Back to GetFilings.com



Table of Contents

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

Form 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2003

 

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                               to                              

 

Commission File No. 001-16383

 


 

CHENIERE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

Delaware   95-4352386
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

717 Texas Avenue, Suite 3100

Houston, Texas

  77002
(Address of principal executive offices)   (Zip code)

 


 

Registrant’s telephone number, including area code: (713) 659-1361

 

Securities registered pursuant to Section 12(b) of the Act:

None

 

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $ 0.003 par value   American Stock Exchange
(Title of Class)   (Name of each exchange on which registered)

 


 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

 

The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $66,180,000 as of June 30, 2003.

 

18,659,994 shares of the registrant’s Common Stock were outstanding as of February 29, 2004.

 

Documents incorporated by reference: The definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) is incorporated by reference into Part III.

 



Table of Contents

CHENIERE ENERGY, INC.

Index to Form 10-K

 

PART I    1
Items 1. and 2. Business and Properties    1
Item 3. Legal Proceedings    24
Item 4. Submission of Matters to a Vote of Security Holders    25
PART II    25
Item 5. Market Price for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities    25
Item 6. Selected Financial Data    26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations    27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk    35
Item 8. Financial Statements and Supplementary Data    36
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    73
Item 9A. Controls and Procedures    73
PART III    73
Item 10. Directors and Executive Officers of the Registrant    73
Item 11. Executive Compensation    74
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    74
Item 13. Certain Relationships and Related Transactions    74
Item 14. Principal Accountant Fees and Services    74
PART IV    74
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K    74
SIGNATURES    79
Freeport LNG Development, L.P. Audited Financial Statements    81
Gryphon Exploration Company Audited Financial Statements    90

 

i


Table of Contents

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

 

This annual report contains certain statements that may include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things: statements regarding our business strategy, plans and objectives; statements expressing beliefs and expectations regarding the development of our LNG receiving terminal business; statements expressing beliefs and expectations regarding our ability to successfully raise the additional capital necessary to meet our obligations under our current exploration agreements; statements expressing beliefs and expectations regarding our ability to secure the leases necessary to facilitate anticipated drilling activities; statements expressing beliefs and expectations regarding our ability to attract additional working interest owners to participate in the exploration and development of our exploration areas; and statements about non-historical information, are forward-looking statements. These forward-looking statements are often identified by the use of terms and phrases such as “expect,” “estimate,” “project,” “plan,” “believe,” “achievable,” “anticipate” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this annual report.

 

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in “ Risk Factors” beginning on page 16. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements.

 

PART I

 

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

 

General

 

Cheniere Energy, Inc., a Delaware corporation, is a Houston-based company engaged primarily in the development of a liquefied natural gas, or LNG, receiving terminal business and related LNG business opportunities centered on the U.S. Gulf Coast. The LNG receiving terminal business consists of receiving deliveries of LNG from LNG ships, processing such LNG to return it to a gaseous state and delivering it to pipelines for transportation to purchasers. We are also engaged in oil and gas exploration, development and exploitation activities in the Gulf of Mexico.

 

We have been publicly traded since July 3, 1996 under the name Cheniere Energy, Inc. Our principal executive offices are located at 717 Texas Avenue, Suite 3100, Houston, Texas 77002, and our telephone number is (713) 659-1361.

 

On October 16, 2000, our stockholders approved a one-for-four reverse stock split. The reverse stock split became effective on October 18, 2000 and reduced our issued and outstanding shares from 43,989,572 shares to 10,997,393 shares. All historical share and per share data appearing in this document reflect the reverse stock split.

 

As used in this annual report, certain terms have the following meanings:

 

  “we” and “our” refer to Cheniere Energy, Inc. and its subsidiaries

 

  “Bbl” means barrel or 42 U.S. gallons liquid volume

 

1


Table of Contents
  “Bcf” means billion cubic feet

 

  “Bcfe” means billion cubic feet of natural gas equivalent using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate and natural gas liquids

 

  “cm” means cubic meter

 

  “liquefaction plant” means all or most of the equipment needed to remove impurities from natural gas, refrigerate the treated natural gas so that it becomes LNG, and transport the LNG to storage

 

  “LNG” means liquefied natural gas

 

  “Mcf” means thousand cubic feet

 

  “Mcfe” means thousand cubic feet of natural gas equivalent using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate and natural gas liquids

 

  “Mmcf” means million cubic feet

 

  “Mmcf/d” means million cubic feet per day

 

  “Mmbtu” means million British thermal units

 

  “regas” means the process by which LNG is heated to convert it back into its gaseous phase

 

  “Tcfe” means trillion cubic feet of natural gas equivalent using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate and natural gas liquids

 

Access to Public Filings

 

We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These reports may be accessed free of charge through our internet website (located at www.cheniere.com), where we provide a link to the SEC’s website (at www.sec.gov). We make our website content available for informational purposes only. The website should not be relied upon for investment purposes.

 

General Development of Business

 

Cheniere Energy Operating Co., Inc. (“Cheniere Operating”) was incorporated in Delaware in February 1996 for the purpose of engaging in the oil and gas exploration business, initially on the Louisiana Gulf Coast. On July 3, 1996, Cheniere Operating underwent a reorganization whereby Bexy Communications, Inc., a publicly-held Delaware corporation (“Bexy”), received 100% of the outstanding shares of Cheniere Operating, and the former stockholders of Cheniere Operating received approximately 93% of the issued and outstanding Bexy shares. As a result of the share exchange, a change in control occurred. The transaction was accounted for as a recapitalization of Cheniere Operating. Bexy spun off its existing assets and liabilities to its original stockholders and changed its name to Cheniere Energy, Inc. Cheniere Operating became a wholly-owned subsidiary of Cheniere.

 

We have two reporting segments: one segment is the LNG Receiving Terminal Development business and the other is the Oil and Gas Exploration and Development business.

 

LNG Receiving Terminal Development

 

LNG is natural gas that has been reduced to a fraction of its volume through a sophisticated refrigeration process. The liquefaction of natural gas (into LNG) allows it to be shipped long distances comparatively safely and economically. Outside the U.S., utilization of LNG has grown dramatically. As of February 15, 2004, there

 

2


Table of Contents

were 70 liquefaction plants in 12 countries capable of producing 6.5 Tcfe of LNG per year and 43 terminals in 12 countries capable of importing and regasifying LNG. Yet in the U.S., due mainly to a historically abundant supply of natural gas, LNG has not been a major energy source. However, U.S. natural gas producers have recently had limited ability to increase supply, and costs of domestic natural gas exploration and production have increased. As a result, we believe that LNG will become a competitive supply alternative to domestic natural gas and other import alternatives. Assuming current construction costs of LNG-related facilities and tankers, we believe that LNG can be economically produced and delivered as natural gas into U.S. pipelines at a cost lower than $3.00 per Mmbtu.

 

In 2000, we undertook a feasibility study to assess the long-term natural gas markets in the U.S. and, in particular, the potential role of LNG in meeting a portion of the gas supply deficit anticipated to develop later in this decade. Based on that analysis, our management concluded that LNG would become an economically viable source of natural gas supply in the U.S. In 2001, we assembled an experienced LNG project development team and began a study to determine viable locations for LNG receiving terminals in the U.S. We have chosen sites along the Gulf Coast at which we may develop LNG receiving terminals. The Gulf Coast area offers several important advantages, including the following:

 

  Texas and Louisiana are the first and third largest natural gas-consuming states in the U.S.,

 

  the local governments and communities are familiar with and supportive of the energy industry,

 

  with the expected declines in local production, the Gulf Coast states will have under-utilized intrastate and interstate pipelines with access to Midwest, Northeast, Mid-Atlantic and Southeast U.S. markets, and

 

  the Gulf Coast states have extended coastlines, providing a number of ports with adequate facilities for such terminals.

 

LNG Receiving Terminal Sites

 

Freeport LNG

 

An LNG receiving facility will be developed on Quintana Island near Freeport, Texas on a 233-acre tract of land and will be designed with regas capacity of 1.5 Bcf per day, one dock, and two storage tanks with an aggregate storage capacity of 6.7 Bcfe. The unloading dock will be able to handle 75,000 cm to greater than 200,000 cm LNG shipping vessels. From the terminal, natural gas will be transported through a 9.3-mile pipeline to Stratton Ridge, Texas, which is a major point of interconnection with the Texas intrastate gas pipeline system. The cost to construct the facility is currently estimated to be in excess of $500 million.

 

In June 2001, we acquired an option to lease acreage suitable for an LNG receiving terminal site near Freeport and funded the initial permitting expenses of the project. In connection with the acquisition of our option, we issued 500,000 shares of common stock valued at $1,150,000, or $2.30 per share, the closing price of our common stock on the date of the transaction, to the seller of the lease option. We also committed to issue an additional 750,000 shares of our common stock to the seller of the lease option at a later date, for which we received no additional consideration. These shares were issued in April 2003 at a value of $1,312,500, or $1.75 per share, the closing price of our common stock on the date of issuance. The seller of the lease option also obtained the right to receive a royalty payment on the gross quantities of gas processed through LNG terminals owned by Cheniere LNG, Inc., our wholly-owned subsidiary. The royalty is calculated based on $0.03 per Mcf on the quantities of gas processed through LNG terminals we own, subject to a maximum royalty of approximately $10,950,000 per year. In 2002, a long-term lease was secured, and at the closing of the sale of our interests in the site and project to Freeport LNG Development, L.P. (“Freeport LNG”), Freeport LNG assumed the obligation to pay the royalty with respect to gas processed and produced at the Freeport LNG facility.

 

In August 2002, we entered into an agreement with entities controlled by Michael S. Smith (“Smith”) to sell a 60% interest in the Freeport site and project. On February 27, 2003, we consummated the transaction by selling

 

3


Table of Contents

our interest in the site and project to Freeport LNG, in which we held a 40% limited partner interest. Smith holds a 60% limited partner interest in Freeport LNG. We recovered $1,740,426, in costs we had incurred on the project and received an additional $5,000,000 from Freeport LNG. For the funding of Freeport LNG project development costs, Smith also committed to contribute up to $9,000,000 and to allocate available proceeds from any sales of options or capacity reservations and/or proceeds from loans related to capacity reservations to these costs. In connection with the closing, we issued warrants to Smith to purchase 700,000 shares of Cheniere common stock at a price of $2.50 per share, exercisable for a period of 10 years.

 

Effective March 1, 2003, we sold a 10% limited partner interest in Freeport LNG to an affiliate of Contango Oil & Gas Company (“Contango”) for $2,333,333 payable over time, including the cancellation of our $750,000 short-term note payable. We also issued warrants to Contango to purchase 300,000 shares of Cheniere common stock at a price of $2.50 per share, exercisable for a period of 10 years. As a result of the sale, we now hold a 30% limited partner interest in Freeport LNG.

 

In June 2003, The Dow Chemical Company (“Dow”) signed an agreement with Freeport LNG for the potential long-term use of the facility. Under the agreement, Dow will have regas rights to as much as 500 Mmcf/d beginning with commercial start-up of the facility in 2007. On February 26, 2004, Freeport LNG and Dow entered into a twenty-year terminal use agreement (“TUA”). Under the terms of the TUA, Dow made a firm commitment to reserve regas capacity of 250 Mmcf/d and has until August 31, 2004 to exercise its option on the remaining 250 Mmcf/d.

 

On December 21, 2003, ConocoPhillips signed an agreement with Freeport LNG under which ConocoPhillips will participate in Freeport LNG’s receiving terminal. Pursuant to the agreement, ConocoPhillips will reserve one Bcf per day of regas capacity in the terminal for its use, obtain a 50% interest in the general partner of Freeport LNG, and provide a substantial majority of the financing to construct the facility, which is currently estimated to cost in excess of $500 million. The management of Freeport LNG will remain in place and will be responsible for all commercial activities and interfacing with customers for the remaining capacity in the facility. ConocoPhillips will be primarily responsible for managing the construction and operation of the facility. ConocoPhillips, as a user of the facility, will be required to pay its proportionate share of operating expenses and fuel costs, a throughput fee of $0.05 per Mcf, and all amounts necessary to amortize the construction funding. ConocoPhillips paid a nonrefundable capacity reservation fee of $10,000,000 to Freeport LNG in January 2004. The transaction is expected to close in the spring of 2004, subject to completion of remaining documentation and satisfaction of closing conditions.

 

In the event the funding provided by ConocoPhillips is insufficient to meet the capital expenditures or working capital requirements of Freeport LNG, the general partner of Freeport LNG may obtain such additional funding from any of the following sources:

 

  cash reserves of Freeport LNG;

 

  loans from banks and other non-affiliate independent sources;

 

  additional capital contributions made to Freeport LNG by the partners;

 

  loans made to Freeport LNG by the partners or their affiliates;

 

  a lender-of-last resort facility available from ConocoPhillips; or

 

  any other funding source determined by the general partner of Freeport LNG.

 

We believe that it is unlikely that we will have to contribute any additional capital funds.

 

The general partner of Freeport LNG is authorized to do all things necessary to obtain debt and/or equity financing in connection with any expansion of the facility. Any equity financing obtained for such expansion will dilute the ownership interests of the limited partners on a pro rata basis. However, each limited partner that is an accredited investor has the right to participate in any such equity financing to the extent that enables such limited partner to maintain its percentage ownership interest in Freeport LNG.

 

4


Table of Contents

Approval of the Freeport LNG project from the Federal Energy Regulatory Commission (“FERC”) is expected in March or April of 2004, with all other necessary federal, state and local approvals shortly thereafter. The front-end engineering and design study for the Freeport LNG project was completed in January 2004. Construction is scheduled to begin in the second half of 2004, with commercial start-up expected in the second half of 2007.

 

Corpus Christi LNG and Sabine Pass LNG

 

We are currently developing two additional LNG receiving terminals: one near Corpus Christi, Texas and one near Sabine Pass, Louisiana. Each of these terminals will be designed with regas capacity of 2.6 Bcf per day, two docks, and three storage tanks with an aggregate storage capacity of 10.1 Bcfe. Each of these facilities will have two unloading docks that can handle 87,000 cm to 250,000 cm LNG shipping vessels. Each location will also have three dedicated tugboats. The cost to construct the Corpus Christi facility is currently estimated at approximately $450-$550 million, and the cost to construct the Sabine Pass facility is currently estimated at approximately $500-$600 million.

 

We formed Corpus Christi LNG, L.P. (“Corpus LNG”) in May 2003 to develop an LNG receiving terminal near Corpus Christi, Texas. Under the terms of the limited partnership agreement, we contributed our technical expertise and know-how, and all of the work in progress related to the Corpus Christi project, in exchange for a 66.7% limited partner interest in Corpus LNG. BPU LNG committed to contribute its approximately 210-acre tract of land plus related easements and additional rights to an additional 400 acres, and cash to fund the first $4,500,000 of Corpus LNG project expenses in exchange for its 33.3% limited partner interest. In January 2004, BPU LNG entered into an option agreement with Corpus LNG to acquire 100 Mmcf of natural gas per day regas capacity through the receiving terminal. We will manage the project through the general partner interest held by our wholly-owned subsidiary.

 

We recently formed Sabine Pass LNG, L.P. (“Sabine Pass LNG”) to develop an LNG receiving terminal near Sabine Pass, Louisiana. We currently plan to retain 100% of the ownership interest in Sabine Pass LNG. We intend to fund some of the development costs but plan to obtain additional equity or debt financing for this project. We have options on three tracts of land comprising 568 acres in Cameron Parish, Louisiana which collectively are suitable for the project site.

 

On December 22, 2003, we submitted to FERC applications for permits to build these LNG receiving facilities, as well as separate but concurrent permit applications for their related pipelines. See “Other Developments.” We have selected Bechtel Corporation to perform the engineering, procurement and construction for the facilities under a fixed price contract to be negotiated. The front end engineering design work for the terminals was completed by Black & Veatch Pritchard, Inc.

 

Other Developments

 

In addition to the sites discussed above for which we have submitted FERC applications, we are also evaluating other sites that we believe may be commercially feasible for developing LNG receiving terminals. These potential sites include locations in Brownsville, Texas and Mobile, Alabama for which we currently have lease options in place.

 

We have also begun to market natural gas pipeline capacity from the site of our proposed Sabine Pass and Corpus LNG receiving terminals. We plan to construct a 16-mile, 42-inch diameter natural gas pipeline from the site of our proposed Sabine Pass LNG receiving terminal, running easterly along a corridor that will allow for interconnection points with interstate and intrastate natural gas pipelines in Southwest Louisiana. We also plan to construct a 24-mile, 48-inch diameter natural gas pipeline from the site of our proposed Corpus LNG receiving terminal, running northwesterly along a corridor that will allow for interconnection points with interstate and

 

5


Table of Contents

intrastate natural gas transmission pipelines in South Texas. The feasibility of constructing such pipelines will depend on market demand for natural gas from the respective terminals.

 

J & S Cheniere

 

Cheniere LNG Services, Inc. (“Cheniere LNG Services”), one of our wholly-owned subsidiaries, holds a minority interest in J & S Cheniere S.A. (“J&S Cheniere”), a Switzerland joint-stock company. The majority interest in J&S Cheniere is held by J & S Group S.A. (“J&S Group”), a Luxembourg corporation affiliated with J & S Trading Company, Ltd., an international petroleum trading and marketing company. Under a shareholders agreement, Cheniere LNG Services identifies and assists with LNG-related business opportunities that it determines are appropriate for J&S Cheniere. Cheniere LNG Services is not required to offer any particular business opportunities nor funding to J&S Cheniere. All financing of the business opportunities will be provided by J&S Group should it determine that a business opportunity is appropriate for J&S Cheniere. However, J&S Group is not required to fund any particular business opportunity. The shareholders agreement gives Cheniere LNG Services the right to purchase additional shares up to a maximum of 50% of the outstanding shares of J&S Cheniere. The shareholders agreement also provides J&S Group the right to acquire all J&S Cheniere shares owned by us in the event we experience a change in control (defined in the shareholders agreement to include a change in a majority of our board, the acquisition of more than 40% of our outstanding common stock other than as approved by our board, and a merger or consolidation that results in 50% or less of the surviving entity’s voting securities being owned by the holders of our voting securities immediately prior to such transaction).

 

As its initial LNG business opportunity, J&S Cheniere has contracted to charter an LNG ship upon completion of its refurbishment in February 2004 for an 18-month period. In January 2004, J&S Cheniere signed a transportation agreement with Sonatrach, the national oil company of Algeria, to optimize the use of this LNG ship. During the six-month term of the agreement, the two companies will jointly operate the vessel and endeavor to find the most profitable routes for the vessel. The ship is anticipated to be used primarily as a trading vessel and not in connection with a specific project.

 

Cheniere LNG, Inc., one of our wholly-owned subsidiaries, and J&S Cheniere entered into an option agreement on December 23, 2003 under which J&S Cheniere has an option to purchase LNG storage tank capacity and regas capacity of up to 200 Mmcf/d in each of the Sabine Pass and Corpus Christi facilities. Following execution of the option agreement, $1,000,000 was paid by J&S Cheniere to Cheniere LNG, Inc. in January 2004. At December 31, 2003, we included the $1,000,000 in accounts receivable and the offset was recorded as deferred revenue, as the option fee is refundable if we do not receive FERC approval for at least one of the terminals or we do not proceed with the development of at least one of the terminals. Upon FERC approval and other related approvals and receipt of permits for each terminal, J&S Cheniere has 60 days to exercise its option at each terminal. The option agreement contemplates negotiation of a definitive TUA for each of the facilities, which will specify the terms and conditions of the purchase and sale of the capacity and related services.

 

Business Strategy

 

We believe that the long-term outlook for natural gas prices in the U.S. is one that will sustain prices at or above $3.00 per Mcf. We believe that such an environment will favor not only domestic exploration and production, but also LNG imports into the U.S. Our primary objective is to develop our LNG receiving terminal development business.

 

We have assembled a team of professionals with extensive experience in the LNG industry. We have researched the LNG opportunity, developed a plan to exploit the opportunity and initiated the process of identifying and securing sites for LNG receiving terminals as well as undertaking necessary regulatory and permitting work to advance these projects. In addition, we are marketing natural gas pipelines from the proposed

 

6


Table of Contents

sites of our Corpus LNG and Sabine Pass LNG receiving terminals. Most of our resources and most of the time and attention of our employees are focused on our LNG receiving terminal development business.

 

Competition and Markets

 

In the United States, due mainly to a historically abundant supply of natural gas, LNG has not been a major energy source. Furthermore, LNG may not become a competitive factor in the U.S. oil and gas industry. Although the LNG receiving business is in its developmental stages, companies in the U.S. are, nonetheless, exploring the possibility of engaging or developing an LNG business.

 

In the event that we complete LNG receiving facilities, the profitability of our operations and the price of our gas will be dependent on the availability of liquefied natural gas, the volume and price of domestic production of natural gas, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the political conditions in international oil-producing regions, taxation and the domestic demand for natural gas.

 

Government Regulation

 

Our LNG operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and other laws. Among other matters, these laws require the acquisition of certain permits and other authorizations before commencement of construction and operation of our LNG receiving terminals.

 

Failure to comply with such laws can result in substantial penalties. This regulatory burden increases the cost of constructing and operating the LNG receiving terminals, but we do not expect such regulatory compliance matters to have a material adverse effect on our financial position or results of operations.

 

FERC

 

In order to site, construct and operate our proposed LNG receiving terminals, we must receive authorization from FERC, under Section 3 of the Natural Gas Act of 1938, or “NGA.” The FERC permitting process includes detailed engineering and design work, preparation of an Environmental Impact Statement under the National Environmental Policy Act, and public notices and opportunities for public hearings.

 

Department of Transportation/Coast Guard Regulations

 

Our LNG receiving terminals will also be subject to Department of Transportation and Coast Guard regulations relating to:

 

  siting requirements

 

  design standards

 

  construction standards

 

  equipment

 

  operations

 

  maintenance

 

  personnel qualifications and training

 

  fire protection

 

  security

 

7


Table of Contents

Environmental Matters

 

Our LNG operations are subject to various federal, state and local laws and regulations relating to the protection of the environment. In some cases, these laws and regulations require us to obtain governmental authorizations before we may conduct certain activities or may require us to limit certain activities in order to protect endangered or threatened species or sensitive areas. These environmental laws may impose substantial penalties for noncompliance and substantial liabilities for pollution. As with the industry generally, compliance with these laws increases our overall cost of business. While these laws affect our capital expenditures and earnings, we believe that these regulations do not affect our competitive position in the industry because our competitors are similarly affected by these laws. Environmental regulations have historically been subject to frequent change. Consequently, we are unable to predict the future costs or other future impacts of environmental regulations on our future operations. Environmental laws that may affect our operations include:

 

CERCLA. The federal Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” also known as the “Superfund” law, imposes liability, without regard to fault, on certain classes of persons who are considered to be responsible for the spill or release of a hazardous substance into the environment. Potentially liable persons include the owner or operator of the site where the release occurred, and persons who disposed or arranged for the disposal of hazardous substances at the site. Under CERCLA, responsible persons may be subject to joint and several liability for:

 

  the costs of cleaning up the hazardous substances that have been released into the environment;

 

  damages to natural resources; and

 

  the costs of certain health studies.

 

In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances. Although CERCLA currently excludes petroleum, natural gas, natural gas liquids, and liquefied natural gas from its definition of “hazardous substances,” this exemption may be limited or modified by Congress in the future.

 

Clean Air Act. Our operations may be subject to the federal Clean Air Act, or “CAA,” and comparable state and local laws. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have been developing regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing other air emission-related issues. We do not believe, however, that our operations will be materially adversely affected by any such requirements.

 

Clean Water Act. Our operations are also subject to the federal Clean Water Act, or “CWA,” and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. In addition, our operations, including construction of LNG receiving terminals, in areas deemed to be wetlands, or which otherwise involve discharges of dredged or fill material into navigable waters of the United States, may be subject to Army Corps of Engineers permitting requirements.

 

Solid Waste. The federal Resource Conservation and Recovery Act, or “RCRA,” and comparable state statutes govern the disposal of “hazardous wastes.” In the event any hazardous wastes are generated in connection with our LNG operations, we may be subject to regulatory requirements affecting the handling, transportation, storage and disposal of such wastes.

 

8


Table of Contents

Endangered Species. Our operations may be restricted by requirements under the Environmental Species Act, or “ESA,” which seeks to ensure that human activities do not jeopardize endangered or threatened animal, fish and plant species nor destroy or modify their critical habitats.

 

Oil and Gas Exploration and Development

 

Although our current focus is primarily on the development of an LNG receiving terminal business, we continue to be involved in oil and gas exploration, development and exploitation, and in exploitation of our existing 3D seismic database through prospect generation. We have historically focused on evaluating and generating drilling prospects using a regional and integrated approach with a large seismic database as a platform. We expect that our oil and gas exploration activities will continue in the Gulf of Mexico, through active interpretation of our seismic data and generation of prospects, through participation in the drilling of wells, and through farm-out arrangements and back-in interests (a reversionary interest in oil and gas leases reserved by us) whereby the capital costs of such activities are borne by industry partners. Our current oil and gas exploration and development activities are focused on two areas:

 

  the Cameron Project, which covers an area of approximately 230 square miles extending roughly three to five miles on either side of the westernmost 28 miles of Louisiana coastline; and

 

  the Offshore Texas Project Area, which covers approximately 6,800 square miles in the shallow waters offshore Texas and the West Cameron Area of offshore Louisiana.

 

Our officers and technical staff have extensive experience both onshore and offshore in the Gulf Coast and believe that we are well-positioned to evaluate, explore and develop properties in these areas.

 

Cameron Project Seismic Exploration Program

 

We were formed in 1996 to fund the acquisition of a proprietary seismic database along the transition zone (the area approximately 3 to 5 miles on either side of the Gulf of Mexico shore line) in Cameron Parish, Louisiana. Under the terms of an exploration agreement with an industry partner, we paid for certain seismic costs in the amount of approximately $16,500,000 and acquired a 50% ownership interest in the seismic data covering the Cameron project, among other interests that have subsequently expired or terminated. After the termination of the exploration agreement, we purchased our partner’s 50% interest in the seismic data for $500,000 and sold all of the seismic data to a seismic marketing company for $3,325,000. We now retain a license to all of the seismic data for use in our exploration program. We are also entitled to receive at no additional cost any subsequent reprocessing of the data, which may be performed by the seismic marketing company.

 

In 1999, we licensed 8,800 square miles of seismic data from Fairfield Industries (the “Offshore Louisiana Area”) and made a commitment to fund the reprocessing of the entire 8,800-square-mile seismic database. In 2000, we entered into an agreement with Warburg, Pincus Equity Partners, L.P., a global private equity fund based in New York, to fund exploration and development in the Offshore Louisiana Area through a then newly formed private corporation, Gryphon Exploration Company (“Gryphon”). See “Investment in Gryphon Exploration Company.”

 

Seismic Exploration Program in Offshore Texas Project Area

 

In 2000, we acquired two licenses to an aggregate of approximately 1,900 square miles of seismic data from Seitel Data Ltd., a division of Seitel Inc. In October 2000, we exercised our option to expand the agreement with Seitel Data Ltd. to cover an additional 1,900 square miles of seismic data. Together, the licenses acquired from Seitel represent coverage of over 433 Outer Continental Shelf blocks in the shallow waters offshore Texas and Louisiana in the Gulf of Mexico. In 2001, we sold to Gryphon for $3,500,000 one of our two licenses to the Seitel 3D seismic data. We retain one license to the Seitel 3D seismic data.

 

9


Table of Contents

In 2000, we also negotiated a Master Data Users Agreement with the Houston-based firm, Jebco Seismic L.P., to acquire 3,000 square miles (333 blocks) of seismic data in both state and federal waters offshore Texas, bringing our total data set in the shallow waters offshore Texas and Louisiana to approximately 6,800 square miles of seismic coverage. As of December 31, 2003, we had received reprocessed data for the 3,000 square miles of seismic data in the Jebco data set and the 3,800 square miles of seismic data in the Seitel data set, representing all of the reprocessing to be done in the Offshore Texas Project Area.

 

In 2001, we sold to Gryphon for $3,500,000 one of our two licenses to the Jebco 3D seismic data covering an additional 3,000 square miles. We retain one license to the Jebco 3D seismic data.

 

Our exploration team generated and captured 21 prospects during 2001, 2002 and 2003 and sold interests in 19 of the prospects to industry partners, retaining various overriding royalty interests and working interests ranging from an overriding royalty interest (a share of the hydrocarbons produced from an oil and gas property, free of the expense of production) of less than 1% to a carried working interest (an agreement whereby we retain an interest in a well but bear none or only a portion of the cost of drilling the initial well) of approximately 24%. Fifteen of the prospects sold during 2001, 2002 and 2003 have been drilled by our industry partners, and we expect that the remaining prospects sold during those years will be drilled by our industry partners during 2004, but we do not serve as operator of the wells and do not control the timing of such drilling activities.

 

Drilling Activities

 

During 2001, 2002 and 2003, we did not participate in the drilling of any wells. Eight wells, however, were drilled during 2002 and nine wells were drilled in 2003 by our industry partners on prospects that we generated. During 2002, six of the eight wells were productive, and during 2003, seven of the nine wells were productive. We currently do not have a cost-bearing interest in the wells; we hold overriding royalty interests (ranging from 0.7% to 3.7%), some of which are convertible into working interests ranging from 12.5% to 20% at payout.

 

Investment in Gryphon Exploration Company

 

Cheniere owns 100% of the outstanding common stock of Gryphon. However, after giving effect to the potential conversion of all shares of Gryphon’s convertible preferred stock to shares of Gryphon common stock, we effectively had a 9.3% ownership interest in Gryphon as of December 31, 2003. Although historically we had the ability to exercise significant influence over Gryphon because of our participation on the Gryphon board of directors, we lost the ability to exercise such influence when our representation on Gryphon’s board was reduced to one director in December 2002. As a result, effective January 1, 2003, we began accounting for our investment in Gryphon using the cost method of accounting (see Note 6 in the Notes to the Consolidated Financial Statements). Accordingly, no disclosures concerning Gryphon’s 2003 activity are included in this Form 10-K.

 

In 2000, we contributed to Gryphon the license to 8,800 square miles of seismic data that we had originally licensed from Fairfield Industries. The data covered more than 1,100 outer continental shelf blocks in the shallow waters of the Gulf of Mexico (the Offshore Louisiana Area). We also assigned our rights in our Joint Exploration Agreement with Samson, which ran from March 2000 through August 2001. For a description of licenses sold to Gryphon in 2001, see “Seismic Exploration Program in Offshore Texas Project Area.”

 

 

10


Table of Contents

Production and Sales

 

The following table presents certain information with respect to our oil and natural gas production, average sales prices received and average production costs during 2001, 2002 and 2003. In April 2002, we sold our interests in the Redfish and Stingray wells on West Cameron Block 49, representing all of our directly-owned producing properties at the time.

 

     Year Ended December 31,

     2003

   2002

   2001

Production:

                    

Oil (Bbl)

     17      495      2,608

Gas (Mcf)

     123,392      91,470      542,774

Gas equivalents (Mcfe)

     123,494      94,441      558,422

Average sales prices:

                    

Oil (per Bbl)

   $ 20.66    $ 20.03    $ 27.43

Gas (per Mcf)

   $ 5.33    $ 2.58    $ 4.48

Selected data per mcfe:

                    

Average sales price

   $ 5.32    $ 2.53    $ 4.25

Production costs(1)

     —      $ 0.95    $ 0.75

Oil and gas depreciation, depletion and amortization excluding impairments

   $ 0.98    $ 0.79    $ 1.84

(1) No production costs were recorded in 2003, as we owned non-cost bearing overriding royalty interests in wells located in offshore federal waters not subject to state production taxes.

 

Acreage and Wells

 

The following table sets forth certain information with respect to our developed and undeveloped leased acreage as of December 31, 2003.

 

    

Developed

Acres


   Undeveloped
Acres(1)


     Gross

   Net

   Gross

   Net

Louisiana

   4,995    —      5,000    5,000

Texas

   12,160    —      12,240    4,779
    
  
  
  

Total

   17,155    —      17,240    9,779
    
  
  
  

(1) We have no leases which expire in 2004.

 

At December 31, 2003, we had no working interest in any producing wells; we had overriding royalty interests in eleven wells.

 

11


Table of Contents

Oil and Gas Reserves

 

All of the information herein regarding estimates of our proved reserves, related future net revenues and PV-10 as of December 31, 2003 is taken from reports generated by Sharp Petroleum Engineering, Inc., our independent petroleum engineers, in accordance with the rules and regulations of the SEC. The independent engineers’ estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data that we provided.

 

    

December 31, 2003

Proved Reserves


     Oil (Bbl)

   Gas (Mcf)

   Mcfe

   PV-10(1)

Offshore Texas

   2,159    423,044    435,998    $ 1,734,797

Offshore Louisiana

   2,964    489,735    507,519    $ 2,542,938
    
  
  
  

Proved Reserves

   5,123    912,779    943,517    $ 4,277,735
    
  
  
  

Proved Developed Reserves

   3,024    759,095    777,239    $ 3,543,042
    
  
  
  


(1) The PV-10 amount (present value of estimated pre-tax future net revenues discounted at 10%) is calculated using year-end prices of $31.00 per barrel of oil and $5.63 per Mcf of gas.

 

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and future amounts and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of proved undeveloped reserves are inherently less certain than estimates of proved developed reserves. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, geologic success and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, our reserves may be subject to downward or upward revision based upon production history, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors. Therefore, the present value shown above should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.

 

In accordance with SEC guidelines, the estimates of future net revenues from our proved reserves and the present value thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. We may receive amounts different than the estimates for a number of reasons, including changes in prices. See Supplemental Information to Consolidated Financial Statements. Estimates of our proved oil and gas reserves were not filed with or included in reports to any other federal authority or agency other than the SEC during the fiscal year ended December 31, 2003.

 

Business Strategy

 

Our objective in the Exploration and Development business is to expand the net value of our assets by building an oil and gas reserve base in a cost-efficient manner, through exploitation of our seismic database to facilitate identifying drilling prospects.

 

Seismic Data

 

We have acquired the following two significant seismic database assets:

 

  a license to a 228-square-mile seismic program covering the transition zone in Cameron Parish, and

 

  a license to a 6,800-square-mile seismic database comprising several seismic surveys in the shallow waters offshore Texas and Louisiana.

 

12


Table of Contents

The offshore Texas database has been available previously to the industry and was processed using a technique called dip move out (“DMO”). We acquired the DMO data and underwrote the reprocessing of the data utilizing another technology known as prestack time migration (“PSTM”). Both DMO and PSTM are processing techniques which improve seismic data quality to more accurately image subsurface features and delineate hydrocarbon accumulations. Of the two techniques, PSTM is more advanced and technically accurate. The regional PSTM data is the technology tool which management believes gives us a competitive advantage.

 

Analysis and Methodology

 

We have developed a prospect generation infrastructure capable of detailed analyses of large volumes of seismic, geological and engineering data. We employ a rigorous methodology which includes:

 

  the detailed analyses of existing fields to identify geological and geophysical attributes for use as analogs,

 

  regional trend mapping to extend prolific plays into under-explored areas,

 

  the use of workstation interpretation techniques to rapidly identify prospects with attributes similar to those identified in the analog fields,

 

  the integration of seismic interpretation, well control, structure, stratigraphy, timing, sourcing factors, and production data to quantify prospect potential, and

 

  the integration of the above sciences with experience and conservative economic evaluation to focus the exploration program on highly commercial projects.

 

By conducting a thorough analysis of the data and strict adherence to the methodology, we believe that we can reduce the risk of dry holes and achieve significant growth, while maintaining a competitive cost of exploration and development.

 

Experience

 

We have built a technical and management team that is experienced in the Gulf of Mexico and in various technical specialties required for our exploration program. The technical staff averages over 30 years of experience exploring for oil and gas in the Gulf Coast. We believe that this experienced team allows us to be very productive in the generation and acquisition of prospects.

 

Competition and Markets

 

The availability of a ready market for and the price of any hydrocarbons that we produce will depend on many factors beyond our control, including the extent of domestic production and imports of foreign oil, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the political conditions in international oil-producing regions, the effect of federal and state regulation of allowable rates of production, taxation, the conduct of drilling operations and federal regulation of natural gas. In the past, as a result of excess deliverability of natural gas, many pipeline companies curtailed the amount of natural gas taken from producing wells, shut in some producing wells, significantly reduced gas taken under existing contracts, refused to make payments under applicable take-or-pay provisions and have not contracted for gas available from some newly completed wells.

 

In addition, the restructuring of the natural gas pipeline industry has eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers. Producers of natural gas, therefore, have been required to develop new markets among gas marketing companies, end-users of natural gas and local distribution companies. All of these factors, together with economic factors in the marketing area, generally may affect the supply and/or demand for oil and gas and thus the prices available for sales of oil and gas.

 

13


Table of Contents

Competition in the industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage. We compete with the major oil companies and other independent producers of varying sizes, all of which are engaged in the exploration, development and acquisition of producing and non-producing properties.

 

Government Regulation

 

Our oil and gas exploration, development and related operations are subject to extensive federal, state and local statutes, rules, regulations, and other laws. Failure to comply with such laws can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability.

 

MMS Regulations

 

We conduct certain activities on federal oil and gas leases which the Minerals Management Service, or “MMS”, administers. The MMS grants leases through competitive bidding. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to The Outer Continental Shelf Lands Act (“OCSLA”). For example, for offshore operations, we must comply with the following MMS requirements:

 

  obtain MMS approval of exploration plans prior to the commencement of exploration operations;

 

  obtain MMS approval of development and production plans prior to the commencement of such operations;

 

  obtain an MMS permit prior to the commencement of drilling (in addition to permits which may be required from other agencies, such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency);

 

  comply with stringent MMS engineering and construction specifications applicable to offshore production facilities located on the Outer Continental Shelf (“OCS”);

 

  comply with MMS prohibitions or restrictions on the flaring or venting of natural gas, liquid hydrocarbons and oil; and

 

  comply with MMS regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities.

 

Bonding and Financial Responsibility Requirements

 

In connection with our ownership or operation of oil and gas leases, we are required by governmental agencies, including the MMS, to obtain bonding or otherwise demonstrate financial responsibility at varying levels. These bonds may cover such obligations as plugging and abandonment of wells, removal and closure of related exploration and production facilities, and pollution liabilities. The costs of such bonding and financial responsibility requirements can be substantial, and we may not be able to obtain such bonds and/or otherwise demonstrate financial responsibility in all cases.

 

Regulation of Production

 

Our oil and gas production operations are subject to state conservation laws and regulations, including:

 

  laws relating to the unitization or pooling of oil and gas properties;

 

  laws establishing the maximum rates of production from wells;

 

  laws regulating the spacing of wells;

 

14


Table of Contents
  laws regulating the plugging and abandonment of wells; and

 

  laws which otherwise regulate the operation of, and production from, both oil and gas wells.

 

Such laws may restrict the rate at which the wells in which we have an interest may produce oil or gas, with the result that the amount or timing of our revenues could be adversely affected.

 

Natural Gas Marketing

 

FERC regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the NGA and the NGPA. Sales of our gas are currently not regulated and are made at market prices. However, in the past, the federal government has regulated the prices at which natural gas could be sold, and Congress could reenact price controls in the future.

 

Environmental Matters

 

Our oil and gas exploration, development and related operations are subject to the same federal, state and local laws and regulations relating to the protection of the environment that are applicable to our LNG operations. See “LNG Receiving Terminal Development—Government Regulation—Environmental Matters.” In addition, our oil and gas exploration, development and related operations are subject to the following:

 

NORM. The disposal of wastes containing Naturally Occurring Radioactive Material, which are commonly generated during oil and gas production, is regulated under state law. Typically, wastes containing naturally occurring radioactive material can be managed on site or disposed of at facilities licensed to receive such waste at costs that are not expected to be material.

 

Oil Pollution Act. The federal Oil Pollution Act (“OPA”) requires owners and operators of facilities that could be the source of an oil spill into waters of the United States (a term defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any such oil spill. OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay the costs of cleaning up an oil spill and to compensate any parties damaged by an oil spill. Such financial assurances may be increased to as much as $150 million if a formal assessment indicates such an increase is warranted.

 

Financial Information about Segments

 

During the last three fiscal years, all of our revenues have resulted from our oil and gas exploration and development activities. For information about our segments’ revenues, profits and losses and total assets, see Note 16 in Notes to Consolidated Financial Statements.

 

Subsidiaries

 

A substantial portion of our assets are held by or under our four wholly-owned operating subsidiaries: Cheniere LNG, Inc., Cheniere LNG Services, Inc., Cheniere Energy Operating Co., Inc. and Cheniere-Gryphon Management, Inc. We conduct most of our operations through one or more of these subsidiaries, including our operations relating to our development of an LNG receiving terminal business.

 

Employees

 

We had 32 full-time employees as of February 27, 2004.

 

15


Table of Contents

RISK FACTORS

 

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. These important factors are not exclusive.

 

Risk Factors Related to Us as an Early Stage Company

 

We are subject to the expenses, difficulties and uncertainties generally associated with early stage companies.

 

We have a limited operating history with respect to our oil and gas exploration activities, and we have not yet started operating any LNG receiving facilities. We face all of the risks inherent in the establishment and growth of any new business. From our inception, we have incurred losses and may continue to incur losses, depending on whether we generate sufficient revenue either from LNG receiving operations or from producing reserves acquired through acquisitions or drilling activities. For the past several years, we dedicated a significant portion of our investment capital toward the development of LNG receiving terminals rather than to our oil and gas exploration activities, and we do not anticipate that our LNG receiving operations will generate revenues before the second half of 2007. Additionally, we may be unable to implement and complete our business plan, and our business may be ultimately unsuccessful. These factors make evaluating our business and forecasting our future operating results difficult. Furthermore, any continued losses and any delays in the implementation or completion of our business plan may have a material adverse effect on our business, our results of operations, our financial condition and the market price of our common stock.

 

We depend on key personnel and could be seriously harmed if we lost their services.

 

We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have agreements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could seriously harm us. In addition, our future success will depend in part on our ability to attract and retain additional qualified personnel.

 

Risk Factors Related to Our LNG Receiving Terminal Development Business

 

The construction of LNG receiving facilities is subject to various development risks.

 

We are involved in the development of several LNG receiving facilities. The construction of these projects is subject to the risks of cost overruns and delays. Key factors that may affect the timing and outcome of such projects include, but are not limited to: project approval by joint venture partners; identification of additional participants to reach optimum levels of participation; timely issuance of necessary permits, licenses and approvals by governmental agencies and third parties; sufficient project financing; unanticipated changes in market demand or supply; competition with similar projects; labor disputes; site difficulties; marine congestion; weather conditions; unforeseen events, such as explosions, fires and product spills; delays in manufacturing and delivery schedules of critical equipment and materials; resistance in the local community; local and general economic conditions; and commercial arrangements for pipelines and related equipment to transport and market LNG.

 

If completion of the LNG receiving facilities is delayed beyond the estimated development periods, the actual cost of completion may increase beyond the amounts currently estimated in our capital budget. A delay in completion of the LNG receiving facilities would also cause a delay in the receipt of revenues projected from operation of the facilities, which may cause our business, results of operations and financial condition to be substantially harmed. The completion of the LNG receiving facilities could also be impacted by the availability or construction of sufficient LNG vessels.

 

16


Table of Contents

Failure to obtain approvals and permits from governmental and regulatory agencies with respect to the development of our LNG receiving terminal business could have a detrimental effect on our LNG projects and on our company.

 

We are currently focusing our efforts and resources on developing our LNG receiving facilities. The transportation of LNG is highly regulated, and we have yet to obtain several governmental and regulatory approvals and permits required in order to complete and maintain our LNG projects. We cannot determine the amount of time it may take to obtain the approvals and permits necessary to proceed with the construction and operation of an LNG receiving terminal. We have no control over the outcome of the review and approval process. If we are unable to obtain the approvals and permits, we may not be able to recover our investment in the project. In addition, failure to obtain these approvals and permits may have a material adverse effect on our business, results of operations and financial condition.

 

Failure of LNG to become a competitive factor in the U.S. oil and gas industry could have a detrimental effect on our ability to implement and complete our business plan.

 

In the United States, due mainly to an abundant supply of natural gas, LNG has not historically been a major energy source. Furthermore, LNG may not become a competitive factor in the U.S. oil and gas industry. The failure of LNG to become a competitive supply alternative to domestic natural gas and other import alternatives may have a material adverse effect on our ability to implement and complete our business plan as well as our business, results of operations and financial condition.

 

We may have difficulty obtaining enough customers to generate a sufficient amount of revenue to recover our expenses incurred to enter the LNG receiving facilities market.

 

We anticipate that we will incur significant costs as we enter the LNG receiving facilities market and pursue customers by utilizing a variety of marketing methods. In order for us to recover these expenses, we must attract and retain a sufficient number of customers to our LNG receiving facilities.

 

We may experience difficulty attracting customers because we are a small company with no operating history in the LNG business. A major focus of our marketing efforts will be to convince customers that the terminal sites we are developing will be approved and that we will secure adequate financing for their construction. If our marketing strategy is not successful, our business, results of operations, and financial condition will be materially adversely affected.

 

We are subject to fluctuations in energy prices or the supply of LNG that would be particularly harmful to the development of our LNG receiving terminal business because of its developmental stage.

 

If LNG prices are higher than prices of domestically produced natural gas or natural gas derived from other sources, our ability to compete with such suppliers 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 receiving facility could be materially impacted. Revenues generated by an LNG receiving 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.

 

Risk Factors Related to Our Exploration and Development Business

 

We are subject to significant exploration risks, including the risk that we may not be able to find or produce enough oil and gas to generate any profits.

 

Our exploration activities involve significant risks, including the risk that we may not be able to find or produce enough oil and gas to generate any profits. The wells we drill may not discover any oil or gas. Further,

 

17


Table of Contents

there is no way to know in advance of drilling and testing whether any prospect will yield oil or gas in sufficient quantities to make money for us. In addition, we are highly dependent on seismic activity and the related application of new technology as a primary exploration methodology. This methodology, however, requires greater pre-drilling expenditures than traditional drilling strategies. Even when fully used and properly interpreted, 3D seismic data can only assist us in identifying subsurface reservoirs and hydrocarbon indicators, and will not allow us to determine conclusively if hydrocarbons will in fact be present and recoverable. If our exploration efforts are unsuccessful, our business, results of operations and financial condition will be substantially harmed.

 

We may not be able to acquire the oil and gas leases we need to sustain profitable operations.

 

In order to engage in oil and gas exploration in the areas covered by our 3D seismic data, we must first acquire rights to conduct exploration and recovery activities on such properties. We may not be successful in acquiring farm-outs (agreements whereby the owner of lease interests grants to a third party the right to earn an assignment of an interest in the lease, typically by drilling one or more wells), seismic permits, lease options, leases or other rights to explore for or recover oil and gas. Both the U.S. Department of the Interior and the States of Texas and Louisiana award oil and gas leases on a competitive bidding basis. Non-governmental owners of the onshore mineral interests within the area covered by our exploration program are not obligated to lease their mineral rights to us except where we have already obtained lease options. In addition, other major and independent oil and gas companies with financial resources significantly greater than ours may bid against us for the purchase of oil and gas leases. If we are unsuccessful in acquiring these leases, permits, options and other interests, the area covered by our 3D seismic data that could be explored through drilling will be significantly reduced, and our business, results of operations and financial condition will be substantially harmed.

 

If we are unable to obtain satisfactory turnkey contracts, we may have to assume additional risks and expenses when drilling wells.

 

We anticipate that any wells drilled in which we have an interest will be drilled by established industry contractors under turnkey contracts that limit our financial and legal exposure. Under a turnkey drilling contract, a negotiated price is agreed upon and the money placed in escrow. The contractor then assumes all of the risk and expense, including any cost overruns, of drilling a well to contract depth and completing any agreed upon evaluation of the wellbore. Upon performance of all these items, the escrowed money is released to the contractor.

 

Circumstances may arise, however, where a turnkey contract is not economically beneficial to us or is otherwise unobtainable from proven industry contractors. In such instances, we may decide to drill wells on a day-rate basis. Under a day-rate drilling contract, the operator pays an agreed sum for each day of drilling required to reach contract depth. All risk and expense of drilling a well to total depths lies with the operator in day-rate contracts. The drilling of such test wells would subject us to the usual drilling hazards such as cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. We would also be liable for any cost overruns attributable to drilling problems that otherwise would have been covered by a turnkey contract. These liabilities, if incurred, may have a materially adverse impact on our business, results of operations and financial condition.

 

If we are unsuccessful at marketing our oil and gas at commercially acceptable prices, our profitability will decline.

 

Our ability to market oil and gas at commercially acceptable prices depends on, among other factors, the following:

 

  the availability and capacity of gathering systems and pipelines;

 

  federal and state regulation of production and transportation;

 

18


Table of Contents
  changes in supply and demand; and

 

  general economic conditions.

 

Our inability to respond appropriately to changes in these factors could negatively effect our profitability.

 

Shortage of rigs, equipment, supplies or personnel may restrict our operations.

 

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rises with increases in the number of active rigs in service. Shortages of drilling rigs, equipment or supplies could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

 

We depend on industry partners and could be seriously harmed if they do not perform satisfactorily, which is usually not within our control.

 

Because we have few employees and limited operating revenues, we are and will continue to be largely dependent on industry partners for the success of our oil and gas exploration projects. We could be seriously harmed if we fail to attract industry partners to participate in the drilling of prospects which we identify or if our industry partners do not perform satisfactorily on projects that affect us. We often have and will continue to have no control over factors that would influence the performance of our partners.

 

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future net cash flows.

 

Numerous uncertainties, including those beyond our control, are inherent in estimating quantities of proved oil and gas reserves. Information included herein for 2003 relating to estimates of our proved reserves is based on reports prepared by Sharp Petroleum Engineering, Inc. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows may vary considerably from the actual results because of a number of variable factors and assumptions involved. These include:

 

  historical production from the area compared with production from other producing areas;

 

  the effects of regulation by governmental agencies;

 

  future oil and gas prices;

 

  operating costs;

 

  severance and excise taxes;

 

  development costs; and

 

  workover and remedial costs.

 

Therefore, the estimates of the quantities of oil and gas and the expected future net cash flows computed by different engineers or by the same engineers (but at different times) may vary significantly. The actual production, revenues and expenditures related to our reserves may vary materially from the engineers’ estimates. In addition, we may make changes to our estimates of reserves and future net cash flows. These changes may be based on the following factors:

 

  production history;

 

  results of future development;

 

19


Table of Contents
  oil and gas prices;

 

  performance of counterparties under agreements to which we are a party; and

 

  operating and development costs.

 

Do not interpret the PV-10 values included in this Form 10-K as the current market value of our properties’ estimated oil and gas reserves. According to the SEC, the PV-10 is generally based on prices and costs as of the date of the estimate. In contrast, the actual future prices and costs may be materially higher or lower. Actual future net cash flows may also be affected by the following factors:

 

  the amount and timing of actual production;

 

  the supply of, and demand for, oil and gas;

 

  the curtailment or increases in consumption by natural gas purchasers; and

 

  the changes in governmental regulations or taxation.

 

The timing in producing and the costs incurred in developing and producing oil and gas will affect the timing of actual future net cash flows from proved reserves. Ultimately, the timing will affect the actual present value of oil and gas. In addition, the SEC requires that we apply a 10% discount factor in calculating PV-10 for reporting purposes. This is not necessarily the most appropriate discount factor to apply because it does not take into account the interest rates in effect, the risks associated with us and our properties, or the oil and gas industry in general.

 

Because of our lack of diversification, factors harming the oil and gas industry in general, including downturns in prices for oil and gas, would be especially harmful to us.

 

We are an independent energy company and are not actively engaged in any other industry. Our revenues and results of operation are substantially dependent on the oil and gas industry in general and the prevailing prices for oil and gas in particular. Circumstances that harm the oil and gas industry in general will have an especially harmful effect on us. Oil and gas prices have been and are likely to continue to be volatile and subject to wide fluctuations in response to any of the following factors:

 

  relatively minor changes in the supply of and demand for oil and gas;

 

  political conditions in international oil producing regions;

 

  the extent of domestic production and importation of oil in relevant markets;

 

  the level of consumer demand;

 

  weather conditions;

 

  the competitive position of oil or gas as a source of energy as compared with other energy sources;

 

  the refining capacity of oil purchasers; and

 

  the effect of federal and state regulation on the production, transportation and sale of oil and gas.

 

It is likely that adverse changes in the oil and gas market or the regulatory environment would have an adverse effect on our business, results of operations and financial condition, including our ability to develop and implement our LNG project and to obtain capital from lending institutions, industry participants, private or public investors or other sources.

 

20


Table of Contents

Risk Factors Related to Our Business in General

 

Our future growth and profitability are highly dependent on the development of our LNG receiving terminal business and the success of our exploration program.

 

Historically, the primary focus of our operations has been identifying drilling prospects, but in recent years we have focused on developing our LNG receiving facilities. Almost all of the assets on our balance sheet are represented by investments to date in our exploration program, including related seismic data. Our drilling activity in 1999 through 2003, to date, has established only limited proved reserves (oil and gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions). Furthermore, we have achieved only limited oil and gas production as of December 31, 2003. For the past several years, we dedicated a significant portion of our investment capital toward the development of LNG receiving terminals rather than to our oil and gas exploration activities, and we do not anticipate that our LNG receiving operations will generate operating revenues before 2007.

 

Our future growth and profitability depend heavily on the development of our LNG receiving facilities and the success of our exploration program in locating additional proved reserves and achieving additional oil and gas production. Failure to develop our LNG receiving facilities or to locate such additional reserves and achieve additional production may have a material adverse effect on our business, results of operations and financial condition.

 

We experience intense competition in the energy industry, which may make it difficult for us to succeed.

 

The energy industry is highly competitive. If we are unable to compete effectively, we will not succeed. A number of factors may give our competitors advantages over us. For example, most of our current and potential competitors have significantly greater financial resources and a significantly greater number of experienced and trained managerial and technical personnel than we do. In addition, the businesses of such competitors are in many cases more diversified than ours. We may not be able to compete effectively with such companies. Moreover, the energy industry competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers. Increased competition causing excess capacity and depressed prices could have a substantially negative impact on our operating revenues.

 

We may not be able to obtain additional financing on terms that are acceptable to us, which could harm our ability to conduct business.

 

As of December 31, 2003, we had $4,487,352 of current assets and working capital of $155,526. In January 2004, we received net proceeds of $13,884,750 from a private placement of 1,100,000 shares of our common stock, and we also received the remaining $2,500,000 from Freeport LNG, which was payable pursuant to the sale of our 60% interest in the Freeport LNG project. In January and February 2004, we received net proceeds of $1,309,559 related to the issuance of 557,056 shares of common stock pursuant to exercises of warrants and stock options. We may need additional capital for a number of purposes. If we are unable to obtain additional financing, it could significantly harm our ability to conduct our business, including our ability to construct LNG terminals and our ability to take advantage of opportunities that come from our exploration program. We will need substantial additional funds to execute our plan for developing and implementing an LNG receiving terminal business, including engineering, environmental, marine, regulatory, construction and legal work, including any such work involved in permitting and Federal Energy Regulatory Commission, or FERC, filings related to our development of the Corpus Christi and Sabine Pass LNG receiving terminals and related pipelines.

 

21


Table of Contents

Obtaining additional capital may result in an adverse effect on our business.

 

Additional capital could be obtained from a combination of funding sources, many of which may have a material adverse effect on our business, results of operations and financial condition. These potential funding sources include:

 

  cash flow from operating activities, which is sensitive to prices we receive for our oil and natural gas;

 

  borrowings from financial institutions, which may subject us to certain restrictive covenants, including covenants restricting our ability to raise additional capital or pay dividends;

 

  debt offerings, which would increase our leverage and add to our need for cash to service such debt;

 

  additional offerings of our equity securities, which would cause dilution of our common stock;

 

  sales of prospects generated by our exploration group, which would reduce future revenues from our exploration program;

 

  additional sales of interests in our LNG projects, which would reduce future revenues from LNG terminal operations; and

 

  arrangement of a business development loan from, or prepayment of terminal use fees by, prospective sellers or purchasers of LNG.

 

Our ability to raise additional capital will depend on our results of operations and the status of various capital and industry markets at the time such additional capital is sought. Accordingly, capital may not become available to us from any particular source or at all. Even if additional capital becomes available, it may not be on terms acceptable to us. Failure to obtain additional financing on acceptable terms may have a material adverse effect on our business, results of operations and financial condition.

 

We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.

 

Our oil and gas operations are subject to all of the risks and hazards typically associated with the exploration for, and the development and production of, oil and gas. In accordance with customary industry practices, we intend to maintain insurance against some, but not all, of these risks and losses. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could seriously harm our business, results of operations and financial condition.

 

Risks in drilling operations include cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. Our activities are also subject to perils specific to marine operations, such as capsizing, collision and damage or loss from severe weather. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.

 

In the event we complete the LNG receiving terminal, the operations of such facility will be subject to the inherent risks normally associated with those operations, including explosions, pollution, release of toxic substances, fires, hurricanes and 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. In addition, our operations face possible risks associated with acts of aggression on our assets. If any of these events were to occur, we could suffer substantial losses. We will maintain insurance against these types of risks to the extent and in the amounts that we believe are reasonable. Our financial condition and results of operations could be adversely affected if a significant event occurs that is not fully covered by insurance.

 

22


Table of Contents

Existing and future U.S. governmental regulation, taxation and price controls could seriously harm us.

 

Oil and gas operations are subject to extensive federal, state and local laws and regulations that regulate the discharge of materials into the environment or otherwise relate to the protection of the environment.

 

Failure to comply with such rules and regulations can result in substantial penalties and may harm us. Present, as well as future, legislation and regulations could cause additional expenditures, restrictions and delays in our business, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. In most areas where we plan to conduct activities, there are statutory provisions regulating the production of oil and natural gas which may restrict the rate of production and adversely affect revenues. We plan to acquire oil and gas leases in the Gulf of Mexico, which, if acquired, would be granted by the federal government and administered by the U.S. Department of Interior Minerals Management Service. This department strictly regulates the exploration, development and production of oil and gas reserves in the Gulf of Mexico. Such regulations could seriously harm our operations in the Gulf of Mexico. The federal government regulates the interstate transportation of oil and natural gas, through the Federal Energy Regulatory Commission, or FERC. The FERC has in the past regulated the prices at which oil and gas could be sold. Federal reenactment of price controls or increased regulation of the transport of oil and natural gas could seriously harm us.

 

Our operations are also subject to extensive federal, state and local laws and regulations governing the discharge of oil and hazardous materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment or wastes that can be disposed of in connection with drilling and production activities, prohibit drilling activities on certain lands lying within wetlands or other protected areas and impose substantial liabilities for pollution or releases of hazardous substances resulting from drilling and production operations. Failure to comply with these laws and regulations may also result in civil and criminal fines and penalties. Moreover, state and federal environmental laws and regulations may become more stringent.

 

Federal laws and regulations such as the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Clean Air Act, or CAA, the Oil Pollution Act of 1990, or OPA, and the Clean Water Act, or CWA, and analogous state laws have continually imposed increasingly strict requirements for water and air pollution control, solid waste management and strict financial responsibility and remedial response obligations relating to oil spill protection. The cost of complying with such environmental legislation could have a general harmful effect on our operations.

 

In addition, the U.S. Department of Transportation through its Office of Pipeline Safety has regulations that govern all aspects of the design, construction, operation and maintenance of pipeline and LNG facilities. While these regulations have existed for several years, they are undergoing extensive changes to fully implement the 2002 amendment to the Natural Gas Pipeline Safety Act. These new regulations are expected to be published in early 2004 and will focus primarily on ensuring the integrity of pipeline systems by requiring periodic inspection of pipeline facilities and repair of any defects discovered in the inspection process. We anticipate that the new rules will result in changes in the way we evaluate and document our pipeline integrity process. However, until the regulations are finalized, we will not know the exact nature of the new requirements nor can we estimate additional compliance costs, if any.

 

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 that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from insurance or our customers, could have a material adverse effect on our business, financial condition or results of operations.

 

23


Table of Contents

Some of our economic value is derived from our ownership interest in Gryphon, over which we exercise no day to day control.

 

We own 100% of the outstanding common stock of Gryphon (9.3% effective ownership after giving effect to the potential conversion of Gryphon’s preferred stock) and some of our value is derived from this investment. We do not exercise control over Gryphon and therefore do not have the ability to effect a change of control to Gryphon. Accordingly, Gryphon’s management team could make business decisions without our consent that could impair the economic value of our investment in Gryphon.

 

We may have to take actions that are disruptive to our business strategy to avoid registration under the Investment Company Act of 1940.

 

The Investment Company Act of 1940, or Investment Company Act, requires registration for companies that are engaged primarily in the business of investing, reinvesting, owning, holding or trading in securities. A company may be deemed to be an investment company if it owns investment securities with a value exceeding 40% of the value of its total assets (excluding government securities and cash items) on an unconsolidated basis, unless an exemption or safe harbor applies. Securities issued by companies other than majority-owned subsidiaries are generally counted as investment securities for purposes of the Investment Company Act. We own a minority equity interest in certain entities that could be counted as investment securities. If the value of our minority interests in these entities exceeds 40% of the value of our total assets (excluding government securities and cash items), we could be considered an investment company in the future if we do not obtain an exemption or qualify for a safe harbor. As a result, fluctuations in the value, or the income and revenues attributable to us from our ownership of interests in companies we do not control could cause us to be deemed an investment company. Registration as an investment company would subject us to restrictions that are inconsistent with our fundamental business strategy. We may have to take actions, including buying, refraining from buying, selling or refraining from selling securities or other assets, contrary to what we would otherwise deem to be in our best interest in order to continue to avoid registration under the Investment Company Act.

 

Terrorist attacks and continued hostilities in the Middle East or other 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 economic and political uncertainties, some of which may materially adversely impact our business. The long-term impact that terrorist attacks and the threat of terrorist attacks may have on our business is not known at this time. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may adversely impact our business in unpredictable ways.

 

The concentration of our customers in the energy industry could increase our exposure to credit risk, which could result in losses.

 

The concentration of our customers in the energy industry may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by prolonged changes in economic and industry conditions. We perform ongoing credit evaluations of our customers and do not generally require collateral in support of our trade receivables. We maintain reserves for credit losses and, generally, actual losses have been consistent with our expectations.

 

Item 3. LEGAL PROCEEDINGS

 

We have been, and may in the future be, involved as a party to various legal proceedings, which are incidental to the ordinary course of business. Management regularly analyzes current information and as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. In the opinion of

 

24


Table of Contents

management and legal counsel, as of December 31, 2003, there were no threatened or pending legal matters that would have a material adverse impact on our consolidated results of operations, financial position or cash flows.

 

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

None.

 

PART II

 

Item 5. MARKET PRICE FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Our Stock has traded on the American Stock Exchange under the symbol LNG since March 24, 2003. Our common stock had previously traded on the American Stock Exchange under the symbol CXY from March 5, 2001 through March 23, 2003. The table below presents the high and low daily closing sales prices of the common stock, as reported by the American Stock Exchange, for each quarter during 2002 and 2003.

 

     High

   Low

Three Months Ended

         

March 31, 2002

   1.50    0.93

June 30, 2002

   1.50    0.82

September 30, 2002

   1.30    0.90

December 31, 2002

   1.35    0.80

Three Months Ended

         

March 31, 2003

   1.60    1.20

June 30, 2003

   5.10    1.39

September 30, 2003

   6.03    4.29

December 31, 2003

   11.90    5.05

 

As of February 29, 2004, we had 18,659,994 shares of common stock outstanding held by approximately 4,200 beneficial owners.

 

We have never paid a cash dividend on our common stock. We currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying any cash dividends on the common stock in the foreseeable future. Any future change in our dividend policy will be made at the discretion of our board of directors in light of our financial condition, capital requirements, earnings, prospects, and any restrictions under any credit agreements, as well as other factors the board of directors deems relevant.

 

25


Table of Contents

Item 6. SELECTED FINANCIAL DATA

 

Selected financial data set forth below are derived from our audited Consolidated Financial Statements for the periods indicated. The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and Notes thereto included elsewhere in this report.

 

     Year Ended December 31,

 
     2003

    2002

    2001

    2000

    1999

 

Revenues

   $ 657,467     $ 239,055     $ 2,372,632     $ 5,320,432     $ 1,614,055  

Production costs

     —         90,038       420,242       388,637       128,859  

Depreciation, depletion and amortization

     428,680       368,562       1,243,828       3,371,383       1,361,644  

Ceiling test write-down

     —         —         5,126,248       —         —    

General and administrative expenses

                                        

LNG Terminal Development(1)

     6,704,538       1,556,782       1,788,419       343,572       —    

Other

     2,542,399       1,918,580       2,503,544       1,595,087       1,908,805  

Loss from operations

     (9,018,150 )     (3,694,907 )     (8,709,649 )     (378,247 )     (1,785,253 )

Interest income

     2,740       7,733       18,578       23,916       31,530  

Equity in net loss of affiliate(2)

     —         (2,184,847 )     (2,974,191 )     (426,649 )     —    

Equity in net loss of limited partnership(3)

     (4,471,529 )     —         —         —         —    

Gain on sale of properties

     —         340,257       —         —         —    

Gain on sale of LNG assets

     4,760,000       —         —         —         —    

Gain on sale of limited partnership interest

     423,454       —         —         —         —    

Minority Interest(4)

     3,015,468       —         —         —         —    

Loss on extinguishment of debt

     —         (100,544 )     —         —         —    

Net loss

     (5,288,017 )     (5,632,308 )     (11,665,262 )     (780,980 )     (1,753,723 )

Net loss per share (basic and diluted)(5)

     (0.36 )     (0.42 )     (0.89 )     (0.07 )     (0.27 )

Weighted average shares outstanding (basic and diluted)(5)

     14,771,700       13,297,393       13,035,256       10,732,678       6,449,104  
     December 31,

 
     2003

    2002

    2001

    2000

    1999

 

Cash

   $ 1,257,693     $ 590,039     $ 610,718     $ 1,888,562     $ 1,175,950  

Working Capital

     155,526       (1,413,235 )     (530,242 )     1,234,390       (3,290,245 )

Oil and gas properties, proved, net

     1,087,152       842,882       1,929,124       6,727,613       9,459,041  

Oil and gas properties, unproved

     18,047,802       16,751,347       16,236,962       18,253,731       20,648,923  

Total assets

     24,590,757       21,059,390       25,023,676       34,665,618       34,481,275  

Total liabilities

     5,331,826       3,262,055       1,874,401       1,604,410       6,735,537  

Total stockholders’ equity

     19,138,899       17,797,335       23,149,275       33,061,208       27,745,738  

(1) The year ended 2002 includes $1,740,426 in recoveries of general and administrative expenses reimbursable under the term of an agreement related to our sale of the Freeport LNG site, which closed in February 2003. See Note 7 to our Consolidated Financial Statements.
(2) Effective January 1, 2003, we began accounting for this investment in Gryphon using the cost method of accounting. The amounts listed for 2002, 2001 and 2000 represent our equity in the net loss of Gryphon under the equity method of accounting. See Note 6 to our Consolidated Financial Statements.
(3) Represents our equity in the net loss of Freeport LNG. See Note 7 to our Consolidated Financial Statements.

 

26


Table of Contents
(4) Represents minority interest in the net loss of Corpus Christi LNG. See Note 8 to our Consolidated Financial Statements.
(5) Net loss per share and weighted average shares outstanding have been restated to give effect to the one-for-four reverse stock split which was effective in October 2000.

 

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

General

 

We are engaged primarily in the development of a liquefied natural gas, or LNG, receiving terminal business and related LNG business opportunities centered on the U.S. Gulf Coast. The LNG receiving terminal business consists of receiving deliveries of LNG from LNG ships, processing such LNG to return it to a gaseous state and delivering it to pipelines for transportation to purchasers. We are also engaged in oil and gas exploration, development and exploitation activities in the Gulf of Mexico.

 

Results of Operations—Comparison of the Fiscal Years Ended December 31, 2003 and 2002

 

Overview—Our financial results for the year ended December 31, 2003 reflect a loss of $5,288,017, or $0.36 per share (basic and diluted), compared to a loss of $5,632,308 or $0.42 per share (basic and diluted) in 2002. The major factors contributing to our loss in 2003 were: LNG receiving terminal development expenses of $6,704,538 (which were offset by a $3,015,468 minority interest in the operations of our Corpus Christi LNG partnership), our equity share of the loss in the Freeport LNG limited partnership of $4,471,529 and other general and administrative expenses of $2,542,399. These factors are offset by a $4,760,000 gain on the sale of LNG assets and a $423,454 gain on the sale of a limited partnership interest in the Freeport LNG terminal.

 

LNG Terminal Development Activities—Our principal focus in both 2003 and 2002 was the development of LNG receiving terminals. As a result, terminal development expenses represented a major part of our operating costs and expenses for both years. In 2003, we phased out our direct involvement in developing the Freeport, Texas, site, but we accelerated the schedule of terminal development at two new sites located near Sabine Pass, Louisiana, and near Corpus Christi, Texas. Accordingly, gross terminal development expenses, before any cost recoveries, were 103% higher in 2003 ($6,704,538) than in 2002 ($3,297,208).

 

In 2003, we formed a limited partnership to develop the Corpus Christi LNG terminal. We are the general partner, and we own a 67% limited partner interest. We recorded $3,015,468 in terminal development expenses related to this site in 2003; however, this amount was completely offset by the minority interest of our 33% partner who provided funding for all development costs in 2003. The remainder of our 2003 terminal development expenses related to the Sabine Pass site, where we own 100% of the project.

 

In 2002, we incurred $3,297,208 in terminal development expenses for the Freeport LNG terminal. We entered into an agreement in August 2002 to sell a 60% interest in the terminal in exchange for payments to us totaling $5,000,000 over time and payments to others of up to $9,000,000 for expenses, which were already incurred or are to be incurred in connection with the development of the Freeport LNG terminal. During 2002, $1,740,426 in such development expenses were charged to the purchaser. This recovery reduced our terminal development expenses reported for 2002 to $1,556,782.

 

In February 2003, our Freeport LNG terminal project was acquired by Freeport LNG in which we received a 40% limited partnership interest in addition to the consideration described above. In connection with the sale of LNG assets to Freeport LNG, we reported a gain of $4,760,000. Furthermore, we sold a 10% interest in Freeport LNG in March 2003 for $2,333,333, resulting in a gain of $423,454. Throughout 2003, we received payments totaling $2,500,000 from Freeport LNG, which amounts were recorded as a reduction to our investment in the partnership. In addition, our 30% limited partner interest in the operations of Freeport LNG resulted in our

 

27


Table of Contents

recording equity in the net loss of the partnership of $4,471,529 for 2003. This non-cash loss reduced our investment in Freeport LNG to zero.

 

Other General and Administrative Expenses—Other general and administrative (“G&A”) expenses relate to our general corporate and other activities. These expenses increased $623,819, or 33%, to $2,542,399 in 2003 compared to $1,918,580 in 2002. The principal components of G&A are employee compensation and contracted services, legal fees and travel. We expanded our staff from 13 to 17 throughout 2003 as we expanded our business. We incurred more legal expenses in connection with securities compliance filings and increased securities registration costs. We traveled more as we increased our profile among the investment community and as we developed an LNG trading venture based in Europe.

 

Oil and Gas Activities—Oil and gas revenues increased by $418,412, or 175%, to $657,467 in 2003 from $239,055 in 2002 as a result of increased production volumes (123,494 Mcfe in 2003 compared with 94,441 Mcfe in 2002) and increased average natural gas prices of $5.33 per Mcf in 2003 from $2.58 per Mcf in 2002. We had production from 11 wells in 2003 as compared with six wells in 2002. We incurred no production costs in 2003 because all of our revenues were generated from non-cost bearing overriding royalty interests. Production costs in 2002 totaled $90,038 and related to the early months of 2002 before we sold our cost-bearing working interests in oil and gas properties.

 

Equity in Net Loss of Unconsolidated Affiliate—On January 1, 2003, we began accounting for our interest in Gryphon on the cost method of accounting because we no longer had sufficient board representation to provide us with the opportunity to exert significant influence over the financial and operating policies of the company. In 2002, we accounted for our investment using the equity method of accounting, and our equity share of Gryphon’s losses was $2,184,847.

 

Results of Operations—Comparison of the Fiscal Years Ended December 31, 2002 and 2001

 

Overview—Our financial results for the year ended December 31, 2002 reflect a loss of $5,632,308, or $0.42 per share (basic and diluted), compared to a loss of $11,665,262 or $0.89 per share (basic and diluted) in 2001. The major factors contributing to our loss in 2002 were: LNG terminal development expenses of $3,297,208 (offset by cost recoveries of $1,740,426) for a net cost of $1,556,782, other general and administrative expenses of $1,918,580, and equity in loss of unconsolidated affiliate of $2,184,847.

 

LNG Terminal Development Activities—Throughout 2002 and 2001, our operations were primarily focused on the development of a potential LNG terminal site near Freeport, Texas. Gross terminal development expenses, before any cost recoveries, incurred in 2002 ($3,297,208) were 84% higher than in 2001 ($1,788,419). The increased level of expenditures relates principally to the advancing stages of the project and the acceleration of work leading to the filing of an application with FERC in March 2003.

 

In August 2002, we entered into an agreement to sell a 60% interest in the Freeport LNG terminal in exchange for payments to us totaling $5,000,000 and additional payments of up to $9,000,000 for expenses which were already incurred or to be incurred later in connection with the development of the Freeport LNG terminal. During 2002, $1,740,426 in such development expenses were charged to the purchaser. This recovery reduced our terminal development expenses reported for 2002 to $1,556,782.

 

Oil and Gas Activities—Oil and gas revenues decreased to $239,055 in 2002 from $2,372,632 in 2001 as a result of decreased production volumes (94,441 Mcfe in 2002 compared with 558,422 Mcfe in 2001). The decline in production volumes primarily results from the sale of our two producing wells at West Cameron Block 49 in April 2002. Adding to the effect of declining production was a decrease in average gas prices to $2.58 per Mcf in 2002 compared to $4.48 per Mcf in the prior year. Production costs decreased 79% to $90,038 in 2002 from $420,242 in 2001.

 

28


Table of Contents

Depreciation, depletion and amortization (“DD&A”) decreased to $368,562 in 2002 from $1,243,828 in 2001 as a result of both the decline in our production volumes, described above, and a lower DD&A rate per unit ($0.79 per Mcfe versus $1.84 per Mcfe). Our DD&A rate declined due to our change in emphasis toward selling prospects for front-end fees plus carried interests, as opposed to direct participation in drilling costs, and due to the effect of our $5,126,248 ceiling test write-downs recorded in 2001.

 

Other General and Administrative Expenses—G&A related to our general corporate and other activities, decreased $584,964, or 23%, to $1,918,580 in 2002 compared to $2,503,544 in 2001. The major components of the decrease were in legal fees, investor relations expenses and franchise taxes. Legal fees were lower in 2002 because in 2001 they included costs related to the buyout of our partner’s interest in the seismic data set of the Cameron Project and a higher level of securities compliance filings and securities registration costs than in 2002. Our investor relations efforts in 2002 were less extensive than in 2001 when we made a concerted effort to communicate with the investment community about our completed transaction with Warburg to form our affiliate, Gryphon, and our new listing on the American Stock Exchange. Franchise taxes were lower in 2002 because we had a reverse stock split, which reduced our authorized shares from 120,000,000 shares to 40,000,000 during 2000.

 

Equity in Loss of Unconsolidated Affiliate—Equity in net loss of unconsolidated affiliate includes our share of the net loss of Gryphon, but also Gryphon’s preferred dividends in arrears. The amount we recognized for 2002 decreased to $2,184,847 from $2,974,191 in 2001 because during 2002 our recognition of these non-cash charges reduced our investment basis to zero. We did not reduce our basis below zero because we did not guarantee any obligations of Gryphon and were not committed to provide additional financial support to Gryphon.

 

Liquidity and Capital Resources

 

Management expects that we will meet all of our liquidity requirements for the next twelve months through a combination of cash balances, collection of receivables, issuances of our debt or equity securities, issuances of common stock pursuant to exercises by the holders of existing warrants and options, sales of regas capacity in our planned LNG receiving terminals, sales of prospects generated by our exploration group, borrowings under our line of credit and cash flows from current operations. In the event that we are unable to obtain additional capital from one or more of these sources, our operations could be adversely affected.

 

At December 31, 2003, we had working capital of $155,526. In January 2004, we received net proceeds of $13,884,750 from a private placement of 1,100,000 shares of our common stock, and we also received the remaining $2,500,000 from Freeport LNG, which was payable pursuant to the sale of our 60% interest in the Freeport LNG project. In January and February 2004, we received net proceeds of $1,309,559 related to the issuance of 557,056 shares of common stock pursuant to exercises of warrants and stock options. The pro forma effect of these transactions, had they been consummated as of December 31, 2003, would have been to increase our working capital to $17,849,835.

 

Cash Flow from Operating Activities

 

Net cash used in operations for the year ended December 31, 2003 totaled $7,558,864, compared to net cash used in operations of $2,764,325 in 2002. Because most of our resources were dedicated to the development of LNG receiving terminals in both 2002 and 2003, the main reason for the increase is that we were involved in the development of three LNG receiving terminals during 2003 as compared with only one terminal throughout most of 2002.

 

Issuances of Common Stock

 

Since our inception, the primary source of financing for our operating expenses, investments in our exploration program and investments in our development of LNG receiving terminals has been the sale of our

 

29


Table of Contents

equity securities. Through December 31, 2003, we have issued 16,488,187 shares of Cheniere common stock, generating net proceeds of $43,462,992. During 2003 and 2001, we raised $4,372,032 and $493,329, respectively, net of offering costs, from the exchange or exercise of warrants, the exercise of stock options and the sale of Cheniere units (common stock and warrants) to accredited investors pursuant to Regulation D. Proceeds of the offerings were used for the development of LNG receiving terminals and for general corporate purposes.

 

We issued a total of 3,190,794 shares of common stock in 2003. In April 2003, we issued 750,000 shares of common stock pursuant to a contingent contractual obligation related to Cheniere’s 2001 acquisition of an option to lease the Freeport LNG terminal site. In May 2003, we issued 792,892 shares of common stock to seventeen investors in a private placement made pursuant to Regulation D. The purchase price of the shares included cash of $1,189,338 and the surrender of existing warrants to purchase 792,892 shares of our common stock. Offering expenses relating to the private placement were $57,956. In August 2003, we issued 378,308 shares pursuant to a cashless exercise of warrants to purchase 700,000 shares. Throughout 2003, we issued a total of 1,082,094 shares pursuant to the exercise of warrants, resulting in net cash proceeds of $2,948,385. We also issued 187,500 shares pursuant to the exercise of stock options, resulting in proceeds of $292,265.

 

We did not sell any equity securities in 2002. In 2001, we issued a total of 750,000 shares of common stock. In February 2001, we issued to one stockholder 250,000 units at a cash purchase price of $2.00 per unit, each unit consisting of one share of Cheniere common stock, $.003 par value per share, and one warrant to purchase one-sixth of a share of Cheniere common stock. Proceeds of the offering, net of offering costs, were $493,329. In June 2001, we issued 500,000 shares of Cheniere common stock as partial consideration for a lease option on an LNG receiving terminal site near Freeport, Texas.

 

Bank Line of Credit

 

On July 25, 2003, we established a $5,000,000 line of credit with a commercial bank, with an initial borrowing base of $2,000,000. The facility is secured by our assets, and its term runs through December 31, 2004. Borrowings bear interest at the bank’s prime rate plus 2.5% per annum. In addition, a commitment fee of 0.5% per annum is assessed on the unused borrowing base capacity. A loan origination fee of 1% of the initial borrowing base was paid at closing. During 2003, we borrowed $1,000,000 under the facility to acquire oil and gas leases. The balance was repaid in January 2004. We also used the facility to establish a standby letter of credit in the amount of $865,142 in connection with our office lease.

 

Short-Term Promissory Notes

 

In February 2003, we executed a promissory note payable in the amount of $225,000. The proceeds of the note were used to pay certain costs related to our 3-D seismic database. In July 2003, we repaid the note payable.

 

In June 2002, we received a $750,000 payment for the sale of options to purchase an aggregate of up to a 20% interest in the Freeport LNG receiving terminal project. The payment was refundable, and repayment was secured by a note payable that we executed. In March 2003, an option was exercised and the note payable was canceled.

 

Sale of Interest in Freeport LNG Terminal

 

In August 2002, we entered into an agreement to sell a 60% interest in our planned LNG receiving facility near Freeport, Texas. In February 2003, our Freeport LNG project was acquired by Freeport LNG Development, L.P., in which we held a 40% interest. Effective March 1, 2003, we sold a 10% interest in Freeport LNG to an affiliate of Contango Oil & Gas Company for $2,333,333 payable over time. We now retain a 30% interest in Freeport LNG. Freeport LNG paid us cash and assumed liabilities related to the Freeport LNG project for costs, which represented an aggregate amount of $1,740,426, in addition to paying us a $1,000,000 initial installment at

 

30


Table of Contents

closing. We received additional payments of $1,500,000 in 2003 and $2,500,000 in January 2004 from Freeport LNG.

 

In June 2003, Dow signed an agreement with Freeport LNG for the potential long-term use of the receiving terminal. Under the agreement, Dow will have regas rights to as much as 500 Mmcf/d beginning with commercial start-up of the facility in 2007. In February 2004, Freeport LNG and Dow entered into a 20-year TUA providing for a firm commitment by Dow for the use of 250 Mmcf/d of regas capacity and an option by Dow until August 2004 to acquire an additional 250 Mmcf/d of regas capacity.

 

On December 21, 2003, ConocoPhillips and Freeport LNG signed an agreement under which ConocoPhillips will reserve one Bcf per day of regas capacity in the terminal at the Freeport facility. ConocoPhillips will also obtain a 50% interest in the general partner of Freeport LNG and provide a substantial majority of the financing to construct the facility, which is currently estimated to cost in excess of $500 million. The ConocoPhillips transaction is expected to close in the spring of 2004, subject to completion of remaining documentation and satisfaction of closing conditions.

 

Because the initial development expenses of the Freeport LNG project are to be funded by the 60% limited partner in Freeport LNG, we have not been required to contribute any cash to Freeport LNG for development activities, nor do we anticipate being required to make capital contributions to Freeport LNG in the future.

 

Corpus Christi LNG Terminal Funding Negotiations

 

Under the terms of the limited partnership agreement of Corpus LNG, which was formed for our Corpus Christi LNG receiving terminal project, we contributed our technical expertise and know-how, and all of the work in progress related to the Corpus Christi project, in exchange for a 66.7% limited partner interest in Corpus LNG. BPU LNG committed to contribute its approximately 210-acre tract of land plus related easements and additional rights to an additional 400 acres, and cash to fund the first $4,500,000 of Corpus LNG project expenses in exchange for a 33.3% limited partner interest. We will manage the project through the general partner interest held by our wholly-owned subsidiary.

 

Exploration Funding

 

On October 11, 2000, we completed a transaction with Warburg to fund our exploration program on approximately 8,800 square miles of seismic data in the Gulf of Mexico through a newly formed affiliated company, Gryphon. We contributed selected assets and liabilities in exchange for 100% of the common stock of Gryphon (36.8% effective interest after conversion of preferred stock) and $2,000,000 in cash. Warburg contributed $25,000,000 and received preferred stock, with an 8% cumulative dividend, convertible into 63.2% of Gryphon’s common stock.

 

Cheniere and Warburg also have the option, in connection with subsequent capital calls made by Gryphon, to contribute up to an additional $75,000,000 to Gryphon, proportionate to their respective ownership interests. Under the terms of the agreement governing these additional contributions, in the event that either we or Warburg elects not to participate in any additional contribution, the other investor has the option to purchase the non-participating investor’s proportionate share. During 2001 and 2002, Gryphon made cash calls totaling $60,000,000 against its capital commitment of $75,000,000. Gryphon made no additional cash calls during 2003. We declined to participate in such cash calls, and Warburg elected to purchase our proportionate share of such cash calls. As a result, our ownership interest in Gryphon, after the potential effect of converting preferred stock into common stock, was reduced from 36.8% at December 31, 2000 to 9.3% as of December 31, 2003.

 

Prior to 2003, we accounted for our investment in Gryphon using the equity method of accounting. Effective January 1, 2003, we began accounting for our investment in Gryphon using the cost method of accounting because we lost the ability to exercise significant influence over Gryphon’s operating and financial policies, as our representation on Gryphon’s board of directors was reduced to one director.

 

31


Table of Contents

Seismic Reprocessing

 

Between June 2000 and October 2000, we acquired licenses to approximately 6,800 miles of seismic data primarily in the shallow waters offshore Texas and also in the West Cameron area in the Gulf of Mexico (the “Offshore Texas Project Area”) in separate transactions with Seitel Data Ltd., a division of Seitel Inc., and Jebco Seismic, L.P. We committed to reprocess all of the data from the Offshore Texas Project Area at a cost of approximately $8,500,000, payable in installments beginning in October 2000 and continuing through the final delivery of reprocessed data, which was received in 2003. We have no existing or contingent liability related to seismic reprocessing as of December 31, 2003.

 

Sale of Licenses to Seismic Data

 

In June and July 2001, we sold licenses to 6,800 square miles of seismic data to Gryphon for $7,000,000. We received cash proceeds of $853,197. Gryphon also assumed $6,820,824 of our obligation to fund the reprocessing of the seismic data. In connection with the transactions, we also transferred 6,740 shares of Gryphon common stock to Gryphon. We retain one license to all of the data in the Offshore Texas Project Area.

 

Sale of Proprietary Seismic Data

 

In September 2001, we acquired for $500,000 all rights to our 228-square-mile proprietary seismic database from the industry partner with whom we had jointly acquired the data in 1996 and 1997. We subsequently sold the seismic data to a seismic marketing company for $2,500,000 and a 50% share in licensing proceeds generated by the marketing company. In September 2002, we sold our remaining interest in future licensing proceeds to the marketing company for $825,000. Proceeds from the September 2001 and 2002 sales of 3D seismic data were recorded as a reduction to our unproved oil and gas property costs. We retain a license to all of the seismic data for use in our exploration program.

 

Contractual Obligations

 

We are committed to making cash payments in the future on certain of our contracts. We have no off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2003.

 

     Payments Due for Years Ended December 31,

     Total

   2004

   2005

   2006

   2007

   2008

   Thereafter

Note Payable(1)

   $ 1,000,000    $ 1,000,000      —        —        —        —        —  

Operating Leases(2)

   $ 3,597,000    $ 455,000    $ 522,000    $ 299,000    $ 305,000    $ 305,000    $ 1,711,000

LNG Consulting Retainer(3)

   $ 100,000    $ 100,000      —        —        —        —        —  

(1) At December 31, 2003, we had borrowings of $1,000,000 against our $5,000,000 line of credit with a commercial bank. The $1,000,000 was repaid in January 2004.
(2) A discussion of operating leases can be found at Note 15 of the Notes to Consolidated Financial Statements.
(3) In April 2001, we engaged research consultants in connection with the development of our LNG receiving terminal business. In connection with the February 2003 closing on the sale of the Freeport LNG terminal (described above), we agreed to make cash payments totaling $200,000 and issued warrants to purchase 225,000 shares of Cheniere common stock at a price of $2.50 per share to the consultants. A payment of $100,000 was made in 2003, and the remaining amount will be paid in 2004.

 

Our obligations under LNG site options are renewable on an annual or semiannual basis. We may terminate our obligation at any time by electing not to renew or by exercising the option.

 

32


Table of Contents

Other Matters

 

Critical Accounting Estimates and Policies

 

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have 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, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and believe the proper implementation and consistent application of the accounting rules are critical. However, not all situations are specifically addressed in the accounting literature. 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 often consult with our independent accountants about the appropriate interpretation and application of these policies. Our most critical accounting policy is our accounting under the full cost method of accounting. This area involves complex situations and a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements.

 

Accounting for LNG Activities

 

We have been in the preliminary stage of developing LNG receiving terminals. Substantially all costs related thereto have been expensed when incurred. Land costs associated with LNG terminal sites are capitalized. Costs of certain permits are capitalized as intangible LNG assets. We have also incurred costs related to options to purchase or lease land that may be used for potential LNG terminal sites.

 

Full Cost Method of Accounting

 

We follow the full cost method of accounting for our oil and gas properties. Under this method, all productive and non-productive exploration and development costs incurred for the purpose of finding oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, together with internal costs directly attributable to property acquisition, exploration and development activities. Interest is capitalized on oil and gas properties not subject to amortization and in the process of development.

 

The costs of our oil and gas properties, including the estimated future costs to develop proved reserves, are depreciated using a composite units-of-production rate based on estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, then the amount of the impairment is added to the capitalized costs to be amortized. Net capitalized costs are limited to a capitalization ceiling, calculated on a quarterly basis as the aggregate of the present value, discounted at 10%, of estimated future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties, less related income tax effects. At June 30, 2001 and September 30, 2001, our capitalized costs exceeded our capitalization ceiling, resulting in ceiling test write-downs totaling $5,126,248 for the year.

 

Our allocation of seismic exploration costs to proved properties involves an estimate of the total reserves to be discovered in the project. This estimate includes a number of assumptions that we have factored into a four-year plan. Such factors include an estimate of the number of exploration prospects generated, prospect reserve potential, success ratios and ownership interests. We transfer unproved properties to proved properties based on a ratio of proved reserves discovered at a point in time to the estimate of total reserves to be discovered in our exploration program. It is reasonably possible, based on the results obtained from future drilling and prospect generation, that revisions to this estimate could affect our capitalization ceiling.

 

33


Table of Contents

Oil and Gas Reserves

 

The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgment of the persons preparing the estimate.

 

Our proved reserve information included in this document for 2003 is based on estimates prepared by Sharp Petroleum Engineering, Inc. Estimates prepared by others may be higher or lower than our estimates.

 

Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of natural gas and crude oil that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

 

The present value of future net cash flows does not necessarily represent the current market value of our estimated proved natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

 

Our rate of recording DD&A is dependent upon our estimate of proved reserves. If the estimate of proved reserves declines, the rate at which we record DD&A expense increases, reducing net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields.

 

New Accounting Pronouncements

 

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, and subsequently revised the Interpretation in December 2003 (FIN 46R). This Interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses consolidation by business enterprises of variable interest entities, which have certain characteristics. As revised, FIN 46R is now generally effective for financial statements for interim or annual periods ending on or after March 15, 2004. We have not identified any variable interest entities. In the event a variable interest entity is identified, we do not expect the requirements of FIN 46R to have a material impact on our consolidated financial statements.

 

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. An issuer is required to classify a financial instrument that is within the scope of this statement as a liability (or an asset in some circumstances). SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. We adopted the standard on July 1, 2003, and the adoption did not have a material impact on our consolidated financial statements.

 

Other Recent Developments

 

In July 2003, an issue was brought before the Financial Accounting Standards Board (FASB) regarding whether or not contract-based oil and gas mineral rights held by lease or contract (“mineral rights”) should be recorded or disclosed as intangible assets. The issue presents a view that these mineral rights are intangible assets

 

34


Table of Contents

as defined in Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations,” and, therefore, should be classified separately on the balance sheet as intangible assets. SFAS No. 141 and SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective for transactions subsequent to June 30, 2001, with the disclosure requirements of SFAS No. 142 required as of January 1, 2002. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements. SFAS No. 142 does not apply to accounting utilized by the oil and gas industry as prescribed by SFAS No. 19, and is silent about whether or not its disclosure provisions apply to oil and gas companies. The Emerging Issues Task Force (EITF) has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in how we classify these assets.

 

Should such a change be required, the amounts related to business combinations and major asset purchases that would be classified as “intangible undeveloped mineral interest” are immaterial as of December 31, 2003 and December 31, 2002. The amounts related to business combinations and major asset purchases that would be classified as “intangible developed mineral interest” are also immaterial as of December 31, 2003 and December 31, 2002.

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

The development of our LNG receiving terminal business is based upon the foundational premise that prices of natural gas in the U.S. will be sustained at levels of $3.00 per Mcf or more. Should the price of natural gas in the U.S. decline to sustained levels below $3.00 per Mcf, our ability to develop and operate LNG receiving terminals could be significantly negatively affected.

 

We produce and sell natural gas, crude oil and condensate. As a result, our financial results can be affected as these commodity prices fluctuate widely in response to changing market forces. We have not entered into any derivative transactions.

 

In the normal course of business, our financial condition is exposed to minimal market risk associated with interest rate movements on our borrowings. A one percent increase or decrease in the levels of interest rates on variable rate debt would not result in a material change to our results of operations.

 

35


Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

INDEX TO FINANCIAL STATEMENTS

 

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

Reports of Independent Accountants

   37

Consolidated Balance Sheet

   39

Consolidated Statement of Operations

   40

Consolidated Statement of Stockholders’ Equity

   41

Consolidated Statement of Cash Flows

   42

Notes to Consolidated Financial Statements

   43

Supplemental Information to Consolidated Financial Statements

   67

 

All schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.

 

36


Table of Contents

REPORT OF INDEPENDENT ACCOUNTANTS

 

To the Board of Directors and

Stockholders of Cheniere Energy, Inc:

 

We have audited the consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of Freeport LNG Development, L.P. (“Freeport LNG”), an investment which, as discussed in note 7 to the consolidated financial statements, is accounted for by the equity method of accounting. The investment in Freeport LNG was zero as of December 31, 2003 and 2002, and the equity in its net loss was $4,471,529 and zero, respectively, for the years then ended. We also did not audit the financial statements of Gryphon Exploration Company (“Gryphon”), an investment which, as discussed in Note 6 to the consolidated financial statements, has been, until January 1, 2003, accounted for by the equity method of accounting. The investment in Gryphon was zero as of December 31, 2003 and 2002, and the equity in its net loss was $2,184,847 for the year ended December 31, 2002. The financial statements of Freeport LNG and Gryphon were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Freeport LNG and Gryphon, are based solely on the reports of the other auditors.

 

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, based on our audits and the reports of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy, Inc. and subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.

 

MANN FRANKFORT STEIN & LIPP CPAs, L.L.P.

 

Houston, Texas

February 29, 2004

 

37


Table of Contents

REPORT OF INDEPENDENT ACCOUNTANTS

 

To the Board of Directors and

Stockholders of Cheniere Energy, Inc:

 

In our opinion, the consolidated statements of operations, stockholders’ equity and cash flows for the year ended December 31, 2001 present fairly, in all material respects, the results of operations and cash flows of Cheniere Energy, Inc. and its subsidiaries for the year ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 18 to the consolidated financial statements, the Company has experienced recurring losses from operations and has a negative working capital balance at December 31, 2001 that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 18. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

PRICEWATERHOUSECOOPERS LLP

 

Houston, Texas

March 29, 2002, except for Note 16 as to

which the date is March 25, 2004

 

 

38


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEET

 

     December 31,

 
     2003

    2002

 

ASSETS

                

CURRENT ASSETS

                

Cash and Cash Equivalents

   $ 1,257,693     $ 590,039  

Accounts Receivable

                

Affiliates

     1,000,000       —    

Other

     1,828,065       1,137,682  

Prepaid Expenses

     401,594       121,099  
    


 


Total Current Assets

     4,487,352       1,848,820  

OIL AND GAS PROPERTIES, full cost method

                

Proved Properties, net

     1,087,152       842,882  

Unproved Properties, not subject to amortization

     18,047,802       16,751,347  
    


 


Total Oil and Gas Properties

     19,134,954       17,594,229  

LNG SITE COSTS

     310,500       1,400,000  

FIXED ASSETS, net

     578,281       216,341  

INVESTMENT IN UNCONSOLIDATED AFFILIATE

     —         —    

INVESTMENT IN LIMITED PARTNERSHIP

     —         —    

INTANGIBLE LNG ASSETS

     79,670       —    
    


 


Total Assets

   $ 24,590,757     $ 21,059,390  
    


 


LIABILITIES AND STOCKHOLDERS’ EQUITY

                

CURRENT LIABILITIES

                

Accounts Payable

   $ 1,984,314     $ 1,828,267  

Accrued Liabilities

     1,347,512       683,788  

Note Payable

     1,000,000       750,000  
    


 


Total Current Liabilities

     4,331,826       3,262,055  

DEFERRED REVENUE

     1,000,000       —    

MINORITY INTEREST

     120,032       —    

COMMITMENTS AND CONTINGENCIES

     —         —    

STOCKHOLDERS’ EQUITY

                

Preferred Stock, $.0001 par value

                

Authorized: 5,000,000 shares

                

Issued and Outstanding: none

     —         —    

Common Stock, $.003 par value

                

Authorized: 40,000,000 shares

                

Issued and Outstanding: 16,488,187 shares at December 31, 2003 and 13,297,393 shares at December 31, 2002

     49,465       39,892  

Additional Paid-in-Capital

     48,034,244       41,414,236  

Accumulated Deficit

     (28,944,810 )     (23,656,793 )
    


 


Total Stockholders’ Equity

     19,138,899       17,797,335  
    


 


Total Liabilities and Stockholders’ Equity

   $ 24,590,757     $ 21,059,390  
    


 


 

The accompanying notes are an integral part of these financial statements.

 

39


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENT OF OPERATIONS

 

     Year Ended December 31,

 
     2003

    2002

    2001

 

Revenues

                        

Oil and Gas Sales

   $ 657,467     $ 239,055     $ 2,372,632  
    


 


 


Total Revenues

     657,467       239,055       2,372,632  
    


 


 


Operating Costs and Expenses

                        

Production Costs

     —         90,038       420,242  

Depreciation, Depletion and Amortization

     428,680       368,562       1,243,828  

Ceiling Test Write-down

     —         —         5,126,248  

General and Administrative Expenses

                        

LNG Terminal Development

     6,704,538       1,556,782       1,788,419  

Other

     2,542,399       1,918,580       2,503,544  
    


 


 


General and Administrative Expenses

     9,246,937       3,475,362       4,291,963  
    


 


 


Total Operating Costs and Expenses

     9,675,617       3,933,962       11,082,281  
    


 


 


Loss from Operations

     (9,018,150 )     (3,694,907 )     (8,709,649 )

Equity in Net Loss of Unconsolidated Affiliate

     —         (2,184,847 )     (2,974,191 )

Equity in Net Loss of Limited Partnership

     (4,471,529 )     —         —    

Gain on Sale of Proved Oil and Gas Properties

     —         340,257       —    

Gain on Sale of LNG Assets

     4,760,000       —         —    

Gain on Sale of Limited Partnership Interest

     423,454       —         —    

Loss on Early Extinguishment of Debt

     —         (100,544 )     —    

Interest Income

     2,740       7,733       18,578  
    


 


 


Loss Before Income Taxes and Minority Interest

     (8,303,485 )     (5,632,308 )     (11,665,262 )

Provision for Income Taxes

     —         —         —    
    


 


 


Loss Before Minority Interest

     (8,303,485 )     (5,632,308 )     —    

Minority Interest

     3,015,468       —         —    
    


 


 


Net Loss

   $ (5,288,017 )   $ (5,632,308 )   $ (11,665,262 )
    


 


 


Net Loss Per Share—Basic and Diluted

   $ (0.36 )   $ (0.42 )   $ (0.89 )
    


 


 


Weighted Average Number of Shares Outstanding—Basic and Diluted

     14,771,700       13,297,393       13,035,256  
    


 


 


 

The accompanying notes are an integral part of these financial statements.

 

40


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

 

     Common Stock

   Additional
Paid-In
Capital


    Accumulated
Deficit


    Total
Stockholders’
Equity


 
     Shares

   Amount

      

Balance—December 31, 2000

   12,547,393    $ 37,642    $ 39,382,789     $ (6,359,223 )   $ 33,061,208  

Issuances of Stock

   750,000      2,250      1,647,750       —         1,650,000  

Issuances of Warrants

   —        —        110,000       —         110,000  

Expenses Related to Offerings

   —        —        (6,671 )     —         (6,671 )

Net Loss

   —        —        —         (11,665,262 )     (11,665,262 )
    
  

  


 


 


Balance—December 31, 2001

   13,297,393    $ 39,892    $ 41,133,868     $ (18,024,485 )   $ 23,149,275  

Issuances of Warrants

   —        —        280,368       —         280,368  

Net Loss

   —        —        —         (5,632,308 )     (5,632,308 )
    
  

  


 


 


Balance—December 31, 2002

   13,297,393    $ 39,892    $ 41,414,236     $ (23,656,793 )   $ 17,797,335  

Issuances of Stock

   3,190,794      9,573      5,732,915       —         5,742,488  

Issuances of Warrants

   —        —        945,049       —         945,049  

Expenses Related to Offerings

   —        —        (57,956 )     —         (57,956 )

Net Loss

   —        —        —         (5,288,017 )     (5,288,017 )
    
  

  


 


 


Balance—December 31, 2003

   16,488,187    $ 49,465    $ 48,034,244     $ (28,944,810 )   $ 19,138,899  
    
  

  


 


 


 

 

The accompanying notes are an integral part of these financial statements.

 

41


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENT OF CASH FLOWS

 

     Year Ended December 31,

 
     2003

    2002

    2001

 

CASH FLOWS FROM OPERATING ACTIVITIES:

                        

Net Loss

   $ (5,288,017 )   $ (5,632,308 )   $ (11,665,262 )

Adjustments to Reconcile Net Loss to Net Cash Used In Operating Activities:

                        

Depreciation, Depletion and Amortization

     428,680       368,562       1,243,828  

Ceiling Test Write-down

     —         —         5,126,248  

Non-Cash Expense

     (3,636 )     (32,649 )     380,000  

Gain on Sale of Proved Oil and Gas Properties

     —         (340,257 )     —    

Loss on Early Extinguishment of Debt

     —         100,544       —    

Equity in Net Loss of Unconsolidated Affiliate

     —         2,184,847       2,974,191  

Equity in Net Loss of Limited Partnership

     4,471,529       —         —    

Gain on Sale of LNG Assets

     (4,760,000 )     —         —    

Gain on Sale of Limited Partnership Interest

     (423,454 )     —         —    

Minority Interest

     (3,015,468 )     —         —    

Changes in Operating Assets and Liabilities

                        

Other Accounts Receivable

     229,747       (752,648 )     591,672  

Prepaid Expenses

     (482,428 )     (27,786 )     14,818  

Accounts Payable and Accrued Liabilities

     1,284,183       1,367,370       (877,772 )
    


 


 


NET CASH USED IN OPERATING ACTIVITIES

     (7,558,864 )     (2,764,325 )     (2,212,277 )
    


 


 


CASH FLOWS FROM INVESTING ACTIVITIES:

                        

Purchases of Fixed Assets

     (340,837 )     (14,506 )     (407,817 )

Oil and Gas Property Additions

     (2,514,357 )     (1,430,472 )     (4,343,705 )

Net Proceeds from Sale of Proved Oil and Gas Properties

     —         2,235,365       —    

Sale of Interest in Oil and Gas Prospects

     391,350       628,259       2,039,429  

Sale of Oil and Gas Seismic Data

     —         825,000       3,353,197  

LNG Site Costs

     —         (250,000 )     (200,000 )

Purchase of Intangible LNG Assets

     (79,670 )     —         —    

Sale of LNG Assets

     1,873,000       —         —    

Sale of Limited Partnership Interest

     700,000       —         —    
    


 


 


NET CASH PROVIDED BY INVESTING ACTIVITIES

     29,486       1,993,646       441,104  
    


 


 


CASH FLOWS FROM FINANCING ACTIVITIES:

                        

Proceeds from Issuances of Notes Payable

     1,225,000       1,250,000       —    

Repayment of Note Payable

     (225,000 )     (500,000 )     —    

Sale of Common Stock

     4,429,988       —         500,000  

Offering Costs

     (57,956 )     —         (6,671 )

Partnership Contributions by Minority Owner

     2,825,000       —         —    
    


 


 


NET CASH PROVIDED BY FINANCING ACTIVITIES

     8,197,032       750,000       493,329  
    


 


 


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     667,654       (20,679 )     (1,277,844 )

CASH AND CASH EQUIVALENTS—BEGINNING OF YEAR

     590,039       610,718       1,888,562  
    


 


 


CASH AND CASH EQUIVALENTS—END OF YEAR

   $ 1,257,693     $ 590,039     $ 610,718  
    


 


 


 

The accompanying notes are an integral part of these financial statements.

 

42


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

 

Cheniere Energy, Inc., a Delaware corporation, is a Houston-based company engaged primarily in the development of a liquefied natural gas (“LNG”) receiving terminal business and related LNG business opportunities centered on the U.S. Gulf Coast. The terms Cheniere and Company refer to Cheniere Energy, Inc. and its subsidiaries. Cheniere is also engaged in oil and gas exploration, development and exploitation activities in the Gulf of Mexico.

 

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation

 

The consolidated financial statements include the accounts of Cheniere Energy, Inc. and its majority-owned subsidiaries. Cheniere also holds ownership interests in entities that are accounted for under the equity method and cost method of accounting. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain items in the prior year financial statements have been reclassified to conform with the 2003 presentation.

 

LNG Activities

 

The Company has been in the preliminary stage of developing LNG receiving terminals. Substantially all costs related thereto have been expensed when incurred. Land costs associated with LNG terminal sites are capitalized. Costs of certain permits are capitalized as intangible LNG assets. Cheniere has also incurred costs related to options to purchase or lease land that may be used for potential LNG terminal sites.

 

Oil and Gas Properties

 

The Company follows the full cost method of accounting for its oil and gas properties. Under this method, all productive and nonproductive exploration and development costs incurred for the purpose of finding oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, together with internal costs directly attributable to property acquisition, exploration and development activities. Interest is capitalized on oil and gas properties not subject to amortization and in the process of development. The Company capitalized interest totaling $41,107, ($42,261) and $165,813 and general and administrative expenses, net of reimbursements, totaling $976,000, $829,000 and $782,000 for the years 2003, 2002 and 2001, respectively. Capitalized interest for 2002 was negative due to a refund of interest that was paid in 2001.

 

The costs of the Company’s oil and gas properties, including the estimated future costs to develop proved reserves, are depreciated using a composite units-of-production rate based on estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, then the amount of the impairment is added to the capitalized costs to be amortized. Net capitalized costs are limited to a capitalization ceiling, calculated on a quarterly basis as the aggregate of the present value, discounted at 10%, of estimated future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties, less related income tax effects.

 

The Company’s allocation of seismic exploration costs between proved and unproved properties involves an estimate of the total reserves to be discovered in the Company’s exploration program. This estimate includes a

 

43


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

number of assumptions that Cheniere has factored into a four-year plan. Such factors include an estimate of the number of exploration prospects generated, prospect reserve potential, success ratios and ownership interests. The Company transfers unproved properties to proved properties based on a ratio of proved reserves discovered at a point in time to the estimate of total reserves to be discovered in Cheniere’s exploration program. It is reasonably possible, based on the results obtained from future drilling and prospect generation, that revisions to this estimate could affect the Company’s capitalization ceiling.

 

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

 

In July 2003, an issue was brought before the Financial Accounting Standards Board (FASB) regarding whether or not contract-based oil and gas mineral rights held by lease or contract (“mineral rights”) should be recorded or disclosed as intangible assets. The issue presents a view that these mineral rights are intangible assets as defined in Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations,” and, therefore, should be classified separately on the balance sheet as intangible assets. SFAS No. 141 and SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective for transactions subsequent to June 30, 2001, with the disclosure requirements of SFAS No. 142 required as of January 1, 2002. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements. SFAS No. 142 does not apply to accounting utilized by the oil and gas industry as prescribed by SFAS No. 19, and is silent about whether or not its disclosure provisions apply to oil and gas companies. The Emerging Issues Task Force (EITF) has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in how Cheniere classifies these assets.

 

Should such a change be required, the amounts related to business combinations and major asset purchases that would be classified as “intangible undeveloped mineral interest” are immaterial as of December 31, 2003 and December 31, 2002. The amounts related to business combinations and major asset purchases that would be classified as “intangible developed mineral interest” are also immaterial as of December 31, 2003 and December 31, 2002.

 

Revenue Recognition

 

Revenues from the sale of oil and gas production are recognized upon passage of title, net of royalty interests. When sales volumes differ from the Company’s entitled share, an underproduced or overproduced imbalance occurs. To the extent an overproduced imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. At December 31, 2003 and 2002, the Company had no gas imbalances.

 

Fixed Assets

 

Fixed assets are recorded at cost. Repairs and maintenance costs are charged to operations as incurred. Depreciation is computed using the straight-line method over their estimated useful lives, which range from two to five years. Upon retirement or other disposition of fixed assets, the cost and related accumulated depreciation is removed from the accounts and the resulting gains or losses are recorded.

 

44


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Offering Costs

 

Offering costs consist primarily of placement fees, professional fees and printing costs. These costs are charged against the related proceeds from the sale of common stock in the periods in which they occur or charged to expense in the event of a terminated offering.

 

Income Taxes

 

Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled as prescribed in SFAS No. 109, Accounting for Income Taxes. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is provided for deferred tax assets if it is more likely than not that such asset will not be realizable.

 

Stock-Based Compensation

 

SFAS No. 123, Accounting for Stock-Based Compensation, encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. The statement also amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results.

 

The Company has chosen to continue to account for stock-based compensation issued to employees using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company’s stock at the date of the grant over the amount an employee must pay to acquire the stock. The Company grants options at or above the market price of its common stock at the date of each grant.

 

45


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The fair value of options is calculated using the Black-Scholes option-pricing model. Had the Company adopted the fair value method of accounting for stock based compensation, compensation expense would have been higher, and net loss and net loss attributable to common shareholders would have increased for the periods presented. No change in cash flows would occur. The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts.

 

     Year Ended December 31,

 
     2003

    2002

    2001

 

Net loss as reported

   $ (5,288,017 )   $ (5,632,308 )   $ (11,665,262 )

Deduct:

                        

Total stock based employee compensation expense determined under fair value based method for all awards, net of related income tax

     (966,795 )     (607,766 )     (427,575 )

Pro forma net loss

   $ (6,254,812 )   $ (6,240,074 )   $ (12,092,837 )

Net Loss Per Share

                        

Basic—as reported

   $ (0.36 )   $ (0.42 )   $ (0.89 )

Basic—pro forma

     (0.42 )     (0.47 )     (0.93 )

Diluted—as reported

     (0.36 )     (0.42 )     (0.89 )

Diluted—pro forma

     (0.42 )     (0.47 )     (0.93 )

 

The weighted average fair value of warrants and options granted as employee compensation during 2003, 2002 and 2001 was $1.44, $1.20 and $0.76 respectively. The fair values were determined using the Black-Scholes option-pricing model with the following weighted average assumptions, and a forfeiture rate that is assumed to be negligible:

 

     Year Ended December 31,

     2003

   2002

   2001

Dividend yield

   0.0%    0.0%    0.0%

Weighted average volatility

   107.5%    107.8%    84.3%

Risk-free interest rate

   3.0%    2.9%    3.5%

Expected lives of options

   4.0 years    4.0 years    4.0 years

 

Earnings (Loss) Per Share

 

Earnings (loss) per share (“EPS”) is computed in accordance with the requirements of SFAS No. 128, Earnings Per Share. Basic EPS excludes dilution and is computed by dividing net income (loss) by the weighted average number of shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net income by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued. Potential dilutive common stock equivalents include stock options from employee benefit plans and warrants to purchase common stock. Basic and diluted EPS for all periods presented are the same since the effect of the Company’s options and warrants is antidilutive to its net loss per share under SFAS No. 128. Stock options and warrants representing securities that could potentially dilute basic EPS in the future that were not included in the fully diluted computation because they would have been anti-dilutive for the years 2003, 2002 and 2001 were 3,259,583, 4,577,132 and 4,591,399, respectively. No adjustments were made to reported net loss in the computation of EPS.

 

46


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Cash Equivalents

 

The Company classifies all investments with original maturities of three months or less as cash equivalents.

 

Fair Value of Financial Instruments

 

The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and notes payable approximate fair value because of the short maturity of those instruments.

 

Commodity Price Risk

 

The Company produces and sells natural gas, crude oil and condensate. As a result, the Company’s financial results can be affected as these commodity prices fluctuate widely in response to changing market forces. The Company has not entered into any hedging transactions. The Company’s market risk with respect to its variable-rate, short-term note payable is considered to be immaterial due to the short-term nature of this instrument.

 

Concentration of Credit Risk

 

All of the Company’s revenues are attributable to overriding royalty interests in properties operated by two companies. These companies sell Cheniere’s royalty share of production for Cheniere, pay the associated severance taxes, and remit the balance to Cheniere. The Company’s products are commodities and have a readily available market for sale.

 

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires that the Company make estimates and assumptions that affect the amounts reported in the financial statements and the accompanying notes. The most significant estimate pertains to proved oil and gas reserve volumes. Actual results could differ from those estimates.

 

New Accounting Pronouncements

 

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, and subsequently revised the Interpretation in December 2003 (FIN 46R). This Interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses consolidation by business enterprises of variable interest entities, which have certain characteristics. As revised, FIN 46R is now generally effective for financial statements for interim or annual periods ending on or after March 15, 2004. We have not identified any variable interest entities. In the event a variable interest entity is identified, we do not expect the requirements of FIN 46R to have a material impact on our consolidated financial statements.

 

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. An issuer is required to classify a financial instrument that is within the scope of this statement as a liability (or an asset in some circumstances). SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. We adopted the standard on July 1, 2003, and the adoption did not have a material impact on our consolidated financial statements.

 

47


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

NOTE 3—ACCRUED LIABILITIES

 

Accrued liabilities consist of the following:

 

     December 31,

     2003

   2002

Taxes other than income

   $ 36,986    $ 42,611

Accrued LNG costs

     1,183,191      391,177

Accrued oil and gas property costs

     —        250,000

Other accrued liabilities

     127,335      —  
    

  

Accrued liabilities

   $ 1,347,512    $ 683,788
    

  

 

NOTE 4—FIXED ASSETS

 

Fixed assets consist of the following:

 

     December 31,

 
     2003

    2002

 

Furniture and fixtures

   $ 209,514     $ 48,618  

Computers and office equipment

     524,359       303,151  

Other

     409,157       263,936  
    


 


       1,143,030       615,705  

Less accumulated depreciation

     (564,749 )     (399,364 )
    


 


Fixed assets, net

   $ 578,281     $ 216,341  
    


 


 

Depreciation expense related to the Company’s fixed assets totaled $165,385, $185,396 and $197,789 for the years ended December 31, 2003, 2002 and 2001, respectively.

 

NOTE 5—OIL AND GAS PROPERTIES

 

Investments in oil and gas properties consist of the following:

 

     December 31,

 
     2003

    2002

 

Oil and gas properties:

                

Proved

   $ 1,223,020     $ 857,388  

Unproved

     18,047,802       16,751,347  
    


 


       19,270,822       17,608,735  

Less accumulated depreciation, depletion and amortization

     (135,868 )     (14,506 )
    


 


     $ 19,134,954     $ 17,594,229  
    


 


 

Depreciation, depletion and amortization of oil and gas property costs totaled $121,362, $74,566 and $1,029,239 for the years ended December 31, 2003, 2002 and 2001, respectively. Depreciation, depletion and amortization per equivalent Mcf (using an Mcf-to-barrel conversion factor of 6 to 1) was $0.98, $0.79 and $1.84 for the years ended December 31, 2003, 2002 and 2001, respectively.

 

Costs incurred for unproved oil and gas properties were $2,514,357 in 2003 and $2,813,370 in 2002. The Company believes that unproved property costs will be evaluated within four years.

 

48


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

At June 30, 2001 and September 30, 2001, the Company’s capitalized costs exceeded its capitalization ceiling, resulting in ceiling test write-downs totaling $5,126,248 for the year ended December 31, 2001.

 

The Company has made substantial investments in acquiring, processing and reprocessing its seismic databases covering a 6,800-square-mile project area offshore Texas and Louisiana and a 228-square-mile project area onshore and offshore Louisiana. The costs of these projects become subject to amortization on a ratable basis as the oil and gas reserves expected to be recovered from the projects are discovered. The Company began drilling prospects identified within its seismic databases in 1999, but did not participate in the drilling of any wells in 2000, 2001, 2002 or 2003. The Company did, however, have overriding royalty interests in wells drilled by others during these periods. Interpretation of this data and related prospect generation is ongoing.

 

In September 2001, Cheniere paid $500,000 to acquire all rights to its 228-square-mile proprietary seismic database from the industry partner with whom it had jointly owned the data since 1996. Concurrent with this acquisition, Cheniere sold the seismic data to a seismic marketing company for $2,500,000 and a 50% share in licensing proceeds generated by the marketing company. In September 2002, Cheniere sold its remaining interest in future licensing proceeds to the marketing company for $825,000. Proceeds from the September 2001 and 2002 sales of 3D seismic data were recorded as a reduction to the Company’s unproved oil and gas property costs. Cheniere retains a license to all of the seismic data for use in its exploration program.

 

In April 2002, the Company sold all of its proved working interests in oil and gas properties for $2,235,365. A gain of $340,257 was recorded on the sale.

 

NOTE 6—INVESTMENT IN UNCONSOLIDATED AFFILIATE

 

Prior to January 1, 2003, Cheniere accounted for its investment in Gryphon Exploration Company (“Gryphon”) using the equity method of accounting because its participation on the Gryphon board of directors provided it with the ability to exercise significant influence over the operating and financial policies of Gryphon. In December 2002, the extent of such influence was diminished when one of the two Cheniere-appointed representatives on the Gryphon board of directors resigned his position as an officer of Cheniere. Accordingly, effective January 1, 2003, Cheniere began accounting for its investment in Gryphon using the cost method of accounting. As of December 31, 2002, Warburg, Pincus Equity Partners, L.P. (“Warburg”) had invested $85,000,000 in Gryphon convertible preferred stock. If Warburg had converted its investment to common stock as of such date, Cheniere’s ownership interest would have been 9.3%. This effective percent ownership remains unchanged as of December 31, 2003.

 

Cheniere began engaging in a series of transactions related to Gryphon in 2000. On October 11, 2000, Cheniere completed a transaction with Warburg to fund its exploration program on approximately 8,800 square miles of seismic data in the Gulf of Mexico (the “Louisiana Data Set”) through a newly-formed affiliated company, Gryphon. Cheniere contributed selected assets and liabilities in exchange for 100% of the common stock of Gryphon (36.8% voting interest after conversion of preferred stock) and $2,000,000 in cash. Such assets included: the Louisiana Data Set, certain offshore leases, a prospect then being drilled, its exploration agreement with an industry partner and certain other assets and liabilities. The net book value of the assets and liabilities contributed was $7,065,919, which consisted of assets of $9,115,963 (primarily unproved oil and gas property) and liabilities of $2,050,044 (primarily accounts payable). Warburg contributed $25,000,000 and received preferred stock, with an 8% accrued dividend, convertible into 63.2% of Gryphon’s common stock. Cheniere accounted for the contribution of net assets at its historical cost, whereby the net amount of such assets and liabilities less the $2,000,000 in cash was reclassified to investment in affiliate. No gain or loss was recognized at the time of contribution, primarily due to Cheniere’s commitment to provide additional funding described above and due to the uncertainty of realization of the carrying value of the contributed unproved oil and gas properties.

 

49


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Cheniere and Warburg also have the option, in connection with subsequent capital calls made by Gryphon, to contribute up to an additional $75,000,000 to Gryphon, proportionate to their respective ownership interests. Under the terms of the agreement governing these additional contributions, in the event that either Cheniere or Warburg elects not to participate in any additional contribution, the other investor has the option to purchase the non-participating investor’s proportionate share. Assuming (i) that Gryphon makes subsequent capital calls for an aggregate of $75,000,000, (ii) that Cheniere elects not to participate in any of the capital calls and (iii) that Warburg elects to purchase all of Cheniere’s proportionate share, and giving effect to Cheniere’s sale to Gryphon of 6,740 shares of Gryphon common stock in July 2001 and its sale to Gryphon of 51,400 shares of Gryphon common stock in March 2002 (see Note 6), the Company’s effective interest in Gryphon, after giving effect to the conversion of Gryphon’s preferred stock, would be reduced to 8.0%.

 

There were no cash calls in 2003. However, during 2002 and 2001, Gryphon made cash calls totaling $60,000,000. Cheniere declined to participate in such cash calls, and Warburg elected to purchase all of Cheniere’s proportionate share of such cash calls. Also during 2001, Cheniere transferred 6,740 shares of Gryphon common stock to Gryphon in connection with the sale of licenses to certain seismic data. In March 2002, Cheniere sold 51,400 shares of its Gryphon common stock to Gryphon, subject to certain repurchase options (discussed below). As a result of these transactions, Cheniere’s ownership interest in Gryphon was reduced to 9.3% as of December 31, 2002.

 

In connection with the seismic license contributed to Gryphon upon its formation, Cheniere entered into an agreement with the third party issuer of the license. The agreement provided that Cheniere would pay a transfer fee to the third party in an aggregate amount of up to $2,500,000. Such transfer fee was contingent upon Gryphon’s completion of up to ten successful wells during the license period and within the license area. Cheniere’s existing and contingent obligations under this agreement were fully discharged in March 2002 in connection with its sale of 51,400 shares of Gryphon common stock to Gryphon and the related assumption by Gryphon of these obligations.

 

During 2002, as a result of Gryphon’s cumulative losses and preferred dividend arrearages, Cheniere’s basis of its investment in Gryphon was reduced to zero, but not below zero, because Cheniere does not guarantee any obligations of Gryphon and is not committed to provide additional financial support to Gryphon. Cheniere’s equity share of Gryphon’s losses for 2002 was $2,184,847, calculated by applying Cheniere’s 100% common stock ownership interest to Gryphon’s net loss of $519,000, reducing such result for Gryphon’s preferred dividend arrearages of $5,844,746 for the year and limiting the cumulative amount of net loss recognized to the balance of Cheniere’s investment in Gryphon. The amount of the net loss that was not recorded by Cheniere as of December 31, 2002 was $4,179,000. For 2001, Cheniere’s equity share of Gryphon’s losses was $2,974,191, calculated by applying Cheniere’s 100% common stock ownership interest to Gryphon’s net income of $84,000 and reducing such result for Gryphon’s preferred dividend arrearages of $3,058,191 for the year. As of December 31, 2003, the amount of Gryphon’s preferred dividends in arrears was $17,125,936.

 

Prior to January 1, 2003, activities related to Cheniere’s investment in Gryphon were accounted for using the equity method of accounting. Accordingly, for the period prior to 2003, the summarized financial information relative to Gryphon is set forth below (in thousands):

 

     December 31,
2002


Current assets

   $ 12,215

Oil and gas properties, full cost method

     91,007

Fixed assets

     458

Current liabilities

     11,870

Long-term liabilities

     —  

Deferred tax liabilities

     2,043

 

50


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

     Year Ended
December 31,


 
     2002

    2001

 

Revenues

   $ 11,143     $ 2,382  

Income (loss) from continuing operations

     (674 )     82  

Net income (loss)

     (519 )     84  

Preferred dividends in arrears

     (5,845 )     (3,058 )

Cheniere’s equity in losses from unconsolidated affiliate

     (2,185 )     (2,974 )

 

The following items represent the differences between Cheniere’s equity share of Gryphon’s net assets and the balance in Cheniere’s investment in unconsolidated affiliate (in thousands):

 

     December 31,
2002


 

Cheniere’s equity share of Gryphon’s net assets

   $ 4,767  

Gryphon losses not yet recorded by Cheniere

     4,179  

Preferred stock dividends in arrears

     (9,349 )

Excess of Cheniere cost basis

     (500 )

Gryphon offering expenses

     903  
    


Cheniere’s investment basis

   $ —    
    


 

NOTE 7—INVESTMENT IN LIMITED PARTNERSHIP

 

In August 2002, Cheniere entered into an agreement with entities controlled by Michael S. Smith (“Smith”) to sell a 60% interest in the Freeport site and project. On February 27, 2003, Cheniere sold its interest in the site and project to Freeport LNG Development, L.P. (“Freeport LNG”), in which the Company held a 40% limited partner interest. Smith holds a 60% limited partner interest in Freeport LNG. Cheniere recovered $1,740,426, in costs it had incurred on the project and received an additional $5,000,000 ($2,500,000 during 2003 and $2,500,000 in January 2004) from Freeport LNG. For the funding of Freeport LNG project development costs, Smith also committed to contribute up to $9,000,000 and to allocate available proceeds from any sales of options or capacity reservations and/or proceeds from loans related to capacity reservations to these costs. In connection with the closing, Cheniere issued warrants to Smith to purchase 700,000 shares of Cheniere common stock at a price of $2.50 per share, exercisable for a period of 10 years.

 

Effective March 1, 2003, Cheniere sold a 10% limited partner interest in Freeport LNG to an affiliate of Contango Oil & Gas Company (“Contango”) for $2,333,333 payable over time, including the cancellation of the Company’s $750,000 short-term note payable. Cheniere also issued warrants to Contango to purchase 300,000 shares of Cheniere common stock at a price of $2.50 per share, exercisable for a period of 10 years. As a result of the sale, Cheniere now holds a 30% limited partner interest in Freeport LNG.

 

The Company accounted for the transfer of the site and planned LNG receiving terminal to Freeport LNG in accordance with Emerging Issues Task Force Issue No. 01-2, Interpretations of APB Opinion No. 29. Accordingly, Cheniere recorded a $4,760,000 gain on sale of LNG assets to the extent of the 60% interest not retained.

 

The Company accounts for its 30% limited partnership investment in Freeport LNG using the equity method of accounting. During 2003, Cheniere received installment payments totaling $2,500,000 from Freeport LNG, which amounts were recorded as a reduction to the basis of the Company’s investment in the partnership. In addition, Cheniere’s 30% limited partner interest in the operations of Freeport LNG resulted in the Company

 

51


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

sharing in the net loss of the partnership in the amount of $4,471,529 for 2003. This non-cash loss reduced the basis of Cheniere’s investment in Freeport LNG to zero.

 

The financial position of Freeport LNG at December 31, 2003 and the results of Freeport LNG’s operations for the year ended December 31, 2003 and for the period from inception (December 1, 2002) through December 31, 2003 are summarized as follows (in thousands):

 

     December 31,
2003


 

Current assets

   $ 295  

Fixed assets, net, and security deposit

     150  
    


Total assets

   $ 445  
    


Current liabilities

   $ 5,887  

Partners’ capital

     (5,442 )
    


Total liabilities and partners’ capital

   $ 445  
    


 

     Year Ended,
December 31,
2003


    Inception
(December 1, 2002)
through
December 31, 2003


 

Loss from continuing operations

   $ (14,940 )   $ (15,832 )

Net loss

     (14,940 )     (15,832 )

Cheniere’s equity in losses from limited partnership

     (4,472 )     (4,472 )

 

As of December 31, 2003, the Company’s investment in Freeport LNG was reduced to zero and the amount of the net loss in the partnership not recorded by Cheniere was $278,071.

 

NOTE 8—MINORITY INTEREST IN LIMITED PARTNERSHIP

 

In May 2003, Cheniere formed a limited partnership, Corpus Christi LNG, L.P. (“Corpus LNG”) to develop an LNG receiving terminal near Corpus Christi, Texas. Under the terms of the limited partnership agreement, Cheniere contributed its technical expertise and know-how, and all of the work in progress related to the Corpus Christi project, in exchange for a 66.7% interest in Corpus LNG.

 

Cheniere’s consolidated financial statements include the accounts of Corpus LNG. The $3,015,468 minority interest included in the consolidated statement of operations for the year ended December 31, 2003 is equal to the entire net loss of Corpus LNG due to Cheniere’s investment basis being zero and the minority owner’s 100% funding of project expenses through December 31, 2003.

 

NOTE 9—NOTES PAYABLE

 

At December 31, 2003, Cheniere had an outstanding debt obligation of $1,000,000 on its line of credit with a commercial bank. The balance was repaid in January 2004. At December 31, 2002, Cheniere had a $750,000 short-term note payable outstanding. This note was canceled in March 2003 as discussed below.

 

Set forth below is a description of financing facilities used by the Company under which financing cash inflows and outflows occurred during the three years ended December 31, 2003.

 

52


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

July 2003—Commercial Bank Financing

 

In July 2003, Cheniere established a $5,000,000 line of credit with a commercial bank, with an initial borrowing base of $2,000,000. The facility is secured by the assets of the Company, and its term, as amended, runs through December 31, 2004. Borrowings bear interest at the bank’s prime rate plus 2.5% per annum, and a commitment fee of 0.5% per annum is assessed on the unused borrowing base capacity. The interest and commitment fee are payable quarterly. A loan origination fee of 1% of the initial borrowing base was paid at closing. At December 31, 2003, Cheniere had a debt obligation of $1,000,000 and an $865,142 letter of credit outstanding against this line of credit. The $1,000,000 debt obligation was repaid in January 2004.

 

February 2003—Promissory Note

 

In February 2003, Cheniere executed a promissory note payable in the amount of $225,000. The proceeds of the note were used to pay certain costs related to the Company’s 3-D seismic database.

 

The note bore interest at a rate of approximately 12% per annum and was secured by a pledge of the Company’s oil and gas receivables. In July 2003, Cheniere repaid the balance outstanding on the promissory note payable. The note and related security agreement were canceled.

 

June 2002—LNG Receiving Terminal Financing

 

In June 2002, Cheniere received a $750,000 payment for the sale of two options to purchase an aggregate of up to a 20% interest in its Freeport LNG receiving terminal project. The payment was refundable in the event an option was not exercised. The potential repayment was secured by an 8% note payable executed by Cheniere. In March 2003, an option was exercised, the note payable canceled, and the payment applied to the purchase price per the terms of the agreement.

 

March 2002—$500,000 Bridge Financing

 

In March 2002, the Company entered into a short-term bridge financing arrangement with an unrelated third-party lender. The amount of the borrowing was $500,000. The term was 120 days. Interest was payable monthly at 10% per annum. Warrants were issued to the lender for the purchase of 150,000 shares of Cheniere common stock, exercisable at a price of $2.50 per share on or before March 7, 2012. In addition, Cheniere extended the term to March 7, 2012 on existing warrants for the purchase of 255,417 shares held by parties affiliated with the lender. Based on the Black-Scholes model, the warrants issued (150,000 shares) and the extension of existing warrants (255,417 shares) in connection with this financing arrangement have an aggregate value of $241,939. Debt discount of $163,045 was recorded based on the relative fair values of the note payable and the warrants. An additional 50,000 warrants were required to be issued to the lender for each month or partial month for which the principal remained unpaid after April 7, 2002. The Company repaid the loan on April 22, 2002, resulting in a loss on early extinguishment of debt in the amount of $100,544, which is classified as an ordinary loss in the Company’s statement of operations. Cheniere also issued an additional 50,000 warrants to the lender, valued at $24,054 based on the Black-Scholes model.

 

NOTE 10—DEFERRED REVENUE

 

On December 23, 2003, Cheniere LNG Services, Inc. (“Cheniere LNG Services”), a wholly-owned subsidiary of Cheniere, entered into a shareholders agreement whereby it became a minority owner of J&S Cheniere S.A., a Switzerland joint-stock company (“J&S Cheniere”). The majority owner is J&S Group S.A. (“J&S Group”). J&S Cheniere was formed for the purpose of buying, selling and trading LNG. Under the

 

53


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

shareholders agreement, Cheniere LNG Services identifies and assists with LNG-related business opportunities that it determines are appropriate for J&S Cheniere. Cheniere LNG Services is not required to offer any particular business opportunities nor funding to J&S Cheniere. Cheniere LNG Services has no board of director representation nor does it participate in the day-to-day management of J&S Cheniere. All financing of the business opportunities will be provided by J&S Group should it determine that a business opportunity is appropriate for J&S Cheniere. However, J&S Group is not required to fund any particular business opportunity. Cheniere accounts for this investment using the cost method of accounting. At December 31, 2003, Cheniere’s investment basis was zero.

 

Also on December 23, 2003, Cheniere LNG, Inc. (“Cheniere LNG”), a wholly-owned subsidiary of Cheniere, and J&S Cheniere entered into an option agreement providing J&S Cheniere an option to purchase LNG storage tank capacity and regas capacity of up to 200 Mmcf/d in each of Cheniere LNG’s Sabine Pass and Corpus Christi LNG facilities. Following execution of the option agreement, $1,000,000 was paid by J&S Cheniere to Cheniere LNG in January 2004. At December 31, 2003, the $1,000,000 was included in accounts receivable. It was recorded as deferred revenue because the option fee is refundable if Cheniere LNG does not receive FERC approval for at least one of the terminals or it does not proceed with the development of at least one of the terminals. Upon FERC approval and other related approvals and receipt of permits for each terminal, J&S Cheniere has 60 days to exercise its option at each terminal. The option agreement contemplates negotiation of a definitive terminal use agreement for each of the facilities, which will specify the terms and conditions of the purchase and sale of the capacity and related services. Cheniere LNG will record the option fee as revenue once it is no longer subject to refund.

 

NOTE 11—INCOME TAXES

 

From its inception, the Company has recorded losses for both financial reporting purposes and for federal income tax reporting purposes. Accordingly, the Company is not presently a taxpayer and has not recorded a provision for income taxes in any of the periods presented in the accompanying financial statements.

 

At December 31, 2003, the Company had net operating loss (“NOL”) carryforwards for tax reporting purposes of approximately $26,500,000. In accordance with SFAS No. 109, a valuation allowance equal to the net tax benefit for deferred taxes has been established due to the uncertainty of realizing the benefit of such NOL carryforwards.

 

54


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Significant components of the Company’s deferred tax assets and liabilities at December 31, 2003 and 2002 are as follows:

 

     December 31,

 
     2003

    2002

 

Deferred tax assets

                

NOL carryforwards

   $ 9,809,102     $ 8,226,583  

Oil and gas properties and fixed assets

     —         70,169  

Investment in unconsolidated affiliate

     513,190       513,190  

LNG Terminal Development

     1,303,499       —    
    


 


       11,625,791       8,809,942  
    


 


Deferred tax liabilities

                

Oil and gas properties and fixed assets

     56,181       —    
    


 


       56,181       —    
    


 


Net deferred tax assets

     11,569,610       8,809,942  

Less: valuation allowance

     (11,569,610 )     (8,809,942 )
    


 


     $ —       $ —    
    


 


 

NOL carryforwards expire starting in 2012 extending through 2023. Certain of the Company’s NOLs are subject to per year availability under Internal Revenue Code Section 382 change of ownership limitations.

 

The gross change in the valuation allowance for deferred tax assets was approximately $2,759,668, $(2,582,183) and $7,739,165 during the years ended December 31, 2003, 2002 and 2001, respectively.

 

NOTE 12—WARRANTS

 

As of December 31, 2003, Cheniere has issued and outstanding 1,299,583 warrants for the purchase of its common stock. The Company has reserved an equal number of shares of common stock for issuance upon the exercise of its outstanding warrants. Warrants issued by the Company do not confer upon the holders thereof any voting or other rights of a stockholder of the Company. The Company has granted warrants in connection with certain of its debt or equity financings and as compensation for services. In instances where warrants were granted in connection with financings, such warrants were valued based on the estimated fair market value of the stock at the date of issuance. Where warrants were issued for services, fair value was calculated using the Black-Scholes pricing model. The terms of warrants outstanding at December 31, 2003 range from approximately three to fourteen years, with a weighted average remaining life of 5.5 years. Prices at which the warrants are exercisable range from $1.06 to $11.50 per share, with a weighted average exercise price of $3.30 per share at December 31, 2003. Information related to Cheniere’s warrants is summarized in the following table:

 

     December 31,

     2003

    2002

    2001

Outstanding at beginning of period

     2,593,521       2,850,288       2,758,621

Warrants issued

     1,716,250       312,500       91,667

Warrants exercised

     (1,082,093 )     —         —  

Warrants canceled

     (1,928,095 )     (569,267 )     —  
    


 


 

Outstanding at end of period

     1,299,583       2,593,521       2,850,288
    


 


 

Weighted average exercise price of warrants outstanding

   $ 3.30     $ 4.06     $ 4.47
    


 


 

Weighted average remaining contractual life of warrants outstanding

     5.5 years       2.7 years       1.8 years

 

55


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table summarizes information about warrants outstanding at December 31, 2003:

 

Exercise Prices


  Number
Outstanding


  Weighted Average
Years Remaining
Contractual Life


$9.50 – $11.50

  25,000   0.7

$7.50

  12,500   0.7

$5.50 – $6.00

  276,250   6.4

$3.00

  50,000   1.3

$2.50

  725,000   6.8

$1.06 – $1.75

  210,833   1.8
   
   
    1,299,583    
   
   

 

In February 2003, in connection with the sale of a 60% interest in its Freeport LNG project, the Company issued warrants valued at $540,015 to purchase 700,000 shares of Cheniere common stock. The Company also issued warrants to purchase 241,250 shares of Cheniere common stock to a former employee of the Company and the current President and Chief Operating Officer of Freeport LNG, in replacement of his options to purchase 241,250 shares of Cheniere common Stock. The number and exercise prices of the warrants were the same as the options replaced and ranged from $1.06 to $12.00 per share. The Company issued warrants valued at $173,576 to purchase 225,000 shares of Cheniere common stock to LNG consultants for services previously performed for the Company. In connection with the sale of a 10% interest in the limited partnership, the Company issued warrants valued at $241,893 to purchase 300,000 shares of Cheniere common stock to the purchaser.

 

In April 2003, the Company issued warrants to purchase 250,000 shares of Cheniere common stock at $2.50 per share to its Chief Executive Officer as a signing bonus. At the time of issue, the current market price was $1.80 per share. The warrants vest one year from the date of issue.

 

In August 2003, the Company issued 378,308 shares of common stock in exchange for the surrender of warrants to purchase 700,000 shares in a cashless transaction. The warrants were exercisable at $2.50 per share based on the then-current market price of $5.44 per share.

 

NOTE 13—STOCK-BASED COMPENSATION

 

In 1997, the Company established the Cheniere Energy, Inc. 1997 Stock Option Plan, as amended (the “Option Plan”), which allows for the issuance of options to purchase up to 2,500,000 shares of Cheniere common stock. The Company has reserved 2,500,000 shares of common stock for issuance upon the exercise of options which have been granted or which may be granted. The Company had granted options on 2,147,500 shares which were outstanding or had been exercised as of December 31, 2003. The term of options granted under the Option Plan is generally five years. Vesting varies, but generally occurs over three or four years, in increments of 33% or 25%, respectively, on each anniversary of the grant date. All options granted under the Option Plan have exercise prices equal to or greater than fair market value at the date of grant.

 

56


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

A summary of the status of the Company’s stock options is presented below:

 

     December 31,

 
     2003

    2002

    2001

 

Outstanding at beginning of period

     1,983,611       1,741,111       884,236  

Options granted at an exercise price of $4.62 per share

     50,000       —         —    

Options granted at an exercise price of $4.45 per share

     50,000       —         —    

Options granted at an exercise price of $2.70 per share

     50,000       —         —    

Options granted at an exercise price of $2.38 per share

     —         —         20,000  

Options granted at an exercise price of $2.16 per share

     —         —         20,000  

Options granted at an exercise price of $1.85 per share

     250,000       —         —    

Options granted at an exercise price of $1.70 per share

     —         —         100,000  

Options granted at an exercise price of $1.45 per share

     50,000       —         —    

Options granted at an exercise price of $1.44 per share

     20,000       —         —    

Options granted at an exercise price of $1.27 per share

     20,000       —         —    

Options granted at an exercise price of $1.25 per share

     —         267,500       —    

Options granted at an exercise price of $1.20 per share

     —         30,000       —    

Options granted at an exercise price of $1.06 per share

     —         —         760,000  

Options granted at an exercise price of $0.93 per share

     —         50,000       —    

Options exercised

     (187,500 )     —         —    

Options converted to warrants

     (241,250 )     —         —    

Options canceled / expired

     (84,861 )     (105,000 )     (43,125 )
    


 


 


Outstanding at end of period

     1,960,000       1,983,611       1,741,111  
    


 


 


Exercisable at end of period

     1,161,980       1,106,111       664,444  
    


 


 


Weighted average exercise price of options outstanding

   $ 2.23     $ 2.07     $ 2.21  
    


 


 


Weighted average exercise price of options exercisable

   $ 2.49     $ 2.56     $ 3.16  
    


 


 


Weighted average fair value of options granted during the period

   $ 1.60     $ 1.20     $ 0.76  
    


 


 


Weighted average remaining contractual life of options outstanding

     2.9 years       3.4 years       4.1 years  

 

57


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table summarizes information about fixed options outstanding at December 31, 2003:

 

Exercise Prices


 

Options Outstanding


 

Options
Exercisable


 

Number
Outstanding


 

Weighted Average
Years Remaining
Contractual Life


 

Number
Outstanding


$6.00

  210,000   0.8   205,313

$4.62

  50,000   4.6   25,000

$4.45

  50,000   4.5   —  

$2.75

  175,000   1.6   175,000

$2.70

  50,000   4.4   —  

$2.38

  20,000   2.0   13,333

$2.16

  20,000   2.1   13,333

$1.94

  237,500   1.9   237,500

$1.85

  250,000   4.3   —  

$1.45

  50,000   4.0   —  

$1.44

  20,000   3.1   6,667

$1.27

  20,000   4.1  

—  

$1.25

  247,500   4.0   122,500

$1.20

  30,000   3.7   10,000

$1.06

  480,000   2.9   336,667

$0.93

  50,000   3.8   16,667
   
     
    1,960,000       1,161,980
   
     

 

NOTE 14—RELATED PARTY TRANSACTIONS

 

In December 2003, Cheniere LNG Services entered into a shareholders agreement whereby Cheniere LNG Services acquired a minority interest in J&S Cheniere. One of the directors of J&S Cheniere is the brother of Charif Souki, Cheniere’s Chairman, President and Chief Executive Officer.

 

In April 2002, Charles M. Reimer, Cheniere’s then-President, advanced amounts totaling $30,000 to the Company. Subsequent to its sale of producing oil and gas properties, Cheniere repaid the advances on April 25, 2002, with accrued interest at 10% per annum totaling $122.

 

In March 2002, Cheniere sold 51,400 shares of its Gryphon common stock to Gryphon, subject to an option to repurchase the shares, thereby reducing its interest in Gryphon from 20.2% to 13.7% on an as-converted basis. Such sale was made in connection with the settlement of a lawsuit filed by Fairfield Industries Incorporated against Cheniere and Gryphon. In connection with its sale of Gryphon common stock to Gryphon, Cheniere had a one-year option to repurchase all or a portion of the 51,400 shares at a price of $50 per share if exercised within 120 days of the sale or at prices increasing ratably thereafter to approximately $68 per share one year after the sale. As consideration for the shares, Gryphon agreed to make payments in full satisfaction of certain existing and contingent obligations of Cheniere totaling $3,561,692. Cheniere, Gryphon and Fairfield Industries reached a settlement agreement whereby a lawsuit and related claims asserted by Fairfield against Cheniere and Gryphon were dismissed.

 

In conjunction with certain of the Company’s private placements of equity in 2001, placement fees have been paid to Investors Administration Services, Limited (“IAS”), a company in which the brother of Charif Souki, Cheniere’s then-Chairman, was a principal. Placement fees to IAS totaled $30,000 for 2001 and were expensed.

 

58


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Commencing October 1, 2001, Cheniere has made office space available for use by Keith F. Carney, a non-management director. The pro rata amount of office lease expense related to that space was $4,400, $4,500 and $1,125 in 2003, 2002 and 2001, respectively.

 

In September 2001, the Company made a payment of $40,000 to Charif Souki, its then-Chairman, representing consulting fees for the months of October 2001 through January 2002.

 

In July 2001, Cheniere sold to Gryphon one of its two licenses to certain 3D seismic data covering an additional 3,000 square miles. Gryphon agreed to pay Cheniere’s accounts payable of $1.3 million and the remaining commitment of $2.9 million related to the reprocessing of the data. In connection with the transaction, Cheniere also transferred to Gryphon 6,740 shares of Gryphon common stock, valued at approximately $418,000 or $62 per share, based on the estimated fair market value of the Gryphon common stock, which considered the fair value of such stock at the formation of Gryphon and any significant changes in Gryphon’s operations or market conditions since that date. The proceeds at closing of $1.3 million were allocated as a reduction to the carrying amount of Cheniere’s investment in Gryphon ($418,000) and unproved oil and gas properties ($882,000). Cheniere retains one license to the seismic data.

 

In June 2001, Cheniere sold to Gryphon for $3,500,000 one of its two licenses to the Seitel 3D seismic data. Gryphon paid $853,197 in cash to Cheniere and agreed to pay $2,646,803 of Cheniere’s obligations related to the reprocessing of the data. Cheniere remained responsible for payment of the final $1,061,692 in reprocessing charges upon final delivery of all reprocessed data, which was received in 2003. This payment obligation was assumed by Gryphon in connection with Cheniere’s March 2002 sale of 51,400 shares of Gryphon common stock to Gryphon.

 

In April 2001, the Company sold an interest in a prospect to Gryphon. Gryphon paid Cheniere $225,563 for a 50% interest in the related leases and will pay a disproportionate share of the drilling costs on terms representative of what a third party would pay for participation in the prospect generated by Cheniere.

 

NOTE 15—COMMITMENTS AND CONTINGENCIES

 

Lease Commitments

 

In November 2000, the Company entered into an office lease agreement with a term, as extended, which ran through March 31, 2004. In October 2003, the Company entered into a lease agreement related to new office space with a term which runs from December 2003 through April 2014. Beginning in April 2004, Cheniere’s monthly lease rental is $21,543 and escalates to $24,235 beginning in February 2009 through the remaining term of the lease. The Company has an option to renew the lease for an additional five years at the then-current market rate. Cheniere is also responsible for its proportionate share of the building operating expenses. In connection with the lease, Cheniere has issued a letter of credit in favor of the landlord in the amount of $865,142. In addition, the lease creates a lien on all property that Cheniere places on the premises as a security interest for payment of amounts due under the terms of the lease.

 

In December 2003, the Company entered an agreement to lease software for use in its exploration activities. This lease provides for annual payments of $230,000 per year to be made prior to the beginning of each contract year. The lease runs through December 31, 2006.

 

59


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Future annual minimum lease payments are as follows:

 

Year Ending

December 31,


   Operating
Lease


2004

   $ 455,000

2005

     522,000

2006

     299,000

2007

     305,000

2008

     305,000

Thereafter

     1,711,000
    

Total

   $ 3,597,000
    

 

Cheniere’s total rental expense for office space for the years ending December 31, 2003, 2002 and 2001 was $128,351, $131,038 and $157,146, respectively.

 

LNG Commitments

 

In connection with the acquisition of the option to lease the Freeport LNG receiving terminal site in June 2001, Cheniere issued 500,000 shares of common stock valued at $1,150,000, or $2.30 per share, the closing price of Cheniere’s common stock on the date of the transaction, to the seller of the lease option. The Company also committed to issue an additional 750,000 shares of its common stock to the seller of the lease option in April 2003, for which Cheniere received no additional consideration. These shares were issued in April 2003 at a value of $1,312,500, or $1.75 per share, the closing price of Cheniere’s common stock on the date of issuance. The seller of the lease option also obtained the right to receive a royalty payment on the gross quantities of gas processed through LNG terminals owned by Cheniere LNG. The royalty is calculated based on $0.03 per Mcf on the quantities of gas processed through LNG terminals that Cheniere owns, subject to a maximum royalty of approximately $10,950,000 per year. In 2002, a long-term lease was secured by Freeport LNG, and at the closing of the sale of Cheniere’s interests in the site and project, Freeport LNG assumed the obligation to pay the royalty with respect to gas processed and produced at the Freeport LNG facility.

 

The Company’s obligations under LNG site options are renewable on an annual or semiannual basis. Cheniere may terminate its obligations at any time by electing not to renew or by exercising the options.

 

On December 23, 2003, Cheniere LNG and J&S Cheniere entered into an option agreement under which J&S Cheniere has an option to purchase LNG storage tank capacity and regas capacity of up to 200 Mmcf/d day in each of Cheniere LNG’s Sabine Pass and Corpus Christi LNG facilities. Following execution of the option agreement, $1,000,000 was paid by J&S Cheniere to Cheniere LNG in January 2004. The option fee is refundable if Cheniere LNG does not receive Federal Energy Regulatory Commission (FERC) approval for at least one of the terminals or it does not proceed with the development of at least one of the terminals. Upon FERC approval and other related approvals and receipt of permits for each terminal, J&S Cheniere has 60 days to exercise its option at each terminal. The option agreement contemplates negotiation of a definitive TUA for each of the facilities, which will specify the terms and conditions of the purchase and sale of the capacity and related services.

 

Legal proceedings

 

The Company has been and may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. Management regularly analyzes current information and as

 

60


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

necessary, provides accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of December 31, 2003, there were no threatened or pending legal matters that would have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

 

NOTE 16—BUSINESS SEGMENT INFORMATION

 

The Company’s business activities are conducted within two principal operating segments: LNG receiving terminal development and oil and gas exploration and development. These segments operate independently, and there are no intercompany revenues or expenses between them.

 

The LNG receiving terminal segment develops LNG receiving terminals in the United States. An experienced LNG development team has been assembled and is actively working on developing LNG receiving terminals on the U.S. Gulf Coast.

 

The exploration and development segment explores for oil and natural gas using a regional database of 7,000 square miles of regional 3D seismic data. Exploration efforts are focused on the shallow waters of the Gulf of Mexico offshore of Louisiana and Texas and consist primarily of seismic data interpretation and prospect generation activities. The segment participates in drilling and production operations with industry partners on the prospects that Cheniere generates. In April 2002, Cheniere sold all of its working interest in producing properties at that time. During the second half of 2002 and all of 2003, all of Cheniere’s revenue resulted from overriding royalty interests in new oil and gas discoveries.

 

61


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

     Segments

             
     LNG
Receiving
Terminal


    Oil & Gas
Exploration and
Development


    Total

    Corporate
and
Other(1)


    Total
Consolidated


 

As of or for the Year Ended December 31, 2003:

                                        

Revenues

   $ —       $ 657,467     $ 657,467     $ —       $ 657,467  

Depreciation, Depletion, and Amortization

     141,933       191,745       333,678       95,002       428,680  

Income (loss) from operations

     (6,846,471 )     465,723       (6,380,748 )     (2,637,402 )     (9,018,150 )

Equity in net loss of equity method investee(2)

     (4,471,529 )     —         (4,471,529 )     —         (4,471,529 )

Gain on sale of LNG assets(3)

     4,760,000       —         4,760,000       —         4,760,000  

Gain on sale of limited partnership interest(4)

     423,454       —         423,454       —         423,454  

Total Assets

     2,952,816       20,219,541       23,172,357       1,418,400       24,590,757  

Investment in equity method investees

     —         —         —         —         —    

Expenditures for additions to long-lived assets

     —         2,553,794       2,553,794       532,879       3,086,673  

As of or for the Year Ended December 31, 2002:

                                        

Revenues

   $ —       $ 239,055     $ 239,055     $ —       $ 239,055  

Depreciation, Depletion, and Amortization

     108,600       190,311       298,911       69,651       368,562  

Income (loss) from operations

     (1,665,482 )     (41,294 )     (1,706,776 )     (1,988,131 )     (3,694,907 )

Equity in net loss of equity method investee(5)

     —         (2,184,847 )     (2,184,847 )     —         (2,184,847 )

Gain on sales of assets(6)

     —         340,257       340,257       —         340,257  

Total Assets

     2,506,584       17,730,029       20,236,613       822,777       21,059,390  

Investment in equity method investees

     —         —         —         —         —    

Expenditures for additions to long-lived assets

     125,000       2,828,381       2,953,381       14,506       2,967,887  

As of or for the Year Ended December 31, 2001:

                                        

Revenues

   $ —       $ 2,372,632     $ 2,372,632     $ —       $ 2,372,632  

Depreciation, Depletion, and Amortization

     16,800       1,115,647       1,132,447       111,381       1,243,828  

Ceiling test write-down(7)

     —         5,126,248       5,126,248       —         5,126,248  

Income (loss) from operations

     (2,149,299 )     (4,375,566 )     (6,524,865 )     (2,184,784 )     (8,709,649 )

Equity in net loss of equity method investee(5)

     —         (2,974,191 )     (2,974,191 )     —         (2,974,191 )

Total Assets

     1,367,190       22,724,819       24,092,009       931,667       25,023,676  

Investment in equity method investees

     —         3,747,199       3,747,199       —         3,747,199  

Expenditures for additions to long-lived assets

     1,350,000       5,067,039       6,417,039       248,386       6,665,425  

(1) Includes corporate activities and certain intercompany eliminations.
(2) Represents equity in net loss of Cheniere’s investment in Freeport LNG. The Company’s investment basis was reduced to zero as of December 31, 2003.
(3) In February 2003, Cheniere sold a 60% interest in its Freeport LNG terminal project to Freeport LNG. A gain of $4,760,000 was recognized on the sale. See Note 7 to the Consolidated Financial Statements.
(4) In March 2003, Cheniere sold a 10% limited partner interest in Freeport LNG to a third party and recognized a gain of $423,454. See Note 7 to the Consolidated Financial Statements.
(5) For the years 2002 and 2001, Cheniere recognized losses of $2,184,847 and $2,974,191, respectively, on its equity investment in Gryphon. Its investment basis was reduced to zero as of December 31, 2002. Effective January 1, 2003, Cheniere began using the cost method of accounting for this investment. See Note 6 to the Consolidated Financial Statements.
(6) In April 2002, the Company sold its producing wells and recognized a gain of $340,257.
(7) During 2001, the Company was required to write down its investment in oil and gas properties in accordance with full cost accounting rules. See Note 2 to the Consolidated Financial Statements.

 

62


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

NOTE 17—SUPPLEMENTAL CASH FLOW DISCLOSURES AND DISCLOSURES OF NON-CASH TRANSACTIONS

 

In December 2003 in connection with the Corpus Christi LNG project, the minority interest owner contributed two tracts of land valued at $310,500 to be used for the LNG terminal site.

 

In August 2003, the Company issued 378,308 shares of common stock in exchange for the surrender of warrants to purchase 700,000 shares in a cashless transaction. The warrants were exercisable at $2.50 per share based on the then-current market price of $5.44 per share.

 

In April 2003, pursuant to a contingent contractual obligation related to Cheniere’s 2001 acquisition of an option to lease the Freeport LNG terminal site, the Company issued 750,000 shares of its common stock, valued at $1,312,500 on the date of issuance, to satisfy a closing requirement related to Cheniere’s February 2003 sale of a 60% interest in its Freeport LNG project.

 

In February 2003, in connection with the sale of a 60% interest in its Freeport LNG site and project, the Company issued warrants valued at $540,015 to purchase 700,000 shares of Cheniere common stock. As a result of the closing on the Freeport transaction, the Company issued warrants valued at $173,576 to purchase 225,000 shares of Cheniere common stock to LNG consultants for services previously performed for the Company. In connection with the sale of a 10% interest in Freeport LNG, the Company issued warrants valued at $241,893 to purchase 300,000 shares of Cheniere common stock to the purchaser, and the purchaser canceled the $750,000 note previously payable by Cheniere. These transactions are described in more detail in Notes 7 and 15 to the Consolidated Financial Statements.

 

In 2002, Cheniere transferred computer equipment with a net book value of $29,001 to an exploration consulting company as compensation for its services. The Company sold 51,400 shares of its Gryphon common stock to Gryphon in consideration for their assumption of certain existing and contingent liabilities of Cheniere totaling $3,561,692. In connection with the sale of the Company’s proved oil and gas properties, Cheniere issued warrants to purchase 50,000 shares of Cheniere common stock to a consultant valued at $22,695. The Company issued warrants to purchase 200,000 shares of Cheniere common stock and extended the expiration period on existing warrants to purchase 255,417 shares of Cheniere common stock, all at a value of $265,993, in connection with a short-term bridge financing arrangement with an unrelated third-party lender. Cheniere issued warrants to purchase 50,000 shares of Cheniere common stock to a consultant valued at $39,269 for assistance in marketing the Company’s LNG terminal capacity. The Company issued 12,500 stock options valued at $10,435 to a consultant for assistance in developing the LNG terminal business. Cheniere issued warrants to purchase 12,500 shares of Cheniere common stock to an investor relations consultant valued at $10,435. During 2002, the Company accrued an additional $96,777 for the services of an LNG project consultant. As of December 31, 2002, Cheniere had an accrued liability to this consultant of $366,777, of which $166,777 was the estimated value of warrants to be issued to purchase 225,000 shares of Cheniere common stock. These warrants were issued in February 2003 at an exercise price of $2.50 per common share.

 

In 2001, Cheniere issued warrants to a consultant to purchase 50,000 shares of Cheniere common stock valued at $93,000. The Company issued 500,000 shares valued at $1,150,000 to acquire an LNG site lease option at Freeport. The Company sold 6,740 shares of Gryphon common stock with a fair market value of $417,880 to Gryphon in connection with the sale of a license to 3D seismic data; additional value ascribed to the sale of seismic data was $256,141 (see Note 14 to Consolidated Financial Statements). In connection with the Company’s sale of licenses to 3D seismic data to Gryphon, Gryphon assumed liabilities for reprocessing charges of $6,820,824 and made a payment on behalf of Cheniere in the amount of $5,847,533 during 2001. The

 

63


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Company accrued $270,000 as of December 31, 2001, related to an obligation to issue to a consultant an equity participation in its Freeport LNG project. The Company issued 25,000 stock options valued at $17,000 to a consultant for assistance in securing long-term supplies of LNG.

 

The Company paid $41,107, $55,920 and $105,813 for interest in the years ended December 31, 2003, 2002 and 2001, respectively. The Company has not paid any income taxes in the three years ended December 31, 2003.

 

The values of securities issued by the Company in connection with the transactions described above are based on third party arms-length negotiated prices or the fair value as calculated using the Black-Scholes pricing model.

 

NOTE 18—LIQUIDITY

 

The financial statements as of December 31, 2001 were prepared on a going concern basis, which contemplated continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As of December 31, 2001, the Company had experienced recurring losses from operations and, during 2001, had negative cash flows from operating activities. In addition, the Company had a working capital deficiency of $530,242 and an accumulated deficit of $18,024,485 as of December 31, 2001. These considerations raised substantial doubt about Cheniere’s ability to continue as a going concern as of December 31, 2001.

 

At December 31, 2003, however, Cheniere’s working capital was $155,526. In January 2004, Cheniere received net proceeds of $13,884,750 from a private placement of 1,100,000 shares of Cheniere common stock. The Company also received the remaining $2,500,000 from Freeport LNG, which was payable pursuant to the sale of Cheniere’s 60% interest in the Freeport LNG project. Also, in January and February 2004, a total of 557,056 shares were issued pursuant to exercises of warrants and stock options resulting in additional net proceeds of $1,309,559. The pro forma effect of these transactions, had they been consummated as of December 31, 2003, would have been to increase Cheniere’s working capital to $17,849,835.

 

Management expects that it will meet all of its liquidity requirements for the next twelve months through a combination of cash balances, collection of receivables, issuances of our debt or equity securities, issuances of common stock pursuant to exercises by the holders of existing warrants and options, sales of regas capacity in its planned LNG receiving terminals, sales of prospects generated by its exploration group, borrowings under its line of credit and cash flows from current operations.

 

NOTE 19—SUBSEQUENT EVENTS

 

In January 2004, the Company issued 1,100,000 shares of Cheniere common stock in a private placement under Regulation D to twelve accredited investors for a total consideration of $14,850,000, or $13.50 per share. The Company paid a 6.5% sales commission totaling $965,250, resulting in $13,884,750 in net proceeds received from the offering. The proceeds of the private placement will be used primarily for the development of LNG receiving terminals and for general corporate purposes.

 

In January 2004, the Company repaid the $1,000,000 balance owing under its $5,000,000 line of credit with a commercial bank using proceeds from the private placement of Cheniere common stock and other available funds.

 

In January and February 2004, 472,056 shares of Cheniere common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $922,059. An additional 131,751 shares of Cheniere common stock were issued in a cashless exercise of options to purchase 157,945 shares.

 

64


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

In January and February 2004, a total of 85,000 shares of Cheniere common stock were issued pursuant to the exercise of warrants. Proceeds of $387,500 were received at the exercise prices.

 

In January 2004, Cheniere received the remaining $2,500,000 from Freeport LNG, which was payable pursuant to Cheniere’s sale of its 60% interest in the Freeport LNG project. This payment to Cheniere was accelerated as a result of Freeport LNG completing a transaction for the sale of terminal capacity for which Freeport LNG received payment of a capacity reservation fee of $10,000,000 in January 2004. This $2,500,000 payment to Cheniere was recorded in January 2004 as a reimbursement from limited partnership investment as Cheniere’s investment in Freeport LNG had been reduced to zero as of December 31, 2003.

 

On January 29, 2004, Cheniere’s shareholders approved the Cheniere Energy, Inc. 2003 Stock Incentive Plan (the “2003 Plan”). The 2003 Plan is a broad-based incentive plan, which allows for the issuance of stock options, purchased stock awards, bonus stock awards, stock appreciation rights, phantom stock awards, restricted stock awards, performance awards, and other stock or performance-based awards to employees, consultants and non-employee directors to purchase up to 1,000,000 shares of Cheniere common stock. The Company has reserved 1,000,000 shares of common stock for issuance upon the exercise of awards that have been granted or which may be granted. The term of any award under the 2003 Plan may not exceed a period of ten years.

 

In February 2004, under the 2003 Plan, 383,000 shares were issued to employees and directors of the Company in the form of bonus and restricted stock awards. The Company recorded $1,915,000 of compensation expense in February 2004 related to the issuance of 127,667 shares (bonus stock awards) valued at $15.00 per share that were fully vested on the date of grant. Compensation related to the 255,333 restricted shares will be accrued over the next two years. The restricted shares will vest on each of the first and second anniversaries of the grant date.

 

65


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table includes the pro forma effects as of December 31, 2003 of Cheniere’s common stock issued pursuant to the private placement in January 2004, common stock issued upon warrant and stock option exercises in January and February 2004, the repayment of the Company’s note payable in January 2004 and the reimbursement from limited partnership investment in January 2004:

 

     Historical

    Unaudited

 
       Pro Forma Adjustments

    Pro Forma

 
       Debits

    Credits

   

Current Assets

   $ 4,487,352     13,884,750 (1)   1,000,000 (2)   $ 21,181,661  
             922,059 (3)              
             387,500 (4)              
             2,500,000 (5)              

Oil and Gas Properties

     19,134,954                   19,134,954  

LNG Site Costs

     310,500                   310,500  

Other

     657,951                   657,951  
    


             


Total Assets

   $ 24,590,757                 $ 41,285,066  
    


             


Current Liabilities

   $ 4,331,826     1,000,000 (2)         $ 3,331,826  

Deferred Revenue

     1,000,000                   1,000,000  

Minority Interest

     120,032                   120,032  

Stockholders’ Equity

                            

Common Stock

     49,465           3,300 (1)     54,831  
                   1,811 (3)        
                   255 (4)        

Additional Paid-in-Capital

     48,034,244           13,881,450 (1)     63,223,187  
                   920,248 (3)        
                   387,245 (4)        

Accumulated Deficit

     (28,944,810 )         2,500,000 (5)     (26,444,810 )
    


             


Total Stockholders’ Equity

     19,138,899                   36,833,208  
    


             


Total Liabilities and Stockholders’ Equity

   $ 24,590,757                 $ 41,285,066  
    


             



The pro forma adjustments include the following items:

(1) Issuance of 1,100,000 shares of common stock in a private placement, net of offering costs
(2) Repayment of $1,000,000 outstanding balance in notes payable
(3) Issuance of common stock pursuant to exercise of options to purchase common stock
(4) Issuance of common stock pursuant to exercise of warrants to purchase common stock
(5) Cash reimbursement received after Cheniere’s investment in Freeport LNG was reduced to zero.

 

66


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA

(unaudited)

 

Costs Incurred in Oil and Gas Producing Activities

 

Presented below are costs incurred in oil and gas property acquisition, exploration and development activities:

 

    Year Ended December 31,

    2003

   2002

   2001

Acquisition of properties

                   

Proved properties

  $ —      $ —      $ —  

Unproved properties

    936,814      130,822      1,899,154

Exploration costs

    1,577,543      2,682,548      2,908,654

Development costs

    —        15,011      99,800
   

  

  

Total

  $ 2,514,357    $ 2,828,381    $ 4,907,608
   

  

  

Proportional share of unconsolidated affiliate(1)

         $ 43,496,000    $ 36,576,000
          

  


(1) Effective January 1, 2003, Cheniere began accounting for its investment in Gryphon using the cost method of accounting. Prior to that time, Cheniere accounted for this investment using the equity method of accounting. Accordingly, the amounts for 2002 and 2001 represent Cheniere’s proportional share, based on its 100% common stock ownership, of the costs incurred in oil and gas activities of Gryphon. Upon the conversion of Gryphon’s preferred shares, such proportional share of Gryphon activities would be reduced to 9.3%, or $4,045,000 for 2002.

 

Included in the above amounts for the years ended December 31, 2003, 2002 and 2001 were $1,063,996, $849,240 and $947,813, respectively, of capitalized general and administrative expenses, capitalized interest expense and capitalized debt discount directly related to property acquisition, exploration and development.

 

Capitalized Costs Related to Oil and Gas Producing Activities

 

The following table presents total capitalized costs of proved and unproved properties and accumulated depreciation, depletion and amortization related to oil and gas producing operations:

 

     December 31,

 
     2003

    2002

 

Proved properties

   $ 1,223,020     $ 857,388  

Unproved properties

     18,047,802       16,751,347  
    


 


       19,270,822       17,608,735  

Accumulated depreciation, depletion and amortization

     (135,868 )     (14,506 )
    


 


     $ 19,134,954     $ 17,594,229  
    


 


Proportional share of unconsolidated affiliate(1)

           $ 89,698,000  
            



(1) Effective January 1, 2003, Cheniere began accounting for its investment in Gryphon using the cost method of accounting. Prior to that time, Cheniere accounted for this investment using the equity method of accounting. Accordingly, the amount for 2002 represents Cheniere’s proportional share, based on its 100% common stock ownership, of the capitalized costs related to oil and gas producing activities of Gryphon. Upon the conversion of Gryphon’s preferred shares, such proportional share of Gryphon’s capitalized costs related to oil and gas producing activities would be reduced to 9.3%, or $8,342,000 at December 31, 2002.

 

67


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA—(Continued)

(unaudited)

 

Results of Operations from Oil and Gas Producing Activities

 

The results of operations from oil and gas producing activities are as follows:

 

     Year Ended December 31,

 
     2003

    2002

    2001

 

Revenues

   $ 657,467     $ 239,055     $ 2,372,632  

Production Costs

     —         (90,038 )     (420,242 )

Depreciation, depletion and amortization

     (121,362 )     (74,566 )     (1,029,239 )

Ceiling test write-down

     —         —         (5,126,248 )

Income tax benefit (expense)

     —         —         —    
    


 


 


Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)

   $ 536,105     $ 74,451     $ (4,203,097 )
    


 


 


Equity in results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) of unconsolidated affiliate(1)

           $ 828,000     $ 907,000  
            


 



(1) Effective January 1, 2003, Cheniere began accounting for its investment in Gryphon using the cost method of accounting. Prior to that time, Cheniere accounted for this investment using the equity method of accounting. Accordingly, the amounts for 2002 and 2001 represent Cheniere’s proportional share, based on its 100% common stock ownership, of the results of operations from oil and gas producing activities (excluding corporate overhead and interest costs). Such proportional share will be reduced to 9.3% upon the conversion of Gryphon’s preferred shares, resulting in a decrease in Cheniere’s proportional interest in the results of operations from oil and gas producing activities to $77,000 for 2002.

 

Reserve Quantities

 

Estimates of proved reserves of Cheniere and the related standardized measure of discounted future net cash flow information are based on the reports generated by the Company’s independent petroleum engineers, Sharp Petroleum Engineering, Inc. in 2003 and Ryder Scott Company in 2001 and substantially, but not wholly, based on the report generated by Ryder Scott Company in 2002, in accordance with the rules and regulations of the SEC. The independent engineers’ estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data provided by the Company. These estimates represent the Company’s interest in the reserves associated with its properties. All of the Company’s oil and gas reserves are located within the United States or its territorial waters.

 

68


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA—(Continued)

(unaudited)

 

The Company’s estimates of its proved reserves and proved developed reserves of oil and gas as of December 31, 2003, 2002 and 2001 and the changes in its proved reserves are as follows:

 

     2003

    2002

    2001

 
     Oil
(Bbls)


   

Gas

(Mcf)


    Oil
(Bbls)


   

Gas

(Mcf)


    Oil
(Bbls)


   

Gas

(Mcf)


 

Proved reserves:

                                    

Beginning of year

   3,980     1,333,000     15,088     3,245,000     19,874     4,568,000  

Revisions of prior estimates

   (3,830 )   (1,093,920 )   —       —       (2,178 )   (780,226 )

Production

   (17 )   (123,392 )   (495 )   (91,470 )   (2,608 )   (542,774 )

Sale of reserves in place

   —       —       (14,598 )   (3,177,278 )   —       —    

Extensions, discoveries and other additions

   4,990     797,091     3,985     1,356,748     —       —    
    

 

 

 

 

 

End of year

   5,123     912,779     3,980     1,333,000     15,088     3,245,000  
    

 

 

 

 

 

Interest in proved reserves of unconsolidated affiliate—end of year(1)

               371,808     27,508,000     210,151     17,468,000  
                

 

 

 

Proved developed reserves:

                                    

Beginning of year

   1,606     503,000     15,088     3,245,000     16,913     3,982,000  
    

 

 

 

 

 

End of year

   3,024     759,095     1,606     503,000     15,088     3,245,000  
    

 

 

 

 

 

Interest in proved developed reserves of unconsolidated affiliate—end of year(1)

               165,421     16,332,000     192,569     13,022,000  
                

 

 

 


(1) Effective January 1, 2003, Cheniere began accounting for its investment in Gryphon using the cost method of accounting. Prior to that time, Cheniere accounted for this investment using the equity method of accounting. Accordingly, the amounts for 2002 and 2001 represent Cheniere’s proportional share, based on its 100% common stock ownership, of the proved reserves and proved developed reserves of Gryphon. Upon the conversion of Gryphon’s preferred shares, such proportional share of Gryphon reserves would be reduced to 9.3%, or proved reserves of 34,578 Bbls and 2,558,000 Mcf and proved developed reserves of 15,384 Bbls and 1,519,000 Mcf at December 31, 2002. Such reserves were not considered in the Company’s calculation of depreciation, depletion and amortization or the calculation of its ceiling test.

 

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and future amounts and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of proved undeveloped reserves are inherently less certain than estimates of proved developed reserves. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, geologic success and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, the Company’s reserves may be subject to downward or upward revision based upon production history, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors.

 

69


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA—(Continued)

(unaudited)

 

Standard Measure of Discounted Future Net Cash Flows

 

The standardized measure of discounted future net cash flows was calculated by applying year-end prices (adjusted for location and quality differentials) to estimated future production, less future expenditures (based on year-end costs) to be incurred in developing and producing the Company’s proved reserves and the estimated effect of future income taxes based on the current tax law. The resulting future net cash flows were discounted using a rate of 10% per annum.

 

The standardized measure of discounted future net cash flow amounts contained in the following tabulation does not purport to represent the fair market value of oil and gas properties. No value has been given to unproved properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. Future realization of oil and gas prices over the remaining reserve lives may vary significantly from current prices. In addition, the method of valuation utilized, based on year-end prices and costs and the use of a 10% discount rate, is not necessarily appropriate for determining fair value.

 

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:

 

     December 31,

 
     2003

    2002

    2001

 

Future gross revenues

   $ 5,231,382     $ 6,343,537     $ 8,076,063  

Less—future costs:

                        

Production

     (134,251 )     (163,683 )     (2,570,550 )

Development

     —         (56,250 )     (910,800 )

Income Taxes

     —         —         —    
    


 


 


Future net cash flows

     5,097,131       6,123,604       4,594,713  

Less—10% annual discount for estimated timing of cash flows

     (819,396 )     (992,141 )     (1,671,812 )
    


 


 


Standardized measure of discounted future net cash flows

   $ 4,277,735     $ 5,131,463     $ 2,922,901  
    


 


 


 

70


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA—(Continued)

(unaudited)

 

The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows:

 

     Year Ended December 31,

 
     2003

    2002

    2001

 

Standardized measure—beginning of period

   $ 5,131,463     $ 2,922,901     $ 20,618,002  

Sales of oil and gas produced, net of production costs

     (657,467 )     (149,017 )     (1,952,390 )

Extensions, discoveries and other additions

     3,691,594       5,208,984       —    

Revisions to previous quantity estimates, timing and other

     (4,944,824 )     (28,799 )     (675,047 )

Net changes in prices and production costs

     726,671       —         (21,242,047 )

Sale of reserves in place

     —         (2,212,670 )     —    

Development costs incurred

     —         15,011       99,800  

Changes in estimated development costs

     —         (624,947 )     (1,556,205 )

Net changes in income taxes

     —         —         5,062,716  

Accretion of discount

     330,298       —         2,568,072  
    


 


 


Standardized measure—end of period

   $ 4,277,735     $ 5,131,463     $ 2,922,901  
    


 


 


Standardized measure—end of period— proportional interest in reserves of unconsolidated affiliate(1)

           $ 95,211,000     $ 28,778,000  
            


 


Current prices at year-end, used in standardized measure

                        

Oil (per Bbl)

   $ 31.00     $ 29.23     $ 19.00  

Gas (per Mcf)

     5.63       4.64       2.61  

(1) Effective January 1, 2003, Cheniere began accounting for its investment in Gryphon using the cost method of accounting. Prior to that time, Cheniere accounted for this investment using the equity method of accounting. Accordingly, the amounts for 2002 and 2001 represent Cheniere’s proportional share, based on its 100% common stock ownership, of the standardized measure of Gryphon’s proved oil and gas reserves. Such proportional share of Gryphon’s standardized measure will be reduced to 9.3% upon the conversion of Gryphon’s preferred shares, resulting in a decrease in Cheniere’s proportional interest in the standardized measure of unconsolidated affiliate to $8,855,000 at December 31, 2002.

 

The Company may receive amounts different than those incorporated into the standardized measure of discounted cash flow for a number of reasons, including changes in prices. Therefore, the present value shown above should not be construed as the current market value of the estimated oil and gas reserves attributable to the Company’s properties.

 

71


Table of Contents

CHENIERE ENERGY, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

SUMMARIZED QUARTERLY FINANCIAL DATA—(Continued)

(unaudited)

 

Quarterly Financial Data—(unaudited)

 

    

First

Quarter


    Second
Quarter


    Third
Quarter


    Fourth
Quarter


    Year

 

Year ended December 31, 2003:

                                        

Revenues

   $ 110,120     $ 121,300     $ 135,245     $ 290,802     $ 657,467  

Gross profit(1)

     51,428       29,989       34,242       113,128       228,787  

Income (loss) from operations

     (862,744 )     (1,185,749 )     (2,924,546 )     (4,045,111 )     (9,018,150 )

Net income (loss)(3)

     3,121,309       (1,624,242 )     (2,387,021 )     (4,398,063 )     (5,288,017 )

Net income (loss) per share—basic and diluted

   $ 0.23     $ (0.11 )   $ (0.16 )   $ (0.27 )   $ (0.36 )

Year ended December 31, 2002:

                                        

Revenues

   $ 161,604     $ 37,955     $ 21,998     $ 17,498     $ 239,055  

Gross profit(1)

     (18,423 )     (52,528 )     (111,912 )     (36,682 )     (219,545 )

Income (loss) from operations(2)

     (1,318,501 )     (1,636,668 )     (1,478,002 )     738,264       (3,694,907 )

Net income (loss)(2)

     (2,530,967 )     (2,366,029 )     (1,474,972 )     739,660       (5,632,308 )

Net loss per share—basic and diluted

   $ (0.19 )   $ (0.18 )   $ (0.11 )   $ 0.06     $ (0.42 )

(1) Revenues less operating expenses other than general and administrative.
(2) Fourth quarter 2002 includes $1,740,426 in recoveries of general and administrative expenses reimbursable under the terms of an agreement related to Cheniere’s sale of its Freeport LNG site, which closed in February 2003.
(3) The first quarter of 2003 includes $4,760,000 and $423,454 in gains, respectively, on sales of 60% of the Freeport LNG terminal project to Freeport LNG and a 10% limited partner interest in Freeport LNG to a third party. See Note 7 to the Consolidated Financial Statements.

 

72


Table of Contents
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

 

On October 17, 2002, Cheniere Energy, Inc. (the “Registrant”) dismissed PricewaterhouseCoopers LLP (“PWC”) as the Registrant’s principal accountant and engaged Mann Frankfort Stein & Lipp CPAs, L.L.P. (“Mann Frankfort”) as the principal accountant for the fiscal year ending December 31, 2002. The change in principal accountant was approved by the audit committee of the Registrant’s board of directors.

 

In connection with the audits of the Registrant’s fiscal year ended December 31, 2001, and the subsequent interim period through such dismissal, there were no disagreements between PWC and the Registrant on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements if not resolved to the satisfaction of PWC, would have caused them to make a reference thereto in their report on the financial statements for such year.

 

The reports of PWC on the consolidated financial statements of the Registrant and subsidiaries as of and for the year ended December 31, 2001 did not contain any adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope, or accounting principles, except the report on the consolidated financial statements as of and for the year ended December 31, 2001 included an explanatory paragraph regarding the existence of substantial doubt about the Registrant’s ability to continue as a going concern.

 

During the Company’s fiscal year ending December 31, 2001 and through October 17, 2002, the Registrant did not consult Mann Frankfort with respect to the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Registrant’s consolidated financial statements, or any other matters or reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.

 

ITEM 9A. CONTROLS AND PROCEDURES

 

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Securities Exchange Act of 1934, as amended (“Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our President, Chief Executive Officer and Chairman of the Board and our Vice President & Chief Financial Officer, Secretary and Treasurer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our President, Chief Executive Officer and Chairman of the Board and our Vice President & Chief Financial Officer, Secretary and Treasurer concluded that our disclosure controls and procedures are effective.

 

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

PART III

 

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

 

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Item 10 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement involving the election of directors, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2003.

 

73


Table of Contents
ITEM 11. EXECUTIVE COMPENSATION

 

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Item 11 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement involving the election of directors, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2003.

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Item 12 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement involving the election of directors, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2003.

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

 

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Item 13 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement involving the election of directors, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2003.

 

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Item 14 of Part III is incorporated by reference from Cheniere’s definitive proxy statement involving the election of directors, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2003.

 

PART IV

 

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

 

(a) Financial Statements, Schedules and Exhibits

 

(1) Financial Statements—Cheniere Energy, Inc. and Subsidiaries:

 

Reports of Independent Accountants

   37

Consolidated Balance Sheet

   39

Consolidated Statement of Operations

   40

Consolidated Statement of Stockholders’ Equity

   41

Consolidated Statement of Cash Flows

   42

Notes to Consolidated Financial Statements

   43

Supplemental Information to the Consolidated Financial Statements

   67

 

The financial statements of Freeport LNG Development, L.P. for the period from December 1, 2002 to December 31, 2003, for which Cheniere used the equity method of accounting, have been filed as part of this report on Form 10-K. (See Item 15(d))

 

The financial statements of Gryphon Exploration Company for the two fiscal years ended December 31, 2002, for which Cheniere used the equity method of accounting, have been filed as part of this report on Form 10-K. (See Item 15(d))

 

74


Table of Contents
(2) Financial Statement Schedules

 

All consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.

 

(3) Exhibits

 

Exhibit No.

  

Description


3.1*    Amended and Restated Certificate of Incorporation of Cheniere Energy, Inc. (“Cheniere”) (Incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-8 (File No. 333-112379), filed on January 30, 2004)
3.2*    Amended and Restated By-laws of Cheniere, as amended through January 29, 2004. (Incorporated by reference to Exhibit 4.3 of the Company’s Registration Statement on Form S-8 (File No. 333-112379), filed on January 20, 2004)
4.1*    Specimen Common Stock Certificate of Cheniere. (Incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-1 (File No. 333-10905), filed on August 27, 1996)
4.2*    Certificate of Designations, Preferences and Rights of Series A Convertible Preferred Stock of Gryphon Exploration Company. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (File No. 000-09092), filed on October 20, 2000)
10.1*†    Cheniere Energy, Inc. 1997 Stock Option Plan. (Incorporated by reference to Exhibit 10.25 of the Company’s Quarterly on Form 10-Q for the quarter ended November 30, 1997 (File No. 000-09092), filed on January 14, 1998)
10.2*†    Amendment No. 1 to Cheniere Energy, Inc. 1997 Stock Option Plan. (Incorporated by reference to Exhibit 10.27 of the Company’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 000-09092), filed on March 29, 2000)
10.3*†    Amendment No. 2 to Cheniere Energy, Inc. 1997 Stock Option Plan. (Incorporated by reference to Exhibit 4.7 of the Company’s Registration Statement on Form S-8 (File No. 333-111457), filed on December 22, 2003)
10.4*†    Amendment No. 3 to Cheniere Energy, Inc. 1997 Stock Option Plan. (Incorporated by reference to Exhibit 8 of the Company’s Registration Statement on Form S-8 (File No. 333-111457), filed on December 22, 2003)
10.5*†    Amendment No. 4 to Cheniere Energy, Inc. 1997 Stock Option Plan. (Incorporated by reference to Exhibit 9 of the Company’s Registration Statement on Form S-8 (File No. 333-111457), filed on December 22, 2003)
10.6*†    Cheniere Energy, Inc. 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 4.5 of the Company’s Registration Statement on Form S-8 (File No. 333-112379), filed on January 30, 2004)
10.7*    Seismic Data Purchase Agreement, dated June 21, 2000 between Seitel Data Ltd. and Cheniere. (Incorporated by reference to Exhibit 10.39 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000 (File No. 000-09092), filed on August 11, 2000)
10.8*    Contribution and Subscription Agreement, dated as of September 15, 2000, by and among the Company, Gryphon Exploration Company and the other investors listed therein. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 000-09092), filed on October 20, 2000)
10.9*    Stockholders Agreement, dated as of October 11, 2000. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 000-09092), filed on October 20, 2000)

 

75


Table of Contents
Exhibit No.

  

Description


10.10*    Settlement and Purchase Agreement, dated and effective as of June 14, 2001 by and between Cheniere, CXY Corporation, Crest Energy, L.L.C., Crest Investment Company and Freeport LNG Terminal, LLC. (Incorporated by reference to Exhibit 10.10 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 (File No. 001-16383), filed on April 1, 2002)
10.11*    Stock Transfer Agreement, dated March 19, 2002, by and between Gryphon Exploration Company and Cheniere. (Incorporated by reference to Exhibit 10.11 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 (File No. 001-16383) filed on April 1, 2002)
10.12*    Contribution Agreement, dated as of August 26, 2002, by and among Freeport LNG Investments, LLC, Freeport LNG-GP, Inc., Cheniere, Cheniere LNG, Inc. and Freeport LNG Terminal, LLC. (Incorporated by reference to Exhibit 2 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on September 4, 2002)
10.13*    Extension and Amendment to Contribution Agreement, dated as of September 19, 2002, by and among Freeport LNG Investments, LLC, Freeport LNG-GP, Inc., Cheniere, Cheniere LNG, Inc. and Freeport LNG Terminal, LLC. (Incorporated by reference to Exhibit 2 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on September 26, 2002)
10.14*    Second Extension and Amendment to Contribution Agreement, effective as of October 4, 2002, by and among Freeport LNG Investments, LLC, Freeport LNG-GP, Inc., Cheniere, Cheniere LNG, Inc. and Freeport LNG Terminal, LLC. (Incorporated by reference to Exhibit 1 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on November 5, 2002)
10.15*    Third Amendment to Contribution Agreement, effective as of February 27, 2003, by and among Freeport LNG Investments, LLC, Freeport LNG-GP, Inc., Cheniere, Cheniere LNG, Inc. and Freeport LNG Terminal, LLC. (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on March 7, 2003)
10.16*    Amended and Restated Limited Partnership Agreement of Freeport LNG Development, L.P., dated as of February 27, 2003, by and among Freeport LNG-GP, Inc., Freeport LNG Investments, LLC and Cheniere LNG, Inc. (Incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on March 7, 2003)
10.17*    First Amendment to Amended and Restated Partnership Agreement of Freeport LNG Development, L.P., dated as of December 20, 2003, by and among Freeport LNG-GP, Inc., Freeport LNG Investments, LLC and Cheniere LNG, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on December 19, 2003)
10.18*    Warrant to Purchase Common Stock, dated as of February 27, 2003, issued by Cheniere in favor of Freeport LNG Investments, LLC. (Incorporated by reference to Exhibit 10.6 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on March 7, 2003)
10.19*    Option Agreement, dated February 27, 2003, by and between Freeport LNG Investments, LLC and Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.7 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on March 7, 2003)
10.20*    Partnership Interest Purchase Agreement, dated as of March 1, 2003, among Contango Sundance, Inc., Contango Oil & Gas, Cheniere LNG, Inc. and Cheniere. (Incorporated by reference to Exhibit 10.8 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on March 7, 2003)

 

76


Table of Contents
Exhibit No.

  

Description


10.21*    Warrant to Purchase Common Stock, dated March 1, 2003, issued by Cheniere in favor of Contango Sundance, Inc. (Incorporated by reference to Exhibit 10.9 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on March 7, 2003)
10.22*    Limited Partnership Agreement of Corpus Christi LNG, L.P., dated as of May 15, 2003, by and among Corpus Christ LNG-GP, Inc., BPU LNG and Cheniere. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-16383), filed on June 11, 2003)
10.23*    Credit Agreement, dated as of July 25, 2003, by and between Cheniere, Cheniere LNG, Inc., Cheniere Energy Operating Co., Inc., Cheniere LNG Services, Inc., Cheniere-Gryphon Management, Inc. and Sterling Bank. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 001-16383), filed on August 13, 2003)
10.24*    First Amendment to Credit Agreement, dated as of October 24, 2003, by and between Cheniere, Cheniere LNG, Inc., Cheniere Energy Operating Co., Inc., Cheniere LNG Services, Inc., Cheniere-Gryphon Management, Inc. and Sterling Bank. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003 (File No. 001-16383), filed on November 13, 2003)
10.25    Omnibus Agreement, dated as of December 20, 2003, by and among Freeport LNG Development, L.P., Freeport LNG-GP, Inc., and ConocoPhillips Company.
21    Subsidiaries of Cheniere Energy, Inc.
23.1    Consent of Mann Frankfort Stein & Lipp CPAs, L.L.P.
23.2    Consent of PricewaterhouseCoopers LLP
23.3    Consent of KPMG LLP
23.4    Consent of Hein & Associates LLP
23.5    Consent of Sharp Petroleum Engineering, Inc.
23.6    Consent of Ryder Scott Company
31.1    Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2    Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1    Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2    Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Incorporated by reference
Management contract or compensatory plan or arrangement

 

(b) Reports On Form 8-K:

 

November 14, 2003—The Company filed a Current Report on Form 8-K on November 14, 2003 to report the Company’s results of operations for the third quarter ended September 30, 2003.

 

December 22, 2003—The Company filed a Current Report on Form 8-K on December 22, 2003 to report that it had entered into the First Amendment to the Amended and Restated Limited Partnership Agreement,

 

77


Table of Contents

dated as of December 20, 2003, by and among Freeport LNG-GP, Inc., Freeport LNG Investments, LLC, the Company, and Contango Sundance, Inc.

 

(d) Freeport LNG Development, L.P. Financial Statements, for which Cheniere used the equity method of accounting for the period from December 1, 2002 to December 31, 2003, are filed as a part of this report beginning on page 81.

 

Gryphon Exploration Company Financial Statements, for which Cheniere used the equity method of accounting for the two fiscal years ending December 31, 2002, are filed as a part of this report beginning on page 90.

 

78


Table of Contents

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

CHENIERE ENERGY, INC.

    (Registrant)

By:   /S/    CHARIF SOUKI
   
   

Charif Souki

President, Chief Executive Officer and

Chairman of the Board

Date: March 25, 2004

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature


  

Title


 

Date


/S/    CHARIF SOUKI        


Charif Souki

  

President, Chief Executive Officer and Chairman of the Board (Principal Executive Officer)

  March 25, 2004

/S/    WALTER L. WILLIAMS        


Walter L. Williams

  

Vice Chairman of the Board and Director

  March 25, 2004

/S/    DON A. TURKLESON        


Don A. Turkleson

  

Vice President & Chief Financial Officer, Secretary & Treasurer (Principal Financial Officer)

  March 25, 2004

/S/    CRAIG K. TOWNSEND        


Craig K. Townsend

  

Vice President & Controller (Principal Accounting Officer)

  March 25, 2004

/S/    NUNO BRANDOLINI        


Nuno Brandolini

  

Director

  March 25, 2004

/S/    KEITH F. CARNEY        


Keith F. Carney

  

Director

  March 25, 2004

/S/    PAUL J. HOENMANS        


Paul J. Hoenmans

  

Director

  March 25, 2004

/S/    DAVID B. KILPATRICK        


David B. Kilpatrick

  

Director

  March 25, 2004

/S/    J. ROBINSON WEST        


J. Robinson West

  

Director

  March 25, 2004

 

 

79


Table of Contents

INDEX TO FINANCIAL STATEMENTS

 

Freeport LNG Development, L.P. Audited Financial Statements

 

Independent Auditor’s Report

   81

Balance Sheet

   82

Statements of Operations

   83

Statement of Partners’ Capital (Deficit)

   84

Statement of Cash Flows

   85

Notes to the Financial Statements

   86

 

Gryphon Exploration Company Audited Financial Statements

 

Reports of Independent Accountants

   90

Balance Sheet

   92

Statements of Income (Loss)

   93

Statements of Stockholders’ Equity

   94

Statements of Cash Flows

   95

Notes to Financial Statements

   96

Supplemental Information to the Financial Statements

   109

 

80


Table of Contents

INDEPENDENT AUDITOR’S REPORT

 

February 10, 2004

 

To the Partners of

Freeport LNG Development, L.P., a Limited Partnership

Houston, Texas

 

We have audited the accompanying balance sheet of Freeport LNG Development, L.P., a Delaware limited partnership (a development stage limited partnership), as of December 31, 2003, and the related statements of operations, changes in partners’ capital (deficit) and cash flows for the year then ended and for the period from inception (December 1, 2002) through December 31, 2003. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

 

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Freeport LNG Development, L.P., as of December 31, 2003, and the results of its operations and its cash flows for the year then ended and for the period from inception (December 1, 2002) through December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

 

HEIN & ASSOCIATES LLP

Phoenix, Arizona

 

 

81


Table of Contents

FREEPORT LNG DEVELOPMENT, L.P.

(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)

 

BALANCE SHEET

 

DECEMBER 31, 2003

 

ASSETS

 

Current assets:

      

Cash and cash equivalents

   $ 77,000

Prepaid expenses

     216,000

Other current assets

     2,000
    

Total current assets

     295,000

Property and equipment, net

     121,000

Security deposit

     29,000
    

TOTAL ASSETS

   $ 445,000
    

LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)

 

Current liabilities:

        

Accounts payable and accrued liabilities

   $ 3,386,000  

Amounts payable to limited partners

     2,501,000  
    


Total current liabilities

     5,887,000  

Commitments and Contingency (Notes 3 and 6)

        

Partners’ capital (deficit), including deficit accumulated during the development stage of $15,832,000.

     (5,442,000 )
    


TOTAL LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)

   $ 445,000  
    


 

 

See accompanying notes to the financial statements.

 

82


Table of Contents

FREEPORT LNG DEVELOPMENT, L.P.

(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)

 

STATEMENTS OF OPERATIONS

 

     For the Year
Ending
December 31, 2003


   Inception
(December 1, 2002)
through
December 31, 2003


REVENUES

   $ —      $ —  

EXPENSES:

             

Quintana site rental and related costs

     573,000      573,000

Personnel and related costs

     2,193,000      2,406,000

Engineering

     2,419,000      2,667,000

Environmental and special studies

     1,063,000      1,285,000

Purchase of limited partners start up and preconstruction cost (Note 4)

     5,000,000      5,000,000

Professional services

     3,068,000      3,152,000

Other general and administrative costs

     624,000      749,000
    

  

Total expenses

     14,940,000      15,832,000
    

  

NET LOSS

   $ 14,940,000    $ 15,832,000
    

  

 

 

 

See accompanying notes to the financial statements.

 

83


Table of Contents

FREEPORT LNG DEVELOPMENT, L.P.

(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)

 

STATEMENT OF PARTNERS’ CAPITAL (DEFICIT)

FOR THE YEAR FROM INCEPTION (DECEMBER 1, 2002)

THROUGH DECEMBER 31, 2003

 

     General
Partner


   Limited
Partners


   Retained
Deficit


    Total Partners’
Capital (Deficit)


 

Balances at inception (December 1, 2002)

   $ —      $ —      $ —       $ —    

Net loss

         —        —        (892,000 )     (892,000 )
    

  

  


 


Balances at December 31, 2002

     —        —        (892,000 )     (892,000 )

Capital contributions

     —        10,390,000      —         10,390,000  

Net loss

     —        —        (14,940,000 )     (14,940,000 )
    

  

  


 


Balances at December 31, 2003

   $ —      $ 10,390,000    $ (15,832,000 )   $ (5,442,000 )
    

  

  


 


 

 

 

See accompanying notes to the financial statements.

 

84


Table of Contents

FREEPORT LNG DEVELOPMENT, L.P.

(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)

 

STATEMENT OF CASH FLOWS

 

     For the Year
Ending
December 31, 2003


    Inception
(December 1, 2002)
through
December 31, 2003


 

OPERATING ACTIVITIES:

                

Net loss

   $ (14,940,000 )   $ (15,832,000 )

Adjustments to reconcile net loss to net cash used in operating activities:

                

Depreciation

     15,000       15,000  

Changes in assets and liabilities:

                

Prepaids and other assets

     (218,000 )     (218,000 )

Security deposits

     (29,000 )     (29,000 )

Accounts payable and accrued liabilities

     2,494,000       3,386,000  

Due to limited partners

     2,501,000       2,501,000  
    


 


Net cash used in operating activities

     (10,177,000 )     (10,177,000 )

INVESTING ACTIVITIES:

                

Purchase of property and equipment

     (136,000 )     (136,000 )

FINANCING ACTIVITIES:

                

Contributions from partners

     10,390,000       10,390,000  
    


 


Net increase in cash and cash equivalents

     77,000       77,000  

Cash and cash equivalents at beginning of period

     —         —    

Cash and cash equivalents at end of period

   $ 77,000     $ 77,000  
    


 


 

 

See accompanying notes to the financial statements.

 

85


Table of Contents

FREEPORT LNG DEVELOPMENT, L.P.

(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)

 

NOTES TO THE FINANCIAL STATEMENTS

 

1. SIGNIFICANT ACCOUNTING POLICIES:

 

Business Activity—Freeport LNG Development, L.P. (the “Partnership”) is in the process of developing and building a liquefied natural gas (LNG) receiving and regasification facility on Quintana Island, near Freeport, Texas (the “Facility”). After construction is completed, the Partnership will own and operate the Facility.

 

Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect certain reported amounts in the financial statements and accompanying notes. Actual results could differ from these estimates and assumptions.

 

Cash and Cash Equivalents—The Partnership considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

 

Property, Plant and Equipment—Property, plant and equipment are stated at cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets for financial reporting purposes. Expenditures for major renewals and betterments that extend the useful lives will be capitalized. Expenditures for normal maintenance and repairs will be expensed as incurred. When assets are sold or abandoned, the cost of the assets sold or abandoned and the related accumulated depreciation will be eliminated from the accounts and any gains or losses will be charged or credited to other income (expense) of the respective period. The estimated useful lives by classification are as follows:

 

Office Equipment

   5 years

Leasehold Improvements

   15 years

 

Revenue Recognition—Revenues will be recognized when the terminal use fees are earned.

 

Income Taxes—The Partnership files its Federal income tax return as a partnership under the Internal Revenue Code. In lieu of corporate income taxes, the partners of the Partnership are taxed on their proportionate share of the Partnership’s taxable income. Accordingly, no provision or liability has been recognized for federal income tax purposes for those periods, as taxes are the personal responsibility of the individual partners of the Partnership.

 

2. DEVELOPMENT STAGE OPERATIONS:

 

The Partnership was formed December 1, 2002. Operations have been devoted to preconstruction costs such as obtaining approvals from the Federal Energy Regulatory Commission (“FERC”), and obtaining the appropriate leases and permits, and completing the engineering and environmental studies necessary for further development of the Facility.

 

3. LIQUIDITY AND CONTINUED OPERATIONS:

 

The Partnership will ultimately need to obtain FERC and other approvals in order to construct and operate the Facility. In addition, there are significant engineering, procurement and construction costs to be incurred and additional feasibility studies to be performed.

 

Notwithstanding the foregoing, the Partnership believes it will continue as a going-concern through December 31, 2004 based on the favorable results of the studies completed to date, and the strong financial

 

86


Table of Contents

FREEPORT LNG DEVELOPMENT, L.P.

(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)

 

NOTES TO THE FINANCIAL STATEMENTS—(Continued)

 

backing of several of its partners and future customers. In addition to the funds received for capacity reservations, the Partnership expects to close on debt financing in 2004 to finance construction of the Facility based on an agreement reached with ConocoPhillips in 2003.

 

Ultimately the Partnership will need to obtain FERC, state and other approvals and it must obtain and close on sufficient project financing, successfully complete the construction of the Facility and achieve profitable operations. If it is unable to do so, the Partnership will be required to pursue other courses of action.

 

4. CONTRIBUTION BY LIMITED PARTNER:

 

The Partnership was formed with one General Partner, Freeport LNG-GP, Inc. (“Freeport GP”) and one Limited Partner, Freeport LNG Investments, LLC (“Investments LP”). The General Partner owned 0% and the Limited Partner owned 100% of the Partnership. The purpose of the limited partnership is to develop and operate the Facility.

 

In February 2003 the Partnership agreement was amended and restated (“Amended and Restated Partnership Agreement”) to provide for, among other things, the addition of Cheniere LNG Inc. (“Cheniere”) as an additional limited partner.

 

Cheniere has represented to the Partnership that, prior to the amendment of the Partnership agreement, Cheniere incurred costs related to the LNG Facility. These costs included research and development, various feasibility and environmental studies, preconstruction costs and other related start-up costs. Together these costs are referred to as Cheniere’s “know how.” The estimated fair value of the work performed by Cheniere was agreed to by all the partners to be $14,300,000. Cheniere had expensed all the costs as incurred.

 

The partners agreed that Cheniere would “contribute” know how valued at $9,300,000 to the Partnership for a 40% limited partner interest in the Partnership. The Partnership agreed to purchase the remaining know how from Cheniere for $5,000,000, payable in installments during 2003 of $2.5 million with the remaining $2.5 million due when the project receives FERC approval, or the Partnership receives a stipulated amount of cash from future customers for capacity reservations for the Facility.

 

The Amended and Restated Partnership Agreement also provided for Investments LP to fund the first $9,000,000 of capital to the Partnership, after which time all additional costs would be borne by the partners in relation to their respective ownership percentages.

 

Because Cheniere’s basis in the contributed assets was zero and the project is still in the preconstruction phase, no value is reflected on the balance sheet for Cheniere’s know how, and Cheniere’s capital account for accounting purposes is recorded at zero. The $5,000,000 due to Cheniere for the purchase of the remaining know how has been expensed in the statement of operations.

 

Subsequent to the contribution, Cheniere sold a 10 percent interest in the Partnership to Contango Oil and Gas Company.

 

In December of 2003, Freeport LNG Investments, LLC was converted to Freeport LNG Investments, LLLP (Delaware).

 

87


Table of Contents

FREEPORT LNG DEVELOPMENT, L.P.

(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)

 

NOTES TO THE FINANCIAL STATEMENTS—(Continued)

 

5. AGREEMENT WITH CONOCOPHILLIPS:

 

In December 2003, the Partnership, Freeport GP, and ConocoPhillips executed an omnibus agreement. This agreement governs several transactions among the entities, including the following:

 

  ConocoPhillips agreed to pay $10,000,000 for a capacity reservation on the Facility.

 

  ConocoPhillips and the Partnership agreed to a term sheet providing for ConocoPhillips to make a loan to cover a substantial majority of the facility’s anticipated construction costs, including interest during the construction phase. The debt service under this loan will be fully serviced by the ConocoPhillips Terminal Use Agreement (“TUA”). In addition, ConocoPhillips has agreed to make available a lender-of-last-resort financing facility for the Partnership’s remaining share of construction costs, if any. The debt service for this loan would be paid by the Partnership from available revenues.

 

  ConocoPhillips also agreed to purchase 50% of the stock of Freeport GP for $9,000,000. After the purchase of the stock, ConocoPhillips and Freeport GP will each appoint three persons to a board which will manage the construction and operation of the Facility.

 

  ConocoPhillips also agreed to the form of the Terminal Use Agreement which will govern the terms under which LNG is processed.

 

ConocoPhillips was not obligated to make the $10,000,000 payment for the capacity reservation until it received specific engineering and design studies, which did not occur until 2004, therefore as of December 31, 2003 the Partnership has not recorded a receivable for this amount. The required documents were provided subsequent to December 31, 2003 and the Partnership received the $10,000,000 payment in January 2004. The Partnership has recorded a liability at December 31, 2003, for the remaining $2,500,000 that is due to Cheniere as discussed in Note 4.

 

6. COMMITMENTS:

 

The Partnership has entered a lease agreement, dated December 12, 2002 and as amended March 1, 2003, with the Brazos River Harbor Navigation District for the lease of the land on which the Facility will be constructed. The lease requires the Partnership to use its best efforts to obtain FERC and all other approvals, and requires communications with the landlord regarding the status of the approvals. The lease may be terminated by either party if the Partnership has not obtained FERC approval by March 1, 2005, and may be terminated earlier by the landlord if the required communications are not made. The lease term is 30 years beginning on March 1, 2003, with six options to renew the lease for an additional 10 years for each option. The initial rent payment is $450,000 per year however, the lease contains escalation clauses which will increase the future minimum lease payment to $1,800,000 per year. The escalation will take effect the earlier of (a) 180 days following FERC approval, (b) the dates on which construction on the LNG Facility begins, or (c) March 1, 2005. The lease includes an option, which has been exercised. The option requires additional lease payments of $200,000 per year beginning in the year when the escalation takes effect. The lease rate may also increase based on increases in the Consumer Price Index (CPI).

 

Subsequent to December 31, 2003, the Partnership executed an additional lease for areas around the Facility for 29 years. The additional lease requires a $100,000 payment each year.

 

88


Table of Contents

FREEPORT LNG DEVELOPMENT, L.P.

(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)

 

NOTES TO THE FINANCIAL STATEMENTS—(Continued)

 

The following table presents the future minimum lease payments due under the original lease, the amendment and the additional lease (executed subsequent to December 31, 2003), assuming the fixed escalation begins on March 1, 2005, and ignoring any increases determined by an increase to the CPI index:

 

2004

   $ 550,000

2005

     2,100,000

2006

     2,100,000

2007

     2,100,000

2008

     2,100,000

Thereafter

     50,400,000
    

     $ 59,350,000
    

 

As of December 31, 2003, no deferred rent has been accrued for the escalation clause, as the Partnership has the right to terminate the lease should it be unable to obtain FERC approval.

 

Additionally, the lease provides that the Partnership will guarantee thru-put fees of $1,250,000 per year (subject to increase for the CPI index) to be received by the Dock Facilities operated by the port from carriers shipping LNG to the Facility. This guarantee begins 42 months after the aforementioned escalation date.

 

Capacity Reservations—Investments LP has entered into an agreement whereby it borrowed $5,000,000 from The Dow Chemical Company (“Dow”). In connection with this agreement, the Partnership agreed to reserve a stipulated capacity at the Facility for Dow. The Dow Capacity Reservation and the ConocoPhillips Capacity Reservation are expected to fully reserve for substantially all of the Facility’s anticipated capacity after completion of Phase 1 of the construction.

 

7. PROPERTY AND EQUIPMENT:

 

Property and equipment consists of:

 

Office equipment

   $ 97,000  

Leasehold improvements

     39,000  
    


Property and equipment

     136,000  

Less: accumulated depreciation

     (15,000 )
    


Total property and equipment, net

   $ 121,000  
    


 

8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES:

 

Accounts payable and accrued liabilities consists of the following:

 

Employee bonuses

   $ 476,000

Engineering and study costs

     1,447,000

Professional fees

     887,000

Investment banking advisor fees

     515,000

Other accrued liabilities and payables

     61,000
    

Total accounts payable and accrued liabilities

   $ 3,386,000
    

 

 

89


Table of Contents

Report of Independent Accountants

 

To the Board of Directors and Stockholders of

Gryphon Exploration Company:

 

We have audited the accompanying balance sheet of Gryphon Exploration Company, as of December 31, 2002, and the related statements of income (loss), stockholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

 

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the 2002 financial statements referred to above present fairly, in all material respects, the financial position of Gryphon Exploration Company, as of December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

 

KPMG LLP

 

March 14, 2003, except as to Note 13, which is as of February 27, 2004

Houston, Texas

 

90


Table of Contents

Report of Independent Accountants

 

To the Board of Directors and Stockholders of

Gryphon Exploration Company

 

In our opinion, the statements of income, of stockholders’ equity and of cash flows for the year ended December 31, 2001 present fairly, in all material respects, the results of operations and cash flows of Gryphon Exploration Company for the year ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

PRICEWATERHOUSECOOPERS LLP

 

March 29, 2002

Houston, Texas

 

91


Table of Contents

GRYPHON EXPLORATION COMPANY

 

BALANCE SHEET

(dollars in thousands, except share related items)

 

     December 31, 2002

 
ASSETS         

CURRENT ASSETS

        

Cash and Cash Equivalents

   $ 2,986  

Restricted Cash Deposits

     260  

Receivables from Joint Interest Owners and Revenue Receivables

     3,188  

Prepaid Expenses and Other

     5,781  
    


Total Current Assets

     12,215  

OIL AND GAS PROPERTIES, full cost method

        

Proved Properties, net

     54,322  

Unproved Properties, not subject to amortization

     36,685  
    


Total Oil and Gas Properties

     91,007  

FIXED ASSETS, net

     458  
    


Total Assets

   $ 103,680  
    


LIABILITIES AND STOCKHOLDERS’ EQUITY         

CURRENT LIABILITIES

        

Accounts Payable and Accrued Liabilities

   $ 5,773  

Advances from Joint Interest Owners

     1,875  

Revenue Payable

     5  

Short-term Note Payable

     2,865  

Hedge Liability

     1,352  
    


Total Current Liabilities

     11,870  
    


DEFERRED TAX LIABILITY

     2,043  

COMMITMENTS AND CONTINGENCIES (NOTE 10)

        

STOCKHOLDERS’ EQUITY

        

Preferred Stock, $.01 par value Authorized: 500,000 shares; Issued and Outstanding: 85,000 shares

     2  

Common Stock, $.01 par value Authorized: 4,000,000 shares; Issued: 145,600 shares Outstanding: 87,460 shares

     1  

Additional Paid-in-Capital

     93,160  

Retained Earnings (Deficit)

     (416 )

Treasury Stock

        

Recorded at cost—58,140 shares

     (2,980 )
    


Total Stockholders’ Equity

     89,767  
    


Total Liabilities and Stockholders’ Equity

   $ 103,680  
    


 

The accompanying notes are an integral part of these financial statements.

 

92


Table of Contents

GRYPHON EXPLORATION COMPANY

 

STATEMENTS OF INCOME (LOSS)

(dollars in thousands)

 

     Year ended
December 31,


 
     2002

    2001

 

Oil and Gas Revenue

   $ 12,495     $ 2,382  

Loss on Derivative Instruments

     (1,352 )     —    
    


 


       11,143       2,382  
    


 


Operating Costs and Expenses

                

Production Costs

     804       254  

Workover Costs

     3,226       —    

Depreciation, Depletion and Amortization

     6,521       1,769  

General and Administrative Expenses

     1,423       685  
    


 


Total Operating Costs and Expenses

     11,974       2,708  
    


 


Loss From Operations Before Interest Income and Income Taxes

     (831 )     (326 )

Interest Income

     157       408  
    


 


Income (Loss) From Operations Before Income Taxes

     (674 )     82  

Income Tax Benefit

     155       2  
    


 


Net Income (Loss)

   $ (519 )   $ 84  
    


 


 

 

 

The accompanying notes are an integral part of these financial statements

 

93


Table of Contents

GRYPHON EXPLORATION COMPANY

 

STATEMENTS OF STOCKHOLDERS’ EQUITY

(dollars in thousands)

 

     Common Stock

   Preferred Stock

   Additional
Paid-In
Capital


    Retained
Earnings


    Treasury
Stock


    Total
Stockholders’
Equity


 
     Shares

    Amount

   Shares

   Amount

        

Balance—December 31, 2000

   145,600     $ 1    25,000    $ —      $ 33,168     $ 19     $ —       $ 33,188  

Treasury Stock

   (6,740 )     —      —        —        —         —         (418 )     (418 )

Issuance of Preferred Stock

   —         —      30,000      1      29,999       —         —         30,000  

Offering Costs

   —         —      —        —        (6 )     —         —         (6 )

Net Income

   —         —      —        —        —         84       —         84  
    

 

  
  

  


 


 


 


Balance—December 31, 2001

   138,860     $ 1    55,000    $ 1    $ 63,161     $ 103     $ (418 )   $ 62,848  
    

 

  
  

  


 


 


 


Treasury Stock

   (51,400 )     —      —        —        —         —         (2,562 )     (2,562 )

Issuance of Preferred Stock

   —         —      30,000      1      29,999       —         —         30,000  

Net Loss

   —         —      —        —        —         (519 )     —         (519 )
    

 

  
  

  


 


 


 


Balance—December 31, 2002

   87,460     $ 1    85,000    $ 2    $ 93,160     $ (416 )   $ (2,980 )   $ 89,767  
    

 

  
  

  


 


 


 


 

 

 

The accompanying notes are an integral part of these financial statements.

 

 

94


Table of Contents

GRYPHON EXPLORATION COMPANY

 

STATEMENTS OF CASH FLOWS

(dollars in thousands)

 

     Year ended December 31,

 
     2002

    2001

 

CASH FLOWS FROM OPERATING ACTIVITIES:

                

Net Income (Loss)

   $ (519 )   $ 84  

Adjustments to Reconcile Net Income (Loss) to

                

Net Cash Provided by Operating Activities:

                

Depreciation, Depletion and Amortization

     6,521       1,769  

Loss on Derivative Instruments

     1,352       —    

Deferred Income Taxes

     862       (2 )

Changes in Operating Assets and Liabilities

                

Restricted Cash Deposits

     1,491       5,421  

Accounts Receivable

     (1,869 )     (246 )

Prepaid Expenses

     (1,920 )     (3,084 )

Accounts Payable and Current Liabilities

     5,517       (6,123 )
    


 


NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES

     11,435       (2,181 )
    


 


CASH FLOWS FROM INVESTING ACTIVITIES:

                

Oil and Gas Property Additions

     (43,495 )     (36,599 )

Noncurrent Restricted Cash Deposits

     —         2,608  

Purchases of Fixed Assets

     (323 )     (513 )
    


 


NET CASH USED IN INVESTING ACTIVITIES

     (43,818 )     (34,504 )
    


 


CASH FLOWS FROM FINANCING ACTIVITIES:

                

Sale of Preferred Stock

     30,000       30,000  

Purchase of Treasury Stock

     (2,562 )     (418 )

Offering Costs

     —         (6 )

Proceeds from borrowings

     —         1,804  

Repayment of borrowings

     —         (716 )
    


 


NET CASH PROVIDED BY FINANCING ACTIVITIES

     27,438       30,664  
    


 


NET DECREASE IN CASH

     (4,945 )     (6,021 )

CASH—BEGINNING OF PERIOD

     7,931       13,952  
    


 


CASH—END OF PERIOD

   $ 2,986     $ 7,931  
    


 


 

The accompanying notes are an integral part of these financial statements.

 

 

95


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS

(dollars in thousands, except share related items)

 

NOTE 1—Organization and Nature of Operations

 

Gryphon Exploration Company, a Delaware corporation, (“Gryphon” or the “Company”) is a Houston-based company formed for the purpose of oil and gas exploration, development and exploitation. The Company is currently engaged in the exploration and production for oil and natural gas in the Gulf of Mexico. The Company began operations October 2000.

 

On October 11, 2000 (“Inception”), Gryphon completed a transaction with Warburg, Pincus Equity Partners, L.P. and certain affiliates thereof, (“Warburg”) a global private equity fund based in New York, and Cheniere Energy, Inc. (“Cheniere”) to fund an exploration program based upon approximately 8,800 square miles of 3D seismic data in the Gulf of Mexico (the “Fairfield data set”). Cheniere contributed selected net assets in exchange for 100% of the common stock of Gryphon. These assets included the Fairfield data set license, certain offshore leases, a prospect then being drilled, an exploration agreement with an industry partner (described in Note 4) and certain other assets and liabilities. In addition, Gryphon assumed certain liabilities and obligations of Cheniere in connection with the contribution of assets. The assets received from Cheniere less the liabilities assumed were recorded at their estimated net fair value at the date of the transaction. Also, at inception, Warburg contributed $25,000 and received Gryphon Series A convertible preferred stock, with an 8% cumulative dividend (Series A preferred stock). Cheniere and Warburg also agreed, under certain circumstances, to contribute additional capital up to $75,000 to Gryphon, proportionate to their respective ownership interests.

 

As further discussed in Note 6, Warburg and certain employees of the Company contributed an additional $60,000 in exchange for 60,000 shares of Series A preferred stock during 2001 and 2002.

 

NOTE 2—Summary of Significant Accounting Policies

 

Basis of Presentation

 

The financial statements include the accounts of Gryphon Exploration Company. As an independent oil and gas producer, the Company’s revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas, oil and condensate, which are dependent upon numerous factors beyond the Company’s control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows, access to capital, and on the quantities of oil and gas reserves that may be economically produced.

 

Oil and Gas Properties

 

General. The Company uses the full cost method of accounting for exploration and development activities as defined by the U.S. Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

 

The sum of net capitalized costs and estimated future development and abandonment costs of oil and gas properties and mineral investments is amortized using the unit-of-production method. The carrying values of oil and gas properties included in these financial statements do not purport to represent replacement or market values.

 

96


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

In accordance with SEC Regulation S-X Rule 410 a(2), proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from new reservoirs under existing economic and operating conditions. Reserves are considered proved if they can be produced economically as demonstrated by either actual production or conclusive formation tests. The Company emphasizes that the volumes of reserves are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates, made by the Company’s engineers and an independent third party reservoir engineering firm, are reviewed and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in assumptions based upon, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to uneconomic conditions.

 

Unproved Oil and Gas Properties. Unproved oil and gas properties include costs that are excluded from proved oil and gas properties and are not subject to amortization. These amounts generally represent costs of investments in unproved properties, non-producing leases, seismic data sets, and major development projects. Gryphon excludes these costs until proved reserves are found or it is determined that the costs are impaired. All costs excluded are reviewed at least annually to determine if impairment has occurred. Any impairment is transferred to the costs to be amortized (the proved oil and gas property pool). The Company evaluates significant properties, composed primarily of costs associated with offshore leases and seismic data sets, at least annually. Non-producing leases are evaluated based on the progress of the Company’s exploration program to date. Exploration costs are transferred from unproved oil and gas properties to proved oil and gas properties upon completion the first exploratory well on each property.

 

Capitalized Seismic Costs / General & Administrative Expenses. The Company capitalizes the costs associated with its 3D data sets as well as a portion of its General and Administrative expenses which are applicable to its exploration activities. As the direct costs associated with drilled properties are transferred from the Company’s unproved oil and gas properties to its proved oil and gas properties, the Company allocates a portion of the capitalized 3D seismic and General and Administrative expense to the proved property pool. The Company’s allocation of these costs is based upon the capitalized costs associated with each 3D data set area divided by the estimated number of prospects projected to be developed from each respective data set. During 2002 and 2001, respectively, the Company allocated approximately $3,400 and $1,800 of seismic exploration cost, general and administrative, and other costs transferred by Cheniere at Inception, to the cost of proved properties based on this allocation method. It is reasonably possible, based on the results obtained from future drilling, that revisions to this estimate could occur in the future, which could affect the Company’s capitalization ceiling.

 

Capitalized Interest. SFAS No. 34, “Capitalization of Interest Costs,” provides standards for the capitalization of interest costs as part of the historical cost of acquiring assets. Financial Accounting Standards Board Interpretation (“FIN”) No. 33 provides guidance for the application of SFAS No. 34 to the full cost method of accounting for oil and gas properties. Under FIN No. 33, costs of investments in unproved properties and major development projects, which are not subject to amortization and on which exploration or development activities are in progress, qualify for capitalization of interest. Capitalized interest is calculated by multiplying the Company’s weighted-average interest rate on debt by the amount of costs included in unproved oil and gas properties. Capitalized interest cannot exceed gross interest expense. As costs are transferred from the unproved oil and gas properties pool to the proved oil and gas properties pool, the associated capitalized interest is also transferred to the proved oil and gas properties pool. The Company incurred no interest expense during in 2002 or 2001, thus no interest costs were capitalized during those periods.

 

97


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

Ceiling Test. The Company limits the capitalized costs of proved oil and gas properties, net of accumulated Depreciation, Depletion, and Amortization (“DD&A”) and the related deferred income taxes, to the estimated future net cash flows from proved oil and gas reserves, using prices in effect at the end of the applicable reporting period held flat for the life of production, discounted at 10%, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional DD&A.

 

Revenue Recognition

 

Revenues from the sale of oil and gas produced are recognized upon passage of title, net of royalty interests. When sales volumes differ from the Company’s entitled share, an overproduced or underproduced imbalance occurs. To the extent the overproduced imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. At December 31, 2002 and 2001, the Company had no material gas imbalances.

 

Reimbursable expenses

 

The Company performs administrative services on behalf of third parties in accordance with certain contractual arrangements. The Company was reimbursed $810 and $449 during 2002 and 2001, respectively, related to these services. These reimbursements are offset against general and administrative expenses of the Company.

 

Prepaid expenses

 

Prepaid expenses at December 31, 2002 and 2001 consist of prepaid insurance premiums of $4,093 and $1,850, respectively, as well as other prepaid expenses.

 

Fixed Assets

 

Fixed assets are recorded at cost. Repairs and maintenance costs are charged to operations as incurred. Depreciation is computed using the straight-line method calculated to amortize the cost of assets over their estimated remaining useful lives, which are estimated as 9 to 36 months for software and computer equipment and 1 to 5 years for office furnishings. Leasehold improvements are amortized over the term of the underlying lease. Upon retirement or other disposition of property and equipment, the cost and related depreciation is removed from the accounts and the resulting gains or losses are recorded.

 

Income Taxes

 

The Company utilizes the liability method of accounting for income taxes, as set forth in Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.” Under the liability method, deferred taxes are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. Valuation allowances are recorded against deferred tax assets when it is considered more likely than not that the deferred tax assets will not be utilized.

 

Stock-Based Compensation

 

SFAS No. 123, “Accounting for Stock-Based Compensation,” encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has

 

98


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

chosen to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the market price of the Company’s stock at the date of the grant over the amount an employee must pay to acquire the stock. The Company grants options at or above the market price of its common stock at the date of each grant.

 

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, an amendment of FASB Statement No. 123. This statement amends FASB Statement No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002 and are included in the notes to these consolidated financial statements.

 

The fair value of options is calculated using the Black-Scholes option-pricing model. Assumptions used for 2002 and 2001 were: no dividend yield, no volatility, risk-free interest rate of 4.3% and 3.8%, respectively, and an expected average option life of 5 years. If the Company had adopted the recognition provisions of SFAS No. 123 for 2002 and 2001, the Company’s financial statements would have not reflected a change in reported net income.

 

Cash Equivalents

 

The Company classifies all investments with original maturities of three months or less as cash equivalents.

 

Restricted Cash Deposits

 

Current restricted cash deposits represent deposits reserved for the funding of contractual drilling costs on behalf of the Company and its working interest partners within one year.

 

Fair Value of Financial Instruments

 

The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable, and short-term debt approximate fair value because of the short maturities of those instruments.

 

Derivative Instruments

 

On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activity, an Amendment of SFAS 133. SFAS Nos. 133 and 138 require that all derivative instruments be recorded on the balance sheet at their respective fair values. See Note 6 for information regarding the Company’s derivative instruments and hedging activities.

 

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and the accompanying notes. Actual results could differ from those estimates. Changes in such estimates may affect amounts reported in future periods.

 

99


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

Concentration of Credit Risk

 

The Company maintains cash balances with a bank and frequently exceeds federally insured limits. The Company invests its cash in money market securities, investment grade commercial paper, and U.S. Government-backed securities. The Company’s joint interest partners consist primarily of independent oil and gas producers. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies. The Company performs credit evaluations of its customers’ financial condition and, if deemed necessary, obtains letters of credit and parental guarantees from selected customers. The Company has not experienced any significant losses from uncollectible accounts. All of the Company’s derivative transactions have been carried out in the over-the-counter market.

 

Environmental Liabilities

 

Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated.

 

Recently Issued Accounting Standards

 

In June 2001, the Financial Accounting Standard Board issued the Statement of Financial Accounting Standards No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations” (ARO), which requires that an asset retirement cost be capitalized as part of the cost of the related long-lived asset and allocated to expense by using a systematic and rational method. Under this Statement, an entity is not required to re-measure an ARO liability at fair value each period but is required to recognize changes in an ARO liability resulting from the passage of time and revisions in cash flow estimates. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company expects to adopt SFAS 143 on January 1, 2003. The Company has not yet determined the impact that the adoption of SFAS 143 will have on its earnings or statement of financial position.

 

In October 2001, the Financial Accounting Standard Board issued the Statement of Financial Accounting Standards No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets”. The Statement requires that long-lived assets that are to be disposed of by sale be measured at lower of book value or fair value less cost of sale. The Statement also expanded the scope of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of this Statement are effective for fiscal years beginning after December 15, 2001. The provisions of this Statement will impact any asset dispositions the Company makes after January 1, 2002.

 

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS No. 145 amends existing guidance on reporting gains and losses on the extinguishment of debt to prohibit the classification of the gain or loss as extraordinary, as the use of such extinguishments have become part of the risk management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to require sale-leaseback accounting for certain lease modifications that have economic effects similar to sale-leaseback transactions. The provisions of the Statement related to the rescission of Statement No. 4 are applied in fiscal years beginning after May 15, 2002. Earlier application of these provisions is encouraged. The provisions of the Statement related to Statement No. 13 were effective for transactions occurring after May 15, 2002, with early application encouraged. The adoption of SFAS No. 145 is not expected to have a material effect on the Company’s financial statements.

 

100


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity. The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The adoption of SFAS No. 146 is not expected to have a material effect on the Company’s financial statements.

 

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statement No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34. This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after December 31, 2002 and are not expected to have a material effect on the Company’s financial statements. The disclosure requirements are effective for financial statements of interim and annual periods ending after December 31, 2002.

 

In January 2003, the FASB issued Interpretation No. 46 Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. This Interpretation addresses the consolidation by business enterprises of variable interest entities as defined in the Interpretation. The Interpretation applies immediately to variable interest in variable interest entities created after January 31, 2003, and to variable interests in variable interest entities obtained after January 31, 2003. For nonpublic enterprises, such as the Company, with a variable interest in a variable interest entity created before February 1, 2003, the Interpretation is applied to the enterprise no later than the end of the first annual reporting period beginning after June 15, 2003. The application of this Interpretation is not expected to have a material effect on the Company’s financial statements. The Interpretation requires certain disclosures in financial statements issued after January 31, 2003 if it is reasonably possible that the Company will consolidate or disclose information about variable interest entities when the Interpretation becomes effective.

 

NOTE 3—Fixed Assets

 

Fixed assets consisted of the following:

 

     December 31, 2002

 

Computers and Office Equipment

   $ 1,362  

Furniture, Fixtures and Other

     240  
    


       1,602  

Less Accumulated Depreciation

     (1,144 )
    


Fixed Assets, net

   $ 458  
    


 

NOTE 4—Exploration Agreements

 

In 2002, Gryphon entered into an exploration agreement with an industry partner. Under the terms of the agreement, the partner acquired an option to participate at a 25% working interest level in up to seven drilling prospects generated by Gryphon in the Gulf of Mexico. During the term of the agreement, Gryphon received overhead reimbursements from this partner. In addition, Gryphon receives an increased interest in each prospect after the partner has received cumulative cash flows equal to its capital costs in each respective prospect.

 

101


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

Gryphon is the operator of the prospects drilled pursuant to this agreement. Overhead reimbursements received under the agreement are credited as a recovery of general and administrative expenses. Total overhead reimbursements received in 2002 under this program and from other various industry partners were $1,160.

 

During 2000 and 2001, the Company was party to an exploration agreement with an industry partner. Cheniere contributed this exploration agreement at Inception (see Note 1). Under the terms of the agreement, Gryphon’s exploration partner acquired an option to participate at a 50% working interest level in any drilling prospect generated by Gryphon through August 2001 within a defined area of mutual interest in the Gulf of Mexico. During the term of the agreement, Gryphon received a management fee of $230 per month from its partner. In addition, for each well drilled, Gryphon’s partner pays a disproportionate share of the cost of leasing and of the initial test well on each prospect. Gryphon is the operator of the drilling program. A portion of the management fee payments was credited as a recovery of general and administrative expenses and the remaining portion reduced capitalized G&A expenses. Management fees received by Gryphon in 2001 totalled $1,120. Certain provisions of this agreement, including those related to management fees, expired August 2001.

 

The Company intends to enter into one or more new industry partner agreements in 2003.

 

NOTE 5—INCOME TAXES

 

The difference between the provision for income taxes and the amount that would be determined by applying the statutory federal income tax rate to the income or loss before income taxes is set forth below:

 

     Year ended
December 31,


 
     2002

    2001

 

Federal Income Tax Expense (Benefit) at 34%

   $ (229 )   $ 28  

Permanent Differences

     21       16  

Other

     53       (46 )
    


 


Income Tax Provision (Benefit)

   $ (155 )   $ (2 )
    


 


 

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the carrying amounts used for income tax purposes. Deferred income taxes also reflect the net tax effects of net operating loss carryforwards. The tax effects of the Company’s temporary differences and carryforwards are as follows:

 

     December 31,
2002


 

Deferred Tax Assets:

        

Net Operating Loss Carryforwards

   $ 7,529  
    


Total Deferred Tax Assets

     7,529  

Deferred Tax Liabilities:

        

Differences between Book and Tax Bases of Oil and Gas Properties, Plant and Equipment

     (9,572 )
    


Deferred Tax Liabilities, net

   $ (2,043 )
    


 

There was no current income tax provision for 2002 or 2001 and no income taxes were payable during those periods.

 

102


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

The Company has determined that it is more likely than not that the deferred tax assets will be realized and a valuation allowance for such assets is not required.

 

At December 31, 2002, the Company had net operating loss (NOL) carryforwards for tax reporting purposes of approximately $22,144, which will expire as follows:

 

2020

   $ 2,170

2021

   $ 19,251

2022

   $ 723

 

NOTE 6—DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

 

The Company produces and sells natural gas, crude oil and condensate. As a result, the Company’s financial results can be significantly affected as these commodity prices fluctuate widely in response to changing market forces. The Company maintains a commodity-price-risk management strategy that uses derivative instruments to minimize significant, unanticipated earning fluctuations caused by commodity-price volatility. The Company does not speculate using derivative instruments.

 

By using derivative financial instruments to reduce exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk for the Company. When the fair value of a derivative contract is negative, the Company owes the counterparty and, therefore, it does not incur credit risk. The Company minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties whose credit rating is investment grade.

 

Market risk is the adverse effect on the value of a financial instrument that results from a change in commodity prices. The market risk associated with commodity-price contracts is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken.

 

The Company periodically enters into natural gas and crude oil option contracts for a portion of its anticipated hydrocarbon sales, to reduce the price risk associated with fluctuations in market prices. The option contracts limit the unfavorable affect that price decreases will have on hydrocarbon sales. The maximum term over which the Company is hedging exposures to the variability of cash flows for commodity price risk is 24 months.

 

Effective January 1, 2001, the Company adopted SFAS No. 133 and SFAS No. 138, an amendment to SFAS 133. SFAS 133 and 138 require that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either (a) offset by the change in fair value of the hedged asset or liability (if applicable) or (b) reported as a component of other comprehensive income (loss) in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. During 2001 and 2002, the Company did not attempt to qualify for the hedge provisions under SFAS 133 and thus has not designated its derivative transactions during those periods as hedging instruments. Accordingly, the Company accounted for the changes in market value of these derivatives through current earnings.

 

103


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

As of December 31, 2002, the Company had hedged portions of its expected 2003 natural gas production as follows:

 

Instrument


   Volume (mmbtus)

   Prices

Swaps

   2,300,000    $3.95-$4.08

Collars

   1,320,000    floor—  $3.50/cap—  $6.00

 

The fair value of these derivative positions at that date was a $1,352 liability.

 

NOTE 7—EQUITY TRANSACTIONS

 

At December 31, 2002, the Company had 85,000 shares of Series A preferred stock issued and outstanding. The preferred stock is convertible at the option of the holder at a rate of $100 per share of common stock upon the occurrence of certain qualifying events. The preferred stock has voting rights as if converted. Each share has a liquidation preference of $1,000. Dividends accrue at a rate of 8% per annum, become payable quarterly as declared, and are cumulative and payable in the event of liquidation of the Company. At December 31, 2002 and 2001, there were $9,349 and $3,510, respectively, of undeclared dividends in arrears.

 

During 2002, the Company issued four private placements of Series A preferred stock in the amounts of $5,000, $10,000, $5,000, and $10,000, which were consummated on April 22, 2002, June 17, 2002, September 3, 2002, and November 5, 2002, respectively. During 2001, the Company issued three private placements of Series A preferred stock, each in the amount of $10,000, which closed on May 15, July 23, and November 19, 2001. As discussed in Note 1, Cheniere has a right to participate in offerings of Series A preferred stock by the Company. Cheniere elected not to participate in any of the Company’s offerings during 2002 or 2001. Based upon the conversion features of the Company’s Series A preferred stock, the interests of the Company’s holders of Series A preferred stock would represent approximately 91%, and 80% on an as converted basis of the outstanding and issued Common Stock at December 31, 2002 and 2001, respectively.

 

As further discussed in Note 8, in July 2001, the Company acquired a 3D seismic data set from Cheniere. In connection with that transaction, the Company repurchased 6,740 shares of Common Stock for aggregate consideration of approximately $418. These shares are included as treasury stock as of December 31, 2002.

 

In March 2002, the Company and Cheniere settled litigation which had been filed against them on a joint and several basis by a seismic company (the “Claimant”). Pursuant to this settlement, the Company made a payment to the Claimant and committed to make certain additional payments if production rights are obtained by the Company or Cheniere in the area covered by the data set licensed from the Claimant. In addition, the Company agreed to become responsible for certain contingent obligations of Cheniere associated with the Seitel data set. The maximum amount of the assumed liabilities associated with this litigation and the contingent liabilities associated with the Seitel dataset was approximately $2,561 in the aggregate. As consideration for the Company’s agreement to assume these contingent liabilities, Cheniere has transferred to Gryphon 51,400 shares of the Company’s common stock which Cheniere held. Pursuant to this agreement, Cheniere has an option valid until March 16, 2003 to repurchase these shares from the Company at a cost equal to $50 per share, subject to an escalation adjustment. At December 31, 2002, the maximum amount of the contingent obligations assumed is $934.

 

Based upon the foregoing transactions, Cheniere holds an interest of approximately 9% in the Company, calculated on a fully diluted basis as of December 31, 2002.

 

104


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

NOTE 8—STOCK-BASED COMPENSATION

 

In 2000, the Company established the Gryphon Exploration Company 2000 Stock Option Plan (the “Option Plan”). In 2001, the Option Plan was amended and restated. The Option Plan, as amended, allows for the issuance of options to purchase up to 186,493 shares of Gryphon common stock at an exercise price of $100 per share. The Company has reserved an equivalent number of shares of common stock for issuance upon the exercise of options which have been granted or which may be granted. The term of options granted under the Option Plan is generally ten years. Vesting occurs over a three-year period, one third on each anniversary of the grant date. The following table summarizes the Company’s stock option activity and related information for the periods presented:

 

     Year ended December 31,

 
     2002

    2001

 

Outstanding at Beginning of Period

     81,122       39,400  

Options Granted at an Exercise Price of $100 per share

     20,332       42,722  

Options Forfeited

     (350 )     (1,000 )
    


 


Outstanding at End of Period

     101,104       81,122  
    


 


Exercisable at End of Period

     40,604       13,483  
    


 


Weighted Average Exercise Price of Options Outstanding

   $ 100     $ 100  
    


 


Weighted Average Exercise Price of Options Exercisable

   $ 100     $ 100  
    


 


Weighted Average Fair Value of Options Granted During the Period

   $ —       $ —    
    


 


Weighted Average Remaining Contractual Life of Options Outstanding

   8.44 years    9.3 years

Weighted Average Remaining Contractual Life of Options Exercisable

   8.11 years    8.8 years

 

The fair value of options is calculated using the Black-Scholes option-pricing model. Assumptions used for 2002 and 2001 were: no dividend yield, no volatility, risk-free interest rate of 4.3% and 3.8%, respectively, and an expected average option life of 5 years. If the Company had adopted the recognition provisions of SFAS No. 123 for 2002 and 2001, the Company’s financial statements would have not reflected a change in reported net income.

 

NOTE 9—RELATED PARTY TRANSACTIONS

 

Under the terms of the Contribution and Subscription Agreement dated October 11, 2000 by and among the Company, Cheniere and the other investors listed therein, Gryphon provided office space to Cheniere at no cost from Inception through December 2000. Also, pursuant to that agreement, Cheniere provided accounting and cash management services to Gryphon without charge for six months following the closing date.

 

In April 2001, Gryphon purchased from Cheniere a 50% working interest in a Texas offshore lease for cash consideration of $225, and simultaneously executed a joint operating agreement which provided that Gryphon would become the operator of the lease.

 

In June 2001, Gryphon completed a transaction with Cheniere for the purchase of a license for 3D seismic data (the Seitel data set) granted to Cheniere by Seitel Data Ltd. As a result of this transaction, Gryphon acquired

 

105


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

the rights to approximately 3,900 square miles of seismic data in the Gulf of Mexico for a total purchase price of $3,500 (see Note 12).

 

In July 2001, Gryphon purchased the right arising under an agreement between JEBCO and Cheniere whereby Cheniere was to receive a seismic data license (the JEBCO data set) to approximately 3,000 square miles of 3D seismic data in the Gulf of Mexico. As part of this transaction, Gryphon also acquired 6,740 shares of Gryphon common stock from Cheniere. The aggregate purchase price of $4,174 was allocated between seismic data and treasury stock based upon their relative fair values at date of the transaction. In June 2001, Gryphon completed a transaction with Cheniere for the purchase of a license for 3D seismic data (the Seitel data set) granted to Cheniere by Seitel Data Ltd. As a result of this transaction, Gryphon acquired the rights to approximately 3,900 square miles of seismic data in the Gulf of Mexico for a total purchase price of $3,500 (see Note 12).

 

As discussed in Note 7 above, in March 2002, the Company entered into a settlement agreement to resolve litigation against Cheniere and the Company. Pursuant to the settlement, the Company agreed to assume certain obligations of Cheniere. The maximum amount of the assumed liabilities pursuant to the settlement and associated agreements was approximately $2,561 in the aggregate. As consideration for the Company’s agreement to assume these contingent liabilities, Cheniere transferred to Gryphon 51,400 shares of the Company’s common stock which Cheniere held. Pursuant to this agreement, Cheniere has an option valid for one year from the date of the agreement to repurchase these shares from the Company at a cost equal to $50 per share, subject to escalation beginning four months after the date of the stock transfer. At December 31, 2002, Cheniere had not exercised any its repurchase rights under the option agreement.

 

During 2000, 2001, and 2002, the Company issued nine private placements of Series A preferred stock for aggregate consideration of $85,000. Of this amount, Warburg contributed $84,679 and the Company’s management contributed $321 (see Note 7).

 

NOTE 10—COMMITMENTS AND CONTINGENCIES

 

The Company has entered into an office lease agreement with a non-cancelable term, which runs through March 2003. Future minimum lease payments are $66 for the year ended December 31, 2003. Total rental expense for office space for 2002 and 2001 was $286 and $285, respectively.

 

At Inception, Gryphon acquired a master license agreement covering the license of approximately 8,800 square miles of 3-D seismic data in the Gulf of Mexico. In connection with the license agreement, the Company has made a commitment to reprocess certain of the seismic data and to pay a fee for such reprocessing as the reprocessed data are delivered. At December 31, 2002, the Company had met its commitments related to future deliveries of reprocessed data.

 

In connection with the purchase from Cheniere of the JEBCO data set (see Note 9), the Company has an obligation to pay for the related seismic data once it has been delivered to the Company, and accepted by Cheniere.

 

NOTE 11—OIL AND GAS OPERATIONS

 

The Company uses the full cost method of accounting for its oil and natural gas properties. Unproved oil and gas properties include costs that are excluded from proved oil and gas properties and that are not subject to

 

106


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

amortization. These amounts generally represent costs of investments in unproved properties, non-producing leases, seismic data sets, and major development projects. Gryphon excludes these costs until proved reserves are found or it is determined that the costs are impaired. The costs of unproved oil and natural gas properties are reviewed at least annually to determine if impairment has occurred. Any impairment is transferred to the proved oil and gas property pool. The Company evaluates significant properties, composed primarily of costs associated with offshore leases and seismic data sets, at least annually. Non-producing leases are evaluated based on the progress of the Company’s exploration program to date.

 

The following table summarizes the costs of unproved properties for the periods during which the costs were incurred:

 

     December 31,

     2002

   2001

Period that costs were incurred—

             

Inception through December 31, 2000

   $ 11,025    $ 13,422

2001

     11,055      14,645

2002

     14,605      —  
    

  

Totals

   $ 36,685    $ 28,067
    

  

 

NOTE 12—SUBSEQUENT EVENTS

 

On February 10, 2003, the Company entered into a three-year, reserve based, revolving credit facility. The nominal amount of the facility is $100,000 and the initial borrowing base is $18,000. The borrowing base will be adjusted from time to time based upon changes in the Company’s oil and gas reserves. The facility is secured by substantially all of the Company’s assets, consisting primarily of its oil and gas properties. Proceeds borrowed from the facility can be used to fund the Company’s operations, for acquisitions, and for general corporate purposes. The facility requires quarterly interest payments based upon up floating rate indexes and includes covenants typically associated with similar credit agreements. The credit facility matures February 10, 2006. As of March 14, 2003, the Company had drawn $5,000 under the facility.

 

In January 2003, the Company entered into an amendment and extension to its office lease. Pursuant to this amendment, the Company expanded its office space by approximately 40% and extended the term by seven years from March 2003. The extended term includes an option which allows the Company to terminate the lease at the end of the fifth year of the extension period. The estimated aggregate obligation of the Company pursuant to the amendment is approximately $2,990 assuming a seven year extension or approximately $2,170 assuming the extension is terminated at the end of year five.

 

NOTE 13—RECENT ACCOUNTING DEVELOPMENTS

 

In July 2003, an issue was brought before the Financial Accounting Standards Board regarding whether or not contract-based oil and gas mineral rights held by lease or contract (“mineral rights”) should be recorded or disclosed as intangible assets. The issue presents a view that these mineral rights are intangible assets as defined in SFAS No. 141, “Business Combinations,” and, therefore, should be classified separately on the balance sheet as intangible assets. SFAS No. 141 and SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective for transactions subsequent to June 30, 2001; with the disclosure requirements of SFAS No. 142 required as of January 1, 2002. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that intangible assets be disaggregated and reported

 

107


Table of Contents

GRYPHON EXPLORATION COMPANY

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

(dollars in thousands, except share related items)

 

separately from goodwill. SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements. SFAS No. 142 does not apply to accounting utilized by the oil and gas industry as prescribed by SFAS No. 19, and is silent about whether or not its disclosure provisions apply to oil and gas companies. The Emerging Issues Task Force (EITF) has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in how Gryphon classifies these assets.

 

Should such a change be required, the amounts related to business combinations and major asset purchases that would be classified as “intangible undeveloped mineral interest” was $10,690 as of December 31, 2002. The amounts related to business combinations and major asset purchases that would be classified as “intangible developed mineral interest” was $1,408 as of December 31, 2002. Intangible developed mineral interest amounts are presented net of accumulated depletion, depreciation and amortization (DD&A). Accumulated DD&A was estimated using historical depletion rates applied proportionately to the costs of the purchases conceptually classified as “intangible developed mineral interest”. The amounts noted above only include mineral rights acquired in major asset purchases, consisting primarily of amounts paid for federal and state oil & gas leases.

 

The numbers above are based on our understanding of the issue before the EITF: if all mineral rights associated with unevaluated property and producing reserves were deemed to be intangible assets:

 

  mineral rights with proved reserves and mineral rights with no proved reserves would be classified as intangible assets and would not be included in oil and gas properties on our consolidated balance sheet;

 

  results of operations and cash flows would not be materially affected because mineral rights would continue to be amortized in accordance with full cost accounting rules; and

 

  disclosures required by SFAS Nos. 141 and 142 relative to intangibles would be included in the notes to our financial statements.

 

108


Table of Contents

GRYPHON EXPLORATION COMPANY

 

SUPPLEMENTAL INFORMATION TO THE FINANCIAL STATEMENTS

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA

(dollars in thousands)

 

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

 

The following tables set forth information about the Company’s oil and gas producing activities pursuant to the requirements of Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”).

 

Investments in oil and gas properties are set forth below:

 

    

December 31,

2002


 

Oil and Gas Properties:

        

Proved

   $ 61,583  

Unproved

     36,685  
    


       98,268  

Less Accumulated Depreciation,

        

Depletion and Amortization

     (7,261 )
    


     $ 91,007  
    


 

As of December 31, 2002 and 2001, the Company’s investment in oil and gas properties included $36,685 and $28,067, respectively in unevaluated properties, which have been excluded from amortization. Such costs will be evaluated in future periods based on management’s assessment of exploration activities, expiration dates of licenses, permits and concessions, changes in economic conditions and other factors.

 

The Company began production of oil and gas in February 2001. The Company capitalized as oil and gas property costs approximately $2,408 and $2,023 of general and administrative expenses directly related to its exploration and development activities in 2002 and 2001, respectively.

 

The Company has made a substantial investment in acquiring, processing and reprocessing Gulf of Mexico seismic data, which cover various areas having an aggregate size of 18,000 square miles. The costs of these projects become subject to amortization on a ratable basis as prospects are identified in each of the data set project areas.

 

Costs Incurred

 

Costs incurred in oil and gas property acquisition, exploration, and development activities are set forth in the table below:

 

    

Year ended

December 31,


     2002

   2001

Acquisition of Properties:

             

Proved Properties

   $ —      $ 227

Unproved Properties

     9,806      14,360

Exploration Costs

     25,079      12,430

Development Costs

     8,611      9,559
    

  

Total

   $ 43,496    $ 36,576
    

  

 

109


Table of Contents

GRYPHON EXPLORATION COMPANY

 

SUPPLEMENTAL INFORMATION TO THE FINANCIAL STATEMENTS

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA—(Continued)

(dollars in thousands)

 

For the years ended December 31, 2002 and 2001 depreciation, depletion and amortization of the capitalized costs of oil and gas properties was $1.70 and $1.52 per mcfe, respectively.

 

Reserve Quantities

 

The following table shows estimates of proved reserves and proved developed reserves, net of royalty interest, of natural gas, crude oil, and condensate owned at year-end and changes in proved reserves during the last two years prepared by independent petroleum engineers in accordance with the rules and regulations of the Securities and Exchange Commission. Volumes for natural gas are in millions of cubic feet (mmcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. Liquid hydrocarbons, consisting of oil and condensates, are expressed in standard 42 gallon barrels (bbls). These estimates represent the Company’s interest in the reserves associated with its properties. All of the Company’s oil and gas reserves are located within the United States and its territorial waters.

 

The Company’s reserves increased in 2002 and 2001 primarily from exploration and development drilling activities, offset in part by production. The Company emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data as well as production performance data. These estimates are reviewed and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in assumptions based on, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to uneconomic conditions.

 

     Year Ended December 31,

 
     2002

    2001

 
     Oil
(Bbls)


    Gas
(Mmcf)


    Oil
(Bbls)


    Gas
(Mmcf)


 

Proved Reserves:

                        

Beginning of Period

   210,151     17,468     2,640     1,674  

Revisions of Previous Estimates

   (41,342 )   (3,904 )   (845 )   (1,268 )

Extensions, Discoveries and Other Additions

   243,319     17,222     219,099     17,822  

Production

   (40,320 )   (3,278 )   (10,743 )   (760 )
    

 

 

 

End of Period

   371,808     27,508     210,151     17,468  
    

 

 

 

Proved Developed Reserves:

                        

Beginning of Period

   192,569     13,022     2,640     1,674  

End of Period

   165,421     16,332     192,569     13,022  

 

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and future amounts and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of proved undeveloped reserves are inherently less certain than estimates of proved developed reserves. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, geologic success and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, the Company’s reserves may be subject to

 

110


Table of Contents

GRYPHON EXPLORATION COMPANY

 

SUPPLEMENTAL INFORMATION TO THE FINANCIAL STATEMENTS

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA—(Continued)

(dollars in thousands)

 

downward or upward revision based upon production history, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors.

 

Standardized Measure of Discounted Future Net Cash Flows

 

The following table sets forth estimates of future cash flows from proved reserves of gas, oil and condensate which were prepared by independent petroleum engineers. The standardized measure of discounted future cash flow amounts are based upon year-end prices of $31.35 and $20.43 per barrel of oil (WTI—Cushing) and $4.75 and $2.64 per mcf of natural gas (NYMEX—Henry Hub) at December 31, 2002 and 2001, respectively. Estimated future cash inflows are reduced by estimated future development and production costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense is calculated by applying the existing statutory tax rates, including any known future changes, to the pre-tax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.

 

The present value of future net revenues does not purport to be an estimate of the fair market value of Gryphon’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Significant changes in estimated reserve volumes or commodity prices could have a material effect on the Company’s financial statements.

 

Under the full cost method of accounting, a non-cash charge to earning related to the carrying value of the Company’s oil and gas properties on a country-by-country basis may be required when prices are low. Whether the Company will be required to take such a charge depends on the prices for crude oil and natural gas at the end of any quarter, as well as the effect of both capital expenditures and changes to proved reserves during the quarter. If a non-cash charge were required, it would reduce earnings for the period and result in lower DD&A expense in future periods.

 

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is set forth in the following table:

 

     December 31,

 
     2002

    2001

 

Future Cash Inflows (Sales)

   $ 148,628     $ 49,949  

Less—Future Costs:

                

Production

     (8,923 )     (4,499 )

Development and Dismantlement

     (7,288 )     (2,926 )
    


 


Future Net Cash Flows before Income Taxes

     132,417       42,524  

Less—10% Annual Discount for Estimated Timing of Cash Flow

     (25,477 )     (9,956 )
    


 


Present Value of Future net Cash Flows before Income Taxes

     106,939       32,568  

Less—Present Value of Future Income Taxes

     (11,728 )     (3,790 )
    


 


Standardized Measure of Discounted Future net Cash Flows

   $ 95,211     $ 28,778  
    


 


 

111


Table of Contents

GRYPHON EXPLORATION COMPANY

 

SUPPLEMENTAL INFORMATION TO THE FINANCIAL STATEMENTS

OIL AND GAS RESERVES AND RELATED FINANCIAL DATA—(Continued)

(dollars in thousands)

 

The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows:

 

    

Year ended

December 31,


 
     2002

    2001

 

Standardized Measure—Beginning of Period

   $ 28,778     $ 9,139  

Increases (Decreases)—

                

Sales, net of Production Costs

     (8,465 )     (2,128 )

Increase due to passage of time (Accretion of Discount)

     3,257       975  

Net Change in Sales Prices, net of Production Costs

     24,104       (11,258 )

Changes in Estimated Future Development Costs

     122       —    

Revisions of Quantity Estimates

     (14,784 )     (3,047 )

Extensions, Discoveries and Other Additions, net of Future Production and Development Costs

     69,357       34,232  

Development Costs Incurred during the Period that Reduced Previously Estimated Development Cost

     1,308       735  

Net Change in Income Taxes

     (7,938 )     138  

Changes in Production Rates (timing) and Other

     (528 )     (8 )
    


 


Standardized Measure—End of Period

   $ 95,211     $ 28,778  
    


 


 

 

112