage and regasification unit with a design capacity
of 1.2 Bcf/d. As of November 2006, Orion was in the early development phase. We intend to pursue
the development of Orion in conjunction with the approval process of our Clearwater project.
Results of Operations
Overview
Our financial results for the nine months ended
September 30, 2006 reflect a net loss of $42.8
million, or $1.57 per share (basic and diluted). Major factors contributing to our loss at
September 30, 2006 include the operating results of Orion and Clearwater since they became
members of the controlled group in March 2006. See
“Purchase and Financing of Our LNG Terminal Projects and LNG
Related Assets” for further discussion of the purchase of these
projects. Additionally, consulting fees and employee costs
related to stock option grants contributed significantly to our net loss and net loss per share.
Other expenses include (1) project development expenses of $13.1 million,
which includes $9.4 million for permitting, $2.1 million for public relations, and $1.5 million for
engineering, legal and other project related costs; (2) $27.3 million in general and administrative
expenses, including $13.9 million related to consulting services provided in relation to our LNG
terminal project acquisitions; and (3) $10.1 million in payroll and
contract services, including
$7.4 million representing non-cash stock option expense recorded in accordance with SFAS No. 123R
related to the stock options granted under the 2006 Long-Term Incentive Plan, and the remainder
for legal, travel and other administrative costs.
34
LNG Terminal Development Costs
Bradwood, Clearwater, and Orion are development stage companies and to date have received no
revenue from operations. LNG terminal development expenses for Bradwood, Clearwater and Orion were
$9.3, $3.6, and $0.2 million, respectively, for the nine months ended
September 30, 2006, primarily
consisting of consulting and engineering studies, permitting costs, legal, public relations, and
general and administrative activities.
Other General and Administrative Expenses
Other general and administrative expenses are primarily related to our general corporate and
other activities. These expenses were $27.3 million for the nine months ended
September 30, 2006.
General and administrative expenses include $13.9 million related to consulting services provided
in relation to our LNG terminal project acquisitions, including a $8.9 million non-cash consulting
fee paid in company stock to our Chairman and a former director and $5.0 million in cash to an
entity controlled by our Chief Executive Officer and our President as additional consideration for
intellectual and intangible properties held by ESI Holdings, Ltd.; $10.1 million in payroll-related
and
contract services including $7.4 million of which represents a non-cash stock option expense
recorded in accordance with SFAS No. 123R pursuant to the stock options granted under the 2006
Management Incentive Plan and $0.4 million in stock grants to non-employee members of the board of
directors pursuant to the 2006 Non-Employee Directors’ Stock Plan; and the remainder for legal,
travel and other administrative costs.
These costs increased significantly during 2006 primarily because we began hiring the
personnel and developing the infrastructure needed to complete development of our LNG terminal
projects and carry out our corporate activities. As of
September 30, 2006, we had 19 employees. We
had no employees at
December 31, 2005.
LNG Terminal Development Costs
Bradwood’s predecessor company, NorthernStar LLC, operated in the development stage during the
period
May 17, 2005 through
December 31, 2005 and generated no operating revenue during that
period. There is no comparable period as 2005 was its first year of existence; however, as the
Bradwood LNG terminal project development has progressed, the rate of expenditures has increased.
Through
December 31, 2005, we had incurred $7.7 million in development costs, primarily related to
costs for environmental studies and preliminary engineering activities necessary to prepare and
submit regulatory permit applications, related processes and public relations.
The audited historical financial statements included in this prospectus represent the
financial position and results of operations of Bradwood as if it were our wholly-owned subsidiary
since inception. Bradwood was determined to be a variable interest entity (VIE) under the Financial
Accounting Standards Board’s Financial Interpretation No. 46R,
“Consolidation of Variable Interest
Entities, an Interpretation of Accounting Research Bulletin No. 51.” Accordingly, we were
determined to be the primary beneficiary of Bradwood, and therefore Bradwood has been consolidated
as if it were a wholly-owned subsidiary in our historical financial statements presented herein,
though we held only a 50% equity interest in Bradwood as of
December 31, 2005
35
Other General and Administrative Expenses
Other general and administrative expenses were $0.9 million for the year ended
December 31,
2005. These costs relate to general corporate activities including consulting and professional
fees, public relations, rent, utilities, and non income-related state and local taxes. As of
December 31, 2005,
the Company had no employees.
Purchase and Financing of Our LNG Terminal Projects and LNG Related Assets
2006
In March 2006, we issued membership units (NorthernStar units) in NorthernStar Natural Gas LLC
(NorthernStar LLC) to holders of interests in our LNG terminal projects. Under GAAP, we are
acquired to record the assets required at the historical cost of the
prior owners of the LNG terminal projects. We followed Staff Accounting Bulletin 103, Topic 5,
Item G
“Transfer of Nonmonetary Assets by Promoters or Shareholders” (SAB 103) which requires that
transfers of non-monetary assets to a company by its promoters or shareholders in exchange for
stock prior to
the company’s initial public offering be recorded at the transferor’s historical
cost basis as determined under GAAP. The following table sets forth the
consideration paid: (a) in cash, (b) through the issuance of notes payable, and (c) in shares of
our common stock, giving effect to the conversion to corporate form on
May 16, 2006 and with the
issuance of 210,000 shares for each membership unit to the then-existing equity holders of each of
the membership units outstanding.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Number of Shares of |
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Common Stock (After |
|
|
Value of Shares of |
|
| |
|
Cash |
|
|
Notes |
|
|
Conversion) |
|
|
Common Stock |
|
Bradwood |
|
$ |
— |
|
|
$ |
— |
|
|
|
6,694,800 |
|
|
$ |
— |
|
Clearwater |
|
|
— |
|
|
|
— |
|
|
|
8,640,513 |
|
|
|
— |
|
Orion |
|
|
1,000,000 |
|
|
|
2,205,009 |
|
|
|
4,296,201 |
|
|
|
— |
|
Legal fees |
|
|
865,863 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total projects |
|
$ |
1,865,863 |
|
|
$ |
2,205,009 |
|
|
|
19,631,514 |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consulting fees
associated with
acquisitions |
|
$ |
5,000,000 |
|
|
$ |
— |
|
|
|
973,686 |
|
|
$ |
8,880,016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NorthernStar LLC issued 93.48 NorthernStar units, cash, and obligations to pay cash as
consideration for the interests in Clearwater and Orion and the 50% interest in Bradwood that it
did not own. Additionally, 4.64 NorthernStar units were issued to our Chairperson and a
former director as advisors. These units were converted to 20,605,200
shares of common stock on
May 16, 2006. MatlinPatterson also received
100,000 additional shares in conjunction with the exchange of advances
and the indebtedness owed to it by our three LNG terminal project companies. MatlinPatterson was
also granted an option to have up to 2,920,000 Mcf per year of gas processed out of interruptible
capacity for its own account per terminal for an option exercise price equal to 0.5% of the cost of
each terminal. The exercise of this option to purchase interruptible capacity will not affect our
ability to sell all or substantially all of our base, firm capacity under TUAs. See
“Certain
Relationships and Related Transactions — Exchange of Debt and Preferred Interests; Preferential
Capacity Rights.”
On
March 7, 2006, a limited partnership controlled by Mr. Garrett and Mr. Soanes, and in which
Mr. Glessner holds a minority interest, exchanged the 50% common membership interest in Bradwood
that NorthernStar LLC did not own in exchange for NorthernStar membership units. On
March 7, 2006,
NorthernStar LLC acquired intellectual and intangible properties held by ESI Holdings, Ltd., an
entity controlled by Mr. Garrett and Mr. Soanes, related to the LNG development business for $5.0
million. This amount was expensed as a general and administrative expense in the accompanying
Statement of Operations for the Nine Months Ending
September 30, 2006.
On
March 27, 2006, MatlinPatterson received a 40% equity interest in Clearwater for the
commitment to finance up to $16.0 million for development costs. The remaining equity interest was
held by the then-existing members of Clearwater. NorthernStar LLC then acquired the Clearwater
entity by exchanging NorthernStar membership units for all of the Clearwater common membership
interests, making Clearwater a wholly-owned subsidiary. NorthernStar LLC issued 41.15 NorthernStar
membership units in the acquisition of Clearwater.
MatlinPatterson formed Orion on
March 7, 2006 and acquired the intellectual property and
intangible rights from an entity controlled by Mr. Garrett and Mr. Soanes. The acquisition price
was comprised of $1.0 million in cash, 19.55% of the equity interests in Orion, and $2.66 million
in non-interest bearing notes (which were discounted by us to $2.2 million using a rate of 10%) and
a commitment by MatlinPatterson to provide development cost funding for the LNG terminal project of
up to $21 million. NorthernStar LLC then acquired Orion by exchanging 20.46 NorthernStar membership
units for all of the Orion common membership units. Orion had no operations or assets prior to the
acquisition of these project assets.
The majority of the assets acquired in the above transactions are related to ongoing
development activities. The liabilities incurred
as a result of these transactions and unpaid as of
September 30, 2006 primarily relate to the non
interest bearing note payable assumed in the Orion transaction ($2.2 million) and the non interest
bearing advance note payable assumed in the Clearwater acquisition ($6.0 million).
Senior Convertible Notes
On
May 17, 2006, we issued $100,000,000 in Senior Convertible Notes due 2013 (convertible
notes). The convertible notes are interest bearing and we, at our discretion, may pay interest in
cash or in-kind by increasing the principal amount of the convertible notes. The convertible notes
bear interest at 5% per annum if paid in cash and 7% per annum if paid in kind. Interest is payable
on May 15 and November 15 of each year. We chose to pay in-kind on the initial interest payment
date,
36
November 15, 2006. The interest rate is subject to increase by 1% under certain circumstances,
including if we fail to complete certain milestones, such as the filing of a registration statement
for an initial public offering; meeting an established deadline for the date such registration
statement is declared effective by the SEC; and meeting an established deadline for the completion
of an initial public offering; however, any such increase in interest is removed upon completion of
the milestone. Unless previously converted, redeemed or repurchased, the convertible notes are
convertible at any time prior to
May 15, 2013 into shares of
our common stock with a par value of $0.01 per share, at an initial conversion price of $9.12 per
share. The conversion price is subject to adjustment in certain circumstances.
The convertible notes may be redeemed at our option after a qualified initial public offering
(Qualified IPO) on the later of 18 months after the issue date or 12 months after the Qualified IPO
subject to satisfaction of certain conditions, at 100% of the principal amount plus additional
amounts set forth in
“Description of Senior Convertible Notes.” A Qualified IPO is an underwritten
initial public offering at not less than $10 per share and with gross proceeds to us and any
selling stockholders of more than $125 million. This offering will constitute a Qualified IPO. The
holders may require us to repurchase all or any portion of the convertible notes on
May 17, 2009 in
cash at a price equal to 100% of the principal amount plus accrued and unpaid interest. We may also
redeem the convertible notes at any time after the third anniversary of the date of issuance of the
convertible notes at our option at 100% of the principal amount plus accrued and unpaid interest,
subject to satisfaction of certain conditions. Unless previously converted, redeemed or
repurchased, the convertible notes will mature and be payable on
May 15, 2013 at 100% of the
principal amount plus accrued and unpaid interest. Upon the occurrence of a change of control, we
are required to make an offer to repurchase any outstanding convertible notes at 110% and 100%
prior to a Qualified IPO and after a Qualified IPO, respectively, plus additional amounts as stated
in the convertible notes.
We are required to file within 90 days of the completion of this offering a Registration
Statement to register the convertible notes and the underlying shares
of our common stock or we begin to incur liquidated damage penalties.
See “Description of Senior Convertible Notes.”
See “Description of Senior Convertible Notes” for further discussion of the terms and
conditions of these securities.
2005
Bradwood Funding
Funding for Bradwood’s development activities was through a total financing commitment with an
affiliate of MatlinPatterson for $14.0 million with advances of $6.9 million as of
December 31,
2005. These amounts substantially funded all of the business activities of Bradwood from its
inception through
December 31, 2005. These amounts were converted to capital upon issuance of the
convertible notes described above as part of MatlinPatterson’s consideration for its acquisition of
equity in us.
Liquidity and Capital Resources
LNG Terminal Development
We are primarily engaged in developing LNG terminals and expect to spend the next several
years developing our projects and continuing the permitting and approval process with federal and
state agencies. These LNG terminal projects will require significant amounts of capital and are
subject to risks and delays in completion. Even if successfully completed, these projects will not
begin to operate and generate significant cash flows until 2010, at the earliest, and their
generation of revenue from on-going operations will be subject to various risks, including credit
risks inherent with reliance on a small number of customers, and operational risks including those
of the LNG terminal as well as connecting pipelines and related infrastructure, among other things.
As a result, our initial and on-going business success will depend to a significant extent
upon our ability to obtain the funding necessary to construct our proposed LNG terminals and
commence operations, and to finance the costs of staffing, operating and expanding
our company
during the long development process and our ability to negotiate and execute TUAs.
We expect for the near term that our operations will primarily consist of expenditures for
development of our three LNG terminal projects to a point at which they have the approvals and
financing necessary to commence construction. Our ultimate generation of revenues will depend on
our ability to obtain TUAs for our projects. Although we believe it will be possible to negotiate
such agreements early in each project’s development, we intend to finalize negotiations of our TUAs
close to the time or after the time we have construction approvals in order to maximize our
negotiating leverage with
37
purchasers of our capacity. In so doing, we believe we can obtain better economic terms. We
may negotiate for payments that would begin prior to the completion of construction of our LNG
terminals or we may seek higher payments commencing upon project operations. Generally, payments
for our regasification services will include a fixed capacity payment and a payment based on the
volumes of LNG processed.
We currently estimate that the total construction cost for our Bradwood and Clearwater
projects will be approximately $1.4 billion, excluding interest during construction and financing
fees. Through
September 30, 2006, we have incurred a total of approximately $20.8 million for
development costs for all three of our projects.
As of
September 30, 2006, we had working capital of $77.9 million, provided primarily by the
issuance of our convertible notes. We currently expect that capital requirements for our three
initial LNG terminal projects will be financed in part through issuances of project level debt,
equity or a combination of the two. An overview of the development and construction costs of all
three initial LNG terminal projects and our detailed financing plans and anticipated capital
requirements for our three initial LNG terminal development projects follow.
Remaining Development and Construction Costs
Our three initial LNG terminal projects are currently in the development stage with no
operating revenues. The primary costs and expenses related to our operations have been:
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• |
|
Consulting and Engineering Studies. Expenses incurred to undertake studies and
simulations necessary for permit approvals and to complete feasibility and
engineering studies for the projects. |
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• |
|
Permitting Costs. Costs incurred to prepare reports and to pay legal and other
expenses related to the regulatory filings and permit applications necessary to
obtain project approvals from federal and state authorities. |
| |
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• |
|
Legal. Costs and expenses are primarily related to project acquisitions and
contracts necessary to undertake project development. |
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• |
|
Public Relations. Costs of outside consultants for community liaison,
advertising and promotion, and of public and government relations to assist in
related approvals. |
| |
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• |
|
Project General and Administrative. Costs of personnel conducting
administrative activities, rent, professional fees, utilities, maintenance costs,
miscellaneous taxes and other costs not otherwise included above that are
directly attributable to project development. |
Development and construction of LNG terminals is capital intensive. Because we are in the
preliminary stage of developing our LNG receiving terminals, substantially all of the costs to
date, related to such activities, have been expensed. These costs primarily include $17.0 million
of consulting and engineering studies, permitting costs, legal, public relations, and general and
administrative. As a result, we are incurring substantial net losses and negative operating cash
flow.
Our ability to obtain construction financing for our projects will depend on our ability to
demonstrate the economic viability and our ability to complete construction of the LNG terminals to
potential lenders which will depend on the final costs of the project, the quality of our
engineering, procurement and construction (EPC) contractor, the terms of our
contract with such EPC
contractor, as well as our ability to attract, negotiate and sell the base, firm terminal capacity
under TUAs.
Bradwood
By the third quarter of 2007, we anticipate receiving all federal, state and local permits,
obtaining necessary financing, and commencing construction in the fourth quarter of 2007. The
terminal is not expected to commence operations prior to the first quarter of 2011.
The Bradwood LNG terminal project has been developed through MatlinPatterson’s member equity
contributions and proceeds from our convertible note offering. Bradwood used $7.0 million of net
cash for development-stage operating activities for the period ended
December 31, 2005 and $9.3
million for the nine months ended
September 30, 2006.
38
We currently estimate that, in the aggregate, the Bradwood LNG terminal project will cost
approximately $600 million, excluding development costs, before interest during construction and
financing fees, to construct and place in service. To date, none of these costs are committed. We
will seek to fund these costs using a combination of project financing, sales of equity at the
project company level, or from proceeds of debt or equity offerings by us. If these types of
financing are not available, we will be required to seek alternative sources of financing, which
may not be available on terms acceptable to us, if at all.
Clearwater
We anticipate that construction of the Clearwater terminal, which will be subject to obtaining
necessary financing, among other factors, will begin in the third quarter of 2008. We expect that
terminal operations will commence in the second quarter of 2010.
To date, Clearwater has been developed through member equity contributions and proceeds from
our convertible note offering. Clearwater used $3.6 million during the nine months ended
September
30, 2006.
We currently estimate that, in the aggregate, the Clearwater LNG terminal project will cost
approximately $800 million, excluding development costs, before interest during construction and
financing fees, to construct and place in service. To date, none of these costs are committed. We
expect to be able to fund these costs using a combination of project financing, sales of equity at
the project company level or from proceeds of debt or equity offerings by us. If these types of
financing are not available, we will be required to seek alternative sources of financing, which
may not be available on terms acceptable to us, if at all.
Orion
Plans for the Orion project are still preliminary and we are unable to provide meaningful
estimates for Coast Guard approval or construction start times. Orion has been financed through
member equity contributions and proceeds from our convertible note offering.
Short-Term Liquidity Needs
Our short term liquidity needs for project development have been primarily funded with the
proceeds from the MatlinPatterson fundings and from our convertible notes offering. Funding for
actual construction will require additional funding and proceeds from this offering are intended to
fund a portion of that amount. Construction of the LNG terminals may be financed through a
combination of any or all of the following:
| |
• |
|
cash balances from the net proceeds of this offering; |
| |
| |
• |
|
issuances of debt and equity securities by us or our subsidiaries, including
issuances of common stock pursuant to exercises by the holders of existing
options; and |
| |
| |
• |
|
LNG terminal capacity reservation fees paid under TUAs. |
Historical Cash Flows
Our historical liquidity and capital resources position is not representative of our current
situation and expected position going forward. At
December 31, 2005, Bradwood, then known as
NorthernStar LLC, had working capital of $0.3 million and Clearwater had a working capital deficit
of $0.6 million. Orion was not in existence in 2005. As of
September 30, 2006 we had a cash and
cash equivalent balance of $82.3 million, following the issuance of our convertible notes in May
2006 resulting in net proceeds of $94 million, and working capital of $77.9 million.
Net cash used for development and general and administrative expenses for the nine months
ended
September 30, 2006 totaled $25.0 million, including $6.0 million in cash payments resulting
from the project company acquisitions. Net cash provided by investing activities was $0.3 million
for this period. We have incurred $1.2 million in capital expenditures, prior to consideration of
the landlord’s allowance, primarily associated with the buildout of our corporate offices to
accommodate our growth. We also paid $0.2 million for the renewal of the land option at Bradwood.
These investing activity expenditures were offset by the assumption of $1.8 million in cash from
the Clearwater acquisition, which was utilized to reduce liabilities
39
assumed in the acquisition. Net cash provided by financing activities was $105.6 million. This
number was comprised of $100 million gross proceeds from the issuance of our convertible notes on
May 17, 2006, reduced by $7.5 million in underwriting fees and legal costs. Additionally we
received $13.1 million in capital contributions from members prior to the offering of the
convertible notes.
Indebtedness
Prior to the issuance of our convertible notes, our source of funds was the commitment of
MatlinPatterson to advance up to an aggregate of $54.3 million, of which $21.0 million was funded
through
April 17, 2006. These amounts were converted to capital upon issue of the convertible notes
described above as part of MatlinPatterson’s consideration for its acquisition of equity in us.
In October 2004, Clearwater entered into an agreement with an LNG supplier to provide a $14.0
million, non-interest bearing, cancelable funding commitment to be used exclusively for development
of the Clearwater project. Two advances, totalling $6.0 million,were made by the LNG supplier prior
to the termination of the agreement in June 2005, resulting in no further obligation to fund the
remaining $8.0 million of the commitment. We are obligated to repay the advances out of the
proceeds of the first draw in the event it is successful in completing a long-term construction and
term loan financing for the completion of the terminal. In the event such financing is not
obtained, the advances shall be repaid in monthly installments over five years upon the achievement
of commercial operations of the terminal or if Clearwater makes a distribution to us. In August
2006, the LNG supplier filed suit claiming repayment of the advance had been triggered as a result
of the project being acquired by us. See “—Legal Proceedings” for discussion of this claim.
Contractual Obligations
We are committed to making cash payments in the future under three office leases, two of which
are for periods of one year or less. Our obligations under option agreements to purchase or lease
our LNG terminal locations are renewable on an annual or semiannual basis. We may terminate our
obligations at any time by electing not to renew the options.
Our contractual obligations for indebtedness and operating leases at
September 30, 2006 are as
follows:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
Payment due by period |
|
| Contractual |
|
|
|
|
|
Less than |
|
|
1-3 |
|
|
3-5 |
|
|
More than |
|
| Obligations |
|
Total |
|
|
1 year |
|
|
years |
|
|
years |
|
|
5 years |
|
Long-Term Debt
Obligations |
|
$ |
108,205,009 |
|
|
$ |
690,927 |
|
|
$ |
7,514,082 |
|
|
$ |
— |
|
|
$ |
100,000,000 |
|
Operating Lease
Obligations |
|
|
5,042,205 |
|
|
|
166,968 |
|
|
|
515,728 |
|
|
|
809,884 |
|
|
|
3,549,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
113,247,214 |
|
|
$ |
857,895 |
|
|
$ |
8,029,810 |
|
|
$ |
809,884 |
|
|
$ |
103,349,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Related Party Transactions
Transactions with Affiliates
In January 2004, ESI Holdings, Ltd. entered into a consulting agreement, which was
subsequently assigned to Bradwood, with a limited company controlled by Mr. Coppedge who, following
the offering, will indirectly hold % of our outstanding common stock assuming the
over-allotment option is not exercised. Under the terms of the agreement, the entity provides
project development management services in obtaining certain regulatory and construction permits.
Among other things, the agreement provided for payments of $15,000 per month during an initial
period and $34,000 per month during a subsequent period defined by certain milestones. In addition,
it will receive potential bonus payments of $500,000 to $2,000,000 for the achievement of certain
milestones. Payments to the related party during the period from inception through the year ended
December 31, 2005 and the nine months ended
September 30, 2006, were approximately $738,000 and
$524,000, respectively with $212,000 and $178,000 included in accounts payable as of the year ended
December 31, 2005 and the nine months ended
September 30, 2006, respectively.
40
Prior to their being named as our officers, Bradwood and Clearwater retained ESI Holdings,
Ltd., an entity controlled by our Chief Executive Officer and our President, for certain consulting
services primarily relating to the development of Bradwood’s business and strategic plans. Payments
to the related party during the period from inception through the year ended
December 31, 2005 and
the nine months ended
September 30, 2006 were approximately $841,000 and $375,000, respectively.
This agreement was terminated effective
March 1, 2006.
See “—Background” and “—Purchase and Financing of Our LNG Terminal Projects and LNG Related
Assets” for a description of related party transactions in our formation history.
Purchase of Intellectual Property and Acquisition Consulting Services
Concurrently with the acquisition of Bradwood and Orion, we acquired intellectual property
rights relating to LNG project conceptualization and development activities from an entity owned by
our Chief Executive Officer and our President in exchange for a $5.0 million cash payment which was
paid on
May 17, 2006. This payment has been included as general and administrative expenses in the
September 30, 2006 financial statements.
In
addition, we issued shares of our common stock valued at $8.9 million to Mr. Lindner, one
of our directors, and a former director, for consulting services provided during our
formation and initial capitalization. These costs have also been included as general and
administrative expenses in our
September 30, 2006 financial statements.
California Office Rental
On
April 1, 2006 we entered into a lease for office space in California with Real Estate
Energy Company, Ltd., an entity controlled by Mr. Lindner, a member of our board of directors. The
lease period extends through
May 31, 2007 and is terminable upon 30 days notice with no termination
penalty. Payments for the lease are $2,000 per month, which we believe is indicative of the market
rates for such commercial office space and services available in the local region.
Other Matters
Critical Accounting Estimates and Policies
The selection and application of accounting policies is an important process that will
continue to develop as our business activities evolve and as accounting rules continue to be
developed. Accounting rules generally do not involve a selection among alternatives, but involve an
implementation and interpretation of existing rules, and the use of
judgment, applied to the specific set
of circumstances existing in our business. We make every effort to comply with all applicable rules
on or before their adoption, and believe the proper implementation and consistent application of
the accounting rules are critical. Nevertheless the accounting literature does not specifically
address every situation. In these cases, we must use our best judgment to adopt a policy for
accounting for these situations. We accomplish this by analogizing to similar situations and the
accounting guidance governing them, and consult with our independent accountants about the
appropriate interpretation and application of these policies.
Accounting for LNG Terminal Development Activities
We are in the preliminary stage of developing our LNG terminals. Our policy is to begin
capitalizing the costs of our LNG terminals and related pipelines once the individual project meets
the following criteria: (i) regulatory approval has been received, (ii) financing for the project
is available and (iii) management has committed to commence construction. Prior to meeting these
criteria, most of the costs associated with a project are expensed as incurred. These costs
primarily include costs related to environmental studies and preliminary engineering activities
necessary to prepare and submit regulatory permit applications for the LNG terminal and related
pipelines and related regulatory processes and public relations. Land costs associated with LNG
terminal sites are capitalized. Costs of certain permits will be capitalized as intangible LNG
assets when we have received approval to commence construction. We have also capitalized costs
related to options to purchase or lease land that may be used for potential LNG terminal sites.
Revenue Recognition
LNG regasification capacity fees that are advanced prior to performance of any services or the
availability of operational capacity will initially be deferred and will be recognized as revenue
once capacity becomes operational over the term of the respective TUA.
41
Accounting Estimates and Assumptions
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosures of contingent gains and losses at the
date of the financial statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
We evaluate our estimates on an ongoing basis, including those related to accrual of expenses,
the useful lives of property and equipment, and assumptions used in valuing common stock options
for the purpose of determining stock-based compensation. We base our stock option expense
calculations on available market information, appropriate valuation methodologies, including the
Black-Scholes-Merton option model, or the Model, and on various other assumptions that are believed
to be reasonable, the results of which form the basis for making judgments about the carrying value
of assets and liabilities. The inputs for this Model are stock price at valuation and issue date,
strike price for the option, dividend yield, risk-free interest rate, life of the option in years,
the expected forfeiture rate and volatility.
New Accounting Standards
In June 2005, the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force
reached a consensus on Issue No. 05-6, Determining the Amortization Period for Leasehold
Improvements (EITF 05-6). The guidance requires that leasehold improvements acquired in a business
combination or purchased subsequent to the inception of a lease be amortized over the lesser of the
useful life of the assets or a term that includes renewals that are reasonably assured at the date
of the business combination or purchases. The guidance is effective for periods beginning after
June 29, 2005.
The Company’s adoption of EITF 05-6 did not have a significant effect on its
financial statements.
In May 2005, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 154,
Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement
No. 3 (SFAS No. 154). SFAS No. 154 requires retrospective application to prior periods’ financial
statements for changes in accounting principles, unless it is impracticable to determine either the
period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that
retrospective application of a change in accounting principle be limited to the direct effects of
the change. Indirect effects of a change in accounting principle, such as a change in
non-discretionary profit-sharing payments resulting from an accounting change, should be recognized
in the period of the accounting change. SFAS No. 154 is effective for accounting changes and
corrections of errors made in fiscal years beginning after
December 15, 2005. Early adoption is
permitted for accounting changes and corrections of errors made in fiscal years beginning after the
date this statement was issued.
The Company’s adoption of SFAS No. 154 is not expected to have a
material effect on
the Company’s reported financial position or results of operations.
In December 2004, the FASB issued SFAS No. 153,
“Exchanges of Nonmonetary Assets, an amendment
of APB Opinion No. 29” (SFAS No. 153). The guidance in APB Opinion No. 29,
“Accounting for
Nonmonetary Transactions” (APB Opinion No. 29), is based on the principle that exchanges of
nonmonetary assets should be measured based on the fair value of assets exchanged. The guidance in
APB Opinion No. 29, however, included certain exceptions to that principle. SFAS No.153 amends APB
Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets
that do not have commercial substance. A nonmonetary exchange has commercial substance if the
future cash flows of the entity are expected to change significantly as a result of the exchange.
SFAS No. 153 is effective for nonmonetary exchanges occurring in fiscal periods beginning after
June 15, 2005. Our adoption of SFAS No. 153 is not expected to have a material impact on our
reported financial position and results of operations.
In September 2006, the FASB issued SFAS No. 157,
“Fair Value Measurements” (SFAS 157), which
clarifies the definition of fair value, establishes guidelines for measuring fair value, and
expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair
value measurements and eliminates inconsistencies in guidance found in various prior accounting
pronouncements. SFAS 157 will be effective for
the Company on
January 1, 2008.
The Company is
currently evaluating the impact of adopting SFAS 157 on its financial position, cash flows, and
results of operations.
In September 2006, the Securities and Exchange Commission (SEC) released Staff Accounting
Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements” (SAB 108). SAB 108 provides interpretive
guidance on the SEC’s views on how the effects of the carryover or reversal of prior year
misstatements should be considered in quantifying a current year misstatement. The provisions of
SAB
42
108 will be effective for us for the fiscal year ended
December 31, 2006. We are currently
evaluating the impact of applying SAB 108 but we do not believe that the application of SAB 108
will have a material effect on our financial position, cash flows, and results of operations.
Quantitative and Qualitative Disclosure About Market Risk
The development of our LNG terminal business is based upon the belief that prices of natural
gas will continue to support the development of LNG terminals in the United States. Any decline in
the price of natural gas in the United States below those levels could significantly, negatively
affect our ability to develop and operate LNG terminals.
We have cash investments that we manage based on internal investment guidelines emphasizing
liquidity and preservation of capital. These investments are stated at historical cost, which
approximates fair market value on our consolidated balance sheet.
43
INDUSTRY OVERVIEW
The information in the section below has been derived, in part, from various official, private
and public sources. Our commentary is based upon management’s current understanding of industry
conditions and speak only as of the date of this prospectus unless the context indicates otherwise.
This information has not been independently verified by us or the Initial Purchaser and may not be
consistent with other third-party information. We believe that the information included in this
prospectus from industry surveys, publications and forecasts is reliable.
Introduction
During the first nine months of 2006, North America consumed an average of more than 60
billion cubic feet per day (Bcf/d) of natural gas. The United States is the largest energy consumer
in the world and is expected to require the largest increase in LNG imports to meet its growing
demand for natural gas. LNG only accounted for approximately 3% of total United States gas
consumption in 2005. However, declining North American natural gas reserves coupled with steadily
increasing demand is creating a constrained supply with a projected shortfall of 13 Bcf/d by 2015
based on projections by the Energy Information Administration (EIA).
The California and the Pacific Northwest gas markets are at the end of the North American
pipeline system and import over 80% of their natural gas supply from neighboring states or Canada.
As a result, these markets are at risk of supply disruptions caused by growth of demand in
“upstream” gas markets as gas reserves in North America decline. We believe that West Coast LNG
terminals are needed to increase regional gas supply and reliability by allowing these markets to
access the abundant reserves of natural gas in the Asia Pacific and Middle East regions. Currently,
there are only five operational LNG terminals in North America, all of which are located on the
East or Gulf Coasts of the United States. According to the Federal Energy Regulatory Commission
(FERC), five LNG terminals are currently under construction in North America, but only one of these
is on the west coast of North America, located on the Baja Peninsula in Mexico.
We believe that natural gas suppliers in the Asia Pacific and Middle East regions will have a
cost, including a 12% return on capital, to produce, liquefy, ship and deliver regasified LNG
through our terminals to West Coast pipeline networks that will be $2.50 — $4.70 per million
British thermal unit (MMBtu). This will enable them to compete favorably with North American
domestic supplies of natural gas given current and projected natural gas market prices. On
December
5, 2006, the Henry Hub spot rate for immediate natural gas deliveries was $7.32/MMBtu, and the
price on New York Mercantile Exchange (NYMEX) for futures
contracts for first quarter 2011
deliveries, when we expect Bradwood to be in operation, was approximately $8.02/MMBtu (this futures
pricing is not necessarily indicative of actual pricing that will ultimately be experienced in
first quarter 2011).
U.S. Natural Gas Market
Demand for Natural Gas
North America is one of the largest interconnected natural gas markets in the world consuming
more than 75 Bcf/d, of which the United States alone accounts for more than 60 Bcf/d. The U.S. is
the world’s largest producer, consumer, and net importer of energy, ranking eleventh worldwide in
reserves of oil, sixth in natural gas, and first in coal. While we believe oil will continue to be
the preferred choice for the production of transportation fuels (gasoline and diesel) and coal
consumption will continue to dominate as the primary fuel for existing base load electric power
generation, natural gas consumption is forecast to have the greatest demand growth of all
hydrocarbon fuels in the United States, driven by the need for clean and efficient mid-market and
peaking power generation, for industrial use and home heating. In its 2006 Energy Outlook, the EIA
forecasts U.S. natural gas demand to grow at an average rate of 1.25% per year, with gas demand
increasing from its current level of 61 Bcf/d to 74 Bcf/d by 2025.
North American Gas Supply and Production
In recent years, despite record gas prices and record levels of drilling activity, the
production of natural gas in the United States and Canada has failed to increase. The 2006 EIA
long-term gas outlook predicts the production of natural gas in North America to remain nearly flat
through 2015 as shown below. Although U.S. unconventional production is expected to increase
marginally, Canadian and conventional U.S. gas production, not including Alaska and Hawaii, is
projected to
44
decrease. With the continued increase in demand and flat production profile, a potential
natural gas shortfall of as much as 13 Bcf/d is forecasted by 2015.
North America Natural Gas Supply & Demand
(Assuming an average of $5.48/MMBtu Price Scenario)
Source: EIA 2006 International Energy Outlook & EIA 2006 Annual Energy Outlook
As the gas market begins to recognize the expected growing imbalance between supply and
demand, we expect natural gas prices will rise until the market reaches equilibrium. There has been
a significant rise in the North American market reference gas price measured at Henry Hub over the
past six years with prices ranging from a low of $2.72/MMBtu in January 2000 to a high of
$13.36/MMBtu in October 2005 because of real or perceived shortfalls of natural gas supply.
Henry Hub (NYMEX) Historical Price
Source: NYMEX settled prices.
45
Worldwide Natural Gas Reserves
As illustrated below, over the past two decades, increases in new natural gas reserves have
far exceeded the amount of gas produced during the same period, doubling the estimated proven
reserves from approximately 3,300 trillion cubic feet (Tcf) in 1984 to more than 6,300 Tcf at year
end 2004. Many of these increases resulted from discoveries resulting from drilling for oil. While
global proven reserves have increased over 80% during the last 20 years, North American reserves
have declined by 30% during the same period. In its Statistical Review of World Energy 2005, BP
(formerly British Petroleum) estimates that at present production rates, proven global reserves
will sustain current global demand for 66 years.
Global Proved Reserves of Natural Gas
Source: BP Statistical Review of World Energy 2006.
In addition, the U.S. Geological Service (USGS) in its most recent assessment, estimated that
there is a 95% probability that the world outside of the United States contains over 2,000 Tcf of
undiscovered natural gas reserves. The USGS median, or 50% probability estimate, is for 4,333 Tcf
of still to be discovered reserves, which would mean that over 40% of the world’s total gas
reserves have not yet been discovered. Almost all these undiscovered reserves are expected to be
found outside North America. These undiscovered reserves combined with proven reserves would
provide over 110 years of natural gas supply.
Although the United States ranks as having the sixth-largest proved reserves of natural gas,
North America as a whole, including Canada, the United States and Mexico, had proved reserves of
only 263 Tcf as of 2005, representing approximately 4% of the proved global reserves at that time.
North America is the only continental region where net proved reserves diminished in 2005 and is
the only regional gas market where natural gas production has outstripped new discoveries.
Moreover, the North American gas fields are mature and have been extensively explored and drilled.
Within North America, the greatest share of the proved, but as yet large undeveloped reserves, are
located in Alaska, the Mackenzie Delta, and the Yukon regions of Canada. Developing these reserves
and associated infrastructure to transport this gas to market, will require massive capital
investments estimated to be as high as $25 to $30 billion. Moreover, the construction of production
facilities and pipelines in the Arctic wilderness is likely to face significant regulatory hurdles,
and completion of this project could take up to 10 years.
Projected Uncontracted Worldwide LNG Liquefaction Capacity
The worldwide LNG market is loosely comprised of two markets, the Pacific Basin LNG market and
Atlantic Basin LNG market. The Atlantic Basin LNG market, including the U.S. East and the Gulf
Coast and Europe, is predominately supplied
46
by the Middle East region and the Atlantic/Mediterranean producing regions. The Pacific Basin
LNG market, which will include the West Coast, is predominately supplied by the Asia Pacific region
producers. Because of their central location, Middle East region liquefaction projects are capable
of economically supplying both LNG market basins. For example, the reported cost of shipping LNG
from the Middle East to the Gulf Coast is estimated to be approximately $0.04-0.10 per MMBtu more
expensive than shipping LNG from the Middle East to the West Coast.
Asia Pacific region producers currently supply approximately 45% of LNG consumed globally, and
have plans to increase liquefaction capacity by more than 10 Bcf/d from 2005 to 2015. During the
same time period, Middle East region producers plan to add an additional 10 Bcf/d of liquefaction
capacity. The following table shows the global LNG liquefaction capacity of both existing and
anticipated future facilities by producing region.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Liquefaction Capacity |
|
Contracted Volumes |
|
Uncontracted Volumes |
| Bcf/d |
|
2005 |
|
2010 |
|
2015 |
|
2005 |
|
2010 |
|
2015 |
|
2005 |
|
2010 |
|
2015 |
Pacific Basin |
|
|
9.64 |
|
|
|
15.55 |
|
|
|
20.94 |
|
|
|
8.60 |
|
|
|
12.94 |
|
|
|
13.48 |
|
|
|
1.04 |
|
|
|
2.61 |
|
|
|
7.45 |
|
Middle East |
|
|
4.78 |
|
|
|
12.49 |
|
|
|
15.37 |
|
|
|
4.35 |
|
|
|
12.00 |
|
|
|
14.77 |
|
|
|
0.43 |
|
|
|
0.49 |
|
|
|
0.60 |
|
Atlantic/Mediterranean |
|
|
7.14 |
|
|
|
13.43 |
|
|
|
24.92 |
|
|
|
6.17 |
|
|
|
10.39 |
|
|
|
12.11 |
|
|
|
0.97 |
|
|
|
3.04 |
|
|
|
12.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
21.56 |
|
|
|
41.47 |
|
|
|
61.22 |
|
|
|
19.12 |
|
|
|
35.33 |
|
|
|
40.36 |
|
|
|
2.43 |
|
|
|
6.14 |
|
|
|
20.86 |
|
Source: Purvin & Gertz, November 2006.
The table above shows the amount of LNG capacity currently contracted under long-term
agreements. The uncontracted capacity, sometimes referred to as a supply overhang, represents the
supply potential for regasification projects that require access to liquid markets that are
supported by highly rated creditworthy buyers.
LNG Trends in North America
Over its 40-year history LNG has become more competitive due to several advances in technology
that have contributed to significantly lowering the cost for the liquefaction, transportation and
regasification of LNG. Together, the effect of the recent technological advances, increased scale
and more competition have resulted in LNG competing favorably with other sources of gas supply. We
believe LNG can be delivered to the West Coast at a price of between approximately $2.50 to
$4.70/MMbtu as detailed in the attached table, which shows the build up of the cost structure of
the LNG value chain for various existing LNG supply projects supplying the Pacific Basin LNG market
(excluding potential or proposed LNG supply projects at Gorgon, Peru and Sakhalin).
| |
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Exploration, |
|
|
|
|
|
|
| |
|
Production and |
|
Shipping |
|
Regas |
|
West Coast |
| Plant ($/MMBtu): |
|
Liquefaction(1)(3) |
|
West Coast(2) |
|
Low |
|
— |
|
High |
|
Low |
|
— |
|
High |
Ras Lasffan 3 (Qatar) |
|
|
0.32 |
|
|
|
1.65 |
|
|
|
— |
|
|
|
2.00 |
|
|
|
0.50 |
|
|
|
— |
|
|
|
0.80 |
|
|
|
2.47 |
|
|
|
— |
|
|
|
3.12 |
|
QatarGas 3 (Qatar) |
|
|
0.57 |
|
|
|
1.65 |
|
|
|
— |
|
|
|
2.00 |
|
|
|
0.50 |
|
|
|
— |
|
|
|
0.80 |
|
|
|
2.72 |
|
|
|
— |
|
|
|
3.37 |
|
Tanguh (Indonesia) |
|
|
0.88 |
|
|
|
1.00 |
|
|
|
— |
|
|
|
1.37 |
|
|
|
0.50 |
|
|
|
— |
|
|
|
0.80 |
|
|
|
2.38 |
|
|
|
— |
|
|
|
3.05 |
|
RasGas (Qatar) |
|
|
1.51 |
|
|
|
1.65 |
|
|
|
— |
|
|
|
2.00 |
|
|
|
0.50 |
|
|
|
— |
|
|
|
0.80 |
|
|
|
3.66 |
|
|
|
— |
|
|
|
4.31 |
|
MNLG 3 (Malayasia) |
|
|
1.65 |
|
|
|
1.04 |
|
|
|
— |
|
|
|
1.57 |
|
|
|
0.50 |
|
|
|
— |
|
|
|
0.80 |
|
|
|
3.19 |
|
|
|
— |
|
|
|
4.02 |
|
Darwin (Australia) |
|
|
1.92 |
|
|
|
1.08 |
|
|
|
— |
|
|
|
1.34 |
|
|
|
0.50 |
|
|
|
— |
|
|
|
0.80 |
|
|
|
3.50 |
|
|
|
— |
|
|
|
4.06 |
|
NWS (Australia) |
|
|
2.46 |
|
|
|
1.19 |
|
|
|
— |
|
|
|
1.41 |
|
|
|
0.50 |
|
|
|
— |
|
|
|
0.80 |
|
|
|
4.15 |
|
|
|
— |
|
|
|
4.67 |
|
|
|
|
| (1) |
|
Source: Wood Mackenzie, November 2006, based on 12% post tax return, including revenue from
liquids. |
| |
| (2) |
|
Source: Wood Mackenzie, August 2006, based on 145,000 m3 carriers and 12% return
on capital. |
| |
| (3) |
|
Source: Wood Mackenzie, November 2006, cost of Exploration & Production fully allocated to
liquids production. |
LNG has been used to provide peaking services for natural gas deliveries in the United
States for many years. There are 126 small scale LNG storage facilities that provide peak shaving
and load balancing services throughout the United States.
In the 1970s and early 1980s, four LNG terminals capable of receiving cargoes by LNG carrier
were constructed and operated for a brief period of time. As a result of the decline in natural gas
prices that occurred in the late 1970s, all but one of those terminals were decommissioned as the
cost of delivered LNG became noncompetitive with conventional U.S.
domestic supplies. Now, each of the decommissioned terminals has since been reactivated, and
have undergone or are
47
proposing substantial capacity expansions. Moreover, all conventional
regasification facilities are fully contracted for periods in excess of 20 years.
The following table presents the existing LNG imports terminals in the United States that are
capable of receiving LNG from LNG carriers and their related daily send-out capacity:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Send Out Capacity |
|
Percent |
| Project/Location |
|
Owner |
|
Start-Up |
|
(Bcf/d) |
|
Contracted |
Lake Charles (LA) |
|
Southern Union |
|
|
1982 |
|
|
|
1.80 |
|
|
|
100 |
% |
Elba Island (GA) |
|
Southern LNG |
|
|
2001 |
(1) |
|
|
0.81 |
|
|
|
100 |
% |
Cove Point (MD) |
|
Dominion |
|
|
2003 |
(1) |
|
|
0.75 |
|
|
|
100 |
% |
Everett (MA) |
|
Suez LNG NA |
|
|
1971 |
|
|
|
0.72 |
|
|
|
100 |
% |
Gulf Gateway (Gulf of Mexico) |
|
Excelerate |
|
|
2005 |
|
|
|
0.40 |
|
|
|
N/A |
(2) |
|
|
|
| Source: Poten and Partners, December 2006. |
| |
| (1) |
|
Date reflects recommissioning. |
| |
| (2) |
|
Excelerate regasification process requires specifically-designed LNG carriers. |
Although additional LNG regasification capacity is under construction in North America, less
than 0.75 Bcf/d of LNG supply to North America is expected to flow through these LNG terminals to
the southwestern U.S. markets.
Competition for Pacific Basin LNG Supply
We believe the projected supply shortfall in the west coast of North America can
cost-effectively be met by LNG since North America is not within economical pipeline distance of
gas reserves in other regions and gas supplies from Alaska are not expected to be developed prior
to 2015. Furthermore, construction of major pipelines connecting Rockies gas with eastern
pipelines such as Kinder Morgan’s Rockies Express and CenterPoint’s Mid-Continent Express will
transport gas production away from the west coast of North America. Whether or not the LNG industry
will be able to supply as much as 13 Bcf/d of LNG by 2015 is uncertain at this stage. We believe it
is likely that supply and demand will be balanced at a higher price level balancing the increased
level of drilling and production and reduced demand. Under such a scenario, LNG is expected to play
an increasingly significant role in balancing supply and demand.
The LNG supply overhang is primarily concentrated in the Asia Pacific region where the
availability of reserves has outpaced the growth in the Pacific Basin LNG market. Other than the
west coast of North America, the likely Asia Pacific region customers for the projected additional
LNG supplies in Asia Pacific and Middle East regions are the established LNG-consuming countries of
Japan, South Korea and Taiwan, and the emerging economies of China and India.
The traditional Pacific Basin LNG markets of Japan, Korea and Taiwan offer potential suppliers
the advantage of an established infrastructure, relatively short supply lines and creditworthy
buyers, but these markets are relatively saturated, highly seasonal, and are characterized by
oligopoly/monopoly structures. Long-term pricing for LNG in the Asia Pacific market is largely
based on formulae that link the LNG price to the price of selected crude oil and alternative energy
products. Additionally, these
contracts often contain price formulas that limit the impact of the
crude oil price movements above and below certain crude oil price levels, commonly referred to as
the
“S” Curve. The
“S” Curve typically reduces the volatility by reducing the rate of increase
(when prices are high) or decrease (when prices are low) in the LNG price once certain agreed upon
levels are reached.
India and China are fast growing markets in the Asia Pacific region with huge demand
potential. We believe the lack of downstream gas distribution infrastructure, non-competitive
pricing, and credit uncertainty will present formidable challenges to developers of an LNG
liquefaction project looking to these markets as off takers. As reported in
LNG in World Markets
in November 2006, China’s earlier priced LNG
contracts with North West Shelf and Tangguh were
priced far below global LNG prices (less than $3.80/MMBtu). Recently signed
contracts, such as the
Shanghai LNG/Petronas agreement, suggest China is now willing to pay closer to market rate
($5.80/MMBtu at an oil price of $60/bbl). India and Pakistan, however, based on recent
negotiations with Iran and published in Platt’s
LNG Daily in December 2006, are targeting to pay no
more than $4.50/MMBtu for LNG compared to prices in the traditional Pacific Basin markets of
approximately $6 to $8/MMBtu.
48
Asian LNG Prices
In contrast, U.S. prices are expected to average $1/MMBtu higher than other traditional
Pacific Basin markets, $2/MMBtu above China and in excess of $3/MMBtu higher than India and
Pakistan. As a result, we believe LNG producers are likely to view the West Coast market more
favorably than selling more LNG into India and China at terms similar to those of existing
contracts.
49
BUSINESS
NorthernStar Natural Gas Inc. was founded in May 2005 to develop, own and operate liquefied
natural gas (LNG) receiving/importation terminals on the West Coast of the United States (West
Coast). We consolidated ownership of our LNG terminal projects in March 2006 to take advantage of
project portfolio diversification, economies of scale, and greater access to capital.
The members of our senior management team have significant project development experience and
have been involved in the development of more than 50 energy infrastructure projects with an
aggregate cost of over $15 billion. They have been directly involved in either the development,
construction or operation of nine LNG terminal projects, including our three development projects.
Our LNG terminal projects, when complete, will provide direct access to major West Coast
natural gas demand centers. We intend to negotiate and sign terminal use agreements (TUAs) for all
or substantially all of the long-term base capacity of each LNG terminal with highly rated
creditworthy counterparties. We expect to provide offloading and regasification services under the
TUAs without taking ownership of LNG or natural gas. Each TUA is expected to have a 20-year term
and to generate a steady, predictable stream of contracted fee payments with no commodity price
risk. In addition, we may periodically sell capacity to third parties or purchase, regasify and
sell cargoes of LNG on a spot basis as opportunities arise when the terminals’ firm capacity is not
being utilized by our TUA customers, generating additional revenues to supplement those received
under the TUAs.
Overview of Our Projects
Our existing LNG terminal project portfolio consists of one project in Oregon and two projects
in Southern California.
| |
• |
|
Our Bradwood project is designed as a land-based LNG terminal in a remote
location of Oregon on the Columbia River with deepwater channel access,
approximately 30 miles inland from the Pacific Ocean. We have entered into an
option agreement which allows us to purchase the property through August 2008.
Bradwood is engineered to have an initial sustainable base capacity of 1.0
billion cubic feet per day (Bcf/d), a peak capacity of 1.3 Bcf/d and a
pre-engineered capability to expand the base capacity to 2.0 Bcf/d. Bradwood’s
location offers prospective customers, via a connecting pipeline discussed more
fully below in “Business —Bradwood,” convenient access to the region’s pipelines
serving a 9.0 Bcf/d market across Oregon, Washington, Idaho, Nevada and Northern
and Southern California. Bradwood is the only LNG terminal project in the Pacific
Northwest to have completed the Federal Energy Regulatory Commission (FERC)
prefiling process, and whose formal applications to the FERC have been accepted
into the application process under Sections 3 and 7 of the Natural Gas Act for
authorization to construct and operate an LNG receiving terminal and pipeline. We
are anticipating regulatory approvals by the FERC and remaining state and local
authorities in the third quarter of 2007. Based on this permitting timeline, we
anticipate the start of terminal construction in the fourth quarter of 2007, and
the commencement of commercial operations in the first quarter of 2011. |
| |
| |
• |
|
Our Clearwater project has contracted for the use of Platform Grace, an
existing oil and gas production platform located in federal waters approximately
13 miles offshore of Oxnard, California, which we intend to convert into an LNG
terminal. We have entered into an option agreement which allows us to purchase
the property through March 2012. The current owner will terminate oil and gas
production activities and permanently abandon production wells prior to our
taking possession of the platform. We plan to refurbish and reconfigure the
platform for regasification of LNG and to add two floating mooring docks capable
of accommodating large LNG carriers. Clearwater is engineered to have a
sustainable base capacity of 1.2 Bcf/d and a peak capacity of 1.4 Bcf/d. The
platform will be connected by a 13-mile offshore pipeline to the Southern
California Gas Co. (SoCalGas) pipeline network and storage infrastructure serving
the 4.0 Bcf/d Southern California market. SoCalGas will construct 65 miles of
pipeline to connect and to loop the existing system to receive 1.4 Bcf/d on a
firm basis. Clearwater signed a Collectable Work Agreement with SoCalGas in 2004
to initiate the engineering design of the pipeline and in August 2006 we entered
into a Collectable System Upgrade Agreement with SoCalGas for the design and
construction of the required pipeline facilities. Clearwater filed its original
Deepwater Port (DWP) license application in February 2004, and, following our
purchase of this project in late |
50
| |
|
|
March 2006, we submitted an amended and restated application in June 2006 as a more
comprehensive response to additional data requests with direction from the relevant
state and federal regulatory agencies. Based upon new agency reviews, the U.S.
Coast Guard and the California State Lands Commission are expected to move forward
with engagement of a contractor for the preparation of our draft environmental
reports. We are anticipating regulatory approval in the second quarter of 2008, the
commencement of construction in the third quarter of 2008, and commencement of
commercial operations in the second quarter of 2010. |
| |
| |
• |
|
Our Orion project has a target location about 25 miles offshore of Carlsbad,
California with direct access to the Los Angeles and San Diego markets. Orion is
expected to be designed to include a concrete hull floating storage and
regasification unit with a sustainable base capacity of 1.2 Bcf/d, a peak
capacity of 1.5 Bcf/d. We intend to pursue the development of Orion in
conjunction with the approval process of our Clearwater project. |
Our three LNG terminal projects are designed to have an aggregate sustainable base capacity of
3.4 Bcf/d and expansion capability that could increase our base capacity to 4.4 Bcf/d.
We expect the proceeds of this offering to fund the equity portion of the construction of our
Bradwood LNG terminal project, to fund the continued development of our remaining initial projects,
and to fund the development of LNG projects in addition to our initial projects
that we determine to have strong development potential, to pay the transaction costs related to
this offering and to fund working capital for general corporate purposes. We expect construction of
our LNG terminals to be funded by project financings supported by TUAs with highly rated
creditworthy parties. The aggregate construction cost for our Bradwood and Clearwater projects is
projected to be approximately $1.4 billion, excluding interest during construction and financing
fees. Through
September 30, 2006, we have incurred a total of approximately $20.8 million in
development costs for all three of our projects.
51
| |
|
|
|
|
|
|
|
|
|
| |
|
|
NorthernStar Natural Gas Inc. |
| |
|
|
|
|
| |
|
|
|
|
|
|
|
|
| |
|
Bradwood |
|
Clearwater |
|
Orion |
| |
| |
|
Columbia River, |
|
13 miles offshore |
|
25 miles offshore |
| Location: |
|
Bradwood OR |
|
Oxnard CA |
|
Carlsbad CA |
| |
|
(dollars in millions) (capacity in Bcf/d) |
Base capacity |
|
1.0 |
|
1.2 |
|
1.2 |
Peak capacity |
|
1.3 |
|
1.4 |
|
1.5 |
Expanded base capacity(1) |
|
2.0 |
|
— |
|
— |
Target market(s) |
|
OR, WA, ID, |
|
|
|
|
|
|
CA, NV |
|
S. CA |
|
S. CA |
Market size |
|
9.0 |
|
4.0 |
|
4.0 |
Primary permitting authority |
|
FERC |
|
Coast |
|
Coast |
|
|
|
|
Guard/CSLC |
|
Guard/CSLC |
Expected primary permit |
|
Third Quarter 2007 |
|
Second Quarter 2008 |
|
Not determined |
Expected commercial operations |
|
First Quarter 2011 |
|
Second Quarter 2010 |
|
Not determined |
|
|
$18 |
|
$20 |
|
$24 |
Estimated
construction cost(1)(2) |
|
$600 |
|
$800 |
|
Not determined |
|
|
|
| (1) |
|
Excludes development and construction cost of Bradwood base capacity expansion from 1.0 to
2.0 Bcf/d, excluding interest during construction and financing fees of approximately $230
million. |
| |
| (2) |
|
Excluding interest during construction and financing fees. |
Our Competitive Strengths
We believe that our competitive strengths include the following:
Strategic project locations provide Pacific basin suppliers with access to attractive U.S.
West Coast markets. We have selected the locations of our LNG terminals because each offers (i)
access to attractive markets; (ii) reduced downstream transportation costs for our customers; (iii)
the opportunity for cost-effective development and construction, reducing unproductive capital
investments; and (iv) reduced development time for permitting and construction.
Significant barriers to entry based on advanced positioning in regulatory approval processes
and natural / existing infrastructure of LNG Terminal sites. We believe that Bradwood and
Clearwater, if completed on schedule, will be the first operating LNG terminals in their respective
markets. Bradwood is the only LNG project in the Pacific Northwest to
have completed the Federal Energy Regulatory Commission (FERC)
prefiling process under Section 3 of the Natural Gas Act for
authorization to construct and operate an LNG receiving terminal. We believe
Bradwood is approximately 6 to 12 months ahead of competing projects in the region reflecting the
current stage of its permitting activities. Its deepwater location does not require a costly
breakwater or significant dredging. Clearwater utilizes an existing platform and does not require
construction of LNG storage facilities, thus we believe that it can have a 24 to 30 months shorter
construction period compared to other offshore terminal designs.
Portfolio of LNG Terminal projects provides economies of scale, market optionality and
increased likelihood for success. We believe that our portfolio of LNG terminal projects in Oregon
and California will be more attractive to potential TUA capacity holders than single project
entities because we can provide our terminal customers with flexibility to deliver
52
LNG supply to multiple receiving points connecting to several major pipelines and West Coast
markets. Further, we believe that simultaneously pursuing a portfolio of LNG terminals will provide
economies of scale at the development, TUA marketing, financing, construction and operating stages.
We believe that we will be able to leverage our knowledge and experience as we develop our projects
to expedite the permitting process and to increase the likelihood of success for each successive
project.
Seasoned and incentivized management team with significant project development experience. The
members of our senior management team have significant project development experience, having been
involved in the development of more than 50 energy infrastructure projects with an aggregate
investment of over $15 billion. They have been directly involved in either the development,
construction or operation of nine LNG terminal projects worldwide including all the existing
projects currently being developed by us. Following the completion of this offering, our senior
management team will, directly or indirectly, control approximately % of our outstanding
common stock.
Our Strategy
Our strategy is to become a leading independent LNG terminal developer, owner and operator in
our targeted markets. These markets, including the West Coast, are those that we believe offer: (i)
attractive margins to potential LNG suppliers; (ii) fewer LNG terminal competitors; (iii) high
barriers to entry; and (iv) the potential to allow us to charge competitive rates with attractive
margins. We intend to implement this strategy through the following steps:
Target LNG Terminal Sites with Attractive Margins. We are presently developing LNG terminals
on the West Coast to help satisfy the region’s substantial existing and forecasted demand for
natural gas with LNG supplies from Asia Pacific, Middle East, and other potential LNG producers. We
believe these gas producers view the liquid, heavily-traded, creditworthy U.S. market as an
attractive alternative to other Pacific Basin LNG markets. We believe the barriers to entry caused
by the significant regulatory, environmental and public-concern hurdles in the West Coast market
will limit the number of LNG terminals built in this market. We believe that implementation of our
low cost, first-to-market strategy will give us a competitive advantage in securing TUAs with
attractive margins and creditworthy counterparties and in obtaining project financing for
construction of our LNG terminals.
Disciplined Project Development. The successful development and construction of LNG terminal
projects requires managing the complex interaction of legal requirements, regulatory processes,
technical knowledge, political environments, public policy and construction execution. Members of
our senior management team, who have developed more than 50 energy infrastructure projects with an
aggregate cost of over $15 billion, have formulated a disciplined project site feasibility and
pre-screening process to identify attractive terminal locations, and are adept at identifying
significant issues and challenges in completing our LNG terminals that require early resolution.
Once a site is selected, our senior management actively manages our project team of seasoned
professionals, who are supported by leading engineering, environmental, regulatory and legal firms.
Each project team strives to anticipate difficulties, define strategies and analyze the needs of
each constituent group and regulatory body so as to design the project to achieve as much
collaboration and widespread support as possible. By applying our disciplined project development
program, we believe that we will incur lower development and capital costs and more quickly
complete our projects. We believe that rapid and responsible development of low-cost LNG terminals
will greatly increase our likelihood of success.
Build Cost-Effective Terminals. Our disciplined project development strategy includes a
process for completing LNG terminals whose cost-effectiveness and location should allow us to
generate attractive margins from our TUAs. We have sited, and are designing and engineering our LNG
terminals to be cost-effective, reducing unproductive capital investments by: (i) locating our
projects in close proximity to major interstate gas transmission pipelines, thereby reducing
pipeline interconnection and construction costs, (ii) maximizing use of existing infrastructure
where possible, such as the existing platform for Clearwater and the existing onshore third-party
natural gas storage facilities in Southern California, and (iii) selecting sites that are
well-suited for LNG terminal operations such as Bradwood, whose deepwater location does not require
a costly breakwater or significant dredging.
Secure Long-Term Terminal Use Agreements. We intend to negotiate and sign firm capacity
20-year TUAs with highly rated creditworthy LNG suppliers, marketers, distribution utilities or
industrial consumers for all or substantially all of our terminal base capacity. We expect that the
terms of our standard TUA will include an initial fee at the time of execution of the TUA, a fixed
reservation charge for the monthly throughput capacity, and a variable charge for each million
British thermal unit (MMBtu) processed through the facility.
53
Our Projects
Set forth below are descriptions of each of our current projects, including our current design
plans, the permitting status and information on anticipated operations. All three of our projects
are in the development stage and none have received necessary permits for construction or
operation. We cannot assure you that the projects will be completed as currently planned or at all.
Bradwood
The Bradwood site is located on the south bank of the Columbia River in Oregon 30 miles from
the Pacific Ocean, with direct access to a deepwater channel capable of accommodating LNG carriers
with sizes up to 220,000 cubic meters. We designed the Bradwood site to have an initial sustainable
base capacity of 1.0 Bcf/d, a peak capacity of 1.3 Bcf/d and an on-site storage capacity of 7.0
Bcf/d provided by two 160,000 cubic meter storage tanks. The Bradwood site has also been designed
to accommodate an additional 160,000 cubic meter storage tank, additional vaporization capacity and
gas compression along the connecting pipeline to expand the base capacity to approximately 2.0
Bcf/d. We hold an option to purchase the site, comprised of approximately 420 acres with
approximately 55 acres zoned for Marine Industrial use.
We have agreed with Northwest Natural Gas Company (NW Natural) to coordinate the permitting of
a connecting pipeline under a consulting services agreement, which also provides NW Natural with a
non-exclusive option to construct and own the connecting pipeline (Bradwood Pipeline). NW Natural
is headquartered in Portland, Oregon and is primarily engaged in the local distribution of natural
gas to over 600,000 customers through separate systems in Oregon.
In addition to the Bradwood Pipeline application, we have recently submitted a request for
service to TransCanada and NW Natural for their open season under which they would construct, own
and operate a pipeline that would connect the Bradwood terminal to Williams’ Northwest pipeline at
Molalla and TransCanada’s GTN Pipeline near Madras. This will provide Bradwood and/or other
shippers with gas transportation service from the LNG terminal to the pipeline systems of both the
Northwest Pipeline Company and TransCanada’s GTN Pipeline, which can deliver approximately 2.0
Bcf/d into Northern California at the Malin, Oregon interconnect point.
We estimate the total capital required for constructing Bradwood LNG terminal to be
approximately $600 million, excluding interest during construction and financing fees, which we expect
to fund through a combination of project financing, proceeds from this offering and proceeds from
future debt or equity offerings. We estimate the remaining project development expenses to reach
the construction phase to be approximately $18 million, which we intend to fund with existing cash
and equivalents.
Pacific Northwest Market
The U.S. Pacific Northwest gas market is supplied by three main corridors: the Northwest
Pipeline Corporation owned pipeline system, which runs along the Pacific coast to southwestern
Oregon; the Northwest Natural Gas owned pipeline system, which runs through Western Oregon; and the
Gas Transmission Northwest Corp owned pipeline which runs from Alberta’s Western Canadian
Sedimentary Basin to Northern California. Together these pipelines access the Oregon, Washington,
Idaho, Nevada and California gas markets, which in the aggregate averaged 8.8 Bcf/d in 2004.
Natural gas demand in the Pacific Northwest gas market (i.e. Oregon, Northern California,
Idaho, Washington and Nevada) averaged 4.5 Bcf/d in 2005. Industrial consumers accounted for over
1.3 Bcf/d of gas demand, commercial/residential consumption averaged 1.5 Bcf/d of gas demand, and
natural gas fired power plants consumed an average of 1.7 Bcf/d of natural gas during this period.
According to Wood Mackenzie, natural gas demand in the Pacific Northwest is expected to
increase 1.9% annually compared to 1.5% nationally due to expanding coastal population and
difficulty of getting coal power plants permitted in California. Through 2015, peak demand is
expected to grow from approximately 5.5 Bcf/d in 2005 to approximately 6.4 Bcf/d in 2015.
According
to the InterContinental Exchange (ICE) the Pacific Northwest gas market is among the most liquid gas markets in the country, as
illustrated by the growth in trades at key market hubs such as Malin and PG&E Citygate, where next
day trades have nearly tripled between 2003 and
54
2005 to volumes that rival Henry Hub. Average actual trades per day for 2005 were 52 with an
average of 20 parties in PG&E Citygate and 48 per day with an average of 21 parties at Malin,
compared to 69 trades with an average of 30 parties for Henry Hub.
Bradwood Development
Permitting Status
Bradwood is the only LNG terminal project in the Pacific Northwest to have completed the
Federal Energy Regulatory Commission (FERC) prefiling process, and whose formal applications to the
FERC have been accepted into the application process under Sections 3 and 7 of the Natural Gas Act
for authorization to construct and operate an LNG receiving terminal and pipeline. Under its
current policy, the FERC will not regulate the terms and conditions of service or the rates charged
for LNG terminal services by the Bradwood LNG terminal. However, the terms and conditions of
services as well as the rates charged by the Bradwood Pipeline will be regulated by the FERC and
service thereon will be on an open access basis. We are anticipating commencing commercial
operations in the first quarter of 2011.
Under the federal Natural Gas Act, as amended in 2005, the FERC now has exclusive authority to
approve the onshore siting of LNG terminals, subject to certain state approvals required under the
federal Coastal Zone Management Act, the federal Clean Air Act, and the Federal Water Pollution
Control Act. In March 2005, Bradwood was accepted by the FERC into the FERC’s pre-filing process
for both its LNG terminal and pipeline. In accordance with the FERC’s pre-filing process, we
prepared detailed draft environmental and technical resource reports (Resource Reports), for review
by the FERC staff, state and federal agencies, as well as the general public. A formal application
was submitted in June 2006, successfully moving the project from pre-filing to final application
stage. The FERC is the lead agency for preparation of the Environmental Impact Statement (EIS), for
the project pursuant to the National Environmental Policy Act of 1969. Consistent with the FERC’s
published environmental report guidelines, we have conducted numerous detailed studies required to
complete the preparation of 13 Resource Reports for the LNG terminal and 12 Resource Reports for
the Bradwood Pipeline, each of which covers all of the topics specified by FERC guidelines. Since
acceptance into the FERC’s pre-filing process, we have successfully completed two rounds of public
meetings, submitted three draft filings with the FERC of all required Resource Reports and
responded to comments in an iterative process designed to ensure that a thorough and detailed
analysis of all aspects of the proposed project has been conducted. We have fully addressed or are
currently addressing all comments and questions that we have received from the FERC staff as part
of the FERC pre-filing and the FERC authorizations process. While not necessarily required by FERC
regulations, we have also sought to respond to information requests from other federal and state
agencies, counties and other local jurisdictions, first responders, local residents and other
interested parties. As noted, a formal application was successfully filed.
In addition to the preparation of the Resource Reports and the responses to information
requests noted above, the FERC process requires, and we have successfully completed, multiple
public meetings for both the LNG terminal and the Bradwood Pipeline. These meetings have been held
in Astoria, Knappa, Longview and Cathlamet, Washington, and included several pipeline routing tours
and several terminal site visits and open houses for the general public and all relevant state and
federal agencies. We have received comments from the public at each of these meetings and we have
incorporated responses to relevant comments in our current design and the resource report filings
with the FERC.
In April 2005, we submitted a notice of intent to the Oregon Department of Energy (ODOE),
which is the initial filing required to begin the ODOE’s energy facility siting process that is
implemented by the Oregon Energy Facility Siting Counsel (EFSC). However, after the enactment of
the federal Energy Policy Act of 2005 in the fall of 2005, which gave the FERC exclusive authority
to site LNG terminals, the EFSC suspended its siting process for the LNG terminal. Since that time,
the ODOE has acted to coordinate comments between the various Oregon state agencies and the FERC.
We have worked collaboratively with the ODOE during this period to respond directly to the
legitimate concerns of various Oregon state agencies and to encourage Oregon’s participation in,
and acceptance of, the FERC process.
We have filed applications for the principal permits and approvals required outside of the
FERC authorizations, including the U.S. Army Corps joint permit application for water quality, the
Oregon Air Emissions Permit, the Washington State Joint application permit for the pipeline, and
the Oregon Coastal Zone Consistency determination. We have also prepared a Waterway Suitability
Assessment (WSA) and submitted to the Coast Guard for its review, whose conclusions will be
provided to the FERC as part of the FERC authorizations process. In connection with the WSA, we
have conducted numerous information gathering meetings and work sessions with members of the Coast
Guard, local police forces, fire
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departments, emergency response personnel, the ODOE, port user groups and senior managers of
upstream ports. We have also done extensive modeling of the river transit and berthing/unberthing
maneuvers using a world class ship simulator and have had Columbia River pilots validate the adequacy of
the tugs and the marine turning basin under extreme weather and river flow conditions.
We are working closely with other state, federal and local agencies in the region in an effort
to meet or exceed all environmental and safety standards, and to address any relevant concerns. We
have coordinated and participated in numerous agency project meetings and permitting coordination
efforts that include representatives of the Environmental Protection Agency, the U.S. Fish and
Wildlife Service, the National Oceanic and Atmospheric Administration Fisheries Department, the
Oregon Department of Fish and Wildlife, the Oregon Attorney Generals Office, the Washington
Department of Fish and Wildlife, the Oregon Department of State Lands, the Oregon Department of
Land Conservation and Development, the Washington Department of Ecology, the Oregon Department of
Energy, the Oregon Department of Environmental Quality, the U.S. Army Corps of Engineers, the
Oregon Department of Geological Resources, the Governor’s Regional Economic Development Team, the
U.S. Coast Guard, the U.S. Department of Transportation, the Oregon Department of Transportation,
the Oregon State Historic Preservation Offices, the Oregon Department of Agriculture and various
other agencies with input into the permitting process. We are also coordinating closely with local
county planning departments to ensure that all legitimate public and municipal concerns are
addressed appropriately. Through cooperative efforts with these agencies, we believe that we have
implemented a proactive approach that has fostered a positive working relationship and has allowed
Bradwood to progress through the regulatory process on schedule and on budget.
As part of the Bradwood permitting and development process, we have completed various studies,
designs and engineering plans necessary for the development of the project. The results of such
studies, plans and designs have been reported to the various agencies involved in the process of
permitting, and have been reviewed in working sessions with various agencies.
As part of the Bradwood permitting and development process, we are currently completing a
number of further studies, designs and engineering plans, including:
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emergency response plan |
We filed Bradwood’s formal applications for the FERC authorization in June of 2006 and will
have filed the remaining significant state and federal permits not included in the FERC process by
the end of the fourth quarter of 2006. We are planning to obtain all permits by the third quarter
of 2007.
Pipeline Status and Access to Natural Gas Storage
We engaged NW Natural under a consulting services agreement to assist Bradwood with, and to
manage other third party consultants in, the preparation of the materials required to file the
federal, state and local permits to construct and operate the Bradwood Pipeline. In June 2006, we
filed an application for the Bradwood Pipeline (pursuant to Section 7c of the Natural Gas Act of
1938). Simultaneously, we are nearing completion of our negotiations with Bradwood’s pipeline
partner, NW Natural, for NW Natural to construct and own the Bradwood Pipeline. If these
negotiations result in a definitive agreement, we anticipate transferring to NW Natural any FERC
authorizations that we may have received that are necessary for NW Natural to construct and operate
the pipeline.
NW Natural currently provides interstate natural gas storage services to third parties at its
Mist storage facility. Shippers on the Bradwood Pipeline would have access to storage at NW
Natural’s Mist storage facility, subject to agreement with NW Natural on storage service. The Mist
storage facility currently has a maximum daily deliverability of 440,000 MMBtu/d and a total
seasonal working gas capacity of 13.9 Bcf. Additionally, through NW Natural’s pipeline facilities,
Bradwood’s customers could access available storage from the Jackson Prairie storage facility,
located in Washington. The Jackson Prairie facility has a total maximum deliverability of
approximately 884,000 MMBtu/d and a total working gas capacity of approximately 21.6 Bcf that is
divided among the three facility owners. Through NW Natural transportation arrangements, gas from
Bradwood will have access to TransCanada’s GTN Pipeline, which runs from Kingsgate at the Canadian
border to
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Malin in Northern California, as well as markets in Nevada and Idaho. LNG suppliers owning LNG
terminal capacity in Bradwood will have access to 9.0 Bcf/d of natural gas demand.
In addition to the Bradwood Pipeline application, we have recently submitted a request for
service to TransCanada and NW Natural for their open season under which they would construct, own
and operate a pipeline that would connect the terminal to Williams Northwest at Molalla and
TransCanada’s GTN Pipeline near Madras. This will provide Bradwood and/or other shippers with gas
transportation service from the LNG terminal to the pipeline systems of both the Northwest Pipeline
Company and TransCanada’s GTN Pipeline, which can deliver approximately 2.0 Bcf/d into Northern
California at the Malin, Oregon interconnect point.
Property Status
We hold an option to purchase the Bradwood property. The option term expires on
August 15,
2008. In August 2006, we paid $200,000 to extend the option through
August 15, 2007, and
subsequently will be required to pay $400,000 to extend the option an additional year through
August 15, 2008. The final $400,000 payment may be reduced to $200,000 provided that Bradwood
agrees that an affiliate of the owners can perform all preparation work at the Bradwood site at a
fair market price to be negotiated. During the option period, Bradwood has the right to use all
existing licenses, permits and written reports of inspections related to the property. The exercise
price for the option is $9 million prior to
August 15, 2007 and $10 million thereafter.
Community Relations
We are engaged in developing local support in the project area. We have employed a community
liaison director since mid-2005, and have solicited the support of certain local and regional union
leaders and local business leaders. Our community liaison director resides in Astoria and oversees
our Astoria office. In addition, we have sponsored local charitable events to develop support from
individuals, businesses, political leaders, local development groups and the Port of Astoria. We
have reached out to many local groups through education, distribution of information and
involvement in community events.
Bradwood Design
We designed Bradwood to have a sustainable base capacity of 1.0 Bcf/d, a peak capacity of 1.3
Bcf/d and, initially, on site storage capacity of 7.0 Bcf in the form of two 160,000 cubic meter
storage tanks. The design includes a dedicated LNG carrier berthing facility capable of handling
LNG carriers as large as 220,000 cubic meters with an LNG cargo unloading rate of 12,000 cubic
meters per hour (m3/hr). The LNG will be transferred from the LNG carrier to the LNG
storage tank using pumps on the LNG carrier and conventional LNG unloading arms located on the
dock. The LNG will be held in the LNG storage tanks until needed. The design includes a vapor
management system to handle the boil-off gas that forms as the LNG is unloaded and as it warms in
the storage tanks. During normal operations, no vapors will be discharged to the atmosphere;
instead, the LNG terminal is designed to contain and reprocess gas vapors for sale. The vapors will
be pressurized by boil-off gas compressors and condensed in boil-off gas condensers. The LNG will
then be removed from the storage tanks with pumps located inside the storage tanks that increase
the pressure of the LNG to approximately 1,320 pounds per square inch gauge, or psig. The send out
pumps are designed to transfer the LNG to submerged combustion vaporizers, which will warm the LNG
to a gaseous state. Submerged combustion vaporizers are large water baths with stainless steel
tubes submerged within the warm water. These vaporizers allow LNG to flow through the inside of the
tubes where it is warmed by the heat transferred by the water bath. Approximately 1.5% of
Bradwood’s LNG send out capacity is expected to be combusted by the vaporizers to maintain the
temperature of the water bath at about 60 degrees Fahrenheit to vaporize the LNG. Natural gas will
exit the vaporizers at a maximum pressure of 1,280 psig, with a minimum gas send out temperature
from the LNG terminal of 35 degrees Fahrenheit.
Following vaporization, the high-pressure gas will then pass through a metering station at the
input valve of the connecting pipeline. Standard gas instrumentation will be installed to measure
pressure, temperature, gas composition, gas flow volume and the energy (Btu) content.
The natural gas from the terminal then flows into the connecting Bradwood Pipeline which will
be 36 inches in diameter for approximately 19 miles through Oregon and reduced to 30 inches as it
passes under the Columbia River and travels an additional approximately 17 miles through
Washington. The natural gas will then be metered once more before it will pass
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into the Williams NW Pipeline near Kelso, Washington, which is one of the main interstate
pipelines serving the Pacific Northwest and British Columbia.
Bradwood Expansion
The Bradwood project has been designed to take advantage of future opportunities for expansion
of the LNG terminal, as well as supporting the expansion of the gas transportation infrastructure
in the Pacific Northwest. Bradwood has not sought any authorization to expand the currently planned
LNG terminal from its present design base of 1.0 Bcf/d. However, subject to receipt of all required
additional permits, the LNG terminal is designed to be readily expandable to a sustainable base
capacity of 2.0 Bcf/d with the addition of a third storage tank and additional vaporizers and pumps
at an estimated capital cost of approximately $230 million, excluding interest during construction
and financing fees, potentially making any potential expansion of Bradwood the lowest incremental
LNG capacity in the Pacific Northwest. The Bradwood site layout and connecting pipeline are
currently designed to accommodate such an expansion.
Clearwater
Clearwater is sited 13 miles offshore of Oxnard, California and is currently anticipated to be
constructed on Platform Grace, an existing oil and gas production platform currently owned by
Venoco, Inc. We designed Clearwater to have a sustainable base capacity of 1.2 Bcf/d and a peak
capacity of 1.4 Bcf/d. The project design includes two floating docks (mooring facilities), located
approximately 400 feet from the platform, and a 36 inch diameter 13 mile sub-sea pipeline to
transport natural gas from the platform to shore. The sub-sea pipeline will cross the beach via an
underground horizontal directional drill and terminates at an existing operational electrical
generation plant at Mandalay Beach in Oxnard, from which the gas would be transported through a 36
inch diameter onshore pipeline 14 miles to the SoCalGas trunk line system at Center Road, which
will be established as a new receipt point into the SoCalGas system. The Clearwater project will
not have LNG storage facilities other than those associated with our LNG carriers because there is
abundant existing gas storage (122 Bcf) in the SoCalGas system and the incremental cost of
developing offshore LNG storage is not justifiable. We expect all onshore pipeline segments to be
constructed, owned and operated by SoCalGas as an integrated component of their gas transmission
system. SoCalGas has extensive experience in building gas pipelines in Southern California and
their franchise allows them to utilize any public road as a right-of-way. By maximizing the use of
existing infrastructure (existing platform and gas storage facilities), the project is designed to
minimize the impact of the LNG terminal on coastal resources and is expected to have a lower
capital cost than competing terminals. Depending on the ultimate configuration of the facility,
certain federal and/or state authorizations to construct and operate the natural gas pipelines
associated with the facility may need to be obtained.
We estimate the total capital required for constructing Clearwater to be approximately $800
million, excluding interest during construction and financing fees, which we expect to fund through
a combination of project financing and proceeds from future debt or equity offerings. The advantage
of using the Platform Grace existing infrastructure is that we believe our LNG terminal can be
constructed in 18 to 24 months from the commencement of construction, compared with typical
construction completion time for another offshore facility of four to five years. We estimate the
total remaining project development expenses to reach the construction phase to be approximately
$20 million, which we intend to fund with a portion of the proceeds of this offering.
Southern California Gas Market
Primary supply sources to the Southern California gas market, which include both the SoCalGas
and SDG&E utilities gas systems, are the Rocky Mountain region, Canada and California on- and
off-shore production. The interstate pipelines that supply this market are the El Paso Natural Gas
Company pipeline (El Paso), Transwestern Pipeline Company pipeline, Kern River Gas Transmission
Company pipeline, Mojave Pipeline Company pipeline, Questar Southern Trails Pipeline Company
pipeline and Gas Transmission Northwest pipeline via the PG&E intrastate pipeline system. The
SoCalGas transmission system interconnects with El Paso at the Colorado River near Needles and
Blythe, California, and with Transwestern and Southern Trails near Needles. According to SoCalGas,
its gas system, is capable of delivering approximately 6.0 Bcf/d of gas into the market through a
combination of storage withdrawal and pipeline deliveries. The maximum existing point capacity from
existing pipeline interconnects is 3.9 Bcf/d. The historical peak demand has been 5.3 Bcf/d.
According to Wood Mackenzie, natural gas demand in the Southern California gas market region
averaged 3.7 Bcf/d in 2005. Industrial consumers account for 46% of gas demand,
commercial/residential consumption averaged 32% of gas
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demand, and natural gas use for power generation averaged 21% of gas demand. Gas demand is
expected to grow at 1% annually.
The Southern California gas market is among the most liquid gas markets in the country.
According to the Intercontinental Exchange, or ICE, short-term physical liquidity of the SoCalGas
trading hub has tripled in the past two years. Next day trade volumes for 2005 was 416,000 MMBtu
compared to 516,000 MMBtu for Henry Hub, while actual trades per day were 52 with 22 parties in
Southern California compared to 69 trades with an average of 30 parties for Henry Hub.
Clearwater Development
Permitting Status
The Clearwater application package was originally filed under the name of Clearwater’s
predecessor company, Crystal Energy, LLC in February 2004. This application package included both a
Deepwater Port (DWP) license application to the Coast Guard and a State Tidelands Lease Application
to the California State Lands Commission (CSLC). Following an initial 30-day application
completeness review completed by the Coast Guard and the CSLC, a request for additional project
information was received. A response to comments package and amended application package was
resubmitted to the Coast Guard and CSLC in July 2004. In addition to the initial project
application materials, a Development and Production Plan (DPP), an amendment was submitted to the
Minerals Management Service (MMS) to address questions raised regarding the termination of oil and
gas production activities on Platform Grace. Additional comments were received on this application
package and a response package was prepared and submitted in January 2005. This response package
ultimately led to a
May 31, 2005 comment letter from the Coast Guard (representing joint federal
and California state agency positions) that provided further guidance and required four key data
requirements which had to be provided before the responsible agencies could consider the
application to have sufficient data to commence preparation of the draft environmental report.
Completing the work required to address the specific data requirements and responding to the
compendium of other agency comments has been the focus of project development activities over the
past year. During that time, the project team renegotiated the Grace Platform agreement to clarify
a number of site control issues, significantly expanded the detail in the platform stability
analyses, obtained detailed offshore geophysical and geotechnical surveys and completed the studies
of the expansion of the SoCalGas pipeline infrastructure to ensure the continuous delivery of up to
1.5 Bcf/d into the main SoCalGas trunk line system.
In response to the Coast Guard letter of May 2005, Clearwater submitted an amended and
restated Deepwater Port License, California State Lands Lease applications and DPP. The
applications were submitted in June and July of 2006. Comments have been received and additional
information has been provided. A solicitation package to engage a contractor to prepare the joint
Draft Environmental Impact Study (DEIS) and Draft Environmental Impact Report (DEIR) for US Coast
Guard and the CSLC should be released in first quarter 2007.
The environmental review process for the proposed Deepwater Port project includes the
preparation of a DEIS in accordance with the guidelines established under the National
Environmental Protection Act (NEPA). Preparation of the DEIS is necessary to issue approvals for
the Deepwater Port License. Under a memorandum of agreement between the Coast Guard, MMS, and
Maritime Administration (MARAD), the EIS lead agency will be the Coast Guard. At the state level,
environmental review is addressed under the regulations established under the California
Environmental Quality Act (CEQA). A joint Environmental Impact Report/Environmental Impact
Statement has been determined to meet the required documentation for approvals at both the state
and federal requirements. The CSLC was designated as the state’s lead agency for preparation of the
CEQA documentation. In addition, a separate Memorandum of Agreement between the Coast Guard and
CSLC is in place to facilitate the cooperation of the federal and state permitting agencies, to
contract and direct the preparation of the DEIS/EIR by a third party contractor.
As part of the permitting and development process for Clearwater, various studies have been
completed. Results of these studies have been reported to the various agencies involved in the
process of permitting, and have been included in working sessions with the agencies to discuss
permitting progress and scheduling.
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Platform Commercial Status
On
March 1, 2006, Clearwater entered into a new agreement with Venoco Inc. to secure access to
and use of Platform Grace, the existing platform. Under the terms of this agreement, the third
party granted Clearwater an option to either (a) lease Platform Grace and certain related assets
for a period consistent with Clearwater’s regulatory approvals, or (b) purchase Platform Grace and
certain related assets for a purchase price equal to the sum of (i) $1.00, (ii) an annual payment
payable each year during the construction period (until the commencement of commercial operations)
in the amount of $6 million for the first two years, $8 million for the third year and $10 million
thereafter, (iii) the assumption of platform abandonment obligations, which have been estimated by
the MMS to be less than $38 million, and (iv) following the commencement of commercial operations,
the conditional obligation to pay an annual throughput fee to the third party of $0.04 per MMBtu
based on gas throughput for the balance of the LNG terminal project’s commercial operations, but
with a minimum payment of $11,800,000 per year based upon a
contract volume of at least 800,000
MMBtu for all scheduled operating days. The actual throughput fee could be higher if throughput
volumes exceed 800,000 MMBtu. The option may be exercised by us during the period commencing on
January 1, 2008 and ending on
March 1, 2012. To exercise the option, Clearwater must (
x) certify to
the owner that it has determined that it will proceed to develop and operate the LNG terminal, (y)
provide certain letter of credit security for its payment and performance obligations, and (iii)
obtain certain amendments to the existing MMS regulatory approvals for Platform Grace and the lease
area in order to address Clearwater’s permitted use and eventual abandonment and removal of
Platform Grace. Once the option is exercised, the owner has 120 days to cease oil and gas
production from the platform and to remove all production related equipment. The option expires on
March 1, 2012, and has an annual cost of $1,000.
Community Relations
As part of the development process, Clearwater provided information at the community level
about the project and LNG in general. We have opened a local office in Oxnard and retained two
members of the local community to act as our community liaisons directors. The community liaison
efforts will continue and increase as the project progresses through the regulatory approval
process.
Clearwater Design
The principal components of our Clearwater Port LNG terminal will be an LNG
carrier-to-platform cryogenic transfer system, the existing Platform Grace, LNG hubs, ambient air
vaporizers, selective catalytic reduction and a sub-sea steel pipeline. The design allows for the
safe and efficient vaporization of LNG with significantly lower emissions. The cryogenic LNG
transfer system will unload LNG carriers at the berths and transport the LNG to the regasification
platform via a sub-sea LNG pipeline utilizing shipboard pumps that will offload LNG carriers at a
rate of up to 2,700 m3 per hour or 1.4 Bcf/d and consist of the following key
components:
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Ambient Air Vaporizers — The vaporization process will utilize ambient air
vaporizers (AAV) to provide most of the heat, approximately 80%, required to
re-gasify the LNG. AAV’s extract heat from the air, versus burning fuel to create
heat, which is the process utilized in other West Coast terminals. The result is
lower operating costs, and greatly reduced emissions. An offshore platform is an
ideal facility to utilize this technology. |
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SSP Loading Buoy — each berth will include an SSP buoy with a marine service
LNG loading arm to connect to the LNG carrier’s manifold. The unloading buoy will
not be part of the mooring system; it will be secured alongside the LNG carrier.
Emergency release couplings will be incorporated at the connection point to the
LNG carrier manifold to facilitate a safe and rapid disconnection if required. |
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SSP Floating Dock — the terminal will include two floating docks or berths to
receive and unload LNG carriers. Each berth will utilize eight SSP buoys to moor
the LNG carrier. Buoy-based mooring systems are common in the oil and gas
industry and a similar system is being proposed for the Main Pass LNG terminal in
the Gulf of Mexico utilizing a competitive technology. Our SSP mooring buoy
design has received a formal “Approval in Principle” for this application from
the American Bureau of Shipping. |
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LNG Flexible Pipeline — a cryogenic flexible pipeline will transport LNG from
the unloading buoy to a sub-sea pipeline and manifold on the sea floor. Small
diameter flexible cryogenic lines have been in use |
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in the U.S. for many years at land-based terminals, and the development of larger
diameter LNG lines has been ongoing for many years. We are separately working with
OPE, Technip and U.S. Hose Corporation to develop two alternative designs for the
flexible LNG riser pipeline. OPE, Technip and U.S. Hose Corporation expect to have
completed testing and to have received certification for service within the project
schedule. |
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Vacuum Jacketed LNG Pipeline — a rigid pipe-in-pipe (PIP) vacuum jacketed
cryogenic pipeline will transfer LNG from the manifold to the platform. Onshore
LNG PIP systems are currently being installed at a Gulf Coast terminal under
construction. Sub-sea PIP systems have been used in West Africa since 1995 to
transport refrigerated liquefied petroleum gas (LPG) to offshore tanker loading
systems. |
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Platform Recertification — The platform design and construction of the new
platform will be recertified to current standards for the new use as an LNG
terminal. The American Bureau of Shipping will perform the certification function
under both MMS and Coast Guard regulations for structure certification as the
Certified Verification Agent and Certifying Entity, respectively. Seismic, storm
and fatigue analyses have been completed to assess performance of the structure
to in its new service based on current design standards and criteria to identify
any structural modifications that may be necessary to bring the platform into
compliance. The analyses demonstrated that Platform Grace will require minimal
reinforcement to support the proposed development. To confirm the results of the
analyses, an extensive sub-surface inspection of Platform Grace was completed in
November 2006. The inspection included an extensive survey for corrosion
including wall thickness measurements to check for material loss. No significant
corrosion or material loss was observed and the results of this inspection
confirm the conclusions of the analyses and suitability of the platform for
service as an LNG receiving terminal. |
Orion
The Orion site is strategically located about 25 miles offshore of Carlsbad,
California with direct access to the Los Angeles and San Diego markets. The project natural gas
interconnection provides access to Los Angles and San Diego gas demand centers near an advantageous
pipeline interconnection point to the SoCalGas and SDG&E
distribution systems. Orion is expected to be designed to include a concrete hull floating storage and
regasification unit with a design capacity of 1.2
Bcf/d. The project design will utilize technical and
environmental resources experienced with Clearwater to the greatest extent possible. By building
upon offshore design experience we will enhance the value of our team’s institutional knowledge.
Orion Development
Mr. Garrett and Mr. Soanes began developing an offshore LNG terminal project in early 2002 in
Southern California. In October 2002, the development entity managed by Mr. Garrett and Mr. Soanes
sold the rights to the project and was retained by the purchaser of those rights as project
development adviser. The entity received consulting income during the period that it was project
development adviser. The purchaser actively pursued the development of the project, including
significant expenditures for seismic studies, permit applications, engineering, pipeline routing
and environmental studies. In September 2005, the purchaser discontinued its development of the
project and in accordance with the initial sales agreement, all intellectual property and
intangible rights related to the project development reverted to the initial development entity.
Mr. Garrett and Mr. Soanes, through this entity, began a new project offshore of Southern
California using some of the intellectual property and intangible rights from the prior project. On
March 7, 2006, the intellectual property and intangible rights related to the new project were sold
to Orion, which we then acquired. The Orion development team has been able to capitalize on a
significant portion of the engineering, research, design, permitting and regulatory work
information related to the other project and completed by the development entity when designing and
siting the Orion project.
Preliminary project feasibility analysis has been completed and the required engineering,
regulatory, legal, and public relations efforts are underway to support the filing of a Deepwater
Port application with the Coast Guard and the corresponding state Tidelands Lease Application for
CSLC as well as other ancillary associated permit applications. We
intend to continue to pursue the
development of Orion in conjunction with the approval process of our Clearwater project. A number
of critical siting studies and fatal flaw analyses have been completed or are currently underway,
including the following:
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A Metocean study of the proposed location, completed in November 2006. |
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A study of concrete hull non-self propelled vessels to be constructed and placed into LNG
service at th specific site discussed in the Metocean study. Such a study assumes a vessel
of 400 to 500 feet in length with modularized bottle storage in the area of 60,000
m3. |
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A study of gas market opportunities and pipeline capacities. |
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A review of current research and development, acceptance, testing, manufacturing and
delivery status of LNG specific cryogenic transfer systems/hoses for marine use (aerial,
floating, and submerged). |
Additionally we are performing a concept level mooring system design, to include a gross
mooring system analysis. A number of studies and proposals are currently in progress or planned to
be initiated in the second quarter of 2007.
Project Management
Our senior management team, which has participated in the development of more than 50 energy
infrastructure projects worldwide with aggregate cost of over $15 billion, has been directly
involved in either the development, construction or operation of nine LNG terminal projects,
including involvement with our three development projects since 2002. Our senior management team
provides overall management and guidance of our existing LNG terminal projects from our central
headquarters in Houston, and retains the principal responsibility for project development, securing
TUAs, obtaining construction financing, construction, day-to-day operations, growth of the business
and profitability. Our local management teams capitalize on their considerable local and regional
market knowledge, goodwill, name recognition and customer relationships to execute day to day
project development activities in order to maximize project value. We have assembled a team of
highly experienced and dedicated project development professionals, which includes professionals
experienced in LNG development, engineering and operations, pipeline development, LNG and gas
marketing, project analysis, public relations, and financial management. Each of our projects is
managed by an experienced lead project developer who is dedicated to the development of the
project, and is supported by a dedicated engineering resource from our in-house technical support
group. The project development leads and teams meet with our senior management team routinely to
review progress and ensure compliance with milestone expectations and budgets. These meetings also
serve to align our corporate commercial and public relations activities with the actual progress
being made in project development. We also use these project updates meetings to ensure that the
projects are properly resourced as well as managed efficiently and to maximize the beneficial
transfer of institutional knowledge within our development team.
Project Development
We utilize a disciplined, thorough feasibility and pre-screening study process to identify
significant issues and challenges that we may face in completing development of our LNG terminals.
For example, we spent over two years carefully screening potential sites along the West Coast and
Canada before selecting our Bradwood site. In addition, we have conducted a detailed feasibility
analysis of each project that considered, among other things, the market size, demand profiles,
pipeline takeaway capacity, political environment (local, state and federal), site zoning and
remoteness, geotechnical issues, waterway suitability, pipeline rights of way, wetland issues, site
alternatives, dredging requirements and storage requirements. We have developed detailed permitting
plans, budgets, schedules and cash commitment curves for each of our projects. We prioritize our
development expenditures to address the highest risk issues as early in the development process as
possible to address single-point failures, and appropriately balance project execution risk and
development cost exposure. We believe that the key to successful project development is to start
with well considered project fundamentals and then actively manage our project teams of seasoned,
successful project professionals, supported by a team of the leading engineering, environmental,
regulatory and legal firms, to work co-operatively with regulators and other stakeholders to
successfully develop the project and to anticipate difficulties and define strategies that offer
multiple success paths. We analyze the needs of each constituent group and regulatory entity to
design each project to achieve the maximum collaboration support we believe possible. We believe
that our processes will allow us to address and resolve challenges to the FERC and Coast Guard and
other permitting agencies’ approval processes early by resolving undesirable project attributes
before submitting our final applications.
Securing Long-Term Terminal Utilization Agreements
We expect to operate our LNG terminals as a terminal service provider and enter into
long-term, firm capacity TUAs with highly rated creditworthy third parties, including LNG
suppliers, natural gas marketers, distribution utilities or large-volume industrial consumers, to
provide a stable and predictable cash flow to
our company. We do not intend to take title or
62
ownership to the natural gas processed through our terminals on a firm capacity basis in order
to reduce our exposure to commodity prices. The physical supply of LNG delivered to our terminals
would be obtained by our customers from their own liquefaction facilities or those under
contract
located primarily in the Asia Pacific or Middle East regions. Customers will also arrange for
delivery of LNG to our terminals. Upon delivery, we plan to process and vaporize the LNG,
converting it into natural gas vapor for our customers, before the natural gas is transported
through pipelines to the national gas distribution network for delivery to the ultimate consumer.
We intend to leverage our senior management’s existing relationships with natural gas market
participants and suppliers in the Asia Pacific and Middle East regions and their in-depth knowledge
of the natural gas market to secure TUAs with highly rated creditworthy natural gas suppliers,
marketers, distribution utilities or industrial consumers for a significant portion of our LNG
terminal base capacity. We expect that these
contracts for firm capacity will be for a term of 20
years and consist of a fixed payment based on the contracted firm capacity and a variable charge
for each MMBtu processed through the LNG terminal. In certain instances, we may negotiate for a
portion of the fixed payment to be paid by the capacity holder in advance of the commencement of
commercial operations. We intend to use any such advances to further fund our development,
construction, and corporate activities, and expect to pledge the future proceeds of the TUAs to
obtain favorable financing to construct our LNG terminals. Depending on market circumstances, we
may decide to retain a small portion of our terminals’ firm capacity or interruptible capacity to
complete spot gas supply transactions to further enhance project cashflow.
Obtaining Construction Financing
Our management is currently engaged in the formal permitting process for all of our three
initial LNG terminal projects. They will be pursuing the steps necessary to construct our three
initial LNG terminal projects, which are expected to include:
| |
• |
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executing one or more TUAs with highly rated creditworthy counterparties for
each LNG terminal project; |
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• |
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arranging a syndicate of banks to provide the construction financing and
permanent project financing; and |
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• |
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arranging for the equity, if any, needed to support construction, to the
extent not already provided by any TUA upfront fees. |
Our management expects to use its breadth of experience and contacts in the LNG and natural
gas markets to optimize this process.
Competition
Overview
We currently compete primarily with companies developing other new LNG terminals on the West
Coast. The FERC list of constructed, permitted or proposed LNG terminal projects in the United
States, Mexico and the Bahamas as of
October 19, 2006 listed 45 offshore and land-based LNG
terminal projects, of which nine proposed LNG terminals are planned to be constructed on the U.S.
West Coast. We believe that only a small number of these LNG terminals will be constructed.
Competition for LNG terminal capacity takes place before an LNG terminal is built. During this
time, the primary competitive factors are price of terminal service, location of facility, pipeline
access to markets (including market size and value) and access to a long-term source of competitive
LNG supply. Generally speaking, once the permitting process has proceeded far enough so that
permission to construct the LNG terminal is probable, the developer of an LNG terminal will enter
into final stage negotiations with LNG suppliers, natural gas marketers, distribution utilities or
large-volume industrial consumers regarding entering into a TUA. One or more TUAs often are
critical to obtaining construction financing for a project. Once all or substantially all of a LNG
terminal’s base capacity has been contracted for with a third party, the LNG terminal operator is
largely indifferent as to competitive market forces during the term of the TUA.
We anticipate the following competitive forces in the LNG market:
63
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• |
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Regional Terminal-to-Terminal. As of October 19, 2006, the United States Gulf
Coast had the largest concentration of potential, proposed or approved LNG
terminals, and terminals in operation or under construction in North America.
Because of existing gas infrastructure and a more favorable permitting
environment than in other United States regions, many developers have announced
plans for LNG terminals in the Gulf of Mexico. These terminals will compete for
LNG supply in the Atlantic Basin and the Middle East, and will compete with each
other for pipeline access to gas markets. We anticipate this to be a highly
competitive market, with limited barriers to entry where first mover advantage,
cost competitiveness and access to markets are key. |
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• |
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Regional Terminal-to-Pipeline Gas. In most locations, commencing operations of
an LNG terminal will cause a rebalancing of supply and demand among certain
markets within North America. In the case of the West Coast, the Canadian gas and
gas from the Rockies may be displaced to alternative markets, such as in the
central United States or the East Coast of the United States. LNG delivered to
the West Coast will have to be priced competitively with alternative pipeline
supplies to allow local supply and demand balances to readjust. We will use
dynamic modeling of regional markets to evaluate the impact on each of our
projects. |
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• |
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National LNG-to-LNG. If more LNG is delivered into the Gulf than the market
requires, or which can be economically transported out of the Gulf, it will
suppress pricing in the Gulf region and possibly prices across the entire market
to the level of landed LNG import parity. We believe it is unlikely that more
expensive reserves in the continental United States would be developed and we
expect indigenous production would decline at higher rates to adjust for the LNG
volumes. Based on current forecasts for production cost profiles, we believe this
new market equilibrium will be found at price levels that will allow us to
attract LNG suppliers, especially to locations on the West Coast, where we
believe few LNG terminals will be built and where there is considerable supply
side pressure. |
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• |
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Global LNG-to-LNG. Increasingly, the effect of global arbitrage is felt in the
world’s gas markets. In recent years, a spot market for LNG has begun to be
developed. As new liquefaction capacity is added in the Middle East, Asia Pacific
and Atlantic supply regions, we believe a portion of that capacity is likely to
be un-contracted, which will act as a buffer and move to the highest priced
market. |
There are several sources of natural gas from which we may face competition which may replace
the expected natural decline of natural gas production in the United States, including:
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• |
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an increase in supply in the existing producing basins in the United States, Canada and Mexico; |
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• |
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development and commercialization of frontier basins in North America; |
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• |
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completion of potential pipelines from the McKenzie Delta or the North Slope of Alaska; and |
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• |
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development and commercialization of new natural gas supply sources in areas
currently restricted from exploration and development due to public policies,
such as areas in the Rocky Mountains and coasts of the United States. |
Competition in the Pacific Northwest
To our knowledge,
the following proposals to either study or develop LNG terminals in the
Pacific Northwest have been reported in the press, as set forth in the table below. Of those,
only Bradwood has completed the FERC prefiling process under sections 3 and 7 of the Natural Gas
Act for authorization to construct and operate a terminal and pipeline. Of our other competitors,
Port Westward LNG submitted a prefiling application in April of 2005 which was not accepted by the
FERC and has not been refilled with the FERC. Jordan Cove submitted a prefiling application to the
FERC in April 2006 and is actively pursuing its project.
The following table identifies each of the LNG terminals known to us proposed to be
constructed in the Pacific Northwest and sets forth, to the extent known by us, their location,
distance to the nearest natural gas pipeline, estimated population density within a two-mile radius
of the project site, financial sponsors and development status.
64
Oregon Projects
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Estimated |
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FERC Filing |
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Base |
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Distance |
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Onshore/ |
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Population |
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Status |
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Capacity |
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to Pipeline |
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Offshore |
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Density(1) |
|
Sponsor |
|
Bradwood |
|
Final Application Submitted |
|
1.0 Bcf/d |
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34 miles |
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Onshore |
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52 |
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NorthernStar |
Jordan Cove (Coos Bay) |
|
Submitted pre-filing application to FERC 4/11/06 |
|
1.0 Bcf/d |
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250 miles |
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Onshore |
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2,743 |
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Fort Chicago |
Port Westward |
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Pre-filing not accepted 04/05 |
|
0.7 Bcf/d |
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25 miles |
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Onshore |
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213 |
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Port Westward LNG |
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Warrenton LNG |
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No Filing |
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Unknown |
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62 miles |
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Onshore |
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* |
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Warrenton Fiber Company |
Skipanon |
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No Filing |
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1.0 Bcf/d |
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60 miles |
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Onshore |
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2,249 |
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Calpine |
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| * |
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Information not available. |
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| (1) |
|
Estimated population density within a two-mile radius of the project site based on the Census
Block Cetroid Populations 2000 taken from the ESRI Data and Maps 2005. |
Competition in California
While there have been a number of proposed projects in California and Baja, only four projects
in California have filed permit applications and there is just one active project under
construction in Baja (ChevronTexaco announced that it has placed its Coronado Island project on
indefinite hold because of high capital costs). A large portion of the gas from Sempra’s Costa Azul
Phase I project in Baja is expected to be consumed in Mexico. Costa Azul completed a Phase II “open
season” to determine the interest of potential capacity holders in taking positions in an expanded
LNG Terminal. Based upon information included in the LNG Terminal “open season” filing and the
preliminary estimated recourse rate for the North Baja LNG pipeline expansion “open season,” we
estimate a tariff (including pipeline transportation) in excess of $0.90/MMBtu will be required to
deliver natural gas to the Southwestern U.S. market (1.0 Bcf/d capacity). In testimony before the
California Public Utility Commission (CPUC), SoCalGas has estimated the cost of incremental system
upgrades required to receive 1.0 Bcf/d at Otay Mesa (Mexican-United States border) to be $677
million.
We believe the cost to expand the SDG&E gas pipeline system to receive large volumes at Otay
Mesa will cause the bulk of deliveries from any Baja LNG terminal expansion to be diverted to the
California/Arizona border (Blythe receipt point). The capacity into the SoCalGas transmission
system through the Blythe receipt point is limited, and gas will flow eastward, away from the
southern California market. We believe there are no plans to increase capacity into SoCalGas
through Blythe as the recent CPUC Firm Access Rights proceeding states Baja gas will displace
existing supplies. The net result is that no new incremental volumes will be delivered into the
SoCalGas system from this receipt point.
Clearwater,
however, would deliver incremental gas into the SoCalGas system through a new
receipt point to be constructed at Center Road. In testimony before the CPUC, SoCalGas has
estimated the cost of required incremental system upgrades to receive 1.5 Bcf/d at Center Road at
$259 million.
The following table gives information regarding Esperanza, Pacific Gateway and the LNG
terminals identified by FERC which are proposed to be constructed in California and Baja California
and sets forth, to the extent known by us, their location, estimated population density within a
two-mile radius of the project site, financial sponsors and development status (distance to the
nearest natural gas pipeline has not been included in this table since it is not a differentiating
factor).
Southern California and Baja California Projects
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Base |
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Estimated |
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Population |
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Filing Status |
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Capacity |
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Onshore/ Offshore |
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Start-up |
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Density(1) |
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Sponsor |
Clearwater (SoCal) |
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Filed Permits |
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1.2 Bcf/d |
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Offshore Platform |
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2010 |
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Low |
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NorthernStar |
Orion (SoCal) |
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Proposed |
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1.2 Bcf/d |
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Offshore Platform |
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Undetermined |
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Low |
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NorthernStar |
65
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Base |
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Estimated |
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Population |
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Filing Status |
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Capacity |
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Onshore/ Offshore |
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Start-up |
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Density(1) |
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Sponsor |
Port of Long Beach (SoCal) |
|
Received Draft EIS |
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1.5 Bcf/d |
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Onshore |
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2011 |
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High |
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ConocoPhillips and Mitsubishi |
Costa Azul (Mexico) |
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Under Construction |
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1.0 Bcf/d |
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Onshore |
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2008 |
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Low |
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Sempra |
Cabrillo Port (SoCal) |
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Received Draft EIS |
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0.8 Bcf/d |
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Offshore Floating Storage Regasification Unit |
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2011 |
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Low |
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BHP |
Esperanza (SoCal) |
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Proposed |
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Unknown |
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Offshore |
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2011 |
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Low |
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Esperanza |
Ocean Way (SoCal) |
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Filed Permits |
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1.4 Bcf/d |
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Offshore Buoy |
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2011 |
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Low |
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Woodside |
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| (1) |
|
U.S. Coast Guard NVIC 05-05 — “Guidance on Assessing the Suitability of a Waterway for
Liquefied Natural Gas Marine Traffic,” published on June 14, 2005, provides guidance to an
applicant seeking a permit to build and operate a shore-side LNG terminal to ensure that full
consideration is given to safety and security of the port, the facility, and the carriers
transporting the LNG. It defines high density as greater than 9,000
persons per square
mile, medium density as 1,000 to 9,000 persons per square mile and low density as less than
1,000 persons per square mile. |
Employees
As of
November 15, 2006 we had 23 employees. None of our employees are members of any labor
union and we are not party to any collective bargaining or similar agreement with our employees. We
believe that our relationship with our employees is good.
Recruiting, Training and Safety
Our future success will depend, in part, on our ability to continue to attract, retain and
motivate qualified employees. We focus our recruiting efforts for our key positions on identifying
and retaining persons with proven industry knowledge and experience. We periodically review market
compensation and benefit data to ensure that we are competitive with other industry employers and
we intend to establish “best practices” throughout our operations to ensure that all employees
comply with our established safety standards, those of our insurance carriers’ and all laws and
regulations.
Insurance
Currently, the primary risks associated with our operations are bodily injury, property damage
and injured workers’ compensation. We presently maintain liability insurance for bodily injury and
third-party property damage and workers’ compensation coverage which we consider sufficient to
insure against these risks, subject to self-insured amounts. We currently maintain and intend to
continue maintaining workers’ compensation insurance policies that provide “first dollar” coverage.
The construction and operation of our proposed LNG terminals and pipelines will be subject to
the inherent risks normally associated with these types of operations, including accidents,
pollution, earthquakes and adverse weather conditions in the Pacific Ocean and other hazards, each
of which could result in a significant delay in the timing of commencement of operations and/or in
damage to or destruction of our facilities or damage to persons and property. In addition, our
operations face possible risks associated with acts of aggression or terrorism on our facilities
and the facilities and LNG carriers of third parties on which our operations are dependent.
In accordance with customary industry practices, we intend to maintain insurance against some,
but not all, of these risks and losses; however, we may not be able to maintain insurance (as our
project lenders may require) in the future at rates that we consider reasonable. The occurrence of
a significant event not fully insured or indemnified against could have a material adverse effect
on our business, results of operations, financial condition and prospects.
Legal Proceedings
On
August 18, 2006, an LNG supplier, Woodside Energy Inc. (WEI), filed a complaint against
Clearwater Port Holdings LLC in the Supreme Court of the State of New York, County of New York,
alleging that WEI is entitled to repayment in full of the $6.0 million long-term advance payable
recorded in our financial statements included in this prospectus as a result of
66
the acquisition by
us of all of the equity in Clearwater Holdings and the issuance by us of the convertible notes in
May 2006. We have filed our answer to the claim and dispute WEI’s allegations, and we believe that
payment of the $6.0 million long-term advance has not been triggered at this time.
Other Sites
We continue to evaluate, and may develop, additional sites that we believe may be commercially
desirable locations for LNG terminals. We will opportunistically consider expansion into other
geographic markets, either organically or through acquisition. By expanding into these markets, we
believe that we could reduce our local market risk exposure, enhance our attractiveness to
customers, and generate efficiencies through economies of scale. We will evaluate new project site
candidates using the same criteria used in selecting our current LNG terminal project portfolio,
including:
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proximity/access to high-value, high-demand markets; |
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the candidate’s potential for successful completion of the project; |
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the caliber of the candidate’s management and project personnel (if applicable); |
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the market area, customer base and expansion potential of the candidate; and |
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the value-added potential offered by the candidate. |
67
STATE AND FEDERAL GOVERNMENT REGULATORY MATTERS
Governmental Regulation and Environmental Matters
General
The siting, construction and operation of our liquefied natural gas (LNG) terminal and
interstate natural gas pipeline projects are subject to extensive regulation under federal, state
and local laws and regulations. We are required by various governmental and quasi-governmental
agencies to obtain permits, licenses, certificates and approvals for, and complete various
consultations with respect to these activities. This regulatory burden increases the cost of
constructing and operating our LNG terminals and failure to comply with such requirements could
result in substantial penalties, delays in the project schedule or the inability to obtain
necessary approvals for the projects. Because these laws and regulations change frequently, we
cannot predict the ultimate cost of compliance or their impact on our business. Additional laws and
regulations may be adopted that could limit our ability to do business or increase the cost of our
doing business and may materially adversely affect our business, results of operations, financial
condition, and prospects.
The costs that we incur to obtain Federal Energy Regulatory Commission (FERC), Coast Guard and
other governmental approvals authorizing us to commence construction of our proposed LNG terminals
and to comply with the ongoing regulation of such terminals could be significant and have a
material adverse effect on our business, results of operations, financial condition, and prospects.
We have no control over the outcome of the review and approval process. Delay in receipt of FERC,
Coast Guard or other required governmental authorizations could cause substantial delays in the
commencement of construction or operations of our LNG terminals or even result in the cessation of
construction or operations in some circumstances. If we are unable to obtain and maintain the
necessary permits and approvals, we may not be able to recover our investment in the projects. Our
failure to obtain and maintain any required permits and approvals from government and regulatory
agencies could have a material adverse effect on our business, results of operations, financial
condition and prospects.
Further, any interstate natural gas pipeline transmission system connected to our LNG
terminals would be subject to FERC regulation under Section 7 of the NGA. Such regulation may
restrict the ability of our customers to deliver to and transport gas from our LNG terminals, which
could have a material adverse effect on our business, results of operations, financial condition,
and prospects. While it does not currently do so, the FERC has in the past regulated the prices at
which natural gas could be sold. Federal reenactment of price controls on the sale of gas or
increased regulation of the transport of natural gas could have a material adverse effect on our
business, results of operations, financial condition and prospects.
Our LNG terminal development operations also are subject to extensive federal, state and local
laws and regulations that regulate the design, construction and operation of LNG import and
regasification terminals, LNG vessel transit operations, and the release of materials into the
environment, or that otherwise relate to the protection of the environment. These laws and
regulations may restrict or prohibit the types, quantities and concentration of substances that can
be released into the environment and impose substantial liabilities for pollution or releases of
hazardous substances. Failure to comply with these laws and regulations may result in substantial
penalties and harm our business. Present and future legislation and regulations could cause
additional expenditures, restrictions and delay of the commencement of our operations, the extent
of which cannot be predicted and which may require us to substantially limit, delay or cease
construction or operations in some circumstances.
Federal laws such as Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA), the Clean Air Act (CAA), the Clean Water Act (CWA), the Endangered Species Act (ESA) and
the Coastal Zone Management Act, as well as analogous or additional state and local laws, have
regularly imposed increasingly strict requirements for water and air pollution control, hazardous
and solid waste management, species and other resource protection and strict financial
responsibility and remedial response obligations. Existing environmental laws and regulations may
be revised or new laws and regulations may be adopted or become applicable to us. Revised or
additional laws and regulations could result in increased compliance costs or additional operating
restrictions. The cost of complying with existing and future environmental legislation could be
significant and have a material adverse effect on our business, results of operations, financial
condition and prospects.
68
Permitting for Onshore LNG terminal
In order to site, construct and operate our proposed onshore LNG terminal, we must receive and
maintain authorization from the FERC under Section 3 of the NGA. The FERC authorization process
under Section 3 of the NGA includes the following minimum elements:
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participation in the FERC pre-filing review process; |
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• |
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public notice and outreach, including applicant-sponsored open houses and
FERC-sponsored DEIS scoping meetings; |
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• |
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filing of an application for authorization to site, construct and operate the
LNG terminal, including an Environmental Report; |
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data gathering and analysis, to the extent required, at the FERC’s request; |
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issuance of a DEIS by the FERC; |
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• |
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public comment meetings on the DEIS; |
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• |
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issuance of a Final Environmental Impact Statement (FEIS), by the FERC; and |
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• |
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issuance of the FERC order authorizing the siting, construction and operation
of the project, which will include site-specific conditions that must be
satisfied prior to commencement of construction. |
Other Permits, Approvals and Consultations
In addition to FERC authorization under Sections 3 and 7 of the NGA, our construction and
operation of an onshore LNG terminal and pipelines are subject to additional federal permits,
approvals and consultations required by certain other federal agencies, principal among which are:
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| Agency |
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Permit/Approval/Consultation |
Advisory Council on Historic Preservation
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Section 106 of the National Historic Preservation Act (NHPA) coordination. |
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U.S. Army Corps of Engineers
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Regulates discharges of dredged or fill material into water of the United
States, including wetlands, under Section 404 of the CWA. Regulates
certain structures or work in or affecting navigable waters of the United
States under Section 10 of the Rivers and Harbors Act of 1899. |
|
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U.S. Department of Commerce
National Oceanic and Atmospheric
Administration,
National Marine Fisheries Service
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Consultation regarding compliance with Section 7 of the Endangered
Species Act (ESA), the Magnuson-Stevens Fishery Conservation and
Management Act, and the Marine Mammal Protection Act. |
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U.S. Department of the Interior
U.S. Fish and Wildlife Service
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Consultation regarding compliance with Section 7 of the ESA, the
Migratory Bird Treaty Act, Coastal Barrier Resources Act, and the Fish
and Wildlife Coordination Act. |
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U.S. Environmental Protection Agency (EPA)
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Section 402 of the Clean Water Act (CWA), National Pollutant Discharge
Elimination System Permit. |
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CAA permits for the construction of a stationary source of air pollutant
emissions and for operation of the source. |
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33 C.F.R. 127, Waterfront Facilities Handling LNG and Liquefied Hazardous
Gas. |
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U.S. Department of Homeland Security,
Coast Guard
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33 C.F.R. 127, Letter of Intent, Waterways Suitability Assessment
Establish and enforce pipeline safety regulations. |
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U.S. Department of Transportation and the
Pipelines and Hazardous Materials Safety
Administration
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Consultation on liquefied natural gas facility design. |
69
Our LNG terminal and pipelines also will be subject to U.S. Department of Transportation
siting requirements, while our terminal will be subject to Coast Guard regulations regarding the
safety and security of port areas. Moreover, our LNG terminal and pipeline projects also will be
subject to certain state and local laws and regulations.
Bradwood — Onshore Terminal
The siting, construction and operation of our proposed Bradwood project in Oregon will require
authorization under Section 3 of the NGA. On
February 23, 2005, we requested authorization to use
the FERC’s NEPA pre-filing review process in conjunction with the Bradwood project. On
March 3,
2005, the FERC granted our request to use the NEPA pre-filing process and designated Docket No.
PF05-10-000 as the pre-filing docket for the Bradwood project. We have completed the FERC
pre-filing review process and, on
June 5, 2006, we submitted Bradwood’s NGA Section 3 application
for authorization to site, construct and operate the Bradwood terminal in Docket No. CP06-365-000.
We anticipate the FERC issuing the DEIS by March 2007. We have targeted the third quarter of 2007
for receipt of Bradwood’s FERC authorization and starting of construction of the LNG terminal once
all other federal, state and local authorizations necessary to commence construction also have been
obtained. We anticipate placing the LNG terminal in service during the first quarter of 2011.
Bradwood Pipeline – Interstate Pipeline
Concurrently with the NGA Section 3 application for authorization to site, construct and operate
the Bradwood LNG terminal, we filed the NGA Section 7 application in Docket No. CP06-366-000 to
construct and operate the Bradwood Pipeline, an interstate natural gas pipeline facility that
connects the terminal to the interstate pipeline grid. The Bradwood Pipeline is subject to the
FERC’s regulation under NGA Section 7, including open access and tariff requirements. The FERC’s
exercise of jurisdiction over interstate gas pipelines pursuant to NGA Section 7 and would continue
as long as this pipeline is operated in interstate commerce.
Permitting for Offshore LNG terminals
In order to own, construct and operate our proposed Clearwater and Orion offshore LNG
terminals, we must receive deepwater port licenses under the Deepwater Port Act (DWPA). The DWPA
empowers the Secretary of Transportation to license and regulate deepwater ports beyond the
territorial limits of the United States. The Secretary of Transportation delegated the
responsibility for processing deepwater port applications to the Maritime Administration (MARAD),
and the Coast Guard. MARAD has the authority and responsibility to issue deepwater port licenses.
The process for obtaining a deepwater port license includes:
| |
• |
|
filing of an application for a deepwater port license to own, construct and
operate the offshore LNG terminal; |
| |
| |
• |
|
public notice and DEIS scoping meetings; |
| |
| |
• |
|
data gathering and analysis at the Coast Guard’s request; |
| |
| |
• |
|
issuance of a DEIS by the Coast Guard; |
| |
| |
• |
|
public comment meetings on the DEIS; |
| |
| |
• |
|
issuance of a FEIS by the Coast Guard; and |
| |
| |
• |
|
issuance of a Department of Transportation deepwater port license, which may
be subject to specified conditions. |
A series of legally mandated deadlines, totaling a maximum of 356 calendar days from the date
that the application is filed, governs the DWPA license review process.
70
| |
• |
|
The Coast Guard performs a completeness review within 21 days from the date of
application submittal. If the application is determined to be complete, the Coast
Guard then has five days to publish a Notice of Application filing in the Federal
Register. |
| |
| |
• |
|
The Federal Register publication of the Notice of Application triggers a
maximum 240 day period in which to perform an application review, complete the
requirements under the NEPA process and hold a final public hearing. |
| |
| |
• |
|
The DWPA mandates that there be at least one public hearing in each adjacent
coastal state. The final public hearing must occur no later than 240 days after
the publication of the Notice of Application in the Federal Register. |
| |
| |
• |
|
The final public hearing then triggers a maximum 90 calendar day deadline for
the Administrator of MARAD to issue a record of decision. This 90-day period is
divided into two 45-day periods. The Governor of California has 45 days after the
final public hearing to make final comments on the application. The Administrator
of MARAD has a subsequent 45 days to issue the record of decision. |
All together, these various periods of time involve a total of 356 calendar days from the date
that an application is submitted to the Coast Guard, though certain extensions of the time period
may apply.
MARAD, in consultation with the Coast Guard, issues a record of decision on the deepwater port
license application. The record of decision approves, denies or approves with conditions a license.
MARAD bases the record of decision primarily on the conditions for license issuance set forth in
the DWPA, as amended by the Maritime Transportation Security Act of 2002. A summary of some of the
more significant conditions follows:
| |
• |
|
We must be financially responsible and able to meet the requirements of the
Oil Pollution Act of 1990. We must be financially able to construct, own and
operate the deepwater port and must provide a financial guarantee or bond
sufficient to meet cost for removal of the deepwater port upon the termination or
revocation of the license. |
| |
| |
• |
|
We must have the experience, knowledge and capability to comply with relevant
laws, regulations, and license conditions. |
| |
| |
• |
|
The construction and operation of the deepwater port must be in the national
interest and consistent with national security and other national policy goals
and objectives, including energy sufficiency and environmental quality. |
| |
| |
• |
|
The deepwater port cannot unreasonably interfere with international navigation
or other reasonable uses of the high seas, as defined by treaty, convention or
customary international law. |
| |
| |
• |
|
We must construct and operate the deepwater port using the best available
technology, so as to prevent or minimize adverse impact on the marine
environment. |
| |
| |
• |
|
The application must properly address all applicable provisions of the CAA,
the Federal Water Pollution Control Act, and the Marine Protection, Research and
Sanctuaries Act, as well as any other applicable federal environmental and
resource protection laws. |
| |
| |
• |
|
The license application must include sufficient information to allow the
Secretary of Transportation to judge whether a deepwater port will comply with
all technical, environmental, and economic criteria. |
| |
| |
• |
|
The Secretary of the Army, the Secretary of State, and the Secretary of
Defense must convey their views on the adequacy of the application, and its
effect on programs within their respective jurisdictions. |
| |
| |
• |
|
The Governor of California approves, or is presumed to approve, the issuance
of a deepwater port license. |
71
While not presently proposed, to the extent that we construct and operate natural gas pipeline
facilities for Clearwater or Orion that connect to the interstate pipeline grid, we also must
obtain authorization from the FERC pursuant to Section 7 of the NGA to construct and operate these
pipeline facilities, which will be subject to the FERC’s regulation under NGA Section 7, including
open access and tariff requirements.
Other Permits, Approvals and Consultations
Permits from the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and
the State of California also are required to construct certain related port facilities, such as
pipelines and onshore facilities, for our LNG terminals. The Coast Guard must abide by the
requirements of NEPA and must prepare an EIS that describes in detail the nature and extent of the
environmental impacts of the proposed action and alternatives, discusses appropriate mitigation
measures for any adverse impacts and recommends whether to approve, approve with conditions or deny
the project. Moreover, our LNG terminals also will be subject to local and state laws, rules and
regulations, such regulation by the CSLC under CEQA.
The CSLC has the authority and responsibility to manage and protect natural and cultural
resources on public lands within California, including tidal and submerged lands. With respect to
the deepwater ports, the Lands Commission must consider whether or not to grant a lease for the
sub-sea pipelines. The lease also may include conditions relating to the parts of the project not
located in state waters. CEQA requires the Lands Commission to issue an Environmental Impact Report
(EIR), for deepwater ports. The environmental review requirements of NEPA and CEQA are similar. The
Coast Guard and the Lands Commission have agreed to issue a single, combined EIS/EIR.
Environmental Regulation
Construction and operation of all our LNG terminals are subject to numerous federal, state and
local laws and regulations governing the treatment, storage, disposal, transportation, discharge,
emission, and other management of chemicals, wastes, and other materials and otherwise relating to
the protection of the environment. These laws and regulations may require us to obtain governmental
authorizations before we may construct or operate our facilities or regulate the conduct of certain
activities (such as treating, storing, or disposing of hazardous waste, discharging wastewaters or
releasing air emissions into the environment). Obtaining such government approvals can be time
consuming and expensive. Often such activities require detailed and multiple submissions,
incorporating complex calculations and computer modeling, prepared by outside experts. Applicable
environmental laws also may require us to limit or abstain from certain activities that could
adversely affect endangered, threatened, or protected species, or environmentally sensitive areas.
These environmental laws frequently restrict the types, quantities and concentrations of various
wastes and other substances that can be released into the environment, and they may require the
installation of expensive pollution control equipment and/or the use of costly treatment measures.
The cost of complying with applicable environmental requirements can be significant. Failure to
comply with environmental laws and regulations may result in the assessment of administrative,
civil, and/or criminal penalties, the imposition of investigation and remediation costs and other
obligations, or the issuance of injunctive relief.
Environmental laws and regulations are complex. Environmental laws and regulations
historically have been subject to frequent change and have tended to become more stringent over
time. Changing regulatory interpretation can also make compliance more difficult and costly.
Consequently, we are unable to predict future costs associated with environmental compliance or
other future impacts of environmental regulation on our operations.
Environmental laws and regulations typically provide for public notice and comment periods in
connection with proposed environmental permitting and other governmental decisions necessary under
environmental laws. Many members of the public continue to be focused on environmental protection
issues. Recently, environmental organizations and other citizen groups, with some success, have
opposed and/or sought to delay the progress of projects similar to our offshore and onshore LNG
terminal projects. Such groups are expected to continue to be involved in environmental permitting
and standard-setting issues, and such involvement would be expected to affect our operations both
generally and on a site-specific basis. Third-party challenges may be filed with respect to
specific environmental authorizations issued for the projects and third parties also may challenge
the issuance of FERC, Coast Guard, and other federal authorizations for the projects on the basis
of the potential environmental impacts associated with the projects. Such challenges may delay the
construction or operation of our projects or result in additional conditions on our projects.
As with the industry generally, compliance with environmental laws increases our overall cost
of doing business. While these laws affect our capital expenditures and earnings, we believe they
do not affect our competitive position in the industry
72
because our competitors are similarly affected. The principal environmental laws that may
affect our operations include, but are not limited to, the following:
CERCLA
CERCLA, certain provisions of which are referred to as the Superfund law, and comparable state
laws impose liability without regard to fault or the legality of the original conduct on certain
categories of persons who are considered responsible for the spill or release of hazardous
substances into the environment. Potentially responsible persons under CERCLA include the owner or
operator of the site where the spill or release occurred and persons who disposed or arranged for
disposal of hazardous substances at the site. Under CERCLA, responsible persons may be subject to
joint and several liability for the costs of investigating and cleaning up hazardous substances
that have been released into the environment, mitigating the effects of contamination, damages to
natural resources, and the costs of certain health studies.
When a release of hazardous substances occurs that is regulated by CERCLA, the responsible
person must provide immediate notice to the government. Failure to do so can lead to penalties. In
addition to statutory liabilities arising under CERCLA for releases of hazardous substances, it is
not uncommon for neighboring landowners and other third parties to file claims for personal injury
and property damage allegedly resulting from the spill or release of hazardous substances. Although
CERCLA currently excludes petroleum, natural gas, natural gas liquids, and liquefied natural gas
from its definition of “hazardous substances,” we would be expected to generate, manage, and
dispose of certain materials in our operations that are “hazardous substances” for purposes of
CERCLA. Our activities involving hazardous substances could expose us to CERCLA liability if our
hazardous substances are released or disposed of improperly.
Many state governments have enacted their own statutes modeled on the federal Superfund
statute. The availability of exclusions for petroleum and natural gas, and the potential scope of
liability and damages, varies under the different state statutes.
RCRA
The federal Resource Conservation and Recovery Act (RCRA) and comparable state and local
statutes, govern the management from “the cradle to the grave” of “hazardous wastes.” Those
statutes also regulate solid wastes. In the event any hazardous wastes are generated in connection
with our LNG operations, we would be subject to the very detailed and rigorous regulatory
requirements affecting the handling, transportation, treatment, storage, disposal and cleanup of
such wastes. In addition, some of our wastes may be subject to the less stringent, solid waste
provisions in the RCRA statute, or applicable state and local counterparts. In many cases, states
administer the RCRA requirements with federal oversight. States also are free to impose additional
and more stringent requirements governing waste management practices.
Clean Water Act
Our operations that discharge wastewaters will be subject to the CWA and analogous state and
local laws. The U.S. Environmental Protection Agency has adopted regulations governing discharges
of wastewater and storm water that would be applicable to wastewater discharges from our
operations. States frequently administer the CWA program under federal oversight. States also are
free to impose additional and more stringent requirements governing wastewater discharges. These
programs require covered facilities to obtain authorization for their discharges through limits
established by appropriate discharge permits. The nature of the discharge and the scope of the
relevant regulatory program will determine whether individual permits, group permits, or general
permits will be required. The permits frequently impose limitations on the types and the amounts of
contaminants that may be discharged via wastewater and impose other conditions that must be
satisfied before wastewater may be discharged into the environment. Such requirements and limits
may affect our future operations and require us to incur substantial capital expenditures.
In addition, our operations, including construction of LNG terminals and support facilities,
in areas deemed to be wetlands, or which otherwise involve the discharges of dredge or fill
material into the navigable waters of the United States, may be subject to the U.S. Army Corps of
Engineers’ permitting requirements under the CWA and, for certain construction activities in or
affecting rivers and streams, the federal Rivers and Harbors Act.
Similar permits would be required at the state and local levels. In some cases, state and
local governments impose requirements on developments on or near waterbodies that are more
stringent than their federal counterparts.
73
Clean Air Act
Our operations will be subject to the federal CAA and comparable state and local laws that
restrict the emission of air pollutants and require the installation of various types of
pollution-control equipment. New facilities may be required to obtain construction permits before
beginning work to install new equipment or build new facilities, and existing facilities may be
required to obtain construction permits before modifying their existing equipment or adding new
equipment. In addition, both new and existing facilities would be subject to operating permit
requirements that would need to be satisfied before they can operate their facilities. Typically,
these permits are issued on an individual basis and can require the installation and use of
pollution-control equipment, testing of emissions and equipment, and related pollution-control
activities. The United States Congress adopted amendments to the CAA in 1990 that contain
provisions potentially resulting in the gradual imposition of certain pollution control
requirements with respect to air emissions from our operations. Consequently, we may be required to
incur capital expenditures in the future for air pollution control equipment in connection with
obtaining or maintaining permits and approvals addressing air emission-related issues. Also, EPA
has developed and continues to develop more stringent regulations governing emissions of toxic air
pollutants. In addition, the projects may require completion of a general federal conformity
determination.
Protected Species
Our operations may be restricted by requirements under the ESA and comparable state and local
laws. These laws seek to ensure that human activities do not jeopardize endangered, threatened, or
similarly protected animal, fish, or plant species, or destroy or adversely modify their critical
habitats. Proposed projects must be evaluated to determine whether they are likely to have such
effects. If so, the planned projects could be halted, delayed, or altered, or their costs could be
increased significantly.
National Environmental Policy Act
NEPA and comparable state and local laws and regulations require formal assessments of the
potential environmental effects of proposed government actions. Major federal actions may require
the preparation of a fairly comprehensive Environmental Impact Statement (EIS). The EIS evaluates
the potential impacts and any feasible alternatives to the proposal. The EIS also identifies
appropriate mitigation measures for any adverse impacts. This review process is coordinated with
several federal, state and analogous agencies and is open to public comment. The results of the
assessments and consideration of alternatives and potential environmental impacts may affect our
ability to obtain the necessary government authorizations for the construction and operation of our
terminals. They also could increase our costs or delay our projects. Several states, including
California, have enacted statutes modeled on the federal NEPA law. Because our projects are
expected to be subject to such environmental assessment obligations, they may affect our ability to
site and develop our LNG terminals as planned.
Occupational Safety And Health Act
The
Occupational Safety and Health Act (OSHA), and comparable state
statutes, regulate the
protection of worker health and safety. In addition to the OSHA requirements governing physical
safety issues, OSHA also regulates worker health and safety issues arising from hazardous
chemicals. In some cases, specific standards limit worker exposure to hazardous chemicals. In
addition, the Hazard Communication Standard issued pursuant to OSHA requires labeling of hazardous
chemicals in the workplace, the use of material safety data sheets to provide workers with hazard
warning information about particular chemicals, and training of workers about hazardous chemicals,
associated safety measures, and related topics.
Community Right-To-Know
Various statutes such as the Emergency Planning and Community Right-To-Know Act (EPCRA)
require companies that use chemicals to provide detailed information to the appropriate federal,
state, and local officials about the chemicals that are present at their facilities. In addition,
EPCRA requires companies to file reports concerning releases of chemicals to the environment. These
obligations impose significant recordkeeping obligations, and the failure to comply can lead to
imposition of penalties.
74
Land Use Limitations
Federal, state and local laws regulating the development of coastal areas, sovereign submerged
lands, or private property, also may prevent, affect or limit our ability to construct and operate
our LNG terminals and supporting facilities as currently planned.
Coastal Zone Management Act
Under the Coastal Zone Management Act, states have the authority to review the potential
impacts of a proposed action to the state’s coastal resources and made a determination whether the
project and its potential impacts are consistent with the state’s coastal zone management plan
(CZMP). FERC requires an applicant for an authorization under Section 3 of the NGA or CPCN under
Section 7 of the NGA to obtain from the relevant state(s), if applicable, a determination of the
project’s consistency with the state’s CZMP. Such a state determination typically may impose
additional requirements or conditions upon the construction and operation phases of a project.
75
MANAGEMENT
Our officers have extensive experience and a strong track record in the development and
realization of large capital projects. Most have held senior executive or management positions in
large energy companies, with over 150 years of combined experience in the development, financing,
construction and operation of energy projects such as power plants (gas, coal and nuclear), gas
pipelines, LNG facilities, and gas gathering and liquids separation systems. Collectively, our
senior management team has been involved in either the development, construction or operation of
more than 50 energy infrastructure projects with an aggregate cost of $15 billion. In addition to
our permanent management team, we also engage consultants for certain matters including legal and
regulatory, engineering, environmental and public relations matters.
Directors and Executive Officers
The following table sets forth the names, ages and positions for each of our directors and
executive officers as of
December 12, 2006:
| |
|
|
|
|
|
|
| Name |
|
Age |
|
Position |
|
|
|
61 |
|
|
Chairman of the Board and Director |
|
|
|
60 |
|
|
Chief Executive Officer and Director |
|
|
|
39 |
|
|
President and Director |
David L. Glessner
|
|
|
57 |
|
|
Vice President, Engineering and Construction |
Jonathan L. Phillips
|
|
|
33 |
|
|
Senior Vice President, General Counsel, Secretary,
and Assistant Treasurer |
|
|
|
44 |
|
|
Chief Financial Officer, Treasurer, Principal Accounting Officer,
and Assistant Secretary |
|
|
|
52 |
|
|
Director |
|
|
|
36 |
|
|
Director |
|
|
|
55 |
|
|
Director |
|
|
|
37 |
|
|
Director |
Biographies
Gerald K. Lindner. Mr. Lindner was elected Chairman of our board of directors effective
February 1, 2006 and has been a director of
the Company since its inception. Prior to the formation
of
the Company, Mr. Lindner was the Chief Executive Officer of MP Northwest LLC (formerly KGen LNG
Northwest LLC). Mr. Lindner is also the Chairman and Chief Executive Officer of KGen Power LLC, an
independent power company established in 2004 by MatlinPatterson with 5300 MW of southeastern
gas-fired power generation assets. From 2002 to 2004, Mr. Lindner was the Co-Head of the Power &
Utilities Group for Alvarez & Marsal, one of the top restructuring firms in the energy and power
industry and an advisor to MatlinPatterson on its restructuring and ownership of NRG Energy. From
1995 to 2002, Mr. Lindner was the founder and Chairman of Opus Power LLC, which worked as an
advisor and partner with several major private equity firms (JPMorgan, Carlyle UK) and utilities
(AEP) on the acquisition of power assets or companies. From 1991 to 1995, he was CEO of LCRW Power
which was formed by Chase Capital, Westinghouse Power Generation and EIF to acquire power plants.
Previous to 1991, Mr. Lindner was President of Hadson/Ultrasystems Development for 7 years, Group
Manager for 3 years at GE Power Systems and Director of M&A/ Development for Fluor Corporation for
7 years. Mr. Lindner served for 5 years as a board member and member of executive committee on the
national IPP industry association, NIEP. Mr. Lindner holds a master’s of business administration
from University of California, Los Angeles and a bachelor’s degree in math/economics from St.
Mary’s College.
William S. Garrett. Mr. Garrett was elected Chief Executive Officer of
the Company effective
February 1, 2006 and has been a director of
the Company since its inception. Prior to joining the
Company, Mr. Garrett was a founder and principal with ESI Holdings, LP, a consulting firm which
provides services to domestic United States, as well as international, firms in the development of
energy infrastructure projects and strategy in the power generation, natural gas and liquefied
natural gas industries, including active involvement in the development of the Bradwood, Clearwater
and Orion LNG terminals. Mr. Garrett was a founding member of Organic Fuels, LLC, a company that
builds, owns, and operates bio-diesel production facilities, whose first plant with a capacity of
30 million gallons per annum commenced operations in January 2006. From 1999 to 2002, Mr. Garrett
served as Vice President, Americas Development for CMS Enterprises, Inc. where he was responsible
for all energy infrastructure development and acquisition for North and South America including LNG
terminals
76
and gas pipelines and distribution systems. From 1997 to 1999, Mr. Garrett was employed as Sr.
Vice President of Arco Integrated Power, Inc. and from 1994 to 1997 as President of the Americas
for Tenneco and El Paso International overseeing strategic planning, development and operational
activities for energy-related projects. Mr. Garrett holds a degree in chemical engineering from the
University of Virginia and completed a U.S. Naval Nuclear Power School program in nuclear
engineering equivalent to a master’s degree. Mr. Garrett also served with the U.S. Navy in its
submarine fleet from 1969 to 1980 and retired as a Captain from the U.S. Naval Reserve in July
2006, with over 37 years of service.
Paul F. Soanes. Mr. Soanes was elected President of
the Company effective
February 1, 2006 and
has been a director of
the Company since its inception. Prior to joining
the Company, Mr. Soanes
was a founder and principal with ESI Holdings, LP, a consulting firm which provided services to the
domestic United States, as well as international, firms in the development of energy infrastructure
projects and strategy in the power generation, natural gas and liquefied natural gas industries,
including active involvement in the development of the Bradwood and Clearwater LNG Terminals. Mr.
Soanes was also a founding member of Organic Fuels, LLC, a company that builds, owns and operates
bio-diesel production facilities, whose first plant with a capacity of 30 million gallons per annum
commenced operations in January 2006. From 2000 to 2002, Mr. Soanes served as director, business
development for CMS Energy where he was responsible for the business development activities in the
natural gas pipeline, marketing and trading, electric generation and LNG industries. From 1991 to
2000, Mr. Soanes served in various positions with ARCO including Vice President – Commercial
Development – Asia for ARCO Global Energy Ventures where he was responsible for strategic planning
and development of ARCO Global Energy Venture’s natural gas monetization activities in Asia and the
Pacific Rim. Mr. Soanes graduated with a bachelor’s degree in commerce from Murdoch University,
Western Australia. He is an Australian Chartered Accountant.
David L. Glessner. Mr. Glessner was elected Vice President, Engineering and Construction
effective March 2006. Prior to joining
the Company, he was engaged as a private consultant from
2004 as lead engineer of the Clearwater and Bradwood LNG terminal projects. From 2002 to 2004, Mr.
Glessner served as Senior Director for Prisma Energy where he was responsible for technical,
commercial and logistical support for the Eco Electrica LNG terminal in Puerto Rico. From 1991 to
2002, Mr. Glessner served in various senior positions with Enron, including General Manager,
Development Engineering, where he was responsible for the development of the Dabhol, India and
Grand Bahamas LNG terminal projects and for various LNG projects in China, Qatar, Jordan, Turkey,
India, Puerto Rico, Venezuela and Japan. Mr. Glessner holds a bachelor’s degree in chemical
engineering from the University of Pittsburgh and a master’s degree from Case Western Reserve
University.
Jonathan L. Phillips. Effective
August 31, 2006, Mr. Phillips was elected Senior Vice
President, General Counsel and Secretary of
the Company. Prior to joining
the Company, he was
employed by Chadbourne & Parke LLP where he was a member of the Project Finance and Private Equity
Practice Groups. His practice was focused on energy transactions related to the natural gas and
LNG, power generation and renewable fuels industries. While at Chadbourne he worked with the
Company’s principals, actively representing NorthernStar, Bradwood and Clearwater. Mr. Phillips
holds a juris doctor from South Texas College of Law and a bachelor’s degree of business
administration from the University of Texas at Austin.
Bradford C. Witmer. Effective
November 15, 2006, Mr. Witmer was elected as Chief Financial
Officer, Treasurer, Principal Accounting Officer and Assistant Secretary of
the Company. From May
2006 through November 15, Mr. Witmer served as Senior Vice President, Finance and Administration,
Treasurer, Principal Accounting Officer and Assistant Secretary. Prior to joining
the Company, he
served in various accounting and financial roles with Suez Energy North America, including serving
from 2001 to 2004 as Vice President and Controller of Suez LNG North America, owner and operator of
an LNG receiving terminal in Everett, Massachusetts. From 1998 to 2001, he served as Vice President
and Controller of Mountaineer Gas Company, a gas distribution utility with over 200,000 customers.
From 1990 to 1996 he was Vice President and Controller of Allegheny & Western Energy Corporation, a
publicly-traded oil and gas exploration, natural gas distribution and marketing firm. Prior to
1990, he was a Manager in the Accounting and Attest Services division of Arthur Andersen & Co. Mr.
Witmer holds a bachelor’s degree in business administration, with a concentration in accounting,
from Ohio University.
Frank Plimpton. Mr. Plimpton has been a director of
the Company since its inception. He has
been a partner of MatlinPatterson since its inception in July 2002. Prior to July 2002, Mr.
Plimpton was a member of the Distressed Securities Group (the predecessor to MatlinPatterson) of
Credit Suisse, an investment banking firm, which he joined in 1998. Mr. Plimpton is also a director
of KGen Power LLC and its affiliates and RailWorks Corporation. Mr. Plimpton holds a juris doctor
and a master’s degree in business administration from University of Chicago and a bachelor’s
degree,
cum laude, in applied mathematics and economics from Harvard College.
77
Ramon Betolaza. Mr. Betolaza has been a director of
the Company since its inception. He has
been a partner of MatlinPatterson since its inception in July 2002. Prior to July 2002, Mr.
Betolaza was a member of the Distressed Securities Group (the predecessor to MatlinPatterson) of
Credit Suisse, an investment banking firm, which he joined in 1997. Mr. Betolaza serves on behalf
of Fund I on the board of Polymer Group, Inc. and serves on behalf of Fund II on the boards of KGen
LLC, NorthernStar Natural Gas Inc., Teesside Gas Processing Plant Limited, Natural Gas Processing
Limited, Enron Europe Liquids Processing Limited, Michel Thierry S.A., Cerruti SA, Matussiere et
Forest SA and Novacare SA. Mr. Betolaza is also a member of the International Advisory Board for
the Instituto de Empresa Fund (IE Fund), a U.S. not-for-profit organization. Mr. Betolaza is also a
director of KGen Power LLC and Polymer Group, Inc. Mr. Betolaza holds a master’s degree in business
administration from Instituto de Empresa (IE) in Madrid (
summa cum laude, class of 1995) and a
Degree in Economics and Financial Management from Universidad Comercial de Deusto, Bilbao
(1988-1993).
Daniel Richard, Jr. Mr. Richard became a director of
the Company effective
June 29, 2006. Mr.
Richard was Senior Vice President, Public Policy & Governmental Relations at Pacific Gas & Electric
Co. from 1997 to 2006, where he was responsible for overall external relations of a major energy
holding company and its regulated utility. Mr. Richard served as a dual officer, reporting to the
chief executive officer of the holding company and the chief executive officer of the utility and
supervised governmental relations, federal affairs, communications and regulatory relations. Prior
to his tenure at Pacific Gas & Electric Co., Mr. Richard was co-founder and principal of an energy
and financial services consulting firm, Morse, Richard, Weisenmiller & Associates, in Oakland,
California. From 1992 to 2004 Mr. Richard was an elected director for the Bay Area Rapid Transit
System, serving as President of the board in 1996 and 1999. During his tenure on the Bay Area Rapid
Transit SystemBoard, Mr. Richard led efforts for nearly $4 billion in capital expansion for the
system. Mr. Richard holds a juris doctor from the McGeorge School of Law and a bachelor’s degree in
political science from Washington University.
William O. Perkins III. Mr.
William O. Perkins III is the founder and president of Small
Ventures USA, L.L.C. (SMV); which was founded in 1997. Based in Houston, the firm deploys capital
across multiple sectors and geographies on an opportunistic basis with a bias towards early stage
investment. In addition to funding, SMV provides operational and financial-trading capabilities to
its investment portfolio. SMV is currently lead investor in a mid-stage El Salvador based
development transaction to build a liquefied natural gas facility and natural gas fueled power
plant. The project, CUTUCO Energy, would represent that largest investment in El Salvador’s
history. Mr. Perkins has a 12 year history of energy derivatives trading, holding senior risk
management and trading positions at AIG, El Paso Energy and Statoil. Most recently, he has been an
significant market participant for Centaurus Energy, which he joined at inception in 2002. Mr.
Perkins received a Bachelor of Science Degree in Electrical Engineering from the University of
Iowa.
Composition of Our Board
Our current board of directors consists of the following directors:
Each of our directors on our board of directors and related committees have served in such
capacity since
May 2, 2006.
At the closing of the offering, we will have directors including a director who
qualifies as an “audit committee financial expert” under the rules and regulations of the SEC and
Nasdaq. The majority of our directors will be independent within the timeframe required by Nasdaq
and the Sarbanes-Oxley Act of 2002.
78
| |
• |
|
Our directors , , and will be independent. |
| |
| |
• |
|
Our board of directors serves for a period of
years at the discretion of the board. |
| |
| |
• |
|
Directors , , and are members of the Committee. |
Current Shareholders Agreement
We currently have a Shareholders Agreement, dated as of
March 7, 2006, as amended, among us
and certain of our shareholders. The Shareholders Agreement currently sets forth representation and
appointment rights for MatlinPatterson, NorthernStar Natural Holdings Ltd., Penguin Partners LLC
and their affiliates (including Mr. Garrett and Mr. Soanes), and Crystal Holdco LLC (Crystal
Holdco) and establishes the size of our board of directors. At the closing of this offering, the
Shareholders Agreement will terminate and our charter and the
bylaws will control the make-up of
our board of directors.
Composition of Our Board of Directors at the Completion of this Offering
Under our charter and
bylaws, the number of directors will be set by a majority of the board
of directors, with a minimum of three directors and a maximum of eleven directors. Directors will
be elected by a plurality of the votes for terms expiring annually. Any director may be removed at
any time, with or without cause, by the affirmative vote of a majority of the holders of our common
stock. Vacancies and newly-created directorships can be filled only by the vote of a majority of
the remaining directors.
Our board of directors has the authority to appoint committees to perform certain management
and administration functions. Our board of directors has an audit committee, a compensation
committee, a corporate governance and nominating committee, and an executive committee. The
composition of the board committees will comply with the applicable rules of the Nasdaq Global
Market and the provisions of the Sarbanes-Oxley Act of 2002.
Audit Committee
Following this offering, our audit committee will be responsible for, among other things,
making recommendations concerning the engagement of our independent public accountants, reviewing
with the independent public accountants the plans and results of the audit engagement, approving
professional services provided by the independent public accountants, reviewing the independence of
the independent public accountants, considering the range of audit and non-audit fees and reviewing
the adequacy of our internal accounting controls. At the time the offering is consummated our audit
committee will be comprised of independent directors including a financial expert who will be added
to our board as per the requirements of the Nasdaq Global Market and the SEC. Our audit committee
will be comprised of , , and .
Compensation Committee
Following this offering, our compensation committee will be primarily concerned with
administering programs and policies regarding the compensation of executive officers and employee
benefit plans. The committee is responsible for determining compensation of our executive officers
and other employees and overseeing the administration of all employee benefit plans and programs.
Our compensation committee will be comprised of , , and .
Compensation Committee Interlocks and Insider Participation
None of our executive officers serves as a member of the board of directors or compensation
committee of any entity that has one or more of its executive officers serving as a member of our
board of directors or compensation committee.
Corporate Governance and Nominating Committee
Following this offering, our corporate governance and nominating committee will be primarily
concerned with identifying individuals qualified to become members of our parent’s board of
directors, selecting the director nominees for the next annual meeting of the stockholders and
review of our corporate governance policies. The committee will be responsible for reviewing
director compensation and benefits, overseeing the annual self-evaluations of our parent’s board of
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directors and making recommendations to the board concerning the structure and membership of
the other board committees. Our corporate governance and nominating committee will be comprised of , , and .
Compensation of Directors and Officers
Directors who are employees do not receive a retainer or fees for service on our board of
directors or any committees. Non-employee directors will receive $120,000 per year for services as
director. For directors employed by affiliates, such amounts are only payable in restricted shares
under our 2006 Non-Employee Directors’ Stock Plan. See “—2006 Non-Employee Directors’ Stock Plan.”
Directors who are not employed by affiliates of major shareholders are entitled to receive up to
25% of such amount in cash. Directors are also reimbursed for out-of-pocket expenses incurred in
attending meetings of our board of directors or committees thereof.
Executive Compensation
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Long Term |
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Compensation |
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Annual Compensation |
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Salary paid |
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from Date of |
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Hire (March |
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