UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

For the transition period from                                          to                                         

Commission File Number 0-32455

Far East Energy Corporation

Registrant’s telephone number, including area code: (832) 598-0470

Securities registered pursuant to Section 12(b) of the Exchange Act: None

Securities registered under 12(g) of the Exchange Act:
Common Stock (par value $0.001 per share)

     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 þ No o

     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 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.    o

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

     The aggregate market value of the voting Common Stock, par value $0.001 per share, held by non-affiliates of the registrant was approximately $76,653,000 as of June 30, 2004 (based on $1.45 per share, the last price of the Common Stock as reported on the OTC Bulletin Board on such date). For purposes of the foregoing calculation only, all directors, executive officers and 5% beneficial owners have been deemed affiliates.

     The number of shares of Common Stock, par value $0.001 per share, outstanding as of March 4, 2005 was 77,439,910.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the registrant’s proxy statement for the annual meeting of stockholders to be held May 24, 2005 are incorporated by reference into Part III of this Form 10-K.

FAR EAST ENERGY CORPORATION
TABLE OF CONTENTS

PART I

Item 1. BUSINESS

Overview

     We were incorporated in Nevada on February 4, 2000. In January 2002, we renamed our company Far East Energy Corporation and changed our focus to exploring, developing, producing and selling coalbed methane gas, or CBM. Today, our operations concentrate on CBM exploration and development in the Yunnan Province in Southern China and in the Shanxi Province in Northern China. Our goal is to become a recognized leader in coalbed methane gas property acquisition, exploration, development and production. Our principal offices are located at 400 North Sam Houston Parkway, Suite 205, Houston, Texas 77060. We also maintain offices in Beijing, China and Kunming, Yunnan Province, China.

     We are a development stage company and to date our activities have been principally limited to organizational activities, including developing a strategic operating plan, capital funding, hiring personnel, entering into contracts, acquiring rights to explore, develop, produce and sell oil and gas or CBM and, beginning in 2003, the drilling, testing and completion of exploratory wells. We have entered into three production sharing contracts that enable us to explore for, develop, produce and sell CBM on over 1.3 million acres located in the Yunnan and Shanxi Provinces of the People’s Republic of China (“PRC”), which we believe makes us the third largest holder of coalbed methane acreage in China. To date, we have drilled three exploratory wells on acreage in the Yunnan Province. We have also successfully completed a hydraulic fracture simulation test on a well previously drilled by our partner, Phillips China Inc., a subsidiary of ConocoPhillips, Inc. (“Phillips”), on acreage in the Quinnan Block of the Shanxi Province. We have not recognized any revenues from our operations and do not anticipate recognizing significant revenues prior to late 2006.

     Until recently, we also owned undeveloped oil, gas and mineral rights and interests in approximately 149,000 net acres located in the eastern portion of Montana. On February 2, 2005, our wholly owned subsidiary, Newark Valley Oil & Gas, Inc., entered into a purchase and sale agreement with Zier & Associates, Ltd. for the sale of our oil and gas leasehold interests and other property interests in Montana. As a condition to the sale of our Montana properties, we acquired certain overriding royalty interests in adjoining acreage for $100,000, which were also sold under the terms of the purchase and sale agreement. The transaction closed on February 2, 2005. At the closing, we received gross proceeds of $1,135,000 from the sale of our Montana properties (including the overriding royalty interests described above). We consider our Montana properties to be non-core assets of our company. We sold these assets in order to focus our efforts on the exploration and development of our coalbed methane holdings located in China. As a result, all of our long-lived assets are presently located in the PRC.

Our Website

     Our website can be found at www.fareastenergy.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished with the U.S. Securities and Exchange Commission (“SEC”) pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) can be accessed free of charge by linking directly from our website under the “Investor Relations—SEC Filings” caption to the SEC’s Edgar Database. These filings will be available as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on the website is not part of this report.

Coalbed Methane Gas and Testing of Coalbed Methane Resources

     CBM is a type of natural gas found in coal seams of various types of coal. As coal is formed, large quantities of natural gas are generated and adsorbed on the internal surface area of the coal.

     Coalbed methane exploration and production involves drilling into a known coal deposit and extracting the gas that is contained in the coal. A coal seam is often saturated with water, with methane being held in the coal by water pressure. To produce methane from coalbeds, water must first be pumped from the seam in order to reduce the water pressure that holds the gas in the seam. This process is called dewatering. When the water pressure is reduced, the gas adsorbed on the coal is released and diffuses into the fractures, or cleats, contained in the coal seam. Gas flows to the well bore through the cleat system as well as any of the other cracks, crevices and fractures found in the coalbed. Dewatering volumes decrease as peak CBM production is reached.

     The productivity potential of a well depends on many reservoir and geological characteristics, including permeability, thickness and depth of the coalbed, the coal ranking of the coalbed, gas content and other factors. We consider these factors, as well as isotherm tests conducted on core samples, the amount of dewatering required of a well and a number of other factors when choosing where to develop coalbed methane present in our CBM acreage.

Permeability

     Coalbed methane exploration requires that the coal have sufficient permeability. Permeability is based upon how many cleats the coal has and how close they are to each other. The more cleats coal has, the better the coal’s permeability and the greater opportunity to retrieve the adsorbed CBM. Therefore, reservoirs with high permeability have a higher propensity for strong production than less permeable reservoirs.

Thickness

     The thickness of the coal seam is crucial to coalbed methane production. A coal seam with traditionally unacceptably low permeability could be produced with sufficient thickness. In this case, the gas would flow out slowly, but because the coal seam is thick, more of the slow-flowing gas would be produced since there is a thick area from which to collect the CBM.

Depth

     The depth of the coal seam is also a significant factor in the productivity potential of a well. Where the coal, and thus the methane, lies at shallow depths, wells are generally easier to drill and less expensive to complete. With greater depth, increased pressure closes cleats in the coal, which reduces permeability and the ability of the CBM to move through and out of the coal. On the other hand, if a coal seam is not buried deeply enough, there may not be sufficient water pressure to hold the gas in place on the coal.

Coal Ranking

     Methane is contained in all ranks of coal. The most CBM is contained in the highest rank coal, which is called anthracite. Unfortunately, anthracite has very low permeability. Semi-anthracite coal typically has lower quantities of CBM than anthracite coal, but may still contain significant cleats as well, making it more permeable. The coalbeds found in our Shanxi Province project are semi-anthracite coal that has a favorable cleat structure, which should also make the permeability favorable.

     The next lesser coal rank is bituminous coal that contains less CBM per ton but usually has a good cleat structure allowing for better permeability. The coalbeds found in our Enhong – Laochang blocks, which are located in the Yunnan Province, have bituminous and semi-anthracite coal.

Dewatering

     Water must be removed from the coal seams to decrease reservoir pressure and release the gas to produce methane from coalbeds. After the detachment of gas molecules from the coal surface, or desorption, occurs, the gas diffuses through the coalbed’s cleats and fractures toward the well bore. Substantial dewatering of the coalbed is required initially. Water production declines as methane gas production increases. Produced water disposal presents major economic and environmental challenges for operators. These costs alone can determine the feasibility of coalbed methane projects.

2

Coalbed Methane in the People’s Republic of China

     China is the world’s largest coal producing country, and has substantial coalbed methane resources located within its abundant coalfields. Because most of China’s CBM is found at shallow depths, it is easier to drill and complete coalbed methane wells than traditional natural gas wells. Additionally, the vast amounts of undeveloped coalbed methane in China result in the country releasing six billion cubic meters of methane into the environment each year from China’s many coal mines. This results in serious pollution and wastes a precious resource, which could be recovered prior to mining, such as CBM.

     Our business strategy is to explore, develop and produce the coalbed methane currently untapped in China. China is currently the world’s second largest user of petroleum and one of the largest importers of oil and gas in the world. China’s energy needs are also increasing rapidly, fueled in part by a recent economic upswing in the country. Demand in China is projected to outpace the rest of the world over the next decade. As a result of China’s increasing energy needs, the Chinese government has, in recent years, focused its attention on the development of energy sources, including CBM. As reported in the China Daily, China has mandated that natural gas replace coal as a major source of electricity by the 2008 Summer Olympics being held in Beijing. As part of its plan to increase coalbed methane production, the State Council of the PRC, the chief administrative body of the PRC, created the China United Coalbed Methane Co. Ltd. (“CUCBM”). The State Council has granted CUCBM the exclusive right to contract with foreign corporations for the exploration, development and production of coalbed methane in China. In addition, the Chinese government has provided incentives to stimulate the development of CBM, including exempting CBM development from import duties and import-related duties (Encouraged and Restricted B of the Guidance Catalog of Industries for Foreign Investments, specific measures executed in accordance with No. 1602 Document issued by the State Administration of Customs in 1997) and reducing value-added tax, or VAT, for CBM projects with foreign companies at 5% compared to 13% to 17% VAT for conventional gas companies (“The Notice of the Interim Regulations Concerning the Value-Added Tax, Consumption Tax and Sales Tax Applied to Foreign Investment Enterprise and Foreign Enterprise” (February 22, 1994) Item 3).

Horizontal Drilling

     Horizontal drilling technology has yielded successful results in coalbed methane applications in the United States. We plan to leverage this technology in our coalbed methane production in China. A horizontal well allows a well bore to be in contact with hundreds of feet of coal because the drill stem, when it hits the coal seam, is redirected from a downward angle to a horizontal plane and follows the coalbed for hundreds of feet in various directions. This access should change the dynamics of the CBM recovery. In a normal CBM well, we would have to drill an 8-inch hole contacting and hollowing out a coal seam 10 feet thick. With horizontal drilling, we can go directly along the coal seam for hundreds of feet or more in many directions, increasing the coalface exposure. This greater exposure of the coalface to flow associated with horizontal drilling allows more CBM production on a daily basis than can be achieved with conventional vertical stimulation techniques. Although horizontal wells are more costly than traditional wells, they offer more potential in reduced surface facilities and increased production rate.

Our Holdings in the People’s Republic of China

     We are parties to production-sharing contracts and farmout agreements covering over 1.3 million acres in two Provinces in China – the Yunnan Province in the southern region of China and the Shanxi Province in the northern region of China.

Yunnan Province, China

     On January 25, 2002, we entered into one production sharing contract with CUCBM to develop two areas in the

3

Yunnan Province: (1) the Enhong project, which covers approximately 145,198 acres and (2) the Laochang project, which covers approximately 119,772 acres. We act as operator under the production sharing contract. The term of the production sharing contract with CUCBM consists of an exploration period, a development period and a production period. The exploration period is divided into two phases called Phase I and Phase II. Following completion of Phase II of the exploration period, we may elect to continue the production sharing contract and conduct development and production operations on any CBM discoveries. The development period as to any CBM field in the Enhong-Laochang project will begin after the approval of a development plan submitted by us with respect to that field by the State Council of the PRC and confirmed by CUCBM. The production period as to any CBM field in the Enhong-Laochang project will begin after the date of commencement of commercial production of that CBM field. Our agreement with CUCBM expires 20 years from the start date of the production period of the Enhong-Laochang project.

     During the exploration period, we hold a 100% participating interest in the properties, and we must bear all exploration costs for discovering and evaluating CBM bearing areas. Prior to the beginning of the development period of any CBM field in the Enhong-Laochang project, CUCBM may elect to participate in the development of that CBM field at a level of between zero to 40%. Therefore, depending upon CUCBM’s participation, should we elect to develop a CBM field, our working interest in that CBM field will range from 60% to 100%. If any CBM field is discovered, the development costs for that CBM field will also be borne by CUCBM and us in proportion to the respective participating interests. Our Phase I and Phase II obligations during the exploration period of our production sharing contract with CUCBM are as follows:

Phase I

     We have completed our Phase I obligations. These obligations required us to drill and complete three wells on the project, perform a hydraulic fracture and test of one of these three wells and drill two slim hole vertical wells.

     We believe the three wells we have drilled under our Phase I requirement have yielded favorable gas content results. Below is a description of the initial testing results we have obtained from these three wells drilled in the Enhong-Laochang project:

	•	FCY-LC01 – total depth 825 meters (2,722 feet). A total of 15 mineable coal seams were penetrated during the drilling of the well, with a total thickness of 29.4 meters (97 feet), which we consider to be excellent. The coring of the coal samples showed a recovery rate of 94.8%. In addition, the drilling revealed four targeted major coal seams with a total thickness of 16.3 meters (54 feet), all within an interval of about 110 meters (363 feet), which we believe are favorable for production of CBM. Testing of 18 desorption samples from the well resulted in gas content estimates of approximately 18 cubic meters per ton of coal or about 650 cubic feet per ton of coal.
	•	FCY-EH02 – total depth 420 meters (1,344 feet). The well penetrated 15 coal seams with a thickness of 16.7 meters (53 feet). The total thickness of the coal seams targeted for potential production was 6.6 meters with a recovery rate of 70%. Estimated gas content, based on preliminary desorption results is approximately 10 cubic meters per ton of coal, or about 350 cubic feet per ton of coal.
	•	FCY-EH01 – total depth 435 meters (1,436 feet). The well penetrated 42 coal seams with a thickness of 42.8 meters (141 feet). The total thickness of the four coal seams targeted for potential production was 17.2 meters (57 feet). Estimated gas content, based on preliminary desorption results, is approximately 8 to 10 cubic meters per ton of coal, or approximately 280 to 350 cubic feet per ton of coal.

Phase II

     On February 23, 2005, we elected to enter into Phase II, which will require us to drill at least one additional horizontal well with a minimum of two laterals. Our Phase II obligations are required to be completed by December 31, 2005. Following completion of Phase II of the exploration period, we may elect to conduct development and production operations on any CBM discoveries.

4

     Although we believe we have realized strong results from the first three wells drilled and completed, we cannot provide any assurances that we will achieve commercial viability for the projects in the Yunnan Province. The three wells alone cannot produce sufficient CBM to achieve commercial viability. We must complete several more wells in close proximity to the wells we have already drilled in order to make it feasible to begin production from any of our current Enhong-Laochang project wells. Furthermore, because there is no gas pipeline, liquefied natural gas (“LNG”) plant or other off take candidate in near proximity to these wells, our ability to sell CBM produced on these projects to communities outside the general area will be contingent upon a pipeline or LNG plant being built near the Enhong- Laochang project. Actual production may vary materially from preliminary test results. Actual production from the wells may be at recovery rates and gas quality materially worse than our first indications.

     Pursuant to the terms of our production sharing contract with CUCBM, we have paid CUCBM signature fees totaling $350,000. We have also agreed to make the following payments in connection with the production sharing contract:

	•	During the exploration period, we must reimburse CUCBM for government-imposed fees for CBM exploration rights. During 2004, we reimbursed CUCBM $8,000 for these fees. The CBM exploration rights will be allocated to CUCBM and us in proportion to our participating interest in the development and production periods;
	•	We must pay assistance fees to CUCBM totaling $45,000 per year during the exploration period and $80,000 per year during the development and production periods;
	•	We have agreed to pay training fees for Chinese personnel working on the projects of $45,000 per year during the exploration period, and $80,000 per year during the development and production periods; and
	•	During the exploration period, we have agreed to pay salary and benefits for CUCBM professionals, which are currently approximately $15,800 per month. The allocation of salary and benefits for CUCBM professionals during the development and production period shall be determined by CUCBM and us through consultation.

     In addition to our holdings in the Enhong-Laochang project, on January 25, 2002, we entered into a production sharing contract with CUCBM with respect to CBM acreage in the Zhaotong region. This contract has not yet received governmental approval, and we have informed CUCBM that we do not anticipate pursuing this contract as we intend to focus our efforts on the Yunnan Province and Shanxi Province projects.

Shanxi Province, China

     In June 2003, we entered into two farmout agreements and assignment agreements with Phillips pursuant to which we acquired a 40% net undivided interest from Phillips in two production sharing contracts between Phillips and CUCBM for the Shanxi Province (the “Shanxi Agreements”). The Shanxi Agreements cover a total of 1,057,650 acres. The project areas covered by the Shanxi Agreements are located in the Shouyang Block (near Taiyuan City) and the Qinnan Block (near Jincheng and Quinshui). The assignment agreements and related amendments to the farmout agreements substituted us for Phillips as the principal party and operator for the projects under the production sharing contracts. These agreements were approved by CUCBM on March 15, 2004 and ratified by the PRC’s Ministry of Commerce on March 22, 2004.

     The term of each of the Shanxi Agreements consists of an exploration period, a development period and a production period. The exploration period is divided into three phases called Phase I, Phase II and Phase III. We have completed our Phase I obligations under the Shanxi Agreements and have elected to enter into Phase II of the exploration period. Following completion of Phase III of the exploration period, we may elect to continue the production sharing contracts and conduct development and production operations on any CBM discoveries. The development period as to any CBM field in the Shanxi Province project will begin after the approval of a development plan submitted by us with respect to that field by the State Council of the PRC and confirmed by CUCBM. The production period as to any CBM field in the Shanxi Province project will begin after date of commencement of commercial production of that CBM field. Our agreement with CUCBM expires on April 1, 2034.

5

     Currently, we have a 40% participating interest, Phillips has a 30% participating interest and CUCBM has a 30% participating interest in each of the Shaouyang Block and the Qinnan Block of the Shanxi Province. If we successfully complete Phase II, Phillips will have the option to elect to retain a net undivided 30% participating interest or an overriding royalty interest up to 3.5% of the total participating interest. Additionally, prior to the beginning of the development period of any CBM field in the Shanxi project, CUCBM may elect to participate in the development of that CBM field at a level of between zero and 30%. Therefore, depending upon whether Phillips and CUCBM elect to participate in the project, our interest will range from 40% (assuming full participation by Phillips and CUCBM) to 96.5% (assuming both CUCBM and Phillips choose not to participate).

     We must bear all exploration costs for discovering and evaluating CBM bearing areas during Phase II. If we successfully complete Phase II and Phillips elects to retain a 30% participating interest, then the exploration and development costs of the project will be borne 70% by us and 30% by Phillips. If any CBM field is discovered, the development costs for that CBM field will also be borne by us, Phillips and CUCBM in proportion to the respective participating interests. Our Phase I, Phase II and Phase III obligations during the exploration period of the Shanxi Agreements are as follows:

Phase I

     We have completed our Phase I obligations. Phase I obligated us, at our expense, to perform a hydraulic fracture of one of three exploration wells previously drilled by Phillips by January 31, 2005. In September 2004, the hydraulic fracture and testing was completed on the QN-002 well drilled previously by Phillips on its acreage in the Qinnan Block located in the Shanxi Province of China. The test was performed on the #3 coal seam at a depth of 550 meters (1,880 feet), completing our requirements for Phase I under the Shanxi Agreements. We will continue dewatering this well until approximately the end of March 2005.

Phase II

     We have elected to enter into Phase II, which requires us to drill two horizontal wells in the Shouyang block by December 31, 2005. We have agreed to use our best commercial efforts to drill each of the horizontal wells to 4,000 meters of horizontal drilling in coal seam with a minimum requirement under the farmout agreement of 2,000 meters drilled in coal seam per well.

Phase III

     If we elect to commit to Phase III in the Shanxi Province, we will be required to drill one horizontal well, under which we will attempt to drill to 4,000 meters in coal seam. Phase III terminates on July 1, 2007. Our total work commitment in Phases II and III, if we elect to commit to Phase III, will consist of a total of 12,000 meters of horizontal drilling in coal seam for the three wells combined.

     We have agreed to make the following payments in connection with the production sharing contracts with CUCBM:

	•	During the exploration period, we must reimburse CUCBM for government-imposed fees for CBM exploration rights. During 2004, we reimbursed CUCBM $56,000 for these fees. The CBM exploration rights will be allocated to CUCBM and us in proportion to our participating interest in the development and production periods;
	•	We have agreed to pay signature fees totalling $300,000, which will be due within 30 days after first approval of the overall development plan following the exploration period;
	•	We must pay assistance fees to CUCBM totaling $100,000 per year during the exploration period and $240,000 per year during the development and production periods;

6

	•	We have agreed to pay training fees for Chinese personnel working on the projects of $120,000 per year during the exploration period, and $300,000 per year during the development and production periods; and
	•	During the exploration period, we have agreed to pay salary and benefits for CUCBM professionals, which are expected to be $13,500 per month through June 2005. The allocation of salary and benefits for CUCBM professionals during the development and production period shall be determined by CUCBM and us through consultation.

     The Shanxi Agreements required that we post a $1.0 million bank guarantee or surety bond by May 14, 2004 to guarantee performance of the evaluation and work program to test existing wells. On May 14, 2004, we placed $1.0 million into escrow to satisfy this bond. The $1.0 million escrow account will continue to be held until December 31, 2005. In the event that we have not completed drilling of the first horizontal well in Phase II by June 30, 2005, we will be required to increase the escrow account to $2.6 million. Notwithstanding the requirement to increase the amount of the escrow account to $2.6 million on June 30, 2005, subject to the prior written consent of Phillips, we will be able to drawdown amounts from this escrow account required to fund operations in Phase II after June 30, 2005. Each drawdown may not exceed $250,000.

Transportation of Our CBM in China

     The marketability of any production will depend, in part, upon the availability, proximity and capacity of pipelines, gas gathering systems and processing facilities. We may transport our CBM through pipelines or by compressing or liquefying the CBM for transportation. No facilities presently exist to transport or process CBM near our Yunnan Province projects, and, although larger pipelines exist in proximity to our Shanxi Province projects, pipelines must be built to connect to larger pipelines that do exist or facilities must be added to compress or liquefy and transport our CBM.

     CBM projects traditionally require multiple wells to properly dewater the coal and generate predictable volumes of gas. It is not yet possible to predict volumes so decisions about marketing the CBM cannot yet be made. Once we have initial production of CBM from our Shanxi or Yunnan Province projects, we can begin to market the CBM produced to local markets as compressed natural gas (“CNG”), which is an alternative to earn revenues from any early production. Production of CNG would require the installation of a compressor which we could purchase and install for approximately $220,000. Installation of the compressor could be completed in approximately 90 days and could be funded from existing cash resources.

     We also have the alternative to market CBM by connecting to a large pipeline in the Shanxi Province, building a pipeline in the Yunnan Province or constructing LNG facilities in the two provinces. We do not currently have the funds to build these facilities. We will be required to raise additional funds through financings or other means or to find a strategic partner to complete these facilities. It is not likely that any such facilities will be built until favorable results are obtained from several more wells. We are delaying any decision regarding the construction of LNG facilities or pipelines until such time as significant CBM production volumes are achieved. We believe this delay may allow us to avoid construction costs to the extent other strategic partners attracted by our CBM production or prospects, have constructed, are constructing or are planning to construct, such facilities.

Yunnan Province

     No gas pipeline, LNG plant, or other offtake candidate currently exists to take CBM from our properties in Yunnan Province, and it is not likely that any such facilities will be built until favorable results are obtained from several more wells. At the present time, because there are no pipelines to move gas for any great distance in the Yunnan Province, natural gas will have to be sold to the local communities. As described above, CNG transportation is an opportunity until sufficient volume is produced to attract pipeline or LNG construction. We believe we would need to develop as many as 10 wells to attract a transportation company to build either a pipeline or an LNG plant near our wells.

     We may construct pipelines to move CBM from our fields to either municipalities or other pipelines. We estimate the cost to construct a pipeline 50 miles in length with a capacity of 350 million cubic feet per day capacity (MMcfpd) to connect to the Enhong and Laochang areas of the Yunnan Province to be approximately $50 million.

Shanxi Province

     Two existing pipelines could support our project in the Shanxi Province. The West-East pipeline runs approximately 10 kilometers south of the Qinnan Block in the Shanxi Province. This pipeline has the capacity of 1,000 MMcfpd. The Shanjing II pipeline to Beijing is a 40” line that has a 1,000 MMcfpd capacity and runs approximately 40 kilometers north of our Shouyang Block in the Shanxi Province. In the Qinnan and Shouyang blocks, we estimate the cost to construct two pipeline connections with 850 MMcfpd of capacity from the Shouyang and Qinnan blocks to the Shangjing II and West-East pipelines, respectively, to be approximately $63 million (about 30 miles in total for the two connecting pipelines).

LNG Facility

     To generate revenue in China prior to the point at which production reaches pipeline quantities, we may elect to

7

construct LNG facilities on our properties. However, we believe a LNG company, attracted by our CBM production or prospects, may decide to construct such facilities near our properties at their own cost. This would allow CBM to be produced and sold in the period before we achieve production in sufficient quantities to justify constructing short connecting pipelines to the Shangjing II and West-East pipelines in the Shanxi Province, or before a pipeline or other offtake facility is operational in the Yunnan Province. We estimate that a 100-ton per day LNG facility, which would liquefy approximately five MMcfpd of gas per day, would cost $10 to $15 million to construct and take about two years for construction. We estimate that a 1,000-ton per day facility capable of liquefying 50 MMcfpd would cost approximately $75 million with construction time close to two years.

Our Competition

     The energy industry is highly competitive in all its phases. Competition is particularly intense with respect to the acquisition of desirable producing properties, the acquisition of coalbed methane prospects suitable for enhanced production efforts, and the hiring of experienced personnel. Our competitors in coalbed methane acquisition, development, and production include major integrated oil and gas companies and substantial independent energy companies, many of which possess greater financial and other resources.

Regulations Impacting Our Business

     Our operations will be subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for any pollution resulting from our operations.

Executive Officers

     The following table sets forth information concerning our executive officers:

     Michael R. McElwrath has served as our President, Chief Executive Officer, Secretary and Treasurer since October 2003. He became a Director in October 2003, and served as Chairman of the Board from October 2003 until January 2005. He was employed as Vice President of Hudson Highland (formerly known as TMP Worldwide) from 1999 until joining us in October 2003. He also served as Acting Assistant Secretary of Energy in the first Bush Administration, as Director of the National Institute for Petroleum and Energy Research, Director of British Petroleum’s outsourced exploration and production lab for the Americas and as Deputy Assistant Secretary for Policy for the U.S. Department of Interior in the last year of the Reagan Administration. Mr. McElwrath holds a J.D. from the University of Texas School of Law, as well as a B.A. from the Plan II Honors Program at the University of Texas. He is also a member of the Society of Petroleum Engineers, the Independent Petroleum Association of America, and the Texas Independent Producers and Royalty Owners Association.

     Bruce N. Huff was appointed Chief Financial Officer and Chief Accounting Officer in May 2004. Prior to joining the Company, Mr. Huff spent 13 years at Harken Energy Corporation beginning as Senior Vice President and Chief Financial Officer and eventually becoming the

8

President and Chief Operating Officer in 1998. He is a graduate of Abilene Christian University and a Certified Public Accountant.

     Tun Aye Sai has served as a Director and as our Director of China Operations since 2001. Mr. Sai has over 30 years of international mining and exploration experience, developing and managing mining projects in China and Southeast Asia. Since 1995, Mr. Sai has also served as a director and consultant for Kensam Enterprises Inc. He holds a Bachelor of Engineering degree in mining from Rangoon Institute of Technology, Rangoon, Burma and a Postgraduate Diploma in management and administration from the Institute of Economics, Rangoon, Burma.

     Garry R. Ward was appointed as our Senior Vice President, Engineering in February 2004. Mr. Ward has 23 years work experience in the energy business evaluating oil and gas properties throughout the United States. Prior to joining our company, Mr. Ward served as Reservoir Manager for Plains E&P between June 2003 and February 2004. Mr. Ward also served as the Reservoir Manager for 3TEC Energy from November 1999 to June 2003. Mr. Ward holds a M.S. degree in petroleum engineering from the University of Houston and a B.S. degree in petroleum engineering from the University of Missouri-Rolla. Additionally, Mr. Ward is a Registered Professional Engineer in the State of Texas.

     Alex Yang joined our company in September 2002 and was appointed as Senior Vice President, Exploration and Production in November 2003. Dr. Yang has 22 years of working experience in China’s energy industry and universities. From April 2002 through August 2002, Dr. Yang was a research fellow at Baylor College of Medicine. From 1999 to March 2002, Dr. Yang served as Chief Executive Officer and President of YT International, LLC, a consulting services company for the petroleum industry. He holds a B.S. degree in geology and exploration from Hefei Industrial University, a M.S. degree in geology from Nanjing University and a Ph.D in geology from Texas A&M University.

Our Employees

     As of March 4, 2005, we had a total of 20 employees, all of whom were employed by us on a full-time basis.

ITEM 2. PROPERTIES

Undeveloped Lease Acreage

     As of December 31, 2004, we owned leasehold interests (or, in the case of our properties in China, had rights under production sharing contracts) covering the following undeveloped lease acreage.

China:

United States:

Other Properties

     Our principal office is located at 400 N. Sam Houston Parkway East, Suite 205, Houston, Texas 77060. The principal office, which presently consists of approximately 2,200 square feet at December 31, 2004, will increase to 4,343 square feet on April 1, 2005. The monthly rental is $2,900 through August 31, 2005, after which it will increase to $5,790 per month through May 31, 2007. We also maintain offices in Beijing, China and Kunming, Yunnan Province, China.

9

ITEM 3. LEGAL PROCEEDINGS

     On December 31, 2004, we entered into a settlement agreement with Jawaharlal Gondi and The Arthi Trust pursuant to which Mr. Gondi resigned as a director of the Company. Pursuant to the terms of the settlement agreement, we paid Mr. Gondi a total gross amount of $165,000 minus all applicable withholding, and reimbursed Mr. Gondi certain out-of-pocket expenses. The settlement agreement also provides that Mr. Gondi and The Arthi Trust, for a period of two years after the date of the settlement agreement, without our prior written consent, will refrain from certain activities related to seeking control of the Company. Pursuant to the settlement agreement, Mr. Gondi and The Arthi Trust also agreed to execute and deliver to us one or more proxies naming the members of our board of directors who are not our officers, as agents and proxies, with full power of substitution and re-substitution, to vote all shares of our capital stock or our other voting securities.

     We have no knowledge of any other pending or threatened material litigation, settlement of litigation, or other material claim involving us.

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

     Not applicable.

PART II

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

     Our common stock is not listed for trading on a registered exchange or quoted on the National Association of Securities Dealers Automated Quotation system (NASDAQ). Shares of our common stock are traded over the counter and quoted on the OTC Bulletin Board under the symbol “FEEC”. The OTC Bulletin Board provides information to professional market makers who match sellers with buyers. The high and low bid quotations of our common stock presented below includes intra-day trading prices. These quotations represent inter-dealer prices, without retail mark-up, mark-down, or commissions, and may not represent actual transactions.

     On March 4, 2005, we had 77,439,910 shares of common stock outstanding. There were approximately 169 stockholders of record as of March 4, 2005.

     We currently intend to retain all future earnings to fund the development and growth of our business. We have not paid dividends on our common stock and do not anticipate paying cash dividends in the immediate future. We did not repurchase any of our equity securities in 2004 and have not adopted a stock repurchase program.

10

Recent Sales of Unregistered Securities

     The following is a description of the unregistered securities we granted or issued during the period subsequent to December 31, 2004 and through the date of this report:

     • On February 9, 2004, we granted to one of our technical advisors an option to purchase 280,000 shares of our common stock at an exercise price of $2.00 per share in consideration for his service as a technical advisor. The option expires on February 9, 2009. The securities, which were taken for investment and were subject to appropriate transfer restrictions, were issued without registration under the Securities Act in reliance upon the exemption provided in Section 4(2) of the Securities Act.

     • On January 10, 2005, we issued a warrant to an accredited investor to purchase 375,000 shares of common stock at an exercise price of $1.25 per share in settlement of claimed anti-dilution rights granted in a previously completed private placement. The warrant expires on December 16, 2007. The securities, which were taken for investment and were subject to appropriate transfer restrictions, were issued without registration under the Securities Act in reliance upon the exemption provided in Section 4(2) of the Securities Act.

     • On January 19, 2005, we granted an option to a gas marketing consultant to purchase 80,000 shares of common stock at an exercise price of $2.00 per share in consideration for consulting services to be rendered by the consultant. The option expires on January 19, 2010. The securities, which were taken for investment and were subject to appropriate transfer restrictions, were issued without registration under the Securities Act in reliance upon the exemption provided in Section 4(2) of the Securities Act.

     • On January 20, 2005, we entered into two option agreements whereby an investor relations consulting firm, in consideration for certain investor relation services, received an option to purchase 50,000 shares of common stock at an exercise price of $4.40 per share and received an option to purchase 50,000 shares of common stock at an exercise price of $3.30 per share. The options expire on the second anniversary of the date on which the Securities and Exchange Commission declares a Registration Statement (as defined in the option agreement) filed by us effective. The securities, which were taken for investment and were subject to appropriate transfer restrictions, were issued without registration under the Securities Act in reliance upon the exemption provided in Section 4(2) of the Securities Act.

     • On January 31, 2005 and February 28, 2005, we issued 5,000 shares of our common stock, or a total of 10,000 shares of our common stock, to a consultant in consideration for certain investor relations services. The securities, which were taken for investment and were subject to appropriate transfer restrictions, were issued without registration under the Securities Act in reliance upon the exemption provided in Section 4(2) of the Securities Act.

11

ITEM 6. SELECTED FINANCIAL DATA

     The following selected financial data should be read in conjunction with the consolidated financial statements and supplementary information included in Item 8, Financial Statements and Supplementary Data.

12

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

     The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes contained elsewhere in this report.

Overview

     We are a development stage company, and our objective is to become a recognized leader in coalbed methane gas property acquisition, exploration, development and production. Our activities to date have been principally limited to organizational activities, including developing a strategic operating plan, capital funding, hiring personnel, entering into contracts, acquiring rights to explore, develop, produce and sell oil and gas or coalbed methane (CBM), and beginning in 2003, the drilling, testing and completion of exploratory wells.

     Our operations concentrate on CBM exploration and development in the Yunnan Province in Southern China and in the Shanxi Province in Northern China. During 2004, we completed drilling two wells in the Yunnan Province and fractured one existing well in the Shanxi Province. We incurred exploration and development costs of approximately $1.2 million in the Yunnan Province and approximately $1.0 million in the Shanxi Province during the year ended December 31, 2004. Additionally, we deposited $1.0 million in an escrow account to guarantee our performance under the Shanxi Agreements. Although we believe the results of our exploration activities in the Yunnan and Shanxi Provinces have been favorable, we will need to complete several more wells to achieve commercial viability in these provinces, which will require significant capital expenditures. No gas pipeline, liquefied natural gas plant, or other off-take candidate currently exists to transport CBM from our properties in the Yunnan Province, and it is not likely that any such facilities will be built until favorable results are obtained from several more wells. No liquefied natural gas plant, or other offtake candidate currently exists near our Shanxi Province projects, and pipelines must also be built on those projects to connect to larger pipelines to transport any CBM that may be produced from those projects. Actual production may vary materially from preliminary test results. Actual sustainable production from the wells may be at recovery rates and gas quality materially worse than our first indications.

     Until recently, we also owned undeveloped oil, gas and mineral rights and interests in approximately 149,000 net acres located in the eastern portion of Montana. On February 2, 2005, our wholly owned subsidiary, Newark Valley Oil & Gas, Inc., entered into a purchase and sale agreement with Zier & Associates, Ltd. for the sale of our oil and gas leasehold interests and other property interests in Montana. As a condition to the sale of our Montana properties, we acquired certain overriding royalty interests in adjoining acreage for $100,000, which were also sold under the terms of the purchase and sale agreement. The transaction closed on February 2, 2005. At the closing, we received gross proceeds of $1,135,000 from the sale of our Montana properties (including the overriding royalty interests described above). We consider our Montana properties to be non-core assets of our company. We sold these assets in order to focus our efforts on the exploration and development of our coalbed methane holdings located in China.

     We have not recognized any revenues from our operations and do not anticipate recognizing significant revenues prior to late 2006. We incurred a net loss of approximately $8.0 million for the year ended December 31, 2004, and we expect to incur losses and negative cash flows for the foreseeable future. As we are a development stage company concentrating on exploration and development of CBM, our expenditures primarily consist of geological and engineering services, exploration costs and travel expenses between our headquarters and China. Our expenses also consist of consulting and professional services (including fund raising expenses), compensation, legal and accounting and general and administrative expenses which we incurred in order to address necessary organizational activities.

     During the year ended December 31, 2004, we raised net proceeds of approximately $14.4 million from the sale of our common stock and warrants to purchase our common stock in private placements and $2.8 million from the exercise of warrants sold in previously completed private equity offerings. Management believes that we can fund our operations and planned exploration and development activities in China with our existing cash resources through the fourth quarter of 2005. During 2005, we estimate total capital expenditures in China will be approximately $6.5 million and our total operating expenditures will be $6.1 million. We will also require resources to fund significant capital expenditures for exploration and development activities and to fund operating expenses in future periods. As we do not have a source of revenue, we will require additional financing in order to continue our exploration and development in China and sustain our operating losses. We intend to finance our operations by various methods, which might include issuing equity securities, the continued exercise of warrants issued to investors in conjunction with the previously completed private offerings, and entering into farmout agreements and other arrangement with strategic partners, among other alternatives. If we fail to raise the necessary funds to complete our exploration activities, and we cannot obtain extensions to the requirements under our production sharing contracts, we would not be able to successfully complete our exploration activities, and we may lose rights under our production sharing contracts.

13

Results of Operations

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

     Geologic and engineering services increased due to a full year of leasehold costs on our Montana properties, surveying of sites for two wells completed in 2004 in the Yunnan Province and geological costs in the Shanxi Province.

     Exploration costs consist of the expense to drill the first Yunnan Province well, FCY-LC01, which was completed in November 2003. Costs related to the well were recorded as unevaluated well costs in property and equipment pending determination of whether proved reserves would be attributed to the well within one year; however, proved reserves have not been attributed to the well as it is still in the dewatering and testing phase. Statement of Financial Accounting Standards No. 19 (SFAS 19) requires that all costs for wells which are not attributed proved reserves within one year after completion be expensed. We anticipate incurring additional costs on the first well, which we will also expense. We completed two additional wells in the Enhong-Laochang block of the Yunnan Province in February 2004 and April 2004. The costs capitalized related to these two wells at December 31, 2004 were approximately $380,000 and $400,000. Because we anticipate that we may not be able to attribute proved reserves within the one year allowed under SFAS 19, we expect that we will expense the capitalized costs related to these wells in the first and second quarter of 2005.

     We incurred an impairment loss of $450,000 during the year ended December 31, 2004 as compared to $3,328,000 in 2003. In February 2005, our wholly owned subsidiary, Newark Valley Oil & Gas, Inc., sold our Montana properties to Zier & Associates, Ltd. for gross proceeds of $1,135,000. As a condition of that sale, we purchased overriding royalty interests on adjacent properties for $100,000, which were also sold under the terms of the purchase and sale agreement. The net proceeds, which we believe to be a measure of the value of properties, were compared to the carrying value, and an impairment of $450,000 was recorded. Any remaining loss on the sale of our Montana assets will be recognized in the first quarter of 2005. We will remain responsible for the payment of expenses and related accounts payable attributable to the Montana properties to the extent they relate to the time prior to February 2, 2005.

     The increase in our other consulting and professional fees in 2004 compared to 2003 is primarily attributed to expenses incurred in connection with our capital raising activities and higher expenses related to investor relations. The increase, to a lesser extent, is the result of CUCBM salaries incurred in 2004 under the terms of our production sharing contracts for the Shanxi Province project, which we did not incur in 2003, and financial printing costs related to the restatement of our previously filed Form 10-KSB and our quarterly reports and our registration statement filed with the SEC in July 2004 and declared effective in February 2005.

14

     Compensation expense increased primarily due to an increase in the number of permanent employees, including hiring permanent employees in engineering, finance and field operations, and bonus compensation earned in 2004. Additionally, the increase is partly attributed to training fees to train Chinese personnel in 2004 under the terms of our production sharing contracts for the Shanxi Province, which we did not incur in 2003.

     We record stock compensation under Accounting Principles Board Opinion 25, Accounting for Stock Issued to Employees (APB 25), which requires that we recognize compensation expense for the amount by which the market price exceeds the grant price on the grant date. Compensation expense decreased from 2003 to 2004 primarily as a result of our board of directors approving the vesting of our former chief executive officer’s unvested options in the third quarter of 2003. This resulted in all of the compensation expense related to these options being recorded in 2003. Additionally, fewer options with an exercise price below the market price were granted in 2004.

     Travel expense increased in 2004 compared to the prior year due primarily to additional travel to China as a result of our increased operations and additional travel for our capital raising efforts.

     Legal and accounting expenses have increased during 2004 compared to 2003 as a result of our registration statement filed with the SEC in July 2004 and declared effective in February 2005, our response to the SEC’s investigation regarding the ownership of our stock, our amendments to our previously filed Form 10-KSB and quarterly reports, Sarbanes Oxley Section 404 reporting, legal assistance with our private placements of equity and legal assistance in China with regulations as we have expanded our operations.

     General and administrative costs increased primarily due to a settlement with a former director, settlement of an asserted claim for warrants to purchase shares of our common stock, CUCBM assistance fees incurred for the first time under the Shanxi Agreements, increased expenses in China due to increased activity on our China projects and the granting of options to our technical advisors, which were formerly known as our advisory board, which is not elected by our stock holders.

     Interest expense decreased in 2004 compared to 2003 primarily as a result of expenses incurred in 2003 related to the beneficial conversion feature for our notes payable in the principal amount of $300,000. These notes payable were executed in the second and third quarters of 2003. We incurred no similar debt obligations in 2004.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

15

     Geologic and engineering services decreased in 2003 compared to 2002 as we reduced our dependence on outside consultants and employed in-house geologists.

     Impairment loss for the year ended December 31, 2003 increased to $3,328,000, as a result of the acquisition of Newark Valley Oil & Gas, Inc. The aggregate acquisition price was $4,778,000, which included 1,600,000 shares of our common stock valued at $3,600,000 among other consideration. The value of the common stock was determined based on the market price of the shares on the date of the consummation of the agreement. Simultaneous to the consummation of the agreement, assets were deemed to be impaired and written down to their fair value. Fair value, which was determined by valuation of the reserves estimated for the assets acquired, indicated a revised carrying value of approximately $1,450,000. Accordingly, an impairment loss of $3,328,000 has been charged to operations in 2003. A reduction in natural gas prices, increase in exploration costs or increase in production costs could result in additional impairment in subsequent periods.

     Other consulting and professional services increased in 2003 compared to 2002 due to the professional fees paid to CUCBM for the first time in 2003.

     Compensation increased in 2003 compared to 2002 due to hiring certain individuals who provided consulting services in 2002 and also due to severance expenses resulting from changes in senior management during 2003.

     Stock compensation expense was $930,000 during 2003 due to the granting of options at exercise prices below market at the date of the grant. We recognize compensation expense for the difference between the exercise price and the market value as the options vest. Additionally, our board of directors approved vesting of our former chief executive officer’s unvested options in the third quarter of 2003, resulting in all compensation expense related to these options being recorded in 2003.

     Travel costs decreased in 2003 compared to 2002, as we focused on planning a development program for the concessions won during 2002. During 2002, we incurred significantly more overseas travel by U.S. personnel as management and consultants pursued several potential foreign concessions and capital raising activities during 2002.

     The increase in our legal and accounting expenses during 2003 as compared to 2002 was primarily attributed to greater professional fees required to comply with SEC reporting requirements as a result of our planning and development of properties and expanded operations during 2003, costs incurred in response to SEC’s investigation regarding the ownership of our stock, and to address other ongoing legal matters related to the threatened litigation at December 31, 2003, which was subsequently settled in 2004. The increase was also partially attributed to costs incurred related to our private placement offering of stock to investors outside of the United States.

     General and administrative expense increased $248,000 in 2003 compared to 2002 due primarily to assistance fees paid to CUCBM pursuant to our production sharing contracts for the Yunnan Province project. Additionally, the increase in general and administrative expense was due to management and accounting personnel temporarily engaged on a contract basis during 2003 and increased overhead expenditures as we established and expanded operations in China.

     Interest expense increased $168,000 due to the recognition of interest expense related to the beneficial conversion feature of our loan in the principal amount of $200,000 from Clarion Finance AG and our loan in the principal amount of $100,000 from Professional Trading Services, which were executed in the second and third quarters of 2003.

16

Capital Resources and Liquidity

     We have no source of revenue or cash flow from operations, and our primary source of cash flow has been cash proceeds from private placements of our common stock and warrants to purchase our common stock. Our principal requirements for cash are exploration and development of our CBM properties in China. We believe that we have adequate cash resources to fund our operations and exploration and development operations in China through the fourth quarter of 2005; however, to continue to operate after 2005 and to complete our projects in China, we will be required to raise additional funds.

Cash flow

     As of December 31, 2004, our cash and cash equivalents were $11,418,000, excluding the $1,000,000 of restricted cash held in escrow pursuant to our Shanxi Province farmout agreements. Cash and cash equivalents was $2,326,000 at December 31, 2003 and $1,008,000 at December 31, 2002.

     Cash used in operating activities for the year ended December 31, 2004 was $5,711,000 as compared to $2,178,000 for 2003 and $1,871,000 for 2002. We generated no revenue in each of those years, and we have experienced increased cash operating expenses, including compensation, geologic and engineering services, legal and accounting and general and administrative due to the factors described above.

     Cash used in investing activities for the year ended December 31, 2004 was $2,411,000 as compared to $1,920,000 for 2003 and $198,000 for 2002. During 2004, we deposited $1,000,000 in escrow for a performance guarantee required under our Shanxi Province farmout agreements. Additionally, in 2004, approximately $1,404,000 was spent in China with the completion of three wells in the Yunnan Province and fracturing performed on one well in the Shanxi Province. Cash used in investing activities for the year ended December 31, 2003 was primarily attributed to acquisition of oil and gas properties and exploration and development costs in China. In 2003, we acquired our Montana properties for consideration including approximately $600,000 in cash, and the remaining $1,282,000 was expended in China in 2003. In 2002, we paid the initial mineral rights amount to acquire the Yunnan Province production sharing contract.

     Cash provided by financing activities increased to $17,216,000 for the year ended December 31, 2004 as compared to $5,416,000 for 2003 and $3,052,000 for 2002. The increase in cash provided by financing activities reflects proceeds from the private placement of our common stock and warrants to purchase our common stock as well as the exercise of warrants from previously completed equity offerings. Net proceeds from these capital raising transactions were approximately $14.4 million in 2004 compared to $5.1 million in 2003. Additionally, during the year ended December 31, 2004, we have received approximately $2,827,000 upon the exercise of warrants to purchase 2,827,286 shares of our common stock. In 2003, we received approximately $33,000 upon the exercise of warrants to purchase 32,692 shares of our common stock.

Capital Resources and Requirements

     In February 2005, our wholly owned subsidiary, Newark Valley Oil & Gas, Inc. entered into a purchase and sale agreement with Zier & Associates, Ltd. for the sale of our oil and gas interests and other property interests in Montana. As a condition of the sale, we acquired certain overriding royalty interests in adjoining acreage for $100,000, which were also sold under the terms of the purchase and sale agreement. At the closing, we received gross proceeds of $1,135,000 from the sale of our Montana properties.

     The Shanxi Agreements required that we post a $1.0 million bank guarantee or surety bond by May 14, 2004 to guarantee performance of the evaluation and work program to test existing wells. On May 14, 2004, we placed $1.0 million into escrow to satisfy this bond. The $1.0 million escrow account will continue to be held until December 31, 2005. In the event that we have not completed drilling of the first horizontal well in Phase II by June 30, 2005, we will be required to increase the escrow account to $2.6 million. We believe that we can satisfy this requirement, if necessary with our current cash resources. Notwithstanding the requirement to increase the amount of the escrow account to $2.6 million on June 30, 2005, subject to the prior written consent of Phillips, we will be able to drawdown amounts from this escrow account required to fund operations in Phase II after June 30, 2005. Each drawdown may not exceed $250,000.

17

We anticipate that we will be able to draw down the total amount of the escrow during 2005.

     Our board of directors has the authority, without further action by the stockholders, to issue up to 500.0 million shares of preferred stock in one or more series and to designate the rights, preferences, privileges and restrictions of each series. We also have 500.0 million shares of common stock authorized under our charter documents, of which 76.5 million shares was issued and outstanding as of December 31, 2004. The issuance of preferred stock could have the effect of restricting dividends on the common stock or delaying or preventing our change in control without further action by the stockholders. While we have no present plans to issue any shares of preferred stock, we may need to do so in the future in connection with capital raising transactions. In addition, we may issue additional shares of common stock in connection with fundraising activities. The issuance of additional common stock would also have a dilutive impact on our stockholders’ ownership interest in our company.

     The exploration and development of coalbed methane gas reserves requires substantial capital expenditures. In order to reduce our investment in a particular project, we may form joint ventures and seek joint venture partners to share the costs. We incurred $2.5 million of costs related to exploration and development during the year ended December 31, 2004. We anticipate that cash expenditures for planned 2005 exploration and development activities would include:

	•	Yunnan Province Phase I. We have completed our Phase I obligations under our production sharing contract for the Yunnan Province in the first quarter of 2005, which required us to perform a hydraulic fracture and test one of the three wells drilled previously and to drill two slim hole vertical wells. Our expected expenditures are approximately $767,000 for the completion of these Phase I expenditures.
	•	Yunnan Province Phase II. We elected to continue to Phase II, and our obligations will require us to drill at least one additional horizontal well with a minimum of two laterals. Our Phase II obligations are required to be completed by December 31, 2005. We expect to incur capital expenditures associated with these Phase II obligations of approximately $2.0 million.
	•	Shanxi Province Phase II. We have completed our Phase I obligations, and we have elected to enter into Phase II under the Shanxi Agreements. Our Phase II obligations require us to drill two horizontal wells in the Shouyang block by December 31, 2005. We expect to incur capital expenditures associated with these Phase II obligations of approximately $3.5 million.

     We will also require resources to fund significant capital expenditures for exploration and development activities and to fund operating expenses in future periods. We do not anticipate recognizing significant revenues prior to late 2006. CBM projects traditionally require multiple wells to properly dewater the coal and generate predictable volumes of gas. It is not yet possible to predict volumes so decisions about marketing the CBM cannot yet be made. To generate revenue in China prior to the point at which production reaches pipeline quantities, we may elect to install compressors and produce compressed natural gas (CNG), which could be sold to local communities. This alternative would cost approximately $220,000 for each compressor. Installation of the compressor could be completed in approximately 90 days, and could be funded from existing cash resources. We could also elect to construct LNG facilities on our properties. We estimate that a 100-ton per day LNG facility, which would liquefy approximately five million cubic feet of gas per day, would cost approximately $10 to $15 million to construct. We estimate that a 1,000-ton per day facility capable of liquefying 50 million cubic feet of gas per day would cost approximately $75 million. However, we believe it is possible that an LNG concern attracted by our CBM production or prospects, may decide to construct such facilities near our properties at their own cost. We may construct pipelines to move CBM from our fields to either municipalities or other pipelines. We estimate the cost to construct a pipeline in the Enhong and Laochang areas of the Yunnan Province to be approximately $50 million. Our farmout agreement from Phillips provides us with rights to two separate blocks, including the Shouyang block, approximately 40 km south of the Shangjing II pipeline to Beijing, and the Qinnan block, approximately 10 km north of the West-East pipeline to Shanghai. We estimate the cost to construct pipeline connections from the Shouyang and Qinnan blocks to the Shangjing II and West-East pipelines, respectively, to be approximately $63 million. We are delaying any decisions regarding the construction of LNG facilities or pipelines until such time as significant CBM volumes are achieved. We believe this delay may allow us to avoid construction costs to the extent other strategic partners have constructed, are constructing or are planning to construct, such facilities.

     We do not currently have the funds to complete our current and proposed business operation in China or sustain our operating losses. Therefore, our ability to continue as a going concern depends upon our ability to raise additional,

18

substantial funds for use in our planned exploration and development activities, and upon the success of these activities. To develop our projects in China over the long term, we need to obtain project funding to satisfy significant expenditures for exploration and development of those projects, if they are successful. If we fail to raise the necessary funds to complete our exploration activities, and we cannot obtain extensions to the requirements under our production sharing contracts, we would not be able to successfully complete our exploration activities, and we may lose rights under our production sharing contracts.

     We intend to obtain the funds for our planned exploration and development activities by various methods, which might include the issuance of equity securities, continued exercise of warrants issued to investors in conjunction with the recently completed private offerings, obtaining farm-out partners and the potential sale of property interests among other alternatives. Therefore, we intend to continue to seek to raise equity or debt financing. No assurance can be given that we will be able to obtain any additional financing on favorable terms, if at all. If our operating requirements vary materially from those currently planned, we may require more financing than currently anticipated. Borrowing money may involve pledging some or all or our assets. Raising additional funds by issuing common stock or other types of equity securities would further dilute our existing stockholders. If we cannot obtain additional financing in a timely manner, we will not be able to continue our operations. Since there can be no guarantee of future fundraising success, and since the success of exploratory drilling can never, by definition be guaranteed, there is substantial doubt about our ability to continue as a going concern. The reports we received from our independent auditors for our years ended December 31, 2004, 2003 and 2002 financial statements contain an explanatory paragraph that states that our net losses since our inception and no established source of revenues raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of that uncertainty. Although there can be no assurances, management believes that we will continue to be successful in raising the funds necessary to explore for CBM, and, assuming success in those exploratory efforts, to raise the funds necessary for production and development.

Contractual Obligations Table

Obligations under non-cancelable agreements at December 31, 2004 were as follows:

Off-Balance Sheet Arrangements

     As part of our ongoing business, we do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structure finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2004, we were not involved in any unconsolidated SPE transactions.

19

Critical Accounting Policies

     Our discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. We consider an accounting estimate to be critical if (1) it requires assumptions to be made that were uncertain at the time the estimate was made; and (2) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.

     Management has discussed the development and selection of its critical accounting policies with our Audit Committee, and the Audit Committee has reviewed the disclosure presented below relating to them.

     We believe the following critical accounting policies reflect our significant estimates and judgments used in the preparation of our financial statements:

     Accounting for Oil and Gas Properties. We use the successful efforts method of accounting for our oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Certain costs of exploratory wells are capitalized pending determination that proved reserves have been found. If the determination is dependent upon the results of planned additional wells and required capital expenditures to produce the reserves found, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well and additional wells are underway or firmly planned to complete the evaluation of the well. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive or at the one year anniversary of completion of the well if proved reserves have not been attributed and capital expenditures as described in the preceding sentence are not required. We assess our capitalized exploratory wells pending evaluation each quarter to determine whether costs should remain capitalized or should be charged to earnings. Other exploration costs, including geological and geophysical costs, are expensed as incurred. We recognize gains or losses on the sale of properties on a field basis.

     The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Seismic costs incurred to select development locations within a productive oil and gas field are typically treated as development costs and capitalized. Judgment is required to determine when the seismic programs are not within proved reserve areas and therefore would be charged to expense as exploratory. The evaluation of oil and gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. For our Montana properties, drilling activities in an area by other companies may also effectively condemn leasehold positions.

     The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding oil and gas reserves. Seismic costs can be substantial which will result in additional exploration expenses when incurred. The initial exploratory wells may be unsuccessful and the associated costs will then be expensed as dry hole costs and any associated leasehold costs may be impaired. Coalbed methane wells require a period of time to dewater the wells prior to testing and determining whether proved reserves can be attributed to the well. If this period exceeds one year, and we anticipate that it will for our initial wells in the Yunnan and Shanxi Provinces, we will be required to charge the costs of these wells to exploration expense.

     Impairment of unproved oil and gas properties. Unproved leasehold costs and exploratory drilling in progress are capitalized and are reviewed periodically for impairment. Costs related to impaired prospects or unsuccessful exploratory drilling are charged to expense. The estimated fair value of unproved leasehold costs includes the present value of probable reserves discounted at rates commensurate with the risks involved in each classification of reserve. Our assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such leaseholds impacts the amount and timing of impairment provisions. An impairment expense could result if oil and gas prices decline in the future, as it may not be economic to develop some of these unproved properties.

20

As of December 31, 2004, we had total unproved oil and gas property costs of approximately $1.3 million consisting of undeveloped leasehold costs of $1.0 million in Montana, $0.3 million in China and unevaluated exploratory drilling costs of $1.3 million incurred in China.

     Estimates of future dismantlement, restoration, and abandonment costs. The accounting for future development and abandonment costs changed on January 1, 2003, with the adoption of Statement of Financial Accounting Standards (SFAS) No. 143. SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The accrual is based on estimates of these costs for each of our properties based upon the type of production structure, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based on numerous factors, including changing technology, the political and regulatory environment and estimates as to the proper discount rate to use and timing of abandonment.

     We have drilled three wells in the Yunnan Province, and Phillips drilled three wells in the Shanxi Province, which we acquired through our farmout agreements with Phillips. We will be required to plug and abandon those wells and restore the well site upon completion of their production. Sufficient testing on the wells has not been completed to determine the lives of these wells and therefore we have insufficient information to determine the timing of the obligations related to plugging, abandoning and restoring the site and cannot determine the present value of the obligation. Due to the small number of wells, we do not believe the obligation is material, and we will recognize the liability when a reasonable estimate of fair value can be made. Therefore, there is no provision in the accompanying consolidated financial statements.

     Assessments of functional currencies. Our Chinese operations use the Chinese Yuan as their functional currency. Management determines the functional currencies of our subsidiaries based on an assessment of the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.

     We have also adopted SFAS No. 52, Foreign Currency Translation, which requires that the translation of the applicable foreign currency into U.S. dollars be performed for balance sheet accounts using current exchange rates in effect at the balance sheet date and for revenue and expense accounts using a weighted average exchange rate during the period. The gains or losses resulting from such translation are included in the consolidated statements of stockholders’ equity and comprehensive income.

     Stock Based Compensation. We apply Accounting Principles Board Opinion 25, Accounting for Stock Issued to Employees (APB 25), and related interpretations in accounting for our stock option grants to employees and members of our board of directors. Compensation cost for stock options granted has been recognized for certain options granted at an exercise price below market value. Other options granted had an exercise price equal to or greater than the market value of the underlying common stock on the day of grant. We apply Statement of Accounting Standards No. 123 as amended by SFAS No. 148, Accounting for Stock-Based Compensation, for our technical advisors and consultants who are granted options. Compensation cost for stock options granted to technical advisors and consultants has been recognized as the fair value of the options granted on the grant date.

New Accounting Pronouncements

Stock Based Compensation

     On December 16, 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which is a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). SFAS 123(R) supersedes APB 25 and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows”. Generally, the approach in SFAS 123(R) is similar to the approach described in SFAS 123. However, SFAS

21

123(R) will require all share-based payments to employees, including grants of stock options to employees and members of the board of directors, to be recognized in our consolidated statements of operations based on their fair values. Pro forma disclosure is no longer an alternative.

     SFAS 123(R) must be adopted no later than July 1, 2005 and permits public companies to adopt its requirements using one of two methods:

	•	A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS 123(R) for all share-based payments granted after the effective date and based on the requirements of SFAS 123 for all awards granted to employees and members of the board of directors prior to the adoption date of SFAS 123(R) that remain unvested on the adoption date.
	•	A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures.

We have elected to adopt the provisions of SFAS 123(R) on July 1, 2005 using the modified prospective method.

     As permitted by SFAS 123, we currently account for share-based payments to employees and members of the board of directors using the intrinsic value method prescribed by APB 25 and related interpretations. As such, we recognize compensation expense to the extent that the exercise price of the options is below the market price on the date of grant for employee and director stock options. Accordingly, we anticipate that the adoption of SFAS 123(R)‘s fair value method will have a significant impact on our future result of operations. If we had adopted SFAS 123(R) in prior periods, the impact would have approximated the impact of SFAS 123 as described in the pro forma net income and earnings per share disclosures in Note 1 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data”. We have recorded options granted to our technical advisors and consultants at fair value on the date of grant, and there will be no effect on our results of operations for those options. We estimate that the adoption of SFAS 123(R), based on the outstanding unvested stock options at December 31, 2004, will result in future compensation charges to stock compensation expense and general and administrative expense of approximately $500,000 during the period from July 1, 2005 through December 31, 2005, and approximately $1.5 million during 2006.

Mineral Rights of Oil- and Gas-Producing Entities

     On September 2, 2004, the Financial Accounting Standards Board Staff issued FASB Staff Position No. 142-2, which addressed the classification and disclosure for drilling and mineral rights of oil- and gas-producing entities that are within the scope of Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Entities (SFAS 19). FASB Staff Position 142-2 states that the scope exception in paragraph 8(b) of Statement of Financial Standards No. 142, Goodwill and Other Intangible Assets (SFAS 142) includes the balance sheet classification and disclosures for drilling and mineral rights of oil- and gas-producing entities that are within the scope of SFAS 19. The drilling and mineral rights are not intangible assets under SFAS 142. As a result, we reclassified our intangible assets to property and equipment on the balance sheets and discontinued amortizing the balance. Subsequently, we will periodically review individual mineral rights to determine whether an impairment has occurred, and whether loss should be recognized.

Accounting for Suspended Well Costs

     On February 4, 2005, the Financial Accounting Standards Board Staff posted proposed FASB Staff Position FAS 19-a, Accounting for Suspended Well Costs, which addresses whether there are circumstances under the successful efforts method of accounting for oil and gas producing activities that would permit the continued capitalization of exploratory well costs beyond one year, other than when additional exploration wells are necessary to justify major capital expenditures and those wells are under way or firmly planned for the near future. The proposed FASB Staff Position states that the staff believes that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. The proposed Staff Position provides a list of indicators that an enterprise is making sufficient progress and provides for new disclosures concerning

22

the capitalized exploratory well costs that are pending the determination of proved reserves. Comments were due on the proposed FASB staff position on March 7, 2005, and we cannot predict the outcome at this time.

Forward-Looking Statements

     This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21B of the Exchange Act. All statements other than statements of historical facts contained in this report, including statements regarding our future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “expect” and similar expressions, as they relate to us, are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs. These forward-looking statements are subject to a number of known and unknown risks, uncertainties and assumptions described in this report.

     Although we believe that the expectations reflected in these forward looking statements are reasonable, there can be no assurance that the actual results or developments we anticipate will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Actual results could differ materially from those projected in such forward-looking statements. Factors that could cause actual results to differ materially from those projected in such forward-looking statements include: our lack of operating history; limited and potentially inadequate management of our cash resources; risk and uncertainties associated with exploration; development and production of coalbed methane; expropriation and other risks associated with foreign operations; matters affecting the energy industry generally; lack of availability of oil and gas field goods and services; environmental risks; drilling and production risks; changes in laws or regulations affecting our operations, as well as other risks described in this report and subsequent filings with the SEC.

     When you consider these forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this report. Our forward-looking statements speak only as of the date made. All subsequent oral and written forward looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

     Additional risks include, among others, the following:

Risks Relating to Our Business

We must obtain additional financing in order to continue our operations. Additionally, our independent accountants have reported that we may not be able to continue as a going concern if we do not obtain additional financing or achieve profitability.

     As of December 31, 2004, our net working capital was $10,826,000 and our total cash and cash equivalents were $11,418,000, excluding $1,000,000 of restricted cash. We do not anticipate recognizing significant revenues prior to late 2006, so we expect to experience operating losses and negative cash flow for the foreseeable future. We believe we currently have cash resources to fund our operations and planned exploration and development activities in China through the fourth quarter 2005. However, as we do not have a source of revenue, we will require additional financing in order to continue our exploration and development in China and sustain our operating losses. To develop our projects over the long term, we need to obtain funding to satisfy very significant expenditures for exploration and development of those projects. Furthermore, no facilities exist to transport or process CBM near our Yunnan Province projects, and pipelines must be built on our Shanxi Province projects to connect to larger pipelines to transport our CBM. Significant expenditures would be required to build out these facilities to the extent a strategic partner does not do so. We intend to finance our operations by various methods, which might include issuing equity securities, the continued exercise of warrants issued to investors in conjunction with the previously completed private offerings, and entering into farmout agreements and other arrangement with strategic partners, among other alternatives. Therefore, we intend to continue to seek to raise equity or debt financing. No assurance can be given that we will be able to obtain any additional financing on favorable terms, if at all. If our operating requirements differ materially from those currently planned, we may require more financing than currently anticipated. Borrowing money may involve pledging some or all of our assets. Raising

23

additional funds by issuing common stock or other types of equity securities would further dilute our existing stockholders. If we cannot obtain additional financing in a timely manner, we will not be able to continue as a going concern. The reports received from our auditors for the years ended December 31, 2004, 2003 and 2002 contained in our financial statements contain an explanatory paragraph that states that our net losses since our inception and no established source of revenues raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of that uncertainty.

We have a limited operating history.

     Since we began our exploration and development activities in 2002, we have been engaged principally in organizational activities, including developing a strategic operating plan, capital funding, hiring personnel, entering into contracts, acquiring rights to explore, develop, produce and sell CBM and, beginning in 2003, the drilling, testing and completion of exploratory wells. We are considered a development stage company for accounting purposes because we have generated no revenues to date. Accordingly, we have no relevant operating history upon which you can evaluate our performance and prospects. In addition, we cannot forecast operating expenses based on our historical results and our ability to accurately forecast future revenues is limited. As a result of our limited operating history, we are more susceptible to business risks including risks of unforeseen capital requirements, failure to establish business relationships, and competitive disadvantages against larger and more established companies.

We have no current source of revenue.

     We will not generate material revenues from our existing properties until we have successfully completed exploration and development, and started production of coalbed methane gas in China. We do not anticipate recognizing significant revenues from operations in China prior to late 2006. Additionally, no facilities exist to transport or process CBM near our Yunnan Province projects, and pipelines must be built on our Shanxi Province projects to connect to larger pipelines to transport our CBM. Our ability to realize revenues from any producing wells may be impaired until these facilities are built out or arrangements are made to deliver our production to market.

We have a history of losses, and expect to incur losses in the foreseeable future. If we do not achieve profitability, our financial condition and the price of our common stock will suffer.

     To date, we have no revenues from the sale of coalbed methane gas. We incurred net losses applicable to common stockholders of $8,004,000 and $7,217,000 for the years ended December 31, 2004 and 2003, respectively. We expect to experience operating losses and negative cash flow for the foreseeable future. We must obtain additional financing and generate significant revenues to fund anticipated drilling, exploration and operation costs and to achieve and maintain profitability. We cannot assure you we will ever generate sufficient revenues to achieve profitability, which will negatively impact the price of our common stock. If we do achieve profitability, we cannot assure you that we will be able to sustain or increase profitability in the future.

The development of coalbed methane properties involves substantial risks and we cannot assure you that our exploration and drilling efforts will be successful.

     The business of exploring for and, to a lesser extent, developing and operating coalbed properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The selection of prospects for coalbed methane gas drilling, the drilling, ownership and operation of CBM wells and the ownership of interests in CBM properties are highly speculative. We cannot predict whether any prospect will produce CBM or commercial quantities of CBM.

     Drilling for coalbed methane gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce coalbed methane in sufficient quantities or quality to realize enough net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain and cost overruns are common. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. In addition, other factors such as permeability may hinder, restrict or even make production impractical or impossible.

24

     Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. We may drill wells that, although productive, do not produce CBM in economic quantities. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well, or otherwise prevent a property or well from being profitable. A productive well may also become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. We cannot assure you that wells drilled by us will be productive or, even if productive, that will produce CBM in economic quantities so that we will recover all or any portion of our investment.

We are in the initial exploration phase and have substantial capital requirements that, if not met, will hinder our growth and operations.

     We face significant challenges, expenses and difficulties as a development stage company seeking to explore, develop and produce coalbed methane gas. The development of our projects in China will require that we obtain funding to satisfy very significant expenditures for exploration and development of these projects, if they are successful. We expect to incur approximately $6.5 million of exploration and development expenditures in 2005. We will also require resources to fund significant capital expenditures for exploration and development activities in future periods. In addition, there is currently no gas pipeline, LNG plant or other offtake candidate in place in Yunnan Province, and an LNG plant or two connecting pipelines will be required to be constructed to transport coalbed methane gas produced in the Qinnan and Shouyang areas of Shanxi Province. We estimate that the cost to construct pipelines in the Yunnan Province and Shanxi Province will total approximately $113 million. We do not currently have sufficient funds to complete our exploration and development activities and build these pipeline or LNG facilities. Our success will depend on our ability to obtain additional financing to fund our capital expenditures and build out CBM delivery facilities or to find a strategic partner with funds to do so. If we cannot obtain adequate capital, and we cannot obtain extensions to the requirements under our production sharing contracts, we would not be able to successfully complete our exploration and development activities, and we may lose rights under our production sharing contracts. This would materially and adversely affect our business, financial condition and results of operations.

No facilities presently exist to transport or process CBM near our Yunnan Province projects, and, although larger pipelines exist in proximity to our Shanxi Province projects, pipelines must be built to connect to larger pipelines or facilities must be added to compress or liquefy and transport any CBM that may be produced from those projects.

     The marketability of any production will depend, in part, upon the availability, proximity and capacity of pipelines, gas gathering systems and processing facilities. We may transport our CBM through pipelines or by compressing or liquefying the CBM for transportation. No gas pipeline, liquefied natural gas plant, or other offtake candidate currently exists to transport CBM from our properties in Yunnan Province, and it is not likely that any such facilities will be built until favorable results are obtained from several more wells. No liquefied natural gas plant exists near our properties in the Shanxi Province, and pipelines must also be built on our Shanxi Province projects to connect to larger pipelines to transport any CBM that may be produced from those projects.

     At the present time, because there are no pipelines to move gas for any great distance in the Yunnan Province, natural gas will have to be sold to the local communities. We may construct pipelines to move CBM from our fields to either municipalities or other pipelines. We estimate the cost to construct a pipeline 50 miles in length with a capacity of 350 MMcfpd to connect to the Enhong and Laochang areas of the Yunnan Province to be approximately $50 million. In the Quinnan and Shouyang blocks of the Shanxi Province, we estimate that we must eventually expend approximately $63 million for two short connecting pipelines with 850 MMcfpd capacity. We believe we would need to develop as many as ten wells to attract a transportation company to build either a pipeline or a LNG plant near our wells in the Yunnan Province and Shanxi Province. CBM sales from the Yunnan and Shanxi Provinces can also be achieved through development of a LNG plant. We estimate that a 100-ton per day LNG plant will cost approximately $10 to $15 million to develop and take about two years for construction. We estimate that a 1,000-ton per day LNG plant would cost approximately $75 million with construction time close to two years. We do not have funds to build any of these facilities. Our success will depend on our ability to raise additional funds through financings or other means or to find a strategic partner to complete these facilities.

25

We must complete multiple CBM wells on our Yunnan Province and Shanxi Province projects before we can commence production.

     We have drilled three CBM wells on our Yunnan Province project. We have also performed a hydraulic fracture and test on one of these three wells and drilled two slim hole vertical wells, which completed our Phase I obligations under our Yunnan Province production sharing contract with CUCBM. We have also performed a hydraulic fracture of one of three exploration wells previously drilled by Phillips, which completed our Phase I obligations under the Shanxi Agreements. The wells we have drilled to date alone cannot produce enough coalbed methane gas to achieve commercial viability. For each project, we must complete as many as ten wells in close proximity to one another in order to begin production from any of the wells in the Yunnan Province. We must also complete additional wells in the Shanxi Province to commence commercial production. We cannot make any assurances that we will have the resources to drill enough additional wells in the Yunnan and Shanxi Provinces to commence production in the areas. As a result, even though we may have producing properties in the region, we may not be in a position to derive any revenues from such wells. Actual production may vary materially from preliminary test results. Actual production from the wells may be at recovery rates and gas quality materially different than our first indications.

All of our operations are located in China.

     China is a developing country, has only recently begun participating in global trade with its accession to the World Trade Organization, and has only a limited history of trade practices as a nation. We are subject to the laws, rules, regulations, and political authority of the government of the PRC. We may encounter material problems while doing business in China, such as interactions with the Chinese government and uncertain foreign legal precedent pertaining to developing coalbed methane gas in China. Risks inherent in international operations also include the following:

	•	Local currency instability;
	•	Inflation;
	•	The risk of realizing economic currency exchange losses when transactions are completed in currencies other than U.S. dollars;
	•	The ability to repatriate earnings under existing exchange control laws; and
	•	Political unrest.

     Changes in domestic and foreign import and export laws and tariffs can also materially impact international operations. In addition, foreign operations involve political, as well as economic risks, including:

	•	Nationalization;
	•	Expropriation;
	•	Contract renegotiations; and
	•	Changes in laws resulting from governmental changes.

     In addition, CUCBM may be subject to rules and regulations of the PRC or the jurisdiction of other governmental agencies in the PRC that may adversely affect CUCBM’s ability to perform under, or our rights and obligations in, our production sharing contracts with CUCBM. In the event of a dispute, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of courts in the United States. We may also be hindered or prevented from enforcing our rights with respect to a governmental instrumentality because of the doctrine of sovereign immunity.

We may have difficulty managing growth in our business.

     Because of our small size and the relatively large scale of operations required for our business to yield revenue, growth in accordance with our business plan, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on these resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan. If we are unable to implement these actions in a timely manner, our results may be adversely affected.

26

We are dependent on our key executives and may not be able to hire and retain key employees to fully implement our business strategy.

     Our success will depend largely on our senior management, which includes, among others, Michael R. McElwrath, our chief executive officer, and Bruce N. Huff, our chief financial officer. As we grow our business, we must attract, retain and integrate additional experienced managers, geoscientists and engineers in order to successfully operate and grow our businesses. The number of available, qualified personnel in the oil and gas industry to fill these positions may be limited. Our inability to attract, retain and integrate these additional personnel or the loss of the services of any of our senior executives or key employees could delay or prevent us from fully implementing our business strategy and could significantly and negatively affect our business.

We are exposed to foreign currency risk.

     In recent years, the Chinese government has fixed the exchange rate between U.S. dollars and Chinese Yuan. Because the exchange rate has been fixed, instead of variable, we have experienced no fluctuations in the value of goods and services we purchase in China because of currency exchange. However, the United States and other foreign governments have repeatedly sought to establish a floating exchange rate between the Chinese Yuan and other foreign currencies. If, in the future, China accedes to these requests and permits currency float against the U.S. dollar, we must either adopt cash management strategies to hedge U.S. dollars against the Yuan or be subject to the exchange rate risks. In such case, if the value of U.S. dollar falls in relation to the Chinese Yuan, the cost to us of funding our Chinese operations would rise because more dollars would be required to fund the same expenditures in Yuan. Conversely, if the value of U.S. dollars rises in relation to the Chinese Yuan, the change in exchange rates would decrease our dollar cost to fund operations in China.

We risk the effects of general economic conditions in China.

     Any CBM sales we secure could be adversely affected by a sustained economic recession in China. As our operations and end user markets are primarily in China, a sustained economic recession in that country could result in lower demand or lower prices for the natural gas to be produced by us.

We are not diversified and we concentrate on one industry.

     Our business strategy will concentrate in exploration and development of coalbed methane gas in China. There is an inherent risk in not having a diverse base of properties in exploration and development, because we will not have alternate sources of revenue if we are not successful with our current exploration and development activities. As we will invest a high percentage of our assets in this market, we may be more affected by any single adverse economic, political or regulatory event than a more diversified entity. Our failure in the exploration and development of CBM property rights in China would have a material adverse affect on our business.

We may depend on a few customers.

     At present, we have no coalbed methane gas sales contracts pending. As we may only contract with a small number of entities that will purchase any gas we may produce, losing any such potential contract or client would have a material negative impact on our business.

If we borrow money to expand our business, we will face the risks of leverage.

     We anticipate that we may in the future incur debt for financing our growth. Our ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our revenue. If we do not meet our debt service payments when due, we may sustain the loss of our equity investment in any of our assets securing such debt upon the foreclosure on such debt by a secured lender.

27

Risk Related to the Oil & Gas Industry

The volatility of natural gas and oil prices could harm our business.

     Our future revenues, profitability and growth and the carrying value of the oil and gas properties depend to a large degree on prevailing oil and gas prices. Commercial lending sources are not currently available to us because of our lack of operating history or income. Our ability to borrow and to obtain additional equity funding on attractive terms also substantially depends upon oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, uncertainties within the market and a variety of other factors beyond our control. These factors include weather conditions in China, the condition of the Chinese economy, the activities of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternative fuel sources. The prices for oil and natural gas production have varied substantially over time and may in the future decline, which would adversely affect us and consequently, our stockholders. Prices for oil and natural gas have been and are likely to remain extremely unstable.

We may not be able to successfully compete with rival companies.

     The energy industry is highly competitive in all its phases. Competition is particularly intense with respect to the acquisition of desirable producing properties, the acquisition of coalbed methane prospects suitable for enhanced production efforts, and the hiring of experienced personnel. Our competitors in coalbed methane acquisition, development, and production include major integrated oil and gas companies in addition to substantial independent energy companies. Many of these competitors possess and employ financial and personnel resources substantially greater than those that are available to us and may be able to pay more for desirable producing properties and prospects and to define, evaluate, bid for, and purchase a greater number of producing properties and prospects than we can. Our financial or personnel resources to generate revenues in the future will depend on our ability to select and acquire suitable producing properties and prospects in competition with these companies.

The production and producing life of wells is uncertain and production will decline.

     It is not possible to predict the life and production of any well. The actual lives could differ from those anticipated. Sufficient coalbed methane may not be produced for us to receive a profit or even to recover our initial investment. In addition, production from our CBM gas wells, if any, will decline over time, and does not indicate any consistent level of future production.

We may suffer losses or incur liability for events for which the operator of a property or we have chosen not to obtain insurance.

     Our operations are subject to hazards and risks inherent in producing and transporting oil and natural gas, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and others. The occurrence of any of these events could result in the following:

	•	Substantial losses due to injury and loss of life,
	•	Severe damage to and destruction of property, natural resources and equipment,
	•	Pollution and other environmental damage,
	•	Clean-up responsibilities, and
	•	Regulatory investigation and penalties and suspension of operations.

As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, we believe any operators of properties in which we have or may acquire an interest will maintain similar insurance coverage. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

28

Environmental hazards and liabilities may adversely affect us and result in liability.

     There are numerous natural hazards involved in the drilling of CBM wells, including unexpected or unusual formations, pressures, blowouts involving possible damages to property and third parties, surface damages, bodily injuries, damage to and loss of equipment, reservoir damage and loss of reserves. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations.

     We maintain insurance coverage for our operations in amounts we deem appropriate, but we do not believe that insurance coverage for environmental damages that occur over time, or complete coverage for sudden and accidental environmental damages, is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the privilege to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur. The insurance coverage we do maintain may also be insufficient. In that event, our assets would be utilized to pay personal injury and property damage claims and the costs of controlling blowouts or replacing destroyed equipment rather than for additional drilling activities.

We face substantial governmental regulation and environmental risks.

     Our business is subject to various laws and regulations that may be changed from time to time in response to economic or political conditions. Matters subject to regulation include the following:

	•	Discharge permits for drilling operations,
	•	Drilling bonds,
	•	Reports concerning operations,
	•	The spacing of wells,
	•	Unitization and pooling of properties,
	•	Taxation, and
	•	Environmental protection.

     Regulatory agencies may also impose price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve oil and gas.

We are subject to environmental regulation that can materially adversely affect the timing and cost of our operations.

     Our exploration and proposed production activities are subject to certain laws and regulations relating to environmental quality and pollution control. Our operations in China are governed by production sharing contracts between CUCBM and us and the Shanxi Agreements. We are subject to the laws, decrees, regulations and standards on environmental protection and safety promulgated by the Chinese government. Various government laws and regulations concerning the discharge of incidental materials into the environment, the generation, storage, transportation and disposal of waste or otherwise relating to the protection of public health, natural resources, wildlife and the environment, affect our current exploration efforts and future development, processing and production operations and the costs related to them. This consists of obtaining environmental permits to conduct seismic acquisition, drilling or construction activities. Such regulations also typically include requirements to develop emergency response plans, waste management plans, environmental plans and spill contingency plans.

     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.

29

Risks Relating to our Securities

The SEC is currently investigating whether anyone has manipulated the price of our stock, profited from selling stock at artificially high prices and failed to file the appropriate SEC ownership forms.

     In December 2003, we learned that we are the subject of an investigation by the SEC. We understand that the SEC may be investigating whether anyone has issued false or misleading statements in connection with purchases and sales of our common stock, whether anyone has profited from selling stock at artificially high prices due to the manipulative statements, and whether any individual or group has failed to file ownership reports with the SEC as required for 10% or more beneficial owners under Section 16 of the Exchange Act or failed to file ownership reports with the SEC as required for 5% or more beneficial owners under Section 13 of the Exchange Act. Management does not know of any acquisitions in excess of 5% of its outstanding shares, except for those described in previous filings with the SEC under Section 13 and Section 16 of the Exchange Act. We have supplied information to the SEC in response to their information requests, including, but not limited to, information on record ownership, stock transfers, sales of our securities and board of director and committee meetings, and we intend to continue to cooperate with their investigation. We do not know what the outcome of their investigation may be.

     The Exchange Act and SEC rules require that a person or group of persons who acquire beneficial ownership of more than 5% of a class of equity securities that are registered under the Exchange Act must report their holdings in a Schedule 13D. The Schedule 13D with the SEC within 10 days after they become 5% stockholders, and must thereafter report changes in their beneficial ownership of their securities. In addition, Section 16(a) of the Exchange Act generally requires that beneficial owners of more than 10% of a class of stock that is registered under the Exchange Act report changes in their holdings within 48 hours of an acquisition or disposition of securities.

     If a person or group owns a large block of stock of a publicly traded company, particularly if that stock is not subject to restrictions on its purchase and sale on the open market, there is a risk that the person or group could sufficiently control the market for the stock to drive the stock’s trading price up or down, and thereby the undisclosed control group could reap trading profits at the expense of other public investors. In addition, Schedule 13D requires owners of a control group of stock to disclose their intentions with respect to management or control of the company. If an undisclosed group owns or obtains control of a block of our stock sufficient to control our company, they could change the management and direction of our company in ways we cannot predict.

A substantial amount of our outstanding securities will have resale restrictions lifted under Rule 144 within the next six months. We cannot predict the effect future sales of our common stock will have on the market price of our common stock.

     On March 4, 2005, we had 77,439,910 shares of common stock outstanding, of which 43,504,491, or 56%, were subject to resale restrictions. Of the 43,504,491 restricted shares, 17,170,000 shares have been held in the name of the holder of record for more than two years and, presuming all other Rule 144 requirements have been met, are currently eligible to have resale restrictions lifted without limitation. Of the 43,504,491 restricted shares 6,743,769 shares have been held for over one year and are eligible to have resale restriction lifted with limitation. Of the 43,504,491 restricted shares, 3,043,825 will become eligible to have resale restrictions lifted with limitation within the next six months by virtue of having been outstanding for more than one year. We have also registered 2,425,000 shares on a registration statement and during its effectiveness these shares will not be subject to resale restrictions.

     We cannot predict the effect, if any, that future sales of our common stock will have on the market price of our common stock prevailing from time to time. Sales of substantial amounts of common stock, such as the outstanding securities that will be available for resale in the coming months, or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.

We do not currently intend to pay dividends.

     We currently intend to retain any profits to fund the development and growth of our business. As a result, we have not paid dividends on our common stock and our board of directors currently does not intend to declare dividends or make any other distributions in the foreseeable future. Consequently, it is uncertain when, if ever, we will declare dividends to our stockholders.

30

The price of our common stock could be volatile.

     The market price of our common stock will likely fluctuate significantly in response to the following factors, some of which are beyond our control:

	•	Variations in our quarterly operating results;
	•	Changes in market valuations of oil and gas companies;
	•	Announcements by us of significant contracts, acquisitions, strategic partnerships, joint ventures or capital commitments;
	•	Additions or departures of key personnel;
	•	Future sales of our common stock;
	•	Stock market price and volume fluctuations attributable to inconsistent trading volume levels of our stock; and
	•	Commencement of or involvement in litigation.

     In addition, the trading volume of our common stock is relatively small, and the market for our stock may not be able to efficiently accommodate significant trades on any given day. As a result, sizable trades of our common stock may cause volatility in the market price of our common stock to a greater extent than in more actively traded securities. These broad fluctuations may adversely affect the market price of our common stock.

We may issue our capital stock without the consent of stockholders. The issuance of any additional equity securities would further dilute our stockholders.

     Our board of directors has the authority, without further action by the stockholders, to issue up to 500.0 million shares of preferred stock in one or more series and to designate the rights, preferences, privileges and restrictions of each series. We also have 500.0 million shares of common stock authorized under our charter documents, of which 76.5 million shares are issued and outstanding as of December 31, 2004. The issuance of preferred stock could have the effect of restricting dividends on the common stock or delaying or preventing our change in control without further action by the stockholders. While we have no present plans to issue any shares of preferred stock, we may need to do so in the future in connection with capital raising transactions. In addition, we may issue additional shares of common stock in connection with fundraising activities. The issuance of additional common stock would also have a dilutive impact on our stockholders’ ownership interest in our company.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We do not engage in hedging activities and do not use commodity futures or forward contracts in our cash management functions. We also do not currently hedge our exposure to currency rate changes. In recent years, the Chinese government has fixed the exchange rate between U.S. dollars and Chinese Yuan. Because the exchange rate has been fixed, instead of variable, we have experienced no fluctuations in the value of goods and services we purchase in China because of currency exchange. However, the United States and other foreign governments have repeatedly sought to establish a floating exchange rate between the Chinese Yuan and other foreign currencies. If, in the future, China accedes to these requests and permits currency float against the U.S. dollar, we must either adopt cash management strategies to hedge U.S. dollars against the Yuan or be subject to the exchange rate risks. In general, we hold cash reserves in U.S. dollars and transfer funds to China as needed to operate our Chinese offices and conduct exploration operations. We do not expect to generate significant revenues from activities in China prior to late 2006.

31

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). Our internal control over financial reporting is designed, under the supervision and with the participation of our chief executive officer and chief financial officer, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal controls may vary over time.

     Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2004. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Our management has concluded that, as of December 31, 2004, our internal control over financial reporting is effective based on these criteria.

     Our independent registered public accounting firm, Payne, Falkner, Smith & Jones, P.C., that audited our consolidated financial statements included in this report, has issued an audit report on management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004, which is included on page 34 of this report.

32

Report of Independent Registered Public Accounting Firm

The Board of Directors
Far East Energy Corporation and Subsidiaries

We have audited the accompanying consolidated balance sheet of Far East Energy Corporation and Subsidiaries (a development stage Company) as of December 31, 2004 and 2003 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2004 and for the period from the date of incorporation on February 4, 2000 to December 31, 2004. Our audits also included the financial statement schedule listed in Item 15. These consolidated financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Far East Energy Corporation and Subsidiaries as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004 and for the period from the date of incorporation on February 4, 2000 to December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

The accompanying consolidated financial statements and schedule have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has incurred net losses since its inception and has no established source of revenues. Those conditions raise substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters are described in Note 2. The consolidated financial statements and schedule do not include any adjustments relating to the recoverability and classification of recorded assets, or the amounts and classification of liabilities that might be necessary in the event the Company cannot continue in existence.

As described in Note 3 to the consolidated financial statements, the accompanying consolidated financial statements as of and for the year ended December 31, 2003 have been restated.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Far East Energy Corporation’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 23, 2005, expressed an unqualified opinion on management’s assessment of internal control over financial reporting and an unqualified opinion on the effectiveness of internal control over financial reporting.

February 23, 2005

/s/ Payne Falkner Smith & Jones, P.C.
Payne Falkner Smith & Jones, P.C.

Dallas, Texas

33

Report of Independent Registered Public Accounting Firm

To the Board of Directors and
Stockholders of Far East Energy Corporation

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Far East Energy Corporation (FEEC) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). FEEC’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of FEEC’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that FEEC maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, FEEC maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Far East Energy Corporation, as of December 31, 2004 and 2003 and the related consolidated statements of operations, stockholders’ equity, and cash flows of FEEC, and our report dated February 23, 2005 expressed an unqualified opinion.

February 23, 2005

/s/ Payne Falkner Smith & Jones P.C.
Payne Falkner Smith & Jones, P.C.

Dallas, Texas

34

FAR EAST ENERGY CORPORATION
(A Development Stage Company)
Consolidated Balance Sheet

See accompanying notes to consolidated financial statements.

35

FAR EAST ENERGY CORPORATION
(A Development Stage Company)
Consolidated Statement of Operations

See the accompanying notes to consolidated financial statements.

36

FAR EAST ENERGY CORPORATION
(A Development Stage Company)
Consolidated Statement of Stockholders’ Equity
For the Years Ended December 31, 2004, 2003, 2002, 2001 and 2000

continued on next page

37

FAR EAST ENERGY CORPORATION
(A Development Stage Company)
Consolidated Statement of Stockholders’ Equity
For the Years Ended December 31, 2004, 2003, 2002, 2001 and 2000
(continued from the previous page)

continued on next page

38

FAR EAST ENERGY CORPORATION
(A Development Stage Company)
Consolidated Statement of Stockholders’ Equity
For the Years Ended December 31, 2004, 2003, 2002, 2001 and 2000
(continued from the previous page)

See the accompanying notes to consolidated financial statements.

39

FAR EAST ENERGY CORPORATION
(A Development Stage Company)
Consolidated Statement of Cash Flows