SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| | þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2011
OR
| | o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ___________________ to ________________________
Commission File Number 0-32455
Far East Energy Corporation
(Exact Name of Registrant as Specified in Its Charter)
| Nevada | | 88-0459590 |
| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| | | |
| 363 N. Sam Houston Parkway East, Suite 380, Houston, Texas | | 77060 |
| (Address of principal executive offices) | | (Zip Code) |
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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No R
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No R
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 R No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes S No £
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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. R
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer £ Accelerated filer S Non-accelerated filer £ Smaller reporting company £
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No R
The aggregate market value of the voting common stock, par value $0.001 per share, held by non-affiliates of -the registrant was approximately $109,507,000 as of June 30, 2011 (based on $0.32 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 10% beneficial owners have been deemed affiliates.
The number of shares of common stock, par value $0.001 per share, outstanding as of March 2, 2012 was 344,632,223.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s proxy statement for the 2011 annual meeting of stockholders are incorporated by reference into Part III of this Form 10-K.
FAR EAST ENERGY CORPORATION
| | | Page |
| | | |
| PART I |
| Item 1. | | 1 |
| Item 1A. | | 19 |
| Item 1B. | | 32 |
| Item 2. | | 32 |
| Item 3. | | 35 |
| Item 4 | | 35 |
| |
| PART II |
| Item 5. | | 36 |
| Item 6. | | 39 |
| Item 7. | | 40 |
| Item 7A. | | 50 |
| Item 8. | | 51 |
| Item 9. | | 81 |
| Item 9A. | | 81 |
| Item 9B. | | 81 |
| | | |
| PART III |
| Item 10. | | 82 |
| Item 11. | | 86 |
| Item 12. | | 104 |
| Item 13. | | 107 |
| Item 14. | | 107 |
| | | |
| PART IV |
| Item 15. | | 110 |
| |
| | | |
PART I
General
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 ("CBM"). Throughout this Annual Report on Form 10-K, the terms "Far East Energy," "Far East," "we," "the Company," "us," "our" and "our company" refer to Far East Energy Corporation and its subsidiaries. References to FEEB refer to Far East Energy (Bermuda), Ltd., our principal operating subsidiary. References to "China" and "PRC" are references to the People's Republic of China. Throughout this Annual Report on Form 10-K, we use the term “our Chinese partner company” when referring to CUCBM, CNPC/PetroChina, as applicable. Today, the operations of our company and its subsidiaries concentrate on CBM exploration and development in the Shanxi Province in northern China and Yunnan Province in southern China. Our goal is to become a recognized leader in CBM property acquisition, exploration, development and production in China. Our principal headquarters office is located at 363 North Sam Houston Parkway East, Suite 380, Houston, Texas 77060. Our main office in China is located in Beijing with a satellite office in Taiyuan City.
Far East Energy believes that good environmental, social, health and safety performance is an integral part of our business success. Our commitment to these principles is demonstrated by the fact that we have had no lost-time accidents in over six years and no major environmental incidents. We conduct our business with respect and care for our employees, contractors, communities, and the environments in which we operate. Our vision is zero harm to people and the environment while creating value for our shareholders as well as for China, including the regions and communities within which we operate. We have a commitment to be a good corporate citizen of China, striving to emphasize and utilize very high levels of Chinese personnel, services, and equipment; and we have achieved very high percentages of Chinese content in each category.
Prior to December 31, 2011, we were classified as a development stage company and our activities were principally limited to drilling, testing and completion of exploratory and pilot development CBM wells and organizational activities. As of December 31, 2011, the Company received its first independent, third party reserve report providing a determination of the Company’s proved, probable and possible reserves and thus emerged from development stage status as a result of the amount of proved reserves estimated in the reserve report and the fact that we have started generating revenues. We are a party to three production sharing contracts ("PSCs") which cover the 485,000 acre (1,962.7 km2) Shouyang Block in Shanxi Province (the "Shouyang PSC"), the 573,000 acre (2,318.8 km2.) Qinnan Block also in Shanxi Province (the "Qinnan PSC"), and the Enhong and Laochang area, which totals 265,000 acres (1,072.4 km2), in Yunnan Province (the "Yunnan PSC"). On November 15, 2011, and December 30, 2011, Modification Agreements amending the Shouyang and Yunnan PSCs, respectively, were executed between China United Coalbed Methane Corporation, Ltd. ("CUCBM") and FEEB, which are pending Chinese government approval. Among other provisions, these modification agreements, extend the exploration periods of the PSCs to at least June 30, 2013 and reduce the acreage covered by the Shouyang PSC to 409,282 acres (1,656.306 km2) and covered by the Yunnan PSC to 119,338 acres (482.943 km2).
On June 12, 2010, CUCBM and Shanxi Province Guoxin Energy Development Group Limited ("SPG") executed the Shouyang Project Coalbed Methane Purchase and Sales Contract (the "Gas Sales Agreement"), to which we are an express beneficiary, to sell CBM produced in the CBM field (the "Shouyang Field") governed by the Shouyang PSC. Pursuant to the Gas Sales Agreement, SPG is initially required to purchase up to 300,000 cubic meters (10,584,000 cubic feet) per day of CBM (the "Daily Volume Limit") produced at the Shouyang Field on a take-or-pay basis, with the purchase of any quantities above such amount to be negotiated pursuant to a separate agreement. The term of the Gas Sales Agreement is 20 years. The gross gas production for 2011 was approximately 268 million cubic feet. See "Shouyang PSC" below.
On November 28, 2011, FEEB entered into a Facility Agreement, as borrower, with Standard Chartered Bank (“SCB”), as lender, and the Company, as guarantor (the “Facility Agreement”). The Facility Agreement provides for a $25 million credit facility to be used for project costs with respect to the Shouyang Area, finance costs and other general corporate purposes approved by SCB. It has an initial 9-month term maturing August 28, 2012, which may be extended by three (3) months upon satisfaction of certain other conditions. Loans under the Facility Agreement may be made in such amounts as may be specified from time to time in one or more utilisation requests according to an agreed expenditure schedule. Loans under the Facility Agreement will bear interest at LIBOR plus an applicable margin rate of 9.5% during the initial period and 10.0% thereafter, and mandatory costs, if any, to compensate SCB for certain Hong Kong regulatory compliance costs. In connection with and as security for the Facility Agreement, FEEB and/or the Company entered into certain other ancillary agreements dated November 28, 2011, including a Share Pledge Agreement, an Account Charge Agreement, an Assignment of Shareholder Loans and a Subordination Agreement (the “Ancillary Agreements”). Under the Ancillary Agreements, the Company pledged its shares in FEEB and granted a security interest in certain intercompany debt to SCB, and FEEB granted a security interest in certain bank accounts to SCB. Pursuant to the terms of the Facility Agreement, in the event we fail to receive approval from the Ministry of Commerce of the People's Republic of China ("MofCom") of the 2011 Shouyang PSC Modification Agreement (defined below), we may not be able to draw down the full amount of available funds otherwise available under the Facility Agreement. The failure to receive such notice on or before May 31, 2012 will constitute an event of default under the Facility Agreement. Upon notice of an event of default under the Facility Agreement, SCB would have the right to accelerate all amounts outstanding under the Facility Agreement.
Although FEEB has not formally accepted the change, China National Petroleum Company ("CNPC") purports to have the right to replace CUCBM as our Chinese partner company in the Qinnan PSC. The exploration period of the Qinnan PSC in Shanxi Province expired on June 30, 2009, and we cannot continue our exploration activities in the Qinnan Block without an extension or a new PSC. We are continuing to pursue an extension of the exploration period of the Qinnan PSC, but we cannot be optimistic at this time. See "Our Holdings in the Shanxi Province of the People’s Republic of China – Qinnan PSC" below for further discussion of our efforts to secure an extension of the exploration period for the Qinnan PSC.
Our Website
Our website can be found at www.fareastenergy.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed with or furnished to the U.S. Securities and Exchange Commission ("SEC"), pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 ("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 our website is not part of this report.
Coalbed Methane Gas and Attributes of Coalbed Methane Resources
Coalbed methane gas 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. CBM exploration and production involves drilling into a known coal deposit and extracting the natural gas that is contained in the coal. A coal seam is often saturated with water, with methane gas being held in the coal by water pressure. To produce CBM 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 through the fractures, or cleats, contained in the coal seam. Gas flows to the wellbore 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 any coalbed methane present in our CBM acreage.
Permeability. Coalbed methane gas production requires that the coal have sufficient permeability. Permeability is the ability of a substance to allow another substance to pass through it. In the case of our CBM properties, permeability is the ability of the coal to allow water and/or gas to pass through it. Permeability in coal is primarily created by naturally occurring fractures, which are commonly referred to as cleats. Permeability is largely based upon how many cleats the coal has and how close they are to each other. The more cleats the coal has, the better the coal's permeability and the greater opportunity to retrieve the adsorbed CBM. Tectonic fracturing can also contribute greatly to permeability. Reservoirs with high permeability have a higher propensity for strong gas production than less permeable reservoirs. The same permeability that can contribute to strong gas production also initially allows more water to flow through the coal. Thus, coal seams with higher permeability often take significantly longer time to dewater than lower permeability coal seams. Once sufficient water is produced, higher permeability normally allows wells to maintain higher production rates for longer periods and enables higher gas recoveries with fewer wells.
Thickness. The thickness of the coal seam is crucial to CBM production. A coal seam with otherwise unacceptably low permeability could produce commercial quantities of gas if the coal seam has sufficient thickness. In this case, the gas would flow out slowly, but because the coal seam is thick, more of the gas would be produced since there is a large 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 gas, 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 deep enough, there may not have been sufficient water pressure to hold the gas in place and through geologic time the gas may have escaped from the coal.
Coal Ranking. Methane gas is contained in all ranks of coal. 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 contain significant cleats as well, making it more permeable. The coalbeds found in our Shanxi Province project are semi-anthracite coal that have a favorable cleat structure, which has a favorable impact on permeability.
The next lesser coal rank is bituminous coal that contains less CBM per ton than the anthracite and semi-anthracite coal but usually has a good cleat structure, allowing for better permeability. The coalbeds found in our Enhong–Laochang project, 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 gas 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 wellbore. Substantial dewatering of the coalbed is required initially. Water production declines as methane gas production increases. Dewatering of a well may generally range in length from a few weeks to as many as three years or more depending on the attributes of the coal seam.
Coalbed Methane in the People's Republic of China
China is the world's largest coal producing country and has substantial CBM resources located within its coalfields. Because most of China's CBM is found at shallow depths, it is easier to drill and complete CBM wells than the deeper wells that are generally required for other forms of natural resource exploration. China's mining operations release approximately 18 billion cubic meters of methane gas into the environment each year because much of the country's CBM resources remain undeveloped. This results in serious pollution and wastes CBM, which could be recovered prior to mining.
Our business strategy is to acquire, explore, develop, produce and sell CBM in China. China is currently the world's second largest user of petroleum and one of the largest importers of oil and, to a lesser extent, gas, in the world. China's energy needs have grown rapidly in the past 20 years, fueled in part by the tremendous economic growth during that period. The growth in demand for energy 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 great attention on the development of energy sources, including CBM. To increase CBM production, the State Council, the chief administrative body of the PRC, created CUCBM in 1996. The State Council granted CUCBM rights to contract with foreign corporations for the exploration, development and production of CBM in China. In mid 2008, one of the major stakeholders of CUCBM, CNPC, expressed a desire to contract directly with foreign corporations to work on CBM projects instead of working through CUCBM. The Chinese government has provided incentives to stimulate the development of CBM, including enacting Chinese government subsidy of 0.2 RMB per cubic meter and Shanxi provincial subsidy of 0.05 RMB per cubic meter, 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 ("VAT") for CBM projects with foreign companies to 0% compared to 13% VAT for conventional gas companies (Interim Regulations of the People's Republic of China on Value Added Tax (November 10, 2008, Article 2)). For more information on the laws, regulations and regulatory bodies that affect our business, see "Regulations Impacting Our Business" below. Wei Pengyuan, Deputy Director General of the Coal Division of China’s National Energy Administration (NEA), recently stated that China plans to raise the subsidy to 0.4 to 0.5 RMB per cubic meter (or $1.78 to $2.22 per Mcf based on the December 31, 2011 exchange rate).
Drilling and Hydraulic Fracturing Technologies
Vertical, deviated and horizontal drilling technologies have each yielded successful results in CBM applications. We are currently leveraging all three technologies in our CBM production in China. Which of these drilling technologies or combination thereof will yield optimal results as we explore and develop our blocks is not yet clear. Vertical wells are the cheapest and most straightforward wells to drill and complete, but each well requires a dedicated surface location. A horizontal well potentially allows a wellbore to be in contact with hundreds or thousands of feet of coal because the drill bit is redirected from a downward angle to a horizontal plane and tracks along the same plane as the coalbed, thereby exposing more coal to the wellbore. This greater exposure of the coalface achieved by horizontal drilling generally allows for greater CBM production on a per well daily basis than can be achieved with conventional vertical drilling and completion techniques. Although horizontal wells are more costly and technically challenging than vertical and deviated wells because of wellbore instability and pumping difficulties, they offer greater potential in reduced surface facilities and increased production rates. Deviated wells are used to access downhole locations that are not accessible with a vertical wellbore. Deviated wells are slightly more expensive and complicated to drill and complete than vertical wells. However, they are drilled from an existing well pad and location. Utilizing an existing well location allows more than one well to be drilled from the same pad, consequently reducing land and pad construction costs, as well as reducing environmental impact. Beginning the second half of 2008, we applied the deviated drilling technology and have drilled with success in our Shouyang Block.
Hydraulic fracturing technology has been utilized in CBM exploration and development for many years. The technique fractures a formation by pumping fluid, in our case water or water with a viscosifying agent, into the formation at a high enough pressure to open the formation to allow a proppant, such as sand, to be pumped into the formation. This act of opening the formation and pumping in a propping agent allows better communication between the wellbore and the formation. This is often necessary in formations where permeability around the wellbore is found to be reduced after drilling, thus lessening the ability of formation fluids to enter the wellbore and be produced. Even though our current hydraulic fracturing operations have generally improved our gas and water production and lowered the field pressure, Far East is continually seeking the best combination of fracturing fluids and propping agents to provide the best completions for our wells.
Acreage in the People's Republic of China
In connection with the modification agreement (the “2011 Shouyang PSC Modification Agreement”), dated November 15, 2011, for Production Sharing Contract for the Exploitation of Coalbed Methane Resources for the Shouyang Area in Shanxi Province, Qinshui Basin, The People’s Republic of China, we have agreed to relinquish 75,736 acres (306.494 km2) of the Shouyang PSC contract area. The following table summarizes the acreage subject to our PSCs in China as of December 31, 2011, as well as the net acreage that will remain available for exploration and production under the PSCs pursuant to our respective participating interest share assuming the 2011
Shouyang PSC Modification Agreement and the modification agreement (the “2011 Yunnan PSC Modification Agreement”), dated December 30, 2011, for Production Sharing Contract for Exploitation of Coalbed Methane Resources in Enhong and Laochang Area, Yunnan Province, The People’s Republic of China, are approved by the MofCom:
| | | Acreage | |
| | | | | | Net | |
| | | Gross (1) | | | Far East (2) | | | Chinese Partner Company | |
| China: | | | | | | | | | |
| Shouyang Block, Shanxi Province | | | 409,282 | | | | | | | |
| Area A | | | 15,978 | | | | 15,978 | | | | - | |
| All other areas | | | 393,304 | | | | 275,313 | | | | 117,991 | |
Qinnan Block, Shanxi Province (3) | | | 573,000 | | | | 401,100 - 573,000 | | | | 171,900 - 0 | |
| Laochang Area, Yunnan Province | | | 119,338 | | | | 71,603 | | | | 47,735 | |
(1) Acreage if the PSC amendments for Shouyang and Yunnan receive necessary governmental approvals.
(2) The Chinese partner company has elected to participate at a 30% participating interest share in the 2011 Shouyang PSC Modification Agreement and 40% participating interest share in the 2011 Yunnan PSC Modification Agreement (defined below).
(3) Currently, the exploration period has technically expired, and we are pursuing claims that the period has been extended due to force majeure, in accordance with the terms of the PSC. Thus, no modification agreement has been signed with respect to the Qinnan PSC and the Chinese partner company has not elected any participating interest share, however, it is entitled to up to 30%.
As with any energy exploration and production company, we continuously review our acreage holdings in order to optimize those holdings. We may, from time to time and as circumstances dictate, decide to relinquish all or part of any of our blocks that we deem non-prospective or sub-optimal in order to optimize our acreage holdings and/or preserve cash resources.
Drilling Activity
The following table sets forth our drilling activities for the years ended December 31, 2011, 2010 and 2009:
| | | Total Wells Drilled and Reached Total Depth(1) | |
| Area | | 2011 | | | 2010 | | | | 2009 | |
| Shouyang Block | | | 35 | | | | 26 | | | | | 5 | |
| Qinnan Block | | | - | | | | - | | | | | 1 | |
| Yunnan Block | | | - | | | | - | | | | | - | |
| | | | 35 | | | | 26 | (2) | | | | 6 | |
| (1) | The Chinese partner companies may choose to participate when the development period begins. |
| (2) | Not included in the number of completed wells in 2010 were seven wells which were spudded in late 2010. |
As of the end of January, there are 66 wells dewatering in the Shouyang Block and producing gas. Additionally, as of that date, one well has been abandoned in the Shouyang Block, and no dry holes have been drilled.
Our Holdings in the Shanxi Province of the People's Republic of China
Overview. In June 2003, we entered into two amendments to certain farmout agreements and assignment agreements with Phillips China, Inc., a subsidiary of ConocoPhillips ("Phillips"), pursuant to which we acquired a 40% net undivided interest from Phillips in the Shouyang and Qinnan PSCs between Phillips and CUCBM for Shanxi Province . 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 PSCs. These agreements were approved by CUCBM on March 15, 2004, and ratified by the MofCom on March 22, 2004. The term of each of the Shouyang and Qinnan PSC 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. Pursuant to the farmout agreements with Phillips, Phillips retained a participation interest of 30% with a right to convert such interest to an overriding royalty interest. Upon our election to enter Phase III of the exploration periods in the Shouyang PSCs in June of 2006, Phillips elected to convey its remaining 30% participating interest to us and to receive an overriding royalty interest of 5% of production from our participating interest, not to exceed 3.5% of the total participating interest.
We have negotiated and signed multiple amendments with our Chinese partner to extend the exploration period under the Shouyang and Qinnan PSC. Far East signed the 2011 Shouyang PSC Modification Agreement with CUCBM on November 15, 2011, and it was subsequently filed with MofCom and we are currently awaiting approval. If we receive the final governmental approvals, the 2011 Shouyang PSC Modification Agreement will become effective and the exploration period will be officially extended to at least June 30, 2013.
The 2011 Shouyang PSC Modification Agreement provides for the relinquishment of 75,736.31 acres (306.494 km2) from the Shouyang contract area. Of that relinquished acreage of 306.494 km2 (75,736.31 acres), approximately 104 km2 is either “no coal” or extremely thin coal insofar as the No. 15 seam is concerned. Approximately 40 km2 of additional area contiguous to that “no coal/thin coal” zone is considered “marginal” insofar as CBM potential in the No. 15 coal seam is concerned. Additionally, 35.1 km2 out of the 306.494 km2 relinquished is part of an area of 99.76 km2 (24,651.23 acres) of preliminarily approved “Chinese reserves” area. FEEB relinquished 35.1 km2 of this 99.76 km2 pending reserves area to CUCBM in return for CUCBM agreeing not to exercise their option to participate for 30% in the remaining 64.66 km2 (15,978 acres). Contained within that 64.66 km2 in which we now have a 100% interest, subject only to ConocoPhillips’ ORRI, is the entirety of our current 1H Pilot Area including all producing wells currently tied into our gathering system and producing gas into the SPG pipeline under the Gas Sales Agreement. The 64.66 km2 also contains the planned extension of our 1H Pilot Area pattern which is planned to expand in a south and southwesterly direction.
In 2009, while we were negotiating the previous extension of the Shouyang PSC, we endeavored to seek a similar extension for the Qinnan PSC. However, we were informed by CUCBM that their interest under the Qinnan PSC was to be transferred to China National Petroleum Corporation or its subsidiary PetroChina Company Limited ("PetroChina"). In the course of discussions with PetroChina, we were requested to sign an agreement whereby FEEB agreed to the transfer of CUCBM’s interest to PetroChina through CNPC. In negotiations with CUCBM and PetroChina related to this request, we have endeavored to negotiate an assignment agreement that would reflect the transfer of interest to CNPC while CNPC and/or PetroChina would acknowledge delays that were incurred by virtue of FEEB not having, for an extended period of time, an official Chinese partner that had the capacity or authority under the Qinnan PSC to work with us. Because of the inability to hold a formal Joint Management Committee ("JMC") meeting or to have the effective involvement of our Chinese partner, we believe that our efforts to continue CBM Operations in the Qinnan block have been materially hindered. Technically, the exploration period under the Qinnan PSC expired on June 30, 2009; however, we have maintained the position that the doctrine of force majeure under the Qinnan PSC entitled us to an extension. We continue to discuss this situation with CUCBM and PetroChina, and as recently as January 2012 have submitted a notice of force majeure in accordance with the Qinnan PSC.
During the exploration period, Far East, as operator, must complete at least the minimum work program and seek commercial deposits of CBM that can be developed in commercially paying quantities. Under the original PSCs, operators were required to prepare pilot development work programs for CBM discoveries that they deemed worthy of further appraisal (a "CBM Field"), seeking to obtain adequate data and information to enable the parties to agree upon the commerciality of a particular discovery. After the approval and implementation of a pilot test program in the CBM Field, the parties to the PSC were to jointly determine whether the field can be commercially
developed. Under the 2011 Shouyang PSC Modification Agreement, the concept of pilot development work programs has been replaced by a requirement for pilot testing to obtain information necessary to prepare an application for overall development program ("ODP") for a particular CBM Field. The preparation of an ODP application will require adequate reserves certified in accordance with PRC law, as well as technical, commercial, environmental, health and safety plans demonstrating how the CBM Field will be developed for the exploitation of CBM reserves located therein. Currently, Far East and CUCBM are in the process of jointly preparing an ODP application for a CBM Field in the northern part of the Shouyang block, comprising an area of 99.76 km2 or 24,651.23 acres (the "SY ODP Area").
Under the 2011 Shouyang PSC Modification Agreement, following expiration of the extended exploration period, we may elect to continue the process of trying to move CBM Fields into the ODP process and the development period for any areas that are in the final stages of the reserve certification process for submission of an ODP application for governmental approval. Any acreage that is not at or past the stage of submittal of a reserves report to CUCBM that reasonably meets the criteria for approval of reserves under PRC law will be relinquished.
The development period as to any CBM Field in the Shanxi Province will begin after the approval of the ODP for any such CBM Field. In connection with the 2011 Shouyang PSC Modification Agreement, CUCBM has agreed to waive its right to any participating interest share in approximately 64.66 km2 or 15,977.833 acres of the Shouyang ODP Area and it has elected to currently exercise its option to receive a 30% participating interest in any other CBM Field that is developed in the Shouyang contract area. Thus, Far East will be entitled to a 100% participating interest share in the entirety of its 1H Pilot Area (subject to ConocoPhillips’ ORRI) .
The production period as to any CBM Field in the Shanxi Province project will begin after the date of commencement of commercial production of that CBM Field, which should occur upon the completion of the ODP for such CBM Field. Any CBM produced and marketed prior to the approval of an ODP is deemed to occur during the development period, and production is to be distributed in accordance with the parties participating interests in such CBM Field. Provided the Company remains in compliance with the requirements under the PSCs, the Shouyang and Qinnan PSC allow production to continue on a CBM Field until the earlier of the end of the useful life of the field or June 30, 2032, unless extended or otherwise amended.
We have fulfilled our previous obligations under the exploration period of the original Shouyang and Qinnan PSCs. As discussed above, we have suspended CBM Operations in Qinnan pending resolution and completion of the transfer of CUCBM's interest in the Qinnan PSC to PetroChina, however, there are no outstanding work obligations for the expired exploration period in Qinnan. We have completed the minimum work obligations under the Shouyang PSC. If approved by the MofCom, the 2011 Shouyang PSC Modification Agreement would require Far East to drill as many as 38 additional wells, spending at least $15.8 million (100,000,000 RMB).
Chinese Party to the PSCs. CUCBM has been our partner in both the Shouyang and Qinnan PSCs. CUCBM was a joint venture of China National Coal Group Corp. and CNPC. In 2009, we understand that CNPC withdrew from the joint venture and CNPC indicated that PetroChina would replace CUCBM as our Chinese partner company for the Qinnan PSC. The exploration period of the Qinnan PSC in Shanxi Province expired on June 30, 2009, and we cannot continue our exploration activities in the Qinnan Block without an extension or a new PSC. We are continuing to pursue an extension of the exploration period of the Qinnan PSC, but we cannot be optimistic at this time. In January 2011, we received a formal notice from CNPC that it has purportedly received all Chinese approvals with respect to the transfer and we were requested to execute a modification agreement to confirm PetroChina as our Chinese partner company for the Qinnan PSC, as a direct assignee from CNPC. In negotiations with CUCBM and PetroChina related to this request, we have endeavored to negotiate an assignment agreement that would reflect the transfer of interest to CNPC and then to PetroChina, while CNPC and or PetroChina would acknowledge delays that were incurred by virtue of FEEB not having, for an extended period of time, an official Chinese partner that had the capacity or authority under the Qinnan PSC to work with us. Due to the inability to hold a formal Joint Management Committee ("JMC") meeting or to have the effective involvement of our Chinese partner, we believe that our efforts to continue CBM Operations in the Qinnan block have been materially hindered. Technically, the exploration period under the Qinnan PSC expired on June 30, 2009; however, we have maintained the position that the doctrine of force majeure provided for in the Qinnan PSC entitled us to an extension. We continue to discuss this situation with CUCBM and PetroChina, and as recently as January 2012 have submitted a notice of force majeure in accordance with the Qinnan PSC.
Shouyang PSC. During the fourth quarter of 2011, CUCBM and Far East agreed on the 2011 Shouyang PSC Modification Agreement, which was submitted to the MofCom for approval.
On June 12, 2010, CUCBM and SPG executed the Gas Sales Agreement through which CBM produced at the Shouyang Field is sold. Pursuant to the Gas Sales Agreement, SPG is initially required to purchase up to the Daily Volume Limit, which is 300,000 cubic meters (10,584,000 cubic feet) per day, of CBM produced at the Shouyang Field on a take-or-pay basis, with the purchase of any quantities above such amount to be negotiated pursuant to a separate agreement. At the request of FEEB and CUCBM to provide competitive pricing options for offtake of CBM production in excess of the Daily Volume Limit with assured offtake capacity, the Gas Sales Agreement obligates SPG to commit to having demand capacity to accept at least 1 million cubic meters (approximately 35 million cubic feet) per day from the Shouyang Field by 2015 but does not obligate FEEB or CUCBM to sell gas in excess of the Daily Volume Limit. The term of the Gas Sales Agreement is 20 years. FEEB and CUCBM sought to have the 300,000 cubic meter (10,584,000 cubic feet) per day Daily Volume Limit included in the Gas Sales Agreement, rather than committing to supply up to the entire capacity of the pipeline (approximately 40 million cubic feet per day), because they desired to preserve the opportunity to negotiate a new contract for gas volumes above 10,584,000 cubic feet in the belief that a competing pipeline company, Shanxi International Energy Company ("Shanxi International"), was considering building to the initial 1H Pilot Area.
The second pipeline would potentially provide an additional 50 million cubic feet per day of offtake infrastructure as well as provide price competition. As of December 31, 2011, the second pipeline was completed in our area, and appears to be nearing completion to Changzhi and Taiyuan, but is not yet commissioned. The pipeline laid purportedly has a capacity of 50 million cubic feet per day.
The in-field gathering system and compression equipment in our initial 1H Pilot Area were connected to SPG's gas pipeline in early January 2011. After completion of that process, low level gas flow commenced in January with initial testing of the gathering system in January. After initial commissioning, gas sales were temporarily interrupted while SPG completed testing and commissioning of certain equipment related to our first stage compressor sites as well as installation of gas sales meters. That work was completed and formal gas flow and sales re-commenced in mid-March 2011.
In September 2011, SPG completed the construction of additional gathering lines in the 1H Pilot Area. Currently, we have 53 wells connected to the newly laid gathering lines. The gross gas production for 2011 was approximately 268 million cubic feet. Gross sales volumes for 2011 were 158 million cubic feet. We believe that the sales volume will continue to increase as gas from additional wells is sold through the gathering system in the coming months.
Under Chinese law and practice, foreign-owned and controlled entities can only sell gas through a licensed, local entity, such as CUCBM. Therefore, concurrently with the execution of the Gas Sales Agreement, FEEB, which is the operator of the Shouyang Field, and CUCBM entered into a letter agreement (the "Acceptance Letter") under which FEEB acknowledged that sales by CUCBM under the Gas Sales Agreement would constitute the joint marketing and sales of CBM from the Shouyang Field for purposes of the Shouyang PSC. The Acceptance Letter further confirmed that FEEB accepted the terms of the Gas Sales Agreement, which named the parties to the Shouyang PSC, including FEEB, as express beneficiaries. On June 12, 2010, FEEB and CUCBM also entered into a letter agreement (the "Letter Agreement") in which they agreed that they would share any value added tax refunds and government subsidies related to gas sales from the Shouyang Field in accordance with their pro rata entitlement to CBM under the PSC. In the Letter Agreement, the parties also acknowledged that the funds received under the Gas Sales Agreement would be allocated in accordance with the Shouyang PSC, which includes an express allocation of funds in accordance with the parties’ working interest therein, subject to certain provisions providing for accelerated recovery of operational, exploration and development expenses prior to the distribution of all surplus CBM.
The price to be paid by SPG, excluding the effect of any applicable rebates or subsidies, for CBM under the Gas Sales Agreement was 1.20 RMB per cubic meter (including tax) until June 12, 2011 and thereafter the price is subject to change based on the parties' agreement in accordance with market economic principles. If the parties are unable to agree on new pricing, the then-current price shall apply to all gas sales. As we have not yet agreed upon a revised price for CBM sales, the 1.20 RMB per cubic meter price continues to apply at this time. Additionally, enacted Chinese government and Shanxi provincial subsidies equal 0.20 RMB and 0.05 RMB per cubic meter, respectively, for a total of 0.25 RMB per cubic meter. Thus, the price received by CUCBM and FEEB, including subsidies for gas sales that will be allocated between CUCBM and FEEB as agreed under the Letter Agreement, should be approximately 1.45 RMB per cubic meter. This equates to approximately $6.45 per Mcf at exchange rates as of December 31, 2011. In July of 2011, the Chinese news service Xinhua News Agency advised that the PRC’s CBM subsidy could be increased as much as 0.2 RMB per cubic meter (or $0.89 per Mcf based on the December 31, 2011 exchange rate). Wei Pengyuan, Deputy Director General of the Coal Division of China’s National Energy Administration (NEA), recently stated that China plans to raise the subsidy to 0.4 to 0.5 RMB per cubic meter (or $1.78 to $2.22 per Mcf based on the December 31, 2011 exchange rate). If implemented, this level of subsidy increase would take our current sales price of $6.45 up to $7.34 to $7.78 per Mcf (inclusive of taxes). The Gas Sales Agreement also provides for price adjustments in accordance with changes to the published Chinese national natural gas price and annual price adjustments based on the parties’ mutual agreement. If the parties do not agree on a new price, the then-current price shall continue in effect and either party may seek to resolve any pricing dispute pursuant to arbitration. SPG is obligated to pay for all CBM monthly in advance, based on anticipated deliveries for the coming month.
The Gas Sales Agreement does not have any minimum delivery obligations, but it does require that all CBM produced at the Shouyang Field up to 300,000 cubic meters (10,584,000 cubic feet) per day be sold to SPG and production in excess of that level shall be subject to further agreement. The parties agreed to use reasonable efforts to provide a stable supply of gas and to provide the same amount of CBM during the summer and the winter. This is relevant for FEEB because typically gas demand is significantly higher in the winter than the summer, so the Gas Sales Agreement is structured to provide for even demand levels and delivery requirements, without setting any minimum requirements or ‘deliver or pay’ obligations on the seller. Each party is to notify the other at least 30 days before it is able to deliver or receive gas. In order to deliver our gas, we needed to install an in-field gathering system as well as a field compression facility to increase the gas pressure to the pressure required for delivery. This was completed in late December 2010. Once the initial gas delivery and acceptance date is set, if one party fails to deliver or receive gas on such date, then it shall pay the other party 5% of the value of CBM comprising such shortfall. After initial CBM deliveries commence, if either party fails to deliver gas or receive gas as nominated for the month, and it fails to notify the other party that it will not deliver or receive such quantity of gas, then the non-performing party will pay the other party a penalty based upon 10% of the value of 80% of the portion of gas not delivered or received, as applicable.
During the initial 180 days following the first delivery of CBM under the Gas Sales Agreement (the "Commissioning Period"), the parties are required to make reasonable efforts to deliver and accept CBM in an amount not to exceed the Daily Volume Limit. Thereafter, SPG will be required to accept and pay for all deliveries of CBM produced under the Shouyang PSC up to the Daily Volume Limit. If at any time after the Commissioning Period SPG fails to accept any CBM delivered to the delivery point up to the Daily Volume Limit, other than due to force majeure, required maintenance or breakdowns, SPG will pay an amount equal to the sales price of 80% of the amount it refuses to accept. If SPG refuses to accept gas, neither CUCBM nor FEEB will be required to provide make-up gas in the future.
The northern portion of the Shouyang Block, the majority of which is contained in the Shouyang ODP Area, is being closely monitored and work programs are being carried out there to achieve three primary goals: (i) to expand the area in our initial 1H Pilot Area where critical desorption and gas production are occurring, thereby increasing gas production, (ii) to determine the optimal approach to minimize costs and maximize gas recovery and (iii) to add pilot development test wells, also known as appraisal wells, spaced at intervals of several kilometers across the entire Shouyang Block to help delineate the geographic extent of the high permeability and high gas content area. The following discussion regarding our drilling activity involves the drilling of wells that constitute “exploratory wells,” as such term is defined in Rule 4-10(a)(13) of Regulation S-X.
Drilling activity in our Shouyang Block during fiscal year 2011 is summarized as follows:
| | | Wells Supdded, Total Depth Not Reached | |
| | | 1st Qtr | | | 2nd Qtr | | | 3rd Qtr | | | 4th Qtr | |
| Vertical | | | 1 | | | | - | | | | 1 | | | | - | |
| Deviated | | | 1 | | | | 8 | | | | 4 | | | | - | |
| Pilot Development Test | | | 5 | | | | - | | | | - | | | | - | |
| Total | | | 7 | | | | 8 | | | | 5 | | | | - | |
| | | Wells Reached Total Depth | |
| | | 1st Qtr | | | 2nd Qtr | | | 3rd Qtr | | | 4th Qtr | | | Total | |
| Vertical | | | 1 | | | | 2 | | | | - | | | | - | | | | 3 | |
| Deviated | | | 4 | | | | 8 | | | | 10 | | | | 3 | | | | 25 | |
| Pilot Development Test | | | 1 | | | | 5 | | | | 1 | | | | - | | | | 7 | |
| Total | | | 6 | | | | 15 | | | | 11 | | | | 3 | | | | 35 | |
As of mid-January, there are 66 wells dewatering the Shouyang Block and producing gas. Additionally, as of that date, one well has been abandoned in the Shouyang Block, and no dry holes have been drilled.
The deviated wells represent another phase in the process of reducing costs, and they reduce our “footprint”. These are essentially vertical wells drilled at a high angle from an existing well pad and location. Utilizing an existing well location allows more than one well to be drilled from the same pad, consequently reducing land and pad construction costs, reducing gathering costs, as well as reducing environmental impact. Once drilled to the coal seam, the wells are fracture stimulated. We have gained insights over time as to situations where cavitation or hydraulic fracture stimulation has improved our dewatering efficiency in the pilot area. Cavitation is a process whereby the diameter of the drilled wellbore is enlarged in the coal strata to increase the effective flow area of the coal seam. Hydraulic fracturing is a stimulation method successfully used in gas shale and other coalbed reservoirs to improve wellbore productivity by providing channels that extend beyond any formation damage done to the wellbore during the drilling process. This allows for water and gas to more easily flow into the wellbore and then be produced. The fracturing activity during 2011 is summarized as follows:
| | | Fracturing | |
| | | Quarter Ended | |
| | | March 31, 2011 | | | June 30, 2011 | | | Sept. 30, 2011 | | | Dec. 31, 2011 | | | Total | |
| Workovers | | | 8 | | | | - | | | | 2 | | | | 1 | | | | 11 | |
| New Wells | | | 7 | | | | 4 | | | | 16 | | | | 2 | | | | 29 | |
| Total | | | 15 | | | | 4 | | | | 18 | | | | 3 | | | | 40 | |
In late March and early April 2011, we successfully fracture stimulated 15 wells. Nine of these wells were completed in the 1H Pilot area. Several modifications to the fracture procedures were made during the process that included higher concentrations of sand and high viscosity fracturing fluid, both designed to improve near wellbore communication with the formation. Three wells were fracture-stimulated with a chemical product which is designed to immobilize coal fines that could be created during the treatment. Three wells were stimulated with water only to improve production by cleaning the near wellbore area of coal fines. Three of the stimulations involved pilot development test wells (“PDTW”) that were designed to test the permeability of the number 15 coal seam in other areas of the block. The SYS02 was a PDTW drilled nearly 22 km south of the 1H Pilot Area. This well is used to test the permeability at a structurally deep position. A positive result from this well indicates that the high permeability of the 1H Pilot Area extends to nearly halfway down the Shouyang Block. The P8, P12, P18 and SYS 05 are PDTW/appraisal wells drilled on the eastern side of the Shouyang Block. The data collected from these wells indicates that the high permeability previously discovered on the western side of the block extends over to the eastern side of the block as well as deep into the southeast of the block.
The total number of wells drilled to total depth as of December 31, 2011 in the Shouyang Block is 88. Of these 88 wells, 68 are wells drilled in the initial 1H Pilot Area to expand the field to the west and 20 are pilot development test wells. In addition to these wells, there are 6 wells in various stages of drilling operations.
A number of PDTWs were drilled at approximately 4 to 5 kilometer intervals to the west and south of the pilot area, with the goal of providing data to support the full extent of the large area of the northern Shouyang Block (pilot area) that contains high gas content as well as good permeability characteristics. We have begun to drill PDTWs to the east and southeast of the initial 1H Pilot Area. Through the PDTWs we seek to determine what portion of the northern area of the Shouyang Block shares the same rare combination of high permeability and high gas content discovered in the initial 1H Pilot Area. With the drilling and production testing of the P12, P18 and SYS05 wells in the east and southeast portion of the block respectively, we believe that permeability and the potential for significant gas production extend into these portions of the block. These wells are currently maintaining production rates in line with reserve qualification requirements.
The following table reflects the permeability determined in the Shouyang Block:
| | | Permeability Range | | Number of Wells |
| Well Area | | (Millidarcies - mD) | | In this Range |
| 1H Pilot Area | | 80-100 | | 1H Pilot Area Wells |
| PDTW | | 200-300 | | 3 |
| PDTW | | 100-199 | | 3 |
| PDTW | | 50-99 | | 4 |
| PDTW | | 10-49 | | 6 |
With permeabilities ranging from 10 millidarcies to 300 millidarcies, we believe that the number 15 coal seam in the expanded areas tested appears to have areas of high permeability coupled with high gas content.
We are in the process of obtaining Chinese reserve certification to support the submission of the ODP which will be filed as soon as possible. A reserves area containing 99.76 km2 (24,651.23 acres) has been preliminarily approved and is awaiting final certification by the Petroleum Reserves Office of China’s Ministry of Land and Resources (MLR). In the November 15, 2011 Shouyang PSC Modification Agreement, FEEB relinquished 35.1 km2 of this 99.76 km2 pending reserves area to CUCBM in return for CUCBM agreeing not to exercise their option to participate for 30% in the remaining 64.66 km2 (15,978 acres). Contained within that 64.66 km2 in which we now have a 100% interest, subject only to ConocoPhillips’ ORRI, is the entirety of our current 1H Pilot Area including all producing wells currently tied into our gathering system and producing gas into the SPG pipeline under the Gas Sales Agreement. The 64.66 km2 also contains the planned extension of our 1H Pilot Area pattern which is planned in a south and southwesterly direction.
The P8 Well drilled by Far East is contained in the acreage that is being relinquished by Far East in connection with the 2011 Shouyang PSC Modification Agreement. However, assuming the 2011 Shouyang PSC Modification Agreement is approved, CUCBM has agreed to compensate Far East for expenses incurred in drilling the P8 Well, by drilling a parameter well on behalf of Far East in the Shouyang Block outside of the Shouyang ODP Area to the same coal seam as the P8 well, including coring, fracturing and other testing.
Qinnan PSC. The exploration period of the Qinnan PSC in Shanxi Province expired on June 30, 2009, and we cannot continue our exploration activities in the Qinnan Block without an extension or a new PSC. We are continuing to pursue an extension of the exploration period of the Qinnan PSC, but we cannot be optimistic at this time. The Company believes the underlying exploration period should be extended due to events beyond its reasonable control, namely the lengthy transfer of rights taking place from CUCBM to CNPC. At our Chinese partner’s request, we have provided certain operational and financial information about our Company to assist them in the decision making process as to whether to recognize an extension of the exploration period in Qinnan. PetroChina has completed an accounting audit pursuant to the Qinnan PSC of our expenditures for 2007 and 2008. We have also provided to PetroChina at their request our work plan for 2010 for Qinnan. In January 2011, we received a formal notice from CNPC that it has purportedly received all Chinese approvals with respect to the transfer of CUCBM’s interest to it, and subsequently to its wholly owned affiliate PetroChina. CNPC also requested we execute a modification agreement to confirm PetroChina as our Chinese partner company for the Qinnan PSC.
In negotiations with CUCBM and PetroChina related to this request, we have endeavored to negotiate an assignment agreement that would reflect the transfer of interest to CNPC while CNPC and PetroChina would acknowledge delays that were incurred by virtue of FEEB not having, for an extended period of time, an official Chinese partner that had the capacity or authority under the Qinnan PSC to work with us. Because of the inability to hold a formal Joint Management Committee (“JMC”) meeting or to have the effective involvement of our Chinese partner, we believe that our efforts to continue CBM Operations in the Qinnan block have been materially hindered. Technically, the exploration period under the Qinnan PSC expired on June 30, 2009; however, we have maintained the position that the doctrine of force majeure under the Qinnan PSC entitled us to an extension. We continue to discuss this situation with CUCBM and PetroChina, and as recently as January 2012 have submitted a notice of force majeure in accordance with the Qinnan PSC. There can be no assurance that we will be successful in extending the exploration period of the Qinnan PSC or that a new PSC will be granted. Additionally, in connection with obtaining this extension or a new PSC, we may be required to commit to certain expenditures or to modify the terms or respective ownership interests and/or acreage in the applicable PSC.
Minimum Exploration Expenditure. Under the PSCs, we have committed to satisfy certain annual minimum exploration expenditure requirements for each PSC. Our minimum exploration expenditure requirement for each block is based on the minimum exploration expenditure requirements of CUCBM established by the MLR, subject to such additional commitments as we deem reasonably necessary and appropriate in light of negotiations to extend the underlying exploration periods of the PSCs and in light of our exploration plans for the particular block. The MLR sets its requirements by applying a minimum expenditure per acre to the total acreage encompassed by each PSC. The annual minimum exploration expenditure requirement is approximately $3.1 million and $3.7 million, respectively, for the Shouyang PSC and the Qinnan PSC, based on the currency exchange rate between the U.S. Dollar and the Chinese Renminbi ("RMB") as of December 31, 2011. For 2011, our exploration expenditure at the Shouyang Block exceeded the minimum requirement. Pursuant to the 2009 Shouyang PSC Modification Agreement, the portion of the exploration expenditures which exceeds the current year's minimum exploration expenditure requirement can no longer be carried forward toward the satisfaction of the subsequent year's minimum requirement. Our future work program at the Qinnan Block depends largely on whether the exploration period of the Qinnan PSC will be extended. These expenditure requirements are denominated in RMB and therefore, are subject to fluctuations in the currency exchange rate between the U.S. Dollar and the Chinese RMB.
If the 2011 Shouyang PSC Modification Agreement is approved by MofCom, we will be obligated to complete a minimum work program that is in excess of the MLR minimum requirements, however, the levels are below what we are planning on as necessary to develop potential reserves and pursue certification of additional Chinese reserve areas and/or ODP applications prior to the expiration of the extended Shouyang exploration period. If the 2011 Shouyang PSC Modification Agreement is approved by MofCom, we anticipate being able to establish a number of areas that reasonably meet the criteria for approval of “Chinese” reserves under PRC law.
Related Payments. Under the PSCs, we are required to make the following yearly payments to our Chinese partner companies. The annual payments are based on the currency exchange rate between the U.S. Dollar and the Chinese RMB as of December 31, 2011. As indicated below, certain amounts may change from year to year. The amounts reflected for Qinnan PSC have been accrued but certain of those payments have not been paid and will not be paid until such time as the extension has been approved.
| Annual Payments | | Shouyang PSC | | | Qinnan PSC | |
| Exploration Period | | | | | | |
| Salary and Benefit | | | | | | |
| 2012 | | $ | 231,542 | | | $ | 151,686 | |
| 2011 | | | 218,436 | (1) | | | 143,100 | |
| | | | | | | | | |
| Exploration Permit Fee | | | 140,136 | | | | 165,529 | |
| Training Fee | | | 60,000 | | | | 60,000 | |
| Assistance Fee | | | 50,000 | | | | 50,000 | |
| | | | | | | | | |
| Development & Production Period | | | | | | | | |
Signature Fee (2) | | | 150,000 | | | | 150,000 | |
| Training Fee | | | 150,000 | | | | 150,000 | |
| Assistance Fee | | | 120,000 | | | | 120,000 | |
(1) The increase from 2011 to 2012 is due to the increase of the standard amount of CUCBM's professionals’ salary and benefits under the amended Shouyang PSC. The salary and benefits for CUCBM professionals during the development and production periods is to be determined by negotiation with CUCBM.
(2) Due within 30 days after first approval of the ODP following the exploration period.
Our Holdings in the Yunnan Province of the People's Republic of China
Overview. On January 25, 2002, we entered into a PSC (the "Yunnan PSC") with CUCBM to develop two areas in Yunnan Province: (1) the Enhong area, which covers approximately 145,198 acres (587.6 km2), and (2) the Laochang area, which covers approximately 119,338 acres (482.943 km2). We are the operator under the Yunnan PSC. The term of the Yunnan PSC consists of an exploration period, a development period and a production period. The exploration period is divided into two phases, Phase I and Phase II. We have completed Phase I and are operating in Phase II. During the third quarter of 2009, the MofCom approved a modification agreement, which among other provisions, extended Phase II of the exploration period to June 30, 2011 from June 30, 2009. During the fourth quarter of 2011, we negotiated and on December 30, 2011 signed the 2011 YN PSC Modification Agreement, that would extend the exploration period until June 30, 2013, in exchange for the relinquishment of the 587.6 km2 in the Enhong part of the PSC contract area. The 2011 Yunnan PSC Modification Agreement has been submitted to MofCom and is currently awaiting approval. Under the 2011 Yunnan PSC Modification Agreement, following expiration of the extended exploration period, we may elect to continue the process of trying to move CBM Fields into the ODP process and the development period for certain areas that are in the final stages of the reserve certification process for submission of an ODP application for governmental approval. Any acreage that is not at or past the stage of submittal of a reserves report to CUCBM that reasonably meets the criteria for approval of reserves under PRC law will be relinquished unless the parties otherwise agree.
The development period as to any CBM Field in the Yunnan PSC area will begin after the approval of an ODP for any such CBM Field. An ODP would be developed and filed jointly by us and CUCBM, seeking approval from Chinese governmental authorities, for any CBM Field the Company and CUCBM elect to develop. The production period as to any CBM Field in the Yunnan PSC area will begin after the date of commencement of commercial production of that CBM Field. Provided that the Company remains in compliance with the requirements under the Yunnan PSC, production will be allowed to continue on a CBM Field until the earlier of the end of the useful life of the field or January 1, 2033, unless extended or otherwise amended.
We are responsible for all exploration costs related to the Yunnan PSC, including all exploration costs for discovering and evaluating CBM-bearing areas. If any CBM Field is discovered within the contract area, CUCBM will be deemed to hold a 40% participating interest in such field and we will be deemed to have a 60% participating interest, unless CUCBM elects to participate at a lower level, in which case we will retain all participating interests not taken by CUCBM and shall be responsible for development costs associated therewith.
Because there are no pipelines currently in the immediate vicinity of our Yunnan Province projects, our ability to sell CBM produced on these projects to communities outside the general area will be contingent upon a gas pipeline, compressed natural gas facility or other off-take vehicle being built close to our project area. We have learned that CNPC has undertaken a pipeline construction project with support from the Yunnan provincial government to extend the Myanmar-China natural gas pipeline to pass through the city of Kunming, then go northward through the city of Zhaotong, and finally connect with major interprovincial pipelines in Sichuan Province. Further, the pipeline plans are expected to include a branch that is intended to connect Kunming to Qujing. We believe that the construction, which would lay pipelines closer to our projects in the Yunnan Province, would help reduce the cost for CBM off-take from our projects and increase our ability to eventually deliver gas to consumers. If CUCBM elects a 40% participating interest in Yunnan Province project, our costs would be reduced accordingly.
Further exploration and development will be the subject of our internal strategic review of our remaining Yunnan holdings to determine whether they fit within our risk profile, given our other opportunities, such as our ability to potentially move into the development phase in the Shouyang ODP Area. We take into consideration, among other factors, our overall corporate strategy, the prospective costs and benefits of the acreage, our relationship with our Chinese partner companies and our current cash position in order to formulate an optimal strategy for the Company. The strategy may include, but not be limited to: (i) minimal capital spending to continue holding the acreage, (ii) sell, farmout or partial farmout of the acreage, (iii) full or partial relinquishment of the acreage, or (iv) continue staged exploration of the acreage. We have not yet concluded this review and cannot make any projection as to the likely outcome of this review. Moreover, CUCBM will have its own view and certain outcomes will be subject to CUCBM and MofCom approval.
In December 2010, we mobilized a drilling company to fracture stimulate 5 wells that we had drilled to test the number 7+8 and number 19 coal seams in Laochang area. These two seams have good gas content based on lab analysis and significant thickness to merit testing for commercial production. Stimulation operations were completed on January 19, 2011 and the dewatering operation started on March 18, 2011 in a total of nine coal layers from all five wells of the clustered pilot. With low and stable fluid levels, some coal seams have reached the critical desorption pressure in the area close to wellbore, and a small amount of gas is being produced and flared. We plan to continue the dewatering/test-production and we anticipate the production of more gas as the dewatering process moves forward and the interference between wells can be established, together with a reduction in the fluid-level, creating a funnel effect covering a relatively larger area of the reservoir. Recently, gas production from one of the pilot wells has remained steady at a rate around 20 Mcf (550-600 m3) per day, with the peak daily rate as high as 65 Mcf (1,850 m3). Production from the pilot has continued for about eight months; however, there can be no assurance that production will continue to increase or sustain current levels. After initial testing, it was determined that this CBM field possesses one of the higher-rank coals in China, which means that the coal in this CBM Field contains more carbon and typically results in a much higher energy content and frequently higher gas content. Accordingly, the Company plans to continue the pilot and further testing.
Our Phase I and Phase II obligations and results during the exploration period of our Yunnan PSC with CUCBM are summarized below.
Phase I. We completed our Phase I obligations under the Yunnan PSC. We drilled and completed three wells on the project, performed a hydraulic fracture and tested one of these three wells. We believe the three wells have yielded favorable gas content results. We also conducted geological data gathering, shot 2D seismic data for 10 kilometers in the Enhong area, drilled one slim hole vertical well in the Enhong area and one slim hole vertical well in the Laochang area with desorption and standard CBM laboratory analysis.
Phase II. On February 23, 2005, we elected to enter into Phase II under our Yunnan PSC, which required us to drill at least one horizontal well with a minimum of two laterals or drill vertical wells equivalent to the same work amount. As discussed below, this obligation will increase somewhat if the 2011 YN PSC Modification Agreement is approved by the MofCom. To continue our preparation for the drilling of the horizontal well and future development of this field, we have continued our geological and geophysical activities and drilled four slim hole vertical wells to gain more data and to enhance our understanding of structure complexity, coal lateral continuity, coal properties and reservoir characteristics. Based on the data gathered from these wells and other wells drilled by the Chinese coal industry, we drilled a cluster of four deviated wells to stimulate and test-produce the major coal
seams in 2008. These wells were drilled diagonally from the same surface location as an existing vertical well to provide a close pattern of five wells to test the coal seams. This pattern allows us to optimize well spacing and reduce the cost of road/pad construction and land use. We believe this will prove to be an optimal method of developing a CBM Field in mountainous terrain. As a result of our testing, we anticipate that these coal seams will have low permeability and that we will need to fracture multiple zones to fully test these wells. The outcome of our strategic review discussed above will determine the future plan for these wells and the acreage.
Minimum Exploration Expenditure. Under the Yunnan PSC, we have committed to satisfy certain annual minimum exploration expenditure requirements. Our minimum exploration expenditure requirements for the blocks subject to the PSC are based on our negotiated agreement to extend the Yunnan PSC exploration period. If the 2011 Yunnan PSC Modification Agreement is approved, Far East will be obligated to drill a total of eight wells during the entire exploration period, as extended, spending at least $0.8 million (4,850,000 RMB) per year as the minimum exploration expenditure. Under applicable MLR rules for minimum expenditure requirements, the annual minimum exploration expenditure requirement for the Yunnan PSC is approximately $1.7 million before the modification but reduced with relinquishment of acreage, based on the currency exchange rate between the U.S. Dollar and the Chinese RMB as of December 31, 2011. For 2011, our exploration expenditure exceeded the minimum requirement. As we have already drilled five wells in the Laochang region during the second phase of Yunnan exploration period, we are only obligated to drill an additional three wells before June 30, 2013 to satisfy the minimum work commitment in the 2011 YN PSC Modification Agreement.
These requirements are denominated in RMB and, therefore, are subject to fluctuations in the currency exchange rate between the U.S. Dollar and the Chinese RMB. The MLR minimum expenditure requirements are a significant factor that influences the Company's exploration work program. Under the Yunnan PSC, we are required to pay certain fees totaling $0.4 million in 2011, which are counted toward the satisfaction of the 2011 minimum exploration expenditure requirements. These fees include assistance fees, training fees, fees for CBM exploration rights and salaries and benefits. Based on the 2011 Yunnan PSC Modification Agreement, the unfulfilled exploration work commitment will be added to the minimum exploration work commitment for the following year. If the Company terminates the Yunnan PSC and there exists an unfulfilled balance of the minimum exploration work commitment, the Company will be required to pay the balance to CUCBM.
Related Payments. Pursuant to the terms of the Yunnan PSC, we have paid CUCBM signature fees totaling $350,000 since the inception of the Yunnan PSCs. Under the Yunnan PSCs, we are required to make the following yearly payments to our Chinese partner company. The annual payments are based on the currency exchange rate between the U.S. Dollar and the Chinese RMB as of December 31, 2011. As indicated below, certain amounts may change from year to year.
| Annual Payments | | Yunnan PSC | |
| Exploration Period | | | |
| Salary and Benefit | | | |
| 2012 | | $ | 298,806 | |
| 2011 | | | 275,000 | (1) |
| | | | | |
| Exploration Permit Fee | | | 76,594 | |
| Training Fee | | | 45,000 | |
| Assistance Fee | | | 45,000 | |
| | | | | |
| Development & Production Period | | | | |
| Training Fee | | | 80,000 | |
| Assistance Fee | | | 80,000 | |
(1) The increase from 2011 to 2012 is due to the increase of the standard amount of CUCBM's professionals’ salary and benefits under the amended Yunnan PSC. The salary and benefits for CUCBM professionals during the development and production periods is to be determined by negotiation with CUCBM.
Transactions with Dart Energy
In 2009, we entered into a series of transactions related to our Qinnan Block with Dart Energy, formerly known as Arrow Energy International Pte Ltd. In connection with these transactions, one of our wholly owned subsidiaries, FEEB, and Dart Energy entered into a Farmout Agreement (the "Farmout Agreement") under which, subject to certain conditions, FEEB would assign to Dart Energy 75.25% of its rights in the Qinnan PSC in Shanxi Province (the "Assignment"). In conjunction with the Farmout Agreement, FEEB issued an Exchangeable Note, $10 million principal amount, to Dart Energy for $10 million in cash and a warrant to Dart Energy for shares of our common stock ("Warrant"). The Warrant was not exercised and expired in December 2009. In February 2011, Dart Energy exercised its right to exchange a total of $6.8 million in principal amount under the Exchangeable Note for 14,315,789 shares of Common Stock. On September 15, 2011, the Company fulfilled its obligations under the Exchangeable Note by paying in full the remaining $3,200,000 principal balance on the Exchangeable Note plus the $1,226,577 in accrued interest. Because the Farmout Agreement was not approved by the Chinese government, the Company elected to terminate the Farmout Agreement on November 11, 2011.
Marketing and Transportation of Our CBM in China
The marketability of any gas production depends, in part, upon the availability, proximity and capacity of pipelines, gas gathering systems and processing facilities.
Pipelines in Shanxi Province. Currently, two national trunk lines, one to Beijing and one to Shanghai, traverse China in proximity to our Shanxi Province projects. Additionally, there are two intra-provincial pipelines that pass within 1 to 2 kilometers of our 1H pilot Area. Under the Gas Sales Agreement, SPG has begun to purchase gas from the Shouyang Block after the completion its pipeline, which runs from the Shanjing II pipeline (that runs from Western China to Beijing) to within 1 kilometer of our initial 1H Pilot Area in our Shouyang Block and then on to the Taiyuan area. The connecting pipeline is complete, and we have installed an in-field gathering system and compression facilities to increase the gas pressure to the pressure required for delivery. A competing pipeline company, Shanxi International Energy Company ("Shanxi International"), built a second pipeline to the initial 1H Pilot Area. The pipeline was laid purportedly with a capacity of 50 million cubic feet per day, extending east from Taiyuan toward the 1H Pilot Area. At the 1H Pilot Area the pipeline has turned south and will continue southeast to the city of Changzhi. As of December 31, 2011, this second pipeline was completed in our area, and nearing completion to Changzhi and Taiyuan, but not commissioned. There is no assurance that any of the existing pipelines we might desire to connect to in the future will have sufficient capacity available to meet our requirements or the costs of using such pipelines would be economical. Additionally, after the expiration of our twenty year gas sales agreement with SPG, there is no assurance that we will be able to use the existing pipeline on terms acceptable to us or at all, as the PRC does not require that open access to pipeline infrastructure be allowed.
Compressed Natural Gas. If we have initial commercial production of CBM from our Qinnan and Yunnan projects, then, prior to the point at which production reaches pipeline quantities, we could potentially begin to market the CBM produced to local markets as CNG. CNG is an alternative to the construction of a pipeline or LNG facility and is especially appropriate for early stage gas production where gas volumes are lower. We may determine to pursue CNG facilities in order to earn revenues from any early production of CBM. Production of CNG would require the installation of a CNG facility, which would likely be constructed and paid for by the purchaser of our gas production.
Pipelines in Yunnan Province. Because there are no pipelines currently in the vicinity of our Yunnan Province projects, our ability to sell CBM produced on these projects to communities outside the general area will be contingent upon a gas pipeline, CNG facility or other off-take vehicle to be built close by our project area. We estimate the initial cost to construct a connecting pipeline and compression facilities from our project area to the nearest large cities, Qujing and Kunming, may be in the range of $30 million to $45 million, if we are required to pay that cost.
We have learned that CNPC has undertaken a pipeline construction project with support from the Yunnan provincial government to extend the Myanmar-China natural gas pipeline to pass through the city of Kunming, then go northward through the city of Zhaotong, and finally connect with major interprovincial pipelines in Sichuan Province. Further, the pipeline plans are expected to include a branch that is intended to connect the city of Kunming to the city of Qujing. We believe that the construction, which would lay pipelines closer to our projects, would help reduce the cost for CBM off-take from our projects and increase our ability to eventually deliver gas to consumers. If CUCBM elects a 40% participating interest in Yunnan Province project, our costs would be reduced accordingly. However, there can be no assurances that this project will be undertaken or be completed or, if it is undertaken, that it will be completed on a timely basis. Additionally, there is no assurance that we will be able to use the pipeline on terms acceptable to us or at all, as the PRC does not require that open access to pipeline infrastructure be allowed.
Our Competition
The energy industry is highly competitive in all of its phases. Competition is particularly intense with respect to the acquisition of desirable producing properties, the acquisition of CBM prospects suitable for enhanced production efforts, the hiring of experienced personnel and the marketing of resources. Our competitors in CBM acquisition, development, and production in China include major integrated oil and gas companies and substantial independent energy companies, many of which possess greater financial and other resources.
Safety and Health Matters
We employ numerous safety precautions and emergency response plans designed specifically for our exploration activities in China to ensure the safety of our employees and independent contractors. We have maintained a strong safety record, which includes no lost-time accidents in over six years and no major environmental incidents. We also conduct our operations in accordance with various laws and regulations concerning occupational safety and health. As protection against operating hazards and environmental risks, we maintain insurance coverage against some, but not all, potential injuries and losses. In addition, we require service providers we engage to maintain similar insurance coverage.
Regulations Impacting Our Business
Our operations are 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; impose substantial liabilities for any pollution resulting from our operation and limit our discretion in marketing any production.
The exploration and production of CBM in China is regulated by and affected by the policies of multiple administrative bodies including the NDRC, the MofCom, the MLR, CNPC and CUCBM. The Mineral Resources Law and the related regulations are the primary source of law governing the exploration and production of coalbed methane in China.
The NDRC is responsible for the development and strategic upgrade of key industries in China, including the CBM industry. Policy making decisions of the NDRC could, therefore, affect our company. Additionally, the MofCom has many policy setting functions and, through its Foreign Investment Administration (the "FIA"), the MofCom is directly responsible for foreign investment in China. Our PSCs and the subsequent amendments to those contracts were, and continue to be, subject to approval of the MofCom. Within the FIA, the Service Trade Division also regulates the public utilities in urban areas, various pipeline networks, transportation and CBM exploration and production and, therefore, the division's policies, rules and regulations could affect our future strategy and operations for transportation and distribution of any CBM production.
The rules and regulations of the MLR and, in particular, CUCBM more directly affect the CBM industry in China as well as our operations. The MLR is the principal authority regulating the CBM industry in China. It has authority over the designation of land for exploration, the approval of geological reserve reports, the review and granting of licenses for exploration and production and the administration of the registration and assignment of
exploration and production licenses. CNPC is in the process of replacing CUCBM as our Chinese partner company for the Qinnan PSC. In January 2011, we received a formal notice from CNPC that it has purportedly received all Chinese approvals with respect to the transfer and has requested we execute a modification agreement to confirm CNPC as our Chinese partner company for the Qinnan PSC. In negotiations with CUCBM and PetroChina related to this request, we have endeavored to negotiate an assignment agreement that would reflect the transfer of interest to CNPC and then to PetroChina, while CNPC and or PetroChina would acknowledge delays that were incurred by virtue of FEEB not having, for an extended period of time, an official Chinese partner that had the capacity or authority under the Qinnan PSC to work with us. We continue to discuss this situation with CUCBM and PetroChina, and as recently as January 2012 have submitted a notice of force majeure regarding the delays in CBM Operations caused by the incomplete transfer of interests from CUCBM.
This partnership relationship is administered and delineated in whole or part through the PSC. In the PSCs, our Chinese partner company represents that it has full authority to contract with foreign investors for the purpose of exploring and producing CBM. Because only a Chinese party can hold an exploration license for CBM, the Chinese partner applies to the MLR for the exploration licenses on behalf of foreign investors. In operating under each PSC, our primary interaction with the Chinese government is with our Chinese partner and the JMC that administers our PSC. Each PSC has its own JMC. . The JMC consists of members of our management team and representatives of Chinese Partner and it meets on a periodic basis to, among other things, discuss and make decisions concerning our exploration and development progress and plans, including budgets and capital expenditure commitments. Under the terms of the PSCs, we must obtain the Chinese Partner’s consent to certain actions, including the transfer of any rights under the PSCs. Additionally, the PSCs authorize us to sell CBM directly into the market but our marketing efforts may be limited by certain Chinese regulations that require companies to have a permit not generally available to foreign companies to sell gas in certain Chinese localities.
Our Employees
As of March 2, 2012, we had 17 employees in China and 8 employees in the United States for a total of 25 employees, all of whom were employed by us on a full-time basis.
Forward-Looking Statements
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21B of the Securities Exchange Act of 1934, as amended ("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," "project," "expect," "consider" 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. 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: the preliminary nature of well data, including permeability and gas content; there can be no assurance as to the volume of gas that is ultimately produced or sold from our wells; the fracture stimulation program may not be successful in increasing gas volumes; due to limitations under Chinese law, we may have only limited rights to enforce the Gas Sales Agreement, to which we are an express beneficiary; additional wells may not be drilled, or if drilled may not be timely; additional pipelines and gathering systems needed to transport our gas may not be constructed, or if constructed may not be timely, or their routes may differ from those anticipated; the pipeline and local distribution/compressed natural gas companies may decline to purchase or take our gas (although the Gas Sales Agreement with the pipeline is a “take or pay” contract), or we may not be able to enforce our rights under definitive agreements with pipelines; conflicts with coal mining operations or coordination of our exploration and production activities with mining activities could adversely impact or add significant costs to our operations; the MofCom may not approve on a timely basis or at all, the extension of the Qinnan PSC or, if so, on commercially advantageous terms; our Chinese partner companies or the MofCom may require certain changes to the terms and conditions of our PSC in conjunction with their approval of the 2011 Shouyang PSC Modification Agreement or our PSCs in conjunction with their approval, including reductions in acreage or a reduction in the term of the extension for the exploration period; our lack of operating history; limited and potentially inadequate management of our cash resources; risk and uncertainties associated with exploration, development and production of CBM; our inability to extract or sell all or a substantial portion of our estimated Contingent Resources; we may not satisfy requirements for listing our securities on a securities exchange; expropriation and other risks associated with foreign operations; disruptions in capital markets affecting fundraising; 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 our 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 capital in order to continue our operations.
On November 20, 2011, we completed a transaction whereby we entered into a $25 million credit facility with Standard Chartered Bank (“SCB”) as lender, the proceeds of which would be used for project costs, finance costs and other corporate purposes approved by SCB. Additionally, although we commenced gas sales under the Gas Sales Agreement in the first quarter of 2011 and production increased in the second quarter and remained steady in
the third quarter, we are not able to predict exactly when we will recognize significant revenues. We expect to experience operating losses and negative cash flow until production levels in the Shouyang Block increase sufficiently.
Management will continue to seek to secure additional capital to continue operations, to meet future expenditure requirements necessary to retain our rights under the PSCs. Management may seek to secure capital by exploring potential strategic relationships or transactions involving one or more of our PSCs, such as a joint venture, farmout, merger, acquisition or sale of some or all of our assets, by obtaining debt, project or equity-related financing. However, there can be no assurance that we will be successful in entering into any strategic relationship or transaction, securing capital or raising funds through debt, project or equity-related financing. Under certain circumstances, the structure of a strategic transaction may require the approval of the Chinese authorities, which could delay closing or make the consummation of a transaction more difficult or impossible. In particular, any transfer of our rights under any PSC will require the approval of our Chinese partner company. There can be no assurance that the Chinese authorities will provide the approvals necessary for a transaction or transfer. The ongoing global financial crisis has created liquidity problems for many companies and financial institutions, and international capital markets have stagnated, especially in the United States and Europe. A continuing downturn in these markets could impair our ability to obtain, or may increase our costs associated with obtaining, additional funds through the sale of our securities or otherwise. The ongoing crisis has created a difficult environment in which to negotiate and consummate a transaction. In addition, the terms and conditions of any potential strategic relationship or transaction or of any debt or equity-related financing are uncertain and we cannot predict the timing, structure or other terms and conditions of any such arrangements or the consideration that may be paid with respect to any transaction or offering of securities and whether the consideration will meet or exceed our offering price.
Our ability to continue as a going concern depends upon our ability to obtain substantial funds for use in our development activities and upon the success of our planned exploration and development activities. There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our unproved oil and gas properties. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Management believes that we will continue to be successful in securing any funds necessary to continue as a going concern.
If our operating requirements or drilling obligations materially change from those currently planned, we may require more capital than currently anticipated or may be required to secure capital earlier than anticipated. For example, it is possible that the Ministry of Land and Resources or one of our Chinese partner companies could seek to, among other things, force us to relinquish acreage, increase our capital expenditures or accelerate our drilling program. If we are unable to commit to the expenditures or accelerate our drilling and dewatering efforts, it may adversely affect our ability to extend the terms of our PSCs. Raising additional funds by issuing shares or other types of equity securities would further dilute our existing stockholders. If we fail to obtain the necessary funds to complete our exploration activities under our PSCs, and we cannot obtain extensions to the requirements under our PSCs, we would not be able to successfully complete our exploration and development activities and we may lose rights under our PSCs or we may have to limit the acreage used in the Shouyang Block.
We must obtain extensions for our PSCs to continue our operations in China.
In 2011, we agreed and signed modification agreements for the Yunnan and Shouyang PSCs. Such modification agreements have been submitted to the MofCom for approval, however, they have not yet been approved and the applications could be rejected or modifications could be required to the commercially agreed upon terms. The extensions to the exploration periods from earlier modification agreements for the Shouyang area of Shanxi Province and the Enhong and Laochang areas of Yunnan Province expired on June 30, 2011. While we are confident that the 2011 Shouyang and Yunnan Modification Agreements as executed between the Company and CUCBM will be approved by MofCom, thereby, among other things, extending the exploration periods, there can be no guarantee in this regard. The exploration period of the Qinnan PSC in Shanxi Province expired on June 30, 2009, and we cannot continue our exploration activities in the Qinnan Block without an extension or a new PSC. We are continuing to pursue an extension of the exploration period of the Qinnan PSC and have asserted claims of force majeure pursuant to the terms of the PSC, but we cannot be optimistic at this time. The Company believes the underlying exploration period should be extended due to events beyond its reasonable control, namely the lengthy transfer of rights taking place from CUCBM to CNPC's designated assign. At CNPC’s request, we have provided
certain operational and financial information about our Company to assist them in the decision making process as to whether to recognize an extension of the exploration period in Qinnan. CNPC has completed an accounting audit pursuant to the Qinnan PSC of our expenditures for 2007 and 2008. We have also provided to CNPC at their request our work plan for 2010 for Qinnan. In January 2011, we received a formal notice from CNPC that it has purportedly received all Chinese approvals with respect to the transfer and has requested that we execute a modification agreement to confirm PetroChina as our Chinese partner company for the Qinnan PSC, as a direct assignee from CNPC. In negotiations with CUCBM and PetroChina related to this request, we have endeavored to negotiate an assignment agreement that would reflect the transfer of interest to CNPC, while CNPC and or PetroChina would acknowledge delays that were incurred by virtue of FEEB not having, for an extended period of time, an official Chinese partner that had the capacity or authority under the Qinnan PSC to work with us. Because of the inability to hold a formal Joint Management Committee ("JMC") meeting or to have the effective involvement of our Chinese partner, we believe that our efforts to continue CBM Operations in the Qinnan block have been materially hindered. Technically, the exploration period under the Qinnan PSC expired on June 30, 2009; however, we have maintained the position that the doctrine of force majeure under the Qinnan PSC entitled us to an extension. We continue to discuss this situation with CUCBM and PetroChina, and as recently as January 2012 have submitted a notice of force majeure in accordance with the Qinnan PSC. There has been no formal acknowledgment of our claim of force majeure or our efforts to finalize the transfer agreement from CUCBM to PetroChina. There can be no assurance that we will be successful in extending the exploration period of the Qinnan PSC or that a new PSC will be granted, and we cannot be optimistic at this time. Additionally, in connection with obtaining this extension or a new PSC, we may be required to commit to certain expenditures or to modify the terms or respective ownership interests and/or acreage in the applicable PSC. However, if we are unable to secure sufficient funds to commit to these expenditures, it may adversely affect our ability to extend the Qinnan PSC.
We have a limited source of revenue.
We will not generate material revenues from our existing properties until we have successfully completed exploration and development, and started meaningful production of CBM. Although we commenced sales under the Gas Sales Agreement in the early first quarter of 2011, and production increased in the second quarter and remained steady in the third quarter, we are not able to predict exactly when we will recognize significant revenues. SPG has completed its pipeline, which runs within 2 kilometers of our 1H Pilot Area and is being used to transport CBM sold pursuant to the Gas Sales Agreement. The in-field gathering system and compression equipment were connected to the pipeline in early January 2011. After completion of that process, low level gas flow commenced in January with initial testing of the gathering system in January. Gas sales were interrupted while SPG completed testing and commissioning of equipment related to our first stage compressor sites as well as installation of gas sales meters. That work was completed and formal gas flow and sales re-commenced in mid-March 2011. Additionally, no facilities exist to transport or process CBM near our Yunnan Province projects. Our ability to realize revenues from any producing wells may be impaired until these pipelines or facilities are built out or arrangements are made to deliver our production to market.
We are in the exploration and development phase of PSCs and have substantial capital requirements that, if not met, will hinder our ability to continue as a going concern.
We face significant challenges, expenses and difficulties as we seek to explore, develop and produce CBM. 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 will also require resources to fund significant capital expenditures for exploration and development activities in future periods. In this regard, CUCBM or CNPC could seek to renegotiate our PSCs to, among other things, increase our expenditures or accelerate our drilling program beyond the minimum contractual requirements under our PSCs. Our success will depend on our ability to secure additional capital to fund our capital expenditures until such time as revenues are sufficient to fund our activities. If we cannot obtain adequate capital, or do not have sufficient revenue to fund our activities, and we cannot obtain extensions to the requirements under our PSCs, we will not be able to successfully complete our exploration and development activities, and we may lose rights under our PSCs. This would materially and adversely affect our business, financial condition and results of operations.
Lingering disruptions in national and international investment and credit markets or fraud or embezzlement of funds at the financial institutions which hold our assets may adversely affect our business, financial condition and results of operation.
Lingering disruptions in the global financial system have continued to depress capital market activities, limit availability of credit, tighten lending standards and cause higher interest rates and costs of capital. Although the global financial system has stabilized to a certain extent, market conditions may continue or worsen. We can make no assurances that we will be able to obtain additional equity or debt financing to fund our anticipated drilling, exploration and operation costs on terms that are acceptable to us or at all. In the absence of capital obtained through a strategic relationship or transaction with one or more interested companies, or through an equity or debt financing, our ability to operate and to meet our obligations under our PSCs would be impaired, which would have a material adverse effect on our business, financial condition and results of operation and may affect our ability to continue as a going concern.
Our cash and cash equivalents are liquid investments with original maturities of three months or less at the time of purchase. We maintain the cash and cash equivalents with reputable major financial institutions in deposit accounts and U.S. government securities money market accounts. Deposits with these institutions exceed the Federal Deposit Insurance Corporation’s insurance limits or similar limits in foreign jurisdictions. If one or more of these institutions are unable to honor our withdrawal requests or redeem our shares in our deposit or money market accounts as a result of the institution’s financial condition, fraud, embezzlement or otherwise, it could have an adverse effect on our business, financial condition and results of operations. The Company is not engaged in any foreign currency hedging activities.
The development of CBM properties involves substantial risks, and we cannot assure that our exploration and drilling efforts will be successful.
The business of exploring for and, to a lesser extent, developing and operating CBM 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 CBM gas drilling, the drilling, ownership and operation of CBM wells and the ownership of interests in CBM properties are highly speculative. We cannot always predict whether any of our wells will produce commercial quantities of CBM.
Drilling for CBM gas may involve unprofitable efforts from, among other things, wells that are productive but do not produce CBM 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 but not limited to uncooperative inhabitants, 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, structural characteristics of the coal, or the quality or quantity of water that must be produced, may hinder, restrict or even make production impractical or impossible.
Drilling 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, the 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. We contract with drilling companies to drill certain of our wells in China, and we face the risk that the other party may not perform, which may delay our drilling program. A productive well may also become uneconomic in the event excessive water or other deleterious substances are encountered, which impair or prevent the production of 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 that wells drilled by us will be productive or, even if productive, will produce CBM in economic quantities so that we will recover all or
any portion of our investment. In the event we are not successful, we may be required to write off some or all of the capitalized well costs on our financial statements.
Sales of CBM produced at our Shouyang block under the Gas Sales Agreement are our only source of revenues, and these revenues are not currently significant.
We will not generate material revenues from our existing properties until we have successfully completed exploration and development and increased production of CBM. Although we have commenced sales under the Gas Sales Agreement, we are not able to predict exactly when we will recognize significant revenues. The gross gas production for 2011 was approximately 268 million cubic feet. Additionally, no facilities exist to transport or process CBM near our Yunnan Province projects. Our ability to realize significant revenues from any producing wells in Yunnan may be impaired until additional pipelines or CNG facilities are built out or arrangements are made to deliver our production to market.
We are an early stage company and, thus have limited operating history for the purpose of evaluation of our performance and prospects.
We have been engaged principally in developing and implementing strategic operating and exploration plans, raising capital, hiring personnel, entering into contracts, acquiring rights to explore, develop, produce and sell CBM, and drilling, testing and completing exploratory wells. As an early stage company, we have limited operating experience in the distribution and marketing of CBM gas in China. We have limited 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 the risk of unforeseen capital requirements, failure to establish business relationships, and competitive disadvantages against larger and more established companies.
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 value of our common stock will suffer.
As of December 31, 2011, we have minimal revenues from the sale of CBM. We incurred yearly net losses applicable to common stockholders since inception. Although we have commenced sales under the Gas Sales Agreement, we expect to continue to experience operating losses and negative cash flow for the foreseeable future. We must secure additional capital and/or generate sufficient revenues to fund anticipated drilling, exploration and operation costs and to achieve and maintain positive net income. We cannot guarantee that we will ever generate sufficient revenues to achieve positive net income, which would negatively impact the price of our common stock. If we do achieve positive net income, we cannot assure you that we will be able to sustain or increase profitability in the future.
We must complete multiple additional CBM wells on our Shanxi Province and Yunnan Province projects before we can significantly increase production in Shanxi and commence production in Yunnan.
To date, we have drilled to total depth, 7 horizontal wells, 25 vertical wells, 44 deviated wells, and 20 pilot development test wells in the Shouyang and Qinnan Blocks in Shanxi Province and 10 vertical wells and 4 deviated wells in Yunnan Province.
While subject to periodic maintenance, we have achieved continuous gas production in some of our wells, but there can be no assurance that mechanical events may not affect production from time to time. We have entered into the Gas Sales Agreement for the purchase and sale of up to 300,000 cubic meters (10,584,000 cubic feet) of CBM per day produced at our Shouyang Block. We plan to continue to dewater existing wells and drill additional wells in the initial 1H Pilot Area to increase production. At this early stage, the volumes being produced while dewatering are still relatively small, and the data obtained is not yet sufficient to be able to project the peak gas production volume or to be able to conclude whether the wells will produce the maximum volume of CBM that SPG is obligated to take under the Gas Sales Agreement. None of the wells we have drilled to date in Yunnan or Qinnan are currently producing CBM gas as they are undergoing or will undergo dewatering and production testing. We are analyzing and evaluating drilling data obtained in an effort to determine how many additional wells we have to drill
in order to begin production of commercial volumes in Qinnan and Yunnan; and, in Shouyang, while commercial production has been achieved, we desire to drill additional wells to increase production. We cannot make any assurances that we will have the resources to drill enough additional wells in the Shanxi and Yunnan Provinces to significantly increase 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 positive cash flow from operations 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.
We are a holding company, and we rely on our subsidiaries for dividends and other payments for funds to meet our obligations.
We are principally a holding company with substantially all of our assets relating to operations in China being owned by our subsidiary, FEEB. Consequently, we have no direct operations and are not expected to own a significant amount of assets other than the outstanding capital stock of our subsidiaries, including FEEB, and cash and cash equivalents. Because we conduct our operations through our subsidiaries, if and when we achieve positive cash flow, we will depend on those entities for dividends and other payments to generate the funds necessary to meet our financial obligations and to pay dividends, if any, with respect to our common stock. The jurisdictions of our subsidiaries may impose restrictions on or require government approval of dividends or certain payments by the subsidiaries. All of our subsidiaries will be separate and independent legal entities and will have no legal obligation whatsoever to pay, and may be contractually restricted from paying, any dividends, distributions or other payments to us.
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 our executive officers. 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 not diversified, and we concentrate on one industry.
Our business strategy concentrates on exploration and development of CBM 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 substantially all 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 our CBM property rights in China would have a material adverse effect on our business.
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 substantially more demands on these resources. Further, we may be required to respond to any expansion of our activities in a relatively short period of time in order to meet the demands created by the expansion of these activities, the growth of our business and our drilling objectives. The failure to timely 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 and the growth of our business may be adversely affected.
We may suffer an adverse impact on our reputation and share value as a result of our relationship with CNPC.
CNPC, our Chinese partner in the Qinnan PSC, has operations in various countries subject to U.S. export or asset controls. We depend on CNPC, as the holder of the exploration license for CBM gas, to allow us to operate our Qinnan Block. We are aware of certain organizational and investor efforts to persuade PetroChina, the reporting subsidiary of CNPC in the United States, to end its business contacts, direct or indirect, with certain countries, including Iran and Sudan, and that investors have divested PetroChina’s securities because of such ties. Iran and Sudan have been designated by the U.S. as state sponsors of terrorism. To date, we have detected no adverse investor sentiment regarding our contractual relationship with CNPC, no reluctance to invest because of such relationship and no desire or intent to divest our securities because of such relationship. Nevertheless, in light of the aforementioned organizational and investor efforts regarding PetroChina, we may suffer an adverse impact on our reputation and share value as a result of our relationship with CNPC.
Risks Relating to Our Operations in China
No facilities presently exist to transport or process CBM near our Yunnan Province projects, and, although a pipeline connects to our Shouyang Block, we have limited rights under Chinese law to enforce SPG’s obligations under the Gas Sales Agreement, which governs that pipeline.
The marketability of any CBM production depends, 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.
Pipelines in Shanxi Province. Currently, two national trunklines, one to Beijing and one to Shanghai, traverse China in proximity to our Shanxi Province projects. Additionally, there are two intra-provincial pipelines that pass within 1 to 2 kilometers of our 1H pilot Area. Under the Gas Sales Agreement, SPG has begun to purchase gas from the Shouyang Block after the completion of the pipeline, which runs from the Shanjing II pipeline (that runs from Western China to Beijing) to within 1 kilometer of our initial 1H Pilot Area in our Shouyang Block, and then on to the Taiyuan area. The connecting pipeline is complete, and we have installed an in-field gathering system and compression facilities to increase the gas pressure to the pressure required for delivery. Gas sales began shortly after completion of the gathering system and compression facilities. Although we are express beneficiaries of the Gas Sales Agreement, we may have limited rights under Chinese law to enforce SPG’s obligations under the agreement without the cooperation of CUCBM. We cannot guarantee the volumes of gas that may be sold under the Gas Sales Agreement. Costs associated with the Shouyang PSC as well as proceeds and subsidies from gas sales under the Gas Sales Agreement are allocated between us and CUCBM in accordance with our participating interest. See “Our Holdings in the Shanxi Province of the People’s Republic of China” of Item 1 - Business for a further description of the Shouyang PSC and participating interests in the PSC. There can be no assurance that such government subsidies will continue or that they will be paid in a timely manner upon commencement of gas sales.
The exploration period of the Qinnan PSC in Shanxi Province technically expired on June 30, 2009, and we cannot continue our exploration activities in the Qinnan Block without an extension or a new PSC. If we are successful in obtaining an extension of the Qinnan PSC, as to which we are not optimistic, or a recognition by our Chinese counterparty that the period should automatically be extended for some period of time, CNG facilities or pipelines to connect our projects to larger pipelines may need to be built to market any CBM that may be produced. If CUCBM elects a 30% participating interest in our Shouyang and Qinnan PSC, our net development costs and revenues associated with those PSCs would be reduced accordingly. There is no assurance that any of the existing pipelines we might desire to connect to in the future will have sufficient capacity available to meet our requirements or the costs of using such pipelines would be economical for our PSCs. Additionally, there is no assurance that after the expiration of our twenty-year gas sales agreement with SPG we will be able to use its pipeline, or the other existing pipelines on terms acceptable to us or at all, as China does not require that open access to pipeline infrastructure be allowed.
Compressed Natural Gas. If we have initial commercial production of CBM from our Qinnan and Yunnan projects, then, prior to the point at which production reaches pipeline quantities, we could potentially begin to market the CBM produced to local markets as CNG. CNG is an alternative to the construction of a pipeline or liquefied natural gas ("LNG") facility and is especially appropriate for early stage gas production where gas volumes are lower. We may determine to pursue CNG facilities in order to earn revenues from any early production of CBM. Production of CNG would require the installation of a CNG facility, which would likely be constructed and paid for by the purchaser of our gas production.
Pipelines in Yunnan Province. There are no pipelines in the vicinity of our Yunnan Province projects, and we estimate the initial cost to construct a connecting pipeline and compression facilities from our project to the nearest large city, Kunming, may be in the range of $30 million to $45 million. If CUCBM elects a 40% participating interest in our Yunnan Province project, our costs would be reduced accordingly. Because there is no gas pipeline, CNG facility, liquefied natural gas (“LNG”) plant or other off-take vehicle 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, CNG or LNG plant being built near the Enhong-Laochang project.
It has been reported that CNPC will undertake a pipeline construction project with support from the Yunnan provincial government to extend the Myanmar-China natural gas pipeline to pass through the city of Kunming, then go northward through the city of Zhaotong, and finally connect with major interprovincial pipelines in Sichuan Province. Further, the pipelines are expected to include a branch to connect the city of Kunming to the city of Qujing. We believe that the construction, which would lay pipelines closer to our projects, would help reduce the cost for CBM off-take from our projects and increase our ability to eventually deliver gas to consumers. If CUCBM elects a 40% participating interest in Yunnan Province project, our costs would be reduced accordingly. However, there can be no assurances that this project will be undertaken or completed on a timely basis, if ever. Additionally, there is no assurance that we will be able to use the pipeline on terms acceptable to us or at all, as the PRC does not require that open access to pipeline infrastructure be allowed.
Our business depends on transportation and other facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce.
The marketability of our CBM production depends in part on the availability, proximity and capacity of pipeline and other systems owned by third parties. The amount of CBM gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration.
In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would have an adverse effect on our business.
Substantially all of our assets and operations are located in China.
Substantially all of our assets and operations are located in China. Accordingly, our business is subject to a significant extent, to the economic, political, and legal developments 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 China. 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 CBM gas and enforcing rights under our PSCs and other agreements governed by Chinese law in China. Risks inherent in international operations also include, but are not limited to, the following:
| | · | global economic conditions; |
| | · | local currency instability; |
| | · | 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 |
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:
| | · | contract renegotiations; |
| | · | changes in diplomatic and trade relations between United States and China; |
| | · | government intervention and price fixing in certain markets; and |
| | · | changes in laws resulting from governmental changes. |
Additionally, CUCBM and CNPC are subject to rules and regulations of China and the jurisdiction or influence of other governmental agencies in China that may adversely affect their ability to perform under, or our rights in our PSCs with them. These rules and regulations may affect our rights under our PSCs by potentially limiting, renegotiating or precluding us from exploring and developing the full acreage provided for and may also affect the opportunities and obligations under our PSCs. CUCBM and CNPC could seek, among other things, to increase our expenditures or accelerate our drilling program beyond the minimum contractual requirements under our PSCs. We must comply with certain procedural requirements under our PSCs and with CUCBM in order to obtain the reimbursement of costs incurred under the PSCs. We cannot assure you that we will recover or that CUCBM will approve reimbursement of all costs incurred under the PSCs, which could adversely impact our business, financial conditions and results of operations. 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 are exposed to foreign currency risk.
In July 2005, the Chinese government began to permit the Chinese Renminbi (“RMB”) to float against the U.S. Dollar. All of our costs to operate our Chinese offices are paid in Chinese RMB. Our exploration costs in China may be incurred, and our revenues may be generated, under contracts denominated in Chinese RMB or U.S. Dollars. If the value of the U.S. Dollar falls in relation to the Chinese RMB, the cost to us of funding our Chinese operations would rise because more U.S. Dollars would be required to fund the same expenditures in RMB. Conversely, if the value of the U.S. Dollar rises in relation to the Chinese RMB, the change in exchange rates would decrease our dollar cost to fund operations in China. Similarly, devaluation of Chinese RMB relative to the U.S. Dollar can reduce the U.S. dollar value of our local cash flow and local net income.
To date, we have not engaged in hedging activities to hedge our foreign currency exposure. In the future, we may enter into hedging instruments to manage our foreign currency exchange risk or continue to be subject to exchange rate risk. However, we may not be successful in reducing foreign currency exchange risks, and as a result, we may from time to time experience losses resulting from fluctuations in the value of the Chinese RMB.
Inflation may adversely affect our financial condition and results of operations.
Although inflation has not materially impacted our operations in the recent past, increased inflation in China or the U.S. could have a negative impact on our operating and general and administrative expenses, as these costs could increase. In recent years, the Company has increased its use of Chinese suppliers, including drilling contractors, that are paid in RMB. In the future, inflation in China may result in higher minimum expenditure requirements under our PSCs if CUCBM adjusts these requirements for inflation. A material increase in these costs as a result of inflation could adversely affect our operations and, if there are material changes in our costs, we may seek to raise more funds earlier than anticipated.
We risk the effects of general economic conditions in China.
Our present and any future CBM sales 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. The recent meltdown of and disruptions in the global financial system may adversely impact China’s growth rates.
We will continue to depend on a few customers if we increase our gas production.
Although we have begun sales under the Gas Sales Agreement, we are not able to predict exactly when we will recognize significant revenues from our gas production or the volumes of gas that may be sold under that agreement. With respect to the other PSCs and gas sales from the Shouyang PSC in excess of the potential 300,000 cubic meters (10,584,000 cubic feet) per day to be sold under the Gas Sales Agreement, when selling our gas production, there may be only a small number of entities we or our Chinese partner companies can contract with which will purchase any gas we may produce. Losing any such potential contract or client would have a material negative impact on our business.
Risks Related to the Oil & Gas Industry
The volatility of natural gas and oil prices could harm our business.
Our future revenues, profitability and growth as well as the carrying value of our oil and gas properties depend to a large degree on prevailing oil and gas prices. Our ability to borrow additional funds 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, including deregulation of the natural gas market, 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. Prices for oil and natural gas have been and are likely to remain extremely unstable. The Chinese government has recently adopted a new policy with a view to de-regulating the natural gas market. On December 26, 2011, the National Development and Reform Commission issued the Notice on the Trial Reform of Natural Gas Pricing Mechanism in Guangdong and Guangxi (the “Notice”) as a first step effort to de-regulate China's gas pricing regime. Under this Notice, Guangdong and Guangxi have been selected to implement the new pricing scheme as a pilot program and if this pilot program works well, it will probably roll out across the country. Pursuant to the Notice, the benchmark price is the ex-factory gas price in the Shanghai market. In calculating the benchmark price, the price of two types of alternative resources oil and LNG is taken into account. The ex-factory gas price to be adopted in Guangdong and Guangxi should be calculated by reference to the Shanghai benchmark price. The Notice sets a ceiling for the ex-factory price for Guangdong and Guangxi, being RMB2.74 cubic meters (roughly equivalent to US $12.19 McF) in Guangdong and RMB2.57 cubic meters (roughly equivalent to US $11.43 McF) in Guangxi. Under such ceilings, the suppliers and purchasers are free to negotiate and determine the actual
purchase price. The Notice further sets out that the ex-factory price for unconventional gas such as shale gas and coal-bed methane will be set according to the market demand. Also in December 2011, the National Development and Reform Commission and the National Resources Bureau jointly issued the Twelfth Five-Year Plan for Coal-Bed Methane Development and Usage, which lays down the Chinese government's focus on the development of coal-bed methane projects in 2015-2020.
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 CBM prospects suitable for enhanced production efforts, and the hiring of experienced personnel. Our competitors in CBM 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.
If any well becomes commercially productive, it will not be possible to predict the life and production of that well. The actual producing lives could differ from those anticipated. Sufficient CBM 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 will decline over time, and does not indicate any consistent level of future production.
We may suffer losses or incur liability for events as the operator of a property or as to which 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. 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.
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, and blowouts and 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; |
| | · | Reports concerning operations; |
| | · | Unitization and pooling of properties; |
| | · | 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 and 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 PSCs and the Shanxi farmout 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. These regulations require us to obtain 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.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and exploitation plans on a timely basis and within our budget.
Shortages or the high costs of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploration and development operations, which could have a material adverse effect on our business, financial
condition or results of operations. If the unavailability or high cost of rigs, equipment, supplies or personnel were particularly severe in China, we could be materially and adversely affected.
Risks Relating to our Securities
There are a substantial number of shares of our common stock underlying outstanding warrants and options as well as shares of our common stock that cannot currently be traded without restriction but which may become eligible for trading in the future. We cannot predict the effect future sales of our common stock will have on the market price of our common stock.
On March 2, 2012, we had 500 million shares of common stock authorized, of which approximately 344,632,223 million shares of common stock were issued and outstanding. As of March 2, 2012, of the issued and outstanding shares, 7.7 million, or 2.2%, were “restricted stock” subject to resale restrictions. These shares of restricted stock will be available for trading in the future, so long as all the requirements of Rule 144, promulgated under the Securities Act of 1933 are met or if such shares are registered for resale. Additionally, as of March 2, 2012, we had another 33.1 million shares of common stock subject to options and warrants, which may be issued in the future upon exercise of the applicable options and warrants.
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 registered or to be registered on registration statements, 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 on our common stock.
We have not paid dividends on our common stock, and we currently intend to retain any profits to fund the development and growth of our business. As a result, our board of directors currently does not intend to declare dividends or make any other distributions on our common stock in the foreseeable future. Consequently, it is uncertain when, if ever, we will declare dividends to our common stockholders. Investors in our common stock may not derive any profits from their investment in us for the foreseeable future, other than through any price appreciation of our common stock that may occur.
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; |
| | · | failure to extend the terms of our production sharing contracts; |
| | · | 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 common 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 common 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.
Trading in our common stock is limited and sporadic, and a significant market for our common stock may not develop.
Our common stock is currently eligible for trading only on the OTC Bulletin Board. While there currently exists a limited and sporadic public trading market for our common stock, the price paid for our common stock and the amount of common stock traded are volatile. We cannot assure or guarantee you that the trading market for our common stock will improve or develop further, and as a result, the liquidity of our common stock may be reduced and you may not recover any of your investment.
We may issue additional equity securities 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 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 million shares of common stock authorized under our charter documents, of which approximately 344.6 million shares were issued and outstanding as of March 2, 2012. 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 or other equity securities, including securities convertible into shares of common stock, in connection with capital raising activities. The issuance of additional common stock would also have a dilutive impact on our stockholders’ ownership interest in our company.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
Undeveloped Acreage
In connection with the Shouyang Modification Agreement (defined below) we have agreed to relinquish 75,736 acres (306.494 km2) of the Shouyang PSC contract area. The following table summarizes the acreage subject to our PSCs in China as of December 31, 2011, as well as the net acreage that will remain available for exploration and production under the PSCs pursuant to our respective participating interest share assuming the 2011 Shouyang PSC Modification Agreement and the 2011 Yunnan PSC Modification Agreement are approved by the MofCom:
| | | Acreage | |
| | | | | | Net | |
| | | Gross (1) | | | Far East (2) | | | Chinese Partner Company | |
| China: | | | | | | | | | |
| Shouyang Block, Shanxi Province | | | 409,282 | | | | | | | |
| Area A | | | 15,978 | | | | 15,978 | | | | - | |
| All other areas | | | 393,304 | | | | 275,313 | | | | 117,991 | |
Qinnan Block, Shanxi Province (3) | | | 573,000 | | | | 401,100 - 573,000 | | | | 171,900 - 0 | |
| Laochang Area, Yunnan Province | | | 119,338 | | | | 71,603 | | | | 47,735 | |
(1) Acreage if the PSC amendments for Shouyang and Yunnan receive necessary governmental approvals.
(2) The Chinese partner company, CUCBM, has elected to participate at a 30% participating interest share in the 2011 Shouyang PSC Modification Agreement and 40% participating interest share in the 2011 Yunnan PSC Modification Agreement (defined below).
(3) Currently, the exploration period has technically expired, and we are pursuing claims that the period has been extended due to force majeure, in accordance with the terms of the PSC. Thus, no modification agreement has been signed with respect to the Qinnan PSC and the Chinese partner company has not elected any participating interest share, however, it is entitled to up to 30%.
For further discussion of our interests in these properties, see the discussion of our production sharing contracts and farmout agreements under "Our Holdings in the Shanxi Province of the People's Republic of China" and "Our Holdings in the Yunnan Province of the People's Republic of China" contained in Item 1, Business.
Reserves
As of December 31, 2011, all of our gas reserves are attributable to properties in China. A summary of our gas reserves as of December 31, 2011 is as follows:
| | | Natural Gas | | | Future Net Revenue | |
| | | | | | | | | | |
| Proved reserves | | | | | | | | | |
| Developed | | | 14,160 | | | | 13,505 | | | $ | 34.5 | |
| Undeveloped | | | 45,469 | | | | 41,094 | | | | 30.9 | |
| Total proved - December 31, 2011 | | | 59,629 | | | | 54,599 | | | | 65.4 | |
| | | | | | | | | | | | | |
| Probable reserves - December 31, 2011 | | | 514,953 | | | | 379,603 | | | | | |
| | | | | | | | | | | | | |
| Possible reserves - December 31, 2011 | | | 165,265 | | | | 114,436 | | | | | |
The gas price used is $6.35/Mcf in accordance with the gas sales agreement dated June 12, 2010 and Chinese government policy. The prices are based on the average price received and US dollar-RMB exchange rate on the first day of each month in 2011.
Preparation of Reserves Estimates
Internal Controls over Reserve Estimate. Our policies regarding internal controls over reserve estimates require reserves to be in compliance with the SEC definitions and guidance for reserves to be prepared by an independent reservoir engineer. Our reservoir engineer and geologist as well as other technical staff, plus our financial and accounting staff gathered technical information, financial data, ownership interests, production data and other information. This information is reviewed by our Chief Executive Officer and Chief Financial Officer to ensure accuracy and completeness of the data provided to the reservoir engineer.
Financial data is obtained from the Company’s accounting records, which are subject to external quarterly reviews, annual audits and their own set of internal controls over financial reporting. All current financial data such as lease operating expenses and production taxes are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, the Company's independent engineering firm, Resource Investment Strategy Consultants (“RISC”) meets with the Company's technical personnel to review field performance and future development plans. Following these reviews the reserve database and supporting data is furnished to RISC so that they can prepare their independent reserve estimates and final report. Access to the Company’s reserve database is restricted to specific members of the engineering department.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process. Our estimated proved reserve information as of December 31, 2011 included in this Annual Report on Form 10-K was prepared by our independent petroleum consultant, RISC, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The scope and results of their procedures are summarized in a letter included as an exhibit to this Annual Report on Form 10-K. RISC is a resource industry consulting firm that has provided consulting services to some of the largest energy companies in the world.
Reserve Technologies. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our independent petroleum consultant employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:
| | · | the quality and quantity of available data and the engineering and geological interpretation of that data; |
| | · | estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results; |
| | · | the accuracy of various mandated economic assumptions such as the future prices of oil and natural gas; and |
| | · | the judgment of the persons preparing the estimates. |
Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.
Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition to the physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, economic factors such as changes in commodity prices or development and production expenses, may require revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates. See Part I, Item 1A—"Risk Factors," for a description of some of the risks and uncertainties associated with our business and reserves.
All of our oil and natural gas reserves are located in China. We engaged RISC to prepare all of our gas reserve estimates and the estimated future net revenue to be derived from our properties. The independent engineers' estimates were prepared by the use of standard geological and engineering methods generally recognized by the petroleum industry. The reserve estimates represent our net revenue interest in our properties. We selected RISC in part due to the extensive experience in the region.
Other Properties
Our principal office is located at 363 N. Sam Houston Parkway East, Suite 380, Houston, Texas 77060. The principal office consists of approximately 5,770 square feet under lease at December 31, 2011. We also maintain offices under lease in the following cities of the People's Republic of China: Beijing and Taiyuan.
ITEM 3. LEGAL PROCEEDINGS
We have no knowledge of any pending or threatened material litigation, settlement of litigation, or other material claim involving us.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock
Our common stock is not listed for trading on a registered exchange. 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.
| | | High | | | Low | |
| 2011 | | | | | | |
| First Quarter | | $ | 0.78 | | | $ | 0.43 | |
| Second Quarter | | $ | 0.55 | | | $ | 0.28 | |
| Third Quarter | | $ | 0.32 | | | $ | 0.16 | |
| Fourth Quarter | | $ | 0.26 | | | $ | 0.12 | |
| | | | | | | | | |
| 2010 | | | | | | | | |
| First Quarter | | $ | 0.72 | | | $ | 0.37 | |
| Second Quarter | | $ | 0.53 | | | $ | 0.38 | |
| Third Quarter | | $ | 0.58 | | | $ | 0.29 | |
| Fourth Quarter | | $ | 0.83 | | | $ | 0.46 | |
On March 2, 2012, we had 344.6 million shares of common stock outstanding and approximately 93 stockholders of record.
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 2011 and have not adopted a stock repurchase program.
Stock Performance Graph
The following graph compares the performance of the Company's Common Stock with that of the S&P 500 Index and the Dow Jones Oil & Gas Index. The graph sets forth the cumulative total stockholder return, which assumes reinvestment of dividends, of a $100 investment on December 31, 2006 in the Company's Common Stock, the S&P 500 Index and the Dow Jones Oil & Gas Index.
| | | CUMULATIVE TOTAL RETURN SUMMARY | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | |
| | | | | | | | | | | | | | | | | | | |
| Far East Energy Corp | | | 100.00 | | | | 105.49 | | | | 19.23 | | | | 50.55 | | | | 76.92 | | | | 23.08 | |
| S&P 500 Index - Total Returns | | | 100.00 | | | | 105.50 | | | | 66.45 | | | | 84.03 | | | | 96.68 | | | | 98.72 | |
| Dow Jones US Oil & Gas Index | | | 100.00 | | | | 134.84 | | | | 86.61 | | | | 101.56 | | | | 121.57 | | | | 126.56 | |
The information included under this section entitled "Stock Performance Graph" is deemed not to be "soliciting material" or "filed" with the SEC, is not subject to the liabilities of Section 18 of the Exchange Act, and shall not be deemed incorporated by reference into any of the filings previously made or made in the future by our company under the Exchange Act or the Securities Act, except to the extent the Company specifically incorporates any such information into a document that is filed.
Issuer Withholdings and Subsequent Cancellations of Equity Securities
Column (a) in the tabulation below indicates shares which were withheld by us to satisfy tax withholding obligations that arose upon the vesting of shares of nonvested stock (also commonly referred to as restricted stock) during 2010. Once withheld, these shares were cancelled and removed from the number of outstanding shares. Currently, the Company does not have a share repurchase plan.
| Period | | (a) Total Number of Shares Purchased | | | (b) Average Price Paid Per Share | | | (c) Total Number of Shares Purchased as Part of Publicly Announced Plan or Programs | | | (d) Maximum Number of Shares that May Yet Be Purchased Under The Plans or Programs | |
| January 2011 | | | 7,662 | | | $ | 0.67 | | | | - | | | | - | |
| February 2011 | | | 26,597 | | | | 0.69 | | | | - | | | | - | |
| April 2011 | | | 14,973 | | | | 0.30 | | | | - | | | | - | |
| Total | | | 49,232 | | | $ | 0.57 | | | | - | | | | - | |
ITEM 6. SELECTED FINANCIAL DATA (In Thousands, Except Per Share Data)
| | | As of and for the Years Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
| Operating Results Data | | | | | | | | | | | | | | | |
| Operating revenues: | | | | | | | | | | | | | | | |
| Sales of gas | | $ | 653 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Other, net | | | 205 | | | | - | | | | - | | | | - | | | | - | |
| Total operating revenue | | | 858 | | | | - | | | | - | | | | - | | | | - | |
| Operating expenses: | | | | | | | | | | | | | | | | | | | | |
Exploration costs (1) | | | 5,967 | | | | 5,117 | | | | 4,501 | | | | 15,283 | | | | 3,345 | |
| Leasehold operating expense | | | 3,873 | | | | 2,314 | | | | 1,864 | | | | 2,900 | | | | 1,945 | |
| General and administrative | | | 9,701 | | | | 7,076 | | | | 6,327 | | | | 4,348 | | | | 7,167 | |
| Depreciation, depletion and amortization | | | 1,045 | | | | 224 | | | | 182 | | | | 171 | | | | 63 | |
| Total operating expenses | | | 20,586 | | | | 14,731 | | | | 12,874 | | | | 22,702 | | | | 12,520 | |
| Operating loss | | | (19,728 | ) | | | (14,731 | ) | | | (12,874 | ) | | | (22,702 | ) | | | (12,520 | ) |
| Other income (expense): | | | | | | | | | | | | | | | | | | | | |
| Interest expense | | | (678 | ) | | | (1,135 | ) | | �� | (863 | ) | | | - | | | | - | |
| Interest income | | | 6 | | | | 5 | | | | 5 | | | | 260 | | | | 721 | |
| Gain on sale of assets | | | (1 | ) | | | (1 | ) | | | (5 | ) | | | - | | | | - | |
| Foreign currency exchange loss | | | (844 | ) | | | (311 | ) | | | (18 | ) | | | (149 | ) | | | (50 | ) |
| Total other income (expense) | | | (1,517 | ) | | | (1,442 | ) | | | (881 | ) | | | 111 | | | | 671 | |
| Loss before income taxes | | | (21,245 | ) | | | (16,173 | ) | | | (13,755 | ) | | | (22,591 | ) | | | (11,849 | ) |
| Income taxes | | | - | | | | - | | | | - | | | | - | | | | - | |
| Net loss | | $ | (21,245 | ) | | $ | (16,173 | ) | | $ | (13,755 | ) | | $ | (22,591 | ) | | $ | (11,849 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Earnings per share: Basic and diluted | | $ | (0.06 | ) | | $ | (0.07 | ) | | $ | (0.08 | ) | | $ | (0.15 | ) | | $ | (0.09 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Financial Position Data | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 95,813 | | | $ | 79,256 | | | $ | 42,404 | | | $ | 39,883 | | | $ | 49,793 | |
| Total liabilities | | | 43,571 | | | | 30,134 | | | | 14,734 | | | | 4,572 | | | | 3,298 | |
| Stockholders' equity | | | 52,242 | | | | 49,122 | | | | 27,670 | | | | 35,311 | | | | 46,495 | |
| | (1) | For additional information on our Exploration costs, see Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies" and Note 6 to the consolidated financial statements. |
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 and all of the other information contained elsewhere in this report. The terms "we," "us," "our" and "our company" refer to Far East Energy Corporation and its consolidated subsidiaries.
Overview. Prior to December 31, 2011, we were classified as a development stage company and our activities were principally limited to the drilling, testing and completion of exploratory and pilot development CBM wells and organizational activities. As of December 31, 2011, the Company received its first independent, third party reserve report providing a calculation of the Company’s proved, probable and possible reserves and thus emerged from development stage status as a result of the amount of proved reserves estimated in the reserve report and have started generating revenues. Our activities have been principally limited to the drilling, testing, and completion of exploratory and pilot development coalbed methane ("CBM") wells. We believe that good environmental, social, health and safety performance is an integral part of our business success. We conduct our business with respect and care for our employees, contractors, communities, and the environments in which we operate. Our vision is zero harm to people and the environment while creating value for our shareholders as well as for China, including the regions and communities within which we operate. Our commitment to these principles is demonstrated by the fact that we have had no lost-time accidents in over six years and no major environmental incidents. We have a commitment to being good corporate citizens of China, striving to emphasize and utilize very high levels of Chinese content in personnel, services, and equipment; and we have achieved very high percentages of Chinese content in each category.
During 2011, we continued our efforts to explore and develop CBM in Shanxi Province in northern People's Republic of China ("PRC" or "China") and in Yunnan Province in southern PRC. We continued to employ numerous safety precautions to ensure the safety of our employees and independent contractors. We also conducted our operations in accordance with various laws and regulations concerning the environment, occupational safety and health.
In early January 2011, the in-field gathering system and compression equipment in the Shouyang PSC area were connected to the pipeline constructed last year by Shanxi Province Guoxin Energy Development Group Limited ("SPG") in accordance with the Gas Sales Agreement (defined below). After completion of that process, low level gas flow commenced in January with initial testing of the gathering system in January. After initial commissioning, gas sales were temporarily interrupted while SPG completed testing and commissioning of certain equipment related to our first stage compressor sites as well as installation of gas sales meters. That work was completed and formal gas flow and sales re-commenced in mid-March 2011. Second stage compressor equipment is on site and will be available for use as needed when production volumes increase. The gross gas production for 2011 was approximately 268 million cubic feet. Gross sales volumes were 158 million cubic feet for 2011. We believe that the sales rate will continue to increase as gas from additional wells is sold through the gathering system in the coming months. For additional information regarding the Shouyang PSC, see "Shouyang PSC" below.
In February 2011, Dart Energy (CBM) International Pte Ltd (formerly Arrow Energy International Pte Ltd) ("Dart Energy") exercised its right to exchange a total of $6.8 million in principal amount under the Exchangeable Note for 14,315,789 shares of the Company's common stock, par value $0.001 per share ("Common Stock") in the aggregate through a series of transactions. On September 15, 2011, the Company paid in full the remaining $3,200,000 principal balance on the Exchangeable Note plus the $1,226,577 in accrued interest, and the Company elected to terminate the Farmout Agreement on November 11, 2011.
On March 16, 2011, we completed a transaction for the sale of 34.9 million shares of our common stock at $0.5025 per share for net proceeds of $16.7 million under our shelf registration statement. The amount remaining available under the registration statement at November 4, 2011 was approximately $9.0 million.
On November 28, 2011, FEEB entered into a Facility Agreement, as borrower, with Standard Chartered Bank (“SCB”), as lender, and the Company, as guarantor (the “Facility Agreement”). The Facility Agreement provides for a $25 million credit facility to be used for project costs with respect to the Shouyang Block, finance costs and other general corporate purposes approved by SCB.
Management may seek to secure capital by exploring potential strategic relationships or transactions involving one or more of our PSCs, such as a joint venture, farmout, merger, acquisition or sale of some or all of our assets, by obtaining additional debt, project or equity-related financing. However, there can be no assurance that we will be successful in entering into any strategic relationship or transaction, securing capital or raising funds through additional debt, project or equity-related financing. In addition, the terms and conditions of any potential strategic relationship or transaction or of any project or debt financing are uncertain, and we cannot predict the timing, structure or other terms and conditions or the consideration that may be paid with respect to any transaction or offering of securities and whether the consideration will meet or exceed our offering price. Under certain circumstances, the structure of a strategic transaction may require the approval of the Chinese authorities, which could delay closing or make the consummation of a transaction more difficult. In particular, any transfer of our rights to an unaffiliated third party under the PSCs will require the approval of our Chinese partner company and the Ministry of Commerce of the People's Republic of China (the “MofCom”). There can be no assurance that the Chinese authorities will provide the approvals necessary for the consummation of a transaction or transfer. There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our unproved oil and gas properties. Based on our planned work programs, which include an accelerated pace of drilling in 2012, (subsequent to September 30, 2011, we slowed the pace of drilling down while negotiating the 2011 Shouyang PSC Modification Agreement) if we do not secure additional capital, whether through additional debt, project or equity-related financing, or enter into an agreement with a strategic partner, we believe that the funds currently available to us should provide sufficient cash to fund our planned expenditures under the Shouyang PSC and other minimum operating costs through the end of July 2012 or if necessary such funds could provide sufficient cash to last through the end of 2012 if the pace of drilling is revised and other steps are taken to preserve cash.
The global financial crisis, despite having abated to a certain extent, has created liquidity problems for many companies and financial institutions and international capital markets have stagnated, especially in the United States and Europe. A continuing downturn in these markets could impair our ability to obtain, or may increase our costs associated with obtaining, additional funds through financing, the sale of our securities or otherwise. The ongoing crisis has created a difficult environment in which to negotiate and consummate a transaction or otherwise. While we will continue to seek to secure additional capital, there can be no assurance that we will be able to enter any strategic relationship or transaction or that we will be successful in raising funds through debt, project, or equity- related financing.
There can be no guarantee of future capital acquisition, fundraising, joint venture relationships, or exploration success or that we will realize the value of our unproved oil and gas properties. However, in addition to revenue generation from the sale of CBM gas, management believes that we will continue to be successful in securing additional capital necessary to allow us to continue as a going concern.
We are a party to three production sharing contracts ("PSCs") as revised which cover the 409,282 acre (1656.3 km2) Shouyang Block in Shanxi Province (the "Shouyang PSC"), the 573,000 acre Qinnan Block also in Shanxi Province (the "Qinnan PSC"), and the Laochang area, which totals 119,338 acres (482.943 km2), in Yunnan Province (the "Yunnan PSC"). We believe our total net acreage in these PSCs makes us one of the biggest holders of CBM acreage in China. For further discussion of our interests in these properties and drilling activities, see the discussion of our production sharing contracts under "Our Holdings in the Shanxi Province of the People's Republic of China" and "Our Holdings in the Yunnan Province of the People's Republic of China" contained in Item 1, Business.
Results of Operations
Year Ended 2011 compared to Year Ended 2010
The table below sets out major components of our expenditures (in thousands):
| | | 2011 | | | 2010 | |
| Additions to Oil and Gas Properties (capitalized) | | | | | | |
- Shouyang Block, Shanxi Province (1) | | $ | 18,166 | | | $ | 15,673 | |
| Exploration Expenditures (expensed) | | | | | | | | |
| - Shouyang Block, Shanxi Province | | | 4,004 | | | | 2,443 | |
| - Qinnan Block, Shanxi Province | | | 491 | | | | 559 | |
| - Yunnan Province | | | 1,472 | | | | 2,115 | |
| - Total | | | 5,967 | | | | 5,117 | |
| Lease Operating Expenditures (expensed) | | | | | | | | |
| - Shouyang Block, Shanxi Province | | | 3,873 | | | | 2,239 | |
| - Qinnan Block, Shanxi Province | | | - | | | | 75 | |
| - Total | | | 3,873 | | | | 2,314 | |
| | | | | | | | | |
| Total Exploration and Operating Expenditures | | $ | 28,006 | | | $ | 23,104 | |
| | | | | | | | | |
| General and Administrative Expenses | | $ | 9,701 | | | $ | 7,076 | |
| (1) | Capitalized in the Consolidated Balance Sheets. |
The table below sets out the operating expenses in the Consolidated Statements of Operations (in thousands):
| | | 2011 | | | 2010 | | | | | | | |
| Exploration costs | | $ | 5,967 | | | $ | 5,117 | | | $ | 850 | | | | 17 | % |
| Lease operating expense | | | 3,873 | | | | 2,314 | | | | 1,559 | | | | 67 | % |
| General and administrative | | | 9,701 | | | | 7,076 | | | | 2,625 | | | | 37 | % |
| Depreciation, depletion and amortization | | | 1,045 | | | | 224 | | | | 821 | | | | 367 | % |
| Total | | $ | 20,586 | | | $ | 14,731 | | | $ | 5,855 | | | | 40 | % |
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. For further discussion of our accounting policies, see "Critical Accounting Policies—Accounting for Oil and Gas Properties" below.
The table below sets out components of exploration costs for the years ended December 31, 2011 and December 31, 2010 (in thousands):
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | |
| Technical personnel compensation | | $ | 621 | | | $ | 557 | |
| PSC related payments | | | 961 | | | | 931 | |
| Contract drilling & related expenses | | | 4,385 | | | | 3,629 | |
| Total | | $ | 5,967 | | | $ | 5,117 | |
Exploration costs for the year ended December 31, 2011 increased $0.9 million due primarily to an increase in contract drilling and related expenses including engineering design, drill stem testing and seismic work
The table below sets out components of lease operating expense ("LOE") for the years ended December 31, 2011 and December 31, 2010 (in thousands):
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | |
| Pumping Related Costs | | $ | 3,252 | | | $ | 1,770 | |
| Workovers | | | 386 | | | | 382 | |
| Supervision | | | 235 | | | | 162 | |
| Total | | $ | 3,873 | | | $ | 2,314 | |
LOE for 2011 was comprised of costs pertaining to the production and dewatering efforts in the Shouyang and Qinnan Blocks in Shanxi Province. LOE for the year ended December 31, 2011 increased primarily due to an increase in production costs, including an increase in the number of wells, and the addition of compression costs for gas delivery.
General and administrative ("G&A") expenses for the year ended December 31, 2011 increased $2.6 million primarily due to increases in legal of $1.0 million, other professional services of $0.6 million, payroll of $0.5 million, in investor relations of $0.2 million, share based compensation of $0.1 million, and in travel of $0.1 million.
Year Ended 2010 compared to Year Ended 2009
The table below sets out major components of our expenditures (in thousands):
| | | 2010 | | | 2009 | |
| Additions to Oil and Gas Properties (capitalized) | | | | | | |
- Shouyang Block, Shanxi Province (1) | | $ | 15,673 | | | $ | 3,584 | |
| Exploration Expenditures (expensed) | | | | | | | | |
| - Shouyang Block, Shanxi Province | | | 2,443 | | | | 2,091 | |
| - Qinnan Block, Shanxi Province | | | 559 | | | | 1,558 | |
| - Yunnan Province | | | 2,115 | | | | 852 | |
| - Total | | | 5,117 | | | | 4,501 | |
| Lease Operating Expenditures (expensed) | | | | | | | | |
| - Shouyang Block, Shanxi Province | | | 2,239 | | | | 1,689 | |
| - Qinnan Block, Shanxi Province | | | 75 | | | | 175 | |
| - Total | | | 2,314 | | | | 1,864 | |
| | | | | | | | | |
| Total Exploration and Operating Expenditures | | $ | 23,104 | | | $ | 9,949 | |
| | | | | | | | | |
| General and Administrative Expenses | | $ | 7,076 | | | $ | 6,327 | |
| (1) | Capitalized in the Consolidated Balance Sheets. |
The costs of drilling exploratory wells are capitalized on the Consolidated Balance Sheets as additions to Unproved Oil and Gas Properties pending determination of whether they have discovered proved commercial reserves. If it is determined that no proved commercial reserves are discovered, the related capitalized unproved property costs will be expensed on the Consolidated Statements of Operations. Other exploration and lease operating expenditures are charged to expense as incurred.
The table below sets out the operating expenses in the Consolidated Statements of Operations (in thousands):
| | | | | | | | | Increase | | | % | |
| | | 2010 | | | 2009 | | | (Decrease) | | | Change | |
| Exploration costs | | $ | 5,117 | | | $ | 4,501 | | | $ | 616 | | | | 14 | % |
| Lease operating expense | | | 2,314 | | | | 1,864 | | | | 450 | | | | 24 | % |
| General and administrative | | | 7,076 | | | | 6,327 | | | | 749 | | | | 12 | % |
| Depreciation, depletion and amortization | | | 224 | | | | 182 | | | | 42 | | | | 23 | % |
| Total | | $ | 14,731 | | | $ | 12,874 | | | $ | 1,857 | | | | 14 | % |
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. For further discussion of our accounting policies, see "Critical Accounting Policies—Accounting for Oil and Gas Properties" below.
The table below sets out components of exploration costs for the years ended December 31, 2010 and December 31, 2009 (in thousands):
| | | Year ended December 31, | |
| | | 2010 | | | 2009 | |
| Technical personnel compensation | | $ | 557 | | | $ | 698 | |
| PSC related payments | | | 931 | | | | 1,218 | |
| Contract drilling & related expenses | | | 3,629 | | | | 2,585 | |
| Total | | $ | 5,117 | | | $ | 4,501 | |
Exploration costs for the year ended December 31, 2010 increased $0.6 million due primarily to an increase in reserves analysis of $0.3 million and higher contract drilling and related expenses related to the Yunnan PSC of $0.2 million.
The table below sets out components of lease operating expense ("LOE") for the years ended December 31, 2010 and December 31, 2009 (in thousands):
| | | Year ended December 31, | |
| | | 2010 | | | 2009 | |
| Pumping Related Costs | | $ | 1,770 | | | $ | 1,351 | |
| Workovers | | | 382 | | | | 292 | |
| Supervision | | | 162 | | | | 221 | |
| Total | | $ | 2,314 | | | $ | 1,864 | |
LOE for 2010 was comprised of costs pertaining to the production and dewatering efforts in the Shouyang and Qinnan Blocks in Shanxi Province. LOE for the year ended December 31, 2010 increased primarily due to an increase in pumping related costs, including an increase in the number of wells, and in accretion costs on asset retirement obligations.
General and administrative ("G&A") expenses for the year ended December 31, 2010 increased $0.7 million primarily due to increases in payroll of $0.6 million, in investor relations of $0.3 million, in gas marketing of $0.2 million, and in travel of $0.2 million. These increases were partially offset by decreases in share-based compensation of $0.4 million and in professional services of $0.2 million.
Financial Condition, Capital Resources and Liquidity
Although gas sales under the Gas Sales Agreement commenced in the first quarter of 2011, our primary source of cash flow has been cash proceeds from public offerings and private placements of our common stock and warrants to purchase our common stock, proceeds received from the closing of the Facility Agreement (defined below) and the exercise of warrants and options to purchase our common stock.
On March 16, 2011, we completed a registered direct offering of 34.9 million shares of our common stock at $0.5025 per share for net proceeds of $16.7 million under our shelf registration statement. The amount remaining available for future offerings under the registration statement at December 31, 2011 was approximately $9.0 million.
On November 28, 2011, FEEB entered into a Facility Agreement with Standard Chartered Bank (“SCB”), as lender, and the Company, as guarantor (the “Facility Agreement”), which provides for a $25 million credit facility to be used for project costs with respect to the Shouyang Block, finance costs and other general corporate purposes approved by SCB. The Facility Agreement has an initial nine month term ending August 28, 2012, which may be extended by three months upon satisfaction of certain other conditions. The Company made an initial draw of $17.9 million in anticipation of first half 2012 operations and to pay finance costs and related expenses. Additional draws may be made under the Facility Agreement in amounts specified from time to time. Pursuant to the terms of the Facility Agreement, in the event we fail to receive approval from the MofCom of the 2011 Shouyang PSC Modification Agreement, we may not be able to draw down the full amount of available funds otherwise available under the Facility Agreement. The failure to receive such notice on or before May 31, 2012 will constitute an event
of default under the Facility Agreement. Upon notice of an event of default under the Facility Agreement, SCB would have the right to accelerate all amounts outstanding under the Facility Agreement.
Our board of directors has the authority, without further action by the stockholders, to issue up to 500 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 million shares of Common Stock authorized under our charter documents, of which approximately 342.1 million shares were issued and outstanding as of December 31, 2011. In September 2009, we filed with the SEC a shelf registration statement on Form S-3 for the offer and sale from time to time up to $75 million of our debt and equity securities, which became effective on November 4, 2009. The amount available under the registration statement at March 2, 2012 was approximately $9.0 million.
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 capital raising activities. The issuance of additional common stock would also have a dilutive impact on our stockholders' ownership interest in our company.
Work Program Funding. Our current work programs satisfied the minimum exploration expenditures for our Shouyang and Yunnan PSCs for 2011. With respect to the Qinnan PSC, we have halted activities on the Qinnan Block pending regulatory approval or denial. Management may seek to secure capital by exploring potential strategic relationships or transactions involving one or more of our PSCs, such as a joint venture, farmout, merger, acquisition or sale of some or all of our assets, by obtaining debt, project or equity-related financing. However, there can be no assurance that we will be successful in entering into any strategic relationship or transaction, securing capital or raising funds through debt, project or equity- related financing. In addition, the terms and conditions of any potential strategic relationship or transaction or of any debt, project or equity-related financing are uncertain and we cannot predict the timing, structure or other terms and conditions or the consideration that may be paid with respect to any transaction or offering of securities and whether the consideration will meet or exceed our offering price. Under certain circumstances, the structure of a strategic transaction may require the approval of the Chinese authorities, which could delay closing or make the consummation of a transaction more difficult. In particular, any transfer of our rights under the PSCs will require the approval of our Chinese partner company and the MofCom. There can be no assurance that the Chinese authorities will provide the approvals necessary for the consummation of a transaction or transfer. There can be no guarantee of future success in capital acquisition, fundraising or exploration success or that we will realize the value of our unproved oil and gas properties. Based on our planned work programs, which includes an accelerated pace of drilling in 2012, (subsequent to September 30, 2011, we slowed the pace of drilling down while negotiating the 2011 Shouyang PSC Modification Agreement) if we do not secure additional capital, or enter into an agreement with a strategic partner, we believe that the funds currently available to us should provide sufficient cash to fund our planned expenditures under the Shouyang PSC and other minimum operating costs through the end of July 2012 or if necessary such funds could provide sufficient cash to last through the end of 2012 if the pace of drilling is revised and other steps are taken to preserve cash. Our ability to continue as a going concern depends upon our ability to obtain substantial funds for use in our development activities and upon the success of our planned exploration and development activities. There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our unproved oil and gas properties. However, in addition to revenue generation from the sale of CBM gas, management believes that we will continue to be successful in securing additional capital necessary to allow us to continue as a going concern.
In February 2011, Dart Energy exercised its right to exchange a total of $6.8 million in principal amount under the Exchangeable Note for 14,315,789 shares of the Common Stock in the aggregate through a series of transactions. On September 15, 2011, the Company paid in full the remaining $3,200,000 principal balance on the Exchangeable Note plus the $1,226,577 in accrued interest, and the Company elected to terminate the Farmout Agreement on November 11, 2011.
Our capital resources and planning can be impacted by fluctuations in the U.S. Dollar and Chinese RMB exchange rate as well as inflation in these countries. For further discussion of these risks, see Item 7A. "Quantitative and Qualitative Disclosures About Market Risk."
Cash flow
As of December 31, 2011, 2010 and 2009, cash and cash equivalents were $23.3 million, $27.8 million, and $5.6 million, respectively. The decrease of $4.5 million in cash and cash equivalents from beginning to end of the fiscal year 2011 was primarily due to $16.4 million cash used by operating activities and $17.9 million cash used by investing activities offset by $29.8 million cash provided by financing activities. During the first nine months of 2010, we used approximately $0.7 million of the restricted cash we received from Dart Energy in connection with the Farmout Agreement for exploration expenditures related to the Qinnan Block. As of December 31, 2010, the restricted cash has been fully utilized for exploration expenditures related to the Qinnan PSC.
Cash used in operating activities for 2011 was $16.4 million as compared to $9.8 million for 2010 and $12.8 million for 2009. Prior to 2011, we generated no revenue. The $6.6 million increase in cash used in operating activities in 2011 compared to 2010 was primarily due to a $2.6 million increase in G&A expenses, $1.6 million increase in LOE pumping related costs, $0.9 million increase in exploratory contract drilling expenses and an increase in working capital used. The decrease in cash used in operating activities in 2010 of $3.0 million compared to 2009 was due primarily to a reclassification of $2 million in the first quarter of 2009 as restricted cash in accordance with the Farmout Agreement and favorable change in working capital of $1.6 million. The decrease in cash used in operating activities in 2009 of $0.6 million as compared to 2008 was due primarily to decreased exploratory contract drilling and related expenses of $3.0 million, decreased in LOE workover costs of $1.0 million, partially offset by an unfavorable change in working capital of $2.6 million, an increase in cash G&A of $0.4 million and an increase in PSC related payments of $0.2 million.
Cash used in investing activities for 2011 was $17.9 million, as compared to $5.0 million for 2010, and $3.4 million for 2009. The $12.8 increase in 2011 was primarily due to an increase in additions to oil and gas properties of $12.4 million. The increase in 2010 was primarily due to an increase in additions to oil and gas properties of $1.5 million. In 2009, the decrease of $4.1 million was primarily due to a decrease in additions to unproved oil and gas properties of $3.9 million.
Cash provided by financing activities for 2011 was $29.8 million, as compared to $37.0 million for 2010, and $13.9 million for 2009. Cash provided by financing activities was due to $16.7 million from the sale of 34.9 million shares of common stock in March 2011 and $17.9 million gross proceeds from a draw on the Credit Facility in December 2011. Cash provided by financing activities for 2010 of $37.0 million was primarily due to the sale of 11.7 million shares of our Common Stock in March and the sale of 105.5 million shares of our Common Stock in August. Cash provided by financing activities for 2009 of $13.9 million was a result of the $10 million in proceeds from the issuance of the Exchangeable Note in the first quarter of 2009 and the sale of 11.6 million shares of our Common Stock and warrants to purchase up to 4.6 million shares of our Common Stock in the fourth quarter of 2009 for $4.4 million. The increase was partially offset by the total financing costs of $0.5 million.
Contractual Obligations
Obligations under non-cancelable agreements at December 31, 2011 were as follows (in thousands):
| | | | | | Payments Due by Period | |
| | | | | | | | | | | | | | | 2017 and | |
| | | Total | | | 2012 | | | | 2013-2014 | | | | 2015-2016 | | | Beyond | |
| Debt Obligations | | $ | 19,440 | (1) | | $ | 19,440 | | | $ | - | | | $ | - | | | $ | - | |
| Capital Lease Obligations | | | - | | | | - | | | | - | | | | - | | | | - | |
Operating Lease Obligations (2) | | | 67 | | | | 67 | | | | - | | | | - | | | | - | |
Purchase Obligations (3) | | | 14,245 | | | | 7,290 | | | | 5,641 | | | | 1,314 | | | | - | |
Other Long-Term Liabilities Reflected on the Registrant's Balance Sheet Under GAAP (4) | | | 739 | | | | - | | | | - | | | | - | | | | 739 | |
| Totals | | $ | 34,491 | | | $ | 26,797 | | | $ | 5,641 | | | $ | 1,314 | | | $ | 739 | |
(1) On November 28, 2011, the Company entered into a $25 million credit facility agreement ("Agreement") to be used for project costs with respect to the Shouyang Area in Shanxi Province, China as well as for general corporate purposes. The Agreement has an initial nine month term ending August 28, 2012, which may be extended by three months upon satisfaction of certain other conditions. The Company made an initial draw of $17.9 million in anticipation of first half 2012 operations and to pay finance costs and related expenses. Additional draws may be made under the Agreement in amounts specified from time to time.
(2) We enter into operating leases in the normal course of business primarily for our office space and equipment.
(3) We include in purchase obligations contractual agreements to purchase goods or services that are legally enforceable and that specify all significant terms, including fixed or minimum quantities, fixed, minimum or variable price provisions and the approximate timing of the transaction. We have included our obligations under the PSCs for the Yunnan Province and the Shanxi Province projects (assuming approval for the Qinnan PSC exploration phase is granted by the Chinese government) for which the amounts were specified in the contracts. We have elected to enter into Phase II for the Yunnan Province project and Phase III for the Shanxi Province projects and have included contractual expenses through completion of these phases, which are currently required to be completed by June 30, 2011.
(4) Amount represents our asset retirement and environmental obligations.
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, 2011, we were not involved in any form of off-balance sheet arrangement.
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. 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 the Audit Committee of our Board of Directors, and the Audit Committee has reviewed the disclosures 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. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Under Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 932, Extractive Activities – Oil and Gas ("ASC 932"), such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. 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 gain or loss on the sale of properties on a field basis.
Unproved leasehold costs are capitalized and reviewed periodically for impairment on a field-by-field basis, considering factors such as drilling and exploitation plans and lease terms. 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. Costs related to impaired prospects are charged to expense. An impairment expense could result if oil and gas prices decline in the future or if downward reserves revisions are recorded, as it may not be economic to develop some of these unproved properties. We also evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, foreign currency exchange rates, political stability in the countries in which the Company has an investment, and available geological and geophysical information. Any impairment assessed is charged to expense.
Oil and Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion, impairment of our oil and natural gas properties, asset retirement obligations, and our long-term Production Participation Plan liability. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:
| | ● | the quality and quantity of available data; |
| | ● | the interpretation of that data; |
| | ● | the accuracy of various mandated economic assumptions; and |
| | ● | the judgments of the persons preparing the estimates. |
Our independent resource industry consulting firm independently estimated all of the proved, probable and possible reserve quantities included in this annual report. In connection with our external petroleum engineers performing their independent reserve estimations, we furnished them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data, and (4) our well ownership interests. The resource industry consulting firm, Resource Investment Strategy Consultants ("RISC"), evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2011. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates, impairment calculations, asset retirement obligations and our Production Participation Plan liability in the same period that changes to reserve estimates are made.
Share-based compensation. We measure the compensation expense for stock options granted as compensation to our employees based on the grant date fair value of the awarded options under FASB ASC Topic 718, Compensation – Stock Compensation ("ASC 718"). We determine the fair value of stock option grants using the Black-Scholes option pricing model. We determine the fair value of shares of nonvested stock based on the last quoted price of our stock on the OTC Bulletin Board on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, we have reduced the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, as defined in ASC 718, if any, are recognized as an addition to paid-in capital.
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 economical to develop some of these unproved properties. As of December 31, 2011, we had total unproved oil and gas property costs of approximately $1.9 million, consisting of undeveloped leasehold costs of $0.3 million in China and unproved oil and gas property costs of $1.6 million incurred in China.
Estimates of future dismantlement, restoration, and abandonment costs. The accounting for future development and abandonment costs is determined by FASB ASC Topic 410, Asset Retirement and Environmental Obligations 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. Based on our experience and technical and financial data collected from managing our projects over the years, we were able to record the costs related to our asset retirement and environmental obligations in our financial statements beginning the fourth quarter of 2009. 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, estimates as to the proper discount rate to use and timing of abandonment.
We have drilled a number of horizontal wells and vertical wells in the Shanxi Province and Yunnan Province. 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. Periodically, we assess the functional currencies of our Chinese subsidiaries to ensure that the appropriate currencies are utilized in accordance with the guidance in FASB ASC Topic 830, Foreign Currency Matters. We determine whether the U.S. or the Chinese currency is the appropriate functional currency based on an assessment of the economic and financing environments in which the Chinese subsidiary is situated. The assessment includes, among other factors, in what currencies the financing and operating expenditures are denominated and whether the subsidiary's operations are sufficient to service additional financings. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In addition to the U.S. Dollar, we conduct our business in Chinese RMB and, therefore, are subject to foreign currency exchange risk on cash flows related to expenses and investing transactions. Prior to July 2005, the exchange rate between U.S. Dollars and Chinese RMB was fixed, and, consequently, we experienced no fluctuations in the value of goods and services we purchased in China because of currency exchange. In July 2005, the Chinese government began to permit the Chinese RMB to float against the U.S. Dollar, but again adopted an informal peg to the U.S. Dollar in 2008 in response to the global financial crisis. In June 2010, China announced that it would gradually allow the Chinese RMB to float against the U.S. Dollar and, as a result, the Chinese currency is expected to slowly appreciate with respect to the U.S. Dollar. All of our costs to operate our Chinese offices are paid in Chinese RMB. Our exploration costs in China may be incurred under contracts denominated in Chinese RMB or U.S. Dollars. As of January 1, 2012 the U.S. Dollar ($) to Chinese RMB (¥) appreciated slightly at an exchange rate of about $1 to ¥6.33, compared to an exchange rate of $1 to ¥6.59 at January 1, 2011. If the Chinese RMB appreciates with respect to the U.S. Dollar, our costs in China may increase. To date we have not engaged in hedging activities to hedge our foreign currency exposure. In the future, we may enter into hedging instruments to manage our foreign currency exchange risk or continue to be subject to exchange rate risk. If the
exchange rate increased by 10%, it is estimated that our costs would be approximately $1.9 million lower in 2011. If the exchange rate were 10% lower during 2011, our costs would increase by approximately $2.3 million.
Although inflation has not materially impacted our operations in the recent past, increased inflation in China or the U.S. could have a negative impact on our operating and general and administrative expenses, as these costs could increase. In the last couple of years, we have increased our use of Chinese suppliers, including drilling contractors, that are paid in RMB. Since 2008, China experienced inflationary pressures, which increased our costs associated with our operations in China. In the future, inflation in China may result in higher minimum expenditure requirements under our PSCs if our Chinese partner companies adjust these requirements for inflation. The actual inflationary impact on the Company may also be exacerbated by the increasing demand for goods and services in the oil and gas industry. A material increase in these costs could adversely affect our operations and, if there are material changes in our costs, we may seek to secure additional capital earlier than anticipated.
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, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of our internal control over financial reporting as of December 31, 2011. 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, 2011, our internal control over financial reporting is effective based on these criteria.
Our independent registered public accounting firm, JonesBaggett LLP, that audited our consolidated financial statements included in this report, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2011, which is included on page 53 of this Annual Report on Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Far East Energy Corporation and Subsidiaries:
We have audited the accompanying consolidated balance sheets of Far East Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2011 and 2010 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed at Item 15(a)(2). These consolidated financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated 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 at December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related 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.
As discussed in Note 10 to the financial statements, during 2011 the Company executed an extension of its Shouyang Production Sharing Contract Modification Agreement. The extension has not yet been approved by the Ministry of Commerce of the People’s Republic of China. It is not possible at this time to predict when the Company will receive such approval.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Far East Energy Corporation and Subsidiaries’ internal control over financial reporting as of December 31, 2011, 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 March 13, 2012, expressed an unqualified opinion thereon.
| /s/ Jones Baggett LLP | |
| | |
| Dallas, Texas | |
| March 13, 2012 | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Far East Energy Corporation and Subsidiaries:
We have audited Far East Energy Corporation and Subsidiaries' (the “Company”) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Far East Energy Corporation’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 included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the effectiveness of the Company’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 of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, 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, Far East Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the 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 and Subsidiaries, as of December 31, 2011 and 2010 and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2011, and our report dated March 13, 2012 expressed an unqualified opinion thereon.
/s/ Jones Baggett LLP | |
| | |
| Dallas, Texas | |
March 13, 2012 | |
FAR EAST ENERGY CORPORATION
Consolidated Balance Sheets
(In Thousands, Except Shares)
| | | At December 31, | |
| | | 2011 | | | 2010 | |
| | | | | | | |
| | | | | | | |
| ASSETS | |
| Current assets | | | | | | |
| Cash and cash equivalents | | $ | 23,263 | | | $ | 27,760 | |
| Accounts receivable | | | 689 | | | | - | |
| Inventory | | | 541 | | | | 304 | |
| Prepaid expenses | | | 373 | | | | 304 | |
| Deposits | | | 543 | | | | 101 | |
| Other current assets | | | 19 | | | | 25 | |
| Total current assets | | | 25,428 | | | | 28,494 | |
| | | | | | | | | |
| Property and equipment | | | | | | | | |
| Oil and gas properties, successful efforts method: | | | | | | | | |
| Proved properties | | | 66,361 | | | | - | |
| Unproved properties | | | 1,899 | | | | 50,094 | |
| Other property and equipment | | | 2,071 | | | | 1,314 | |
| Total property and equipment | | | 70,331 | | | | 51,408 | |
| Less accumulated depreciation, depletion and amortization | | | (1,602 | ) | | | (677 | ) |
| Total property and equipment, net | | | 68,729 | | | | 50,731 | |
| | | | | | | | | |
| Deferred financing costs | | | 1,440 | | | | 31 | |
| Other long-term assets | | | 216 | | | | - | |
| Total assets | | $ | 95,813 | | | $ | 79,256 | |
| | | | | | | | | |
| | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | |
| | | | | | | | | |
| Current liabilities | | | | | | | | |
| Accounts payable | | $ | 11,400 | | | $ | 10,613 | |
| Accrued liabilities | | | 13,562 | | | | 9,072 | |
| Short-term debt | | | 17,870 | | | | | |
| Exchangeable note payable | | | - | | | | 9,958 | |
| Total current liabilities | | | 42,832 | | | | 29,643 | |
| | | | | | | | | |
| Asset retirement and environmental obligations | | | 739 | | | | 491 | |
| | | | | | | | | |
| Commitments and contingencies (Note 10) | | | | | | | | |
| | | | | | | | | |
| Stockholders' equity | | | | | | | | |
| Preferred stock, $0.001 par value, 500,000,000 shares authorized, none outstanding | | | - | | | | - | |
| Common stock, $0.001 par value, 500,000,000 shares authorized, 342,103,218 and 291,202,928 issued and outstanding at December 31, 2011 and 2010, respectively | | | 342 | | | | 291 | |
| Additional paid-in capital | | | 174,317 | | | | 149,378 | |
| Unearned compensation | | | (792 | ) | | | (167 | ) |
| Accumulated deficit | | | (121,625 | ) | | | (100,380 | ) |
| Total stockholders' equity | | | 52,242 | | | | 49,122 | |
| Total liabilities and stockholders' equity | | $ | 95,813 | | | $ | 79,256 | |
See the accompanying notes to consolidated financial statements.
FAR EAST ENERGY CORPORATION
Consolidated Statements of Operations
(In Thousands, Except Per Share Data)
| | | Year ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| Operating revenues: | | | | | | | | | |
| Gas sales | | $ | 653 | | | $ | - | | | $ | - | |
| Other, net | | | 205 | | | | - | | | | - | |
| | | | 858 | | | | - | | | | - | |
| Operating expenses: | | | | | | | | | | | | |
| Exploration costs | | | 5,967 | | | | 5,117 | | | | 4,501 | |
| Lease operating expense | | | 3,873 | | | | 2,314 | | | | 1,864 | |
| General and administrative | | | 9,701 | | | | 7,076 | | | | 6,327 | |
| Depreciation, depletion and amortization | | | 1,045 | | | | 224 | | | | 182 | |
| Total operating expenses | | | 20,586 | | | | 14,731 | | | | 12,874 | |
| Operating loss | | | (19,728 | ) | | | (14,731 | ) | | | (12,874 | ) |
| Other income (expense): | | | | | | | | | | | | |
| Interest expense | | | (678 | ) | | | (1,135 | ) | | | (863 | ) |
| Interest income | | | 6 | | | | 5 | | | | 5 | |
| Gain (loss) on sale of assets | | | (1 | ) | | | (1 | ) | | | (5 | ) |
| Foreign currency transaction loss | | | (844 | ) | | | (311 | ) | | | (18 | ) |
| Total other income | | | (1,517 | ) | | | (1,442 | ) | | | (881 | ) |
| Loss before income taxes | | | (21,245 | ) | | | (16,173 | ) | | | (13,755 | ) |
| Income taxes | | | - | | | | - | | | | - | |
| Net loss | | $ | (21,245 | ) | | $ | (16,173 | ) | | $ | (13,755 | ) |
| | | | | | | | | | | | | |
| Comprehensive loss | | $ | (21,245 | ) | | $ | (16,173 | ) | | $ | (13,755 | ) |
| | | | | | | | | | | | | |
| Net loss per share: | | | | | | | | | | | | |
| Basic and diluted | | $ | (0.06 | ) | | $ | (0.07 | ) | | $ | (0.08 | ) |
| | | | | | | | | | | | | |
| Weighted average shares outstanding: | | | | | | | | | | | | |
| Basic and diluted | | | 333,214 | | | | 220,671 | | | | 162,251 | |
See the accompanying notes to consolidated financial statements.
FAR EAST ENERGY CORPORATION
Consolidated Statements of Stockholders' Equity
(In Thousands, Except Share Data)
| | | | | | | | | | | | | | | Deficit | | | | |
| | | | | | | | | | | | | | | Accumulated | | | | |
| | | Common Stock | | | Additional | | | | | | During the | | | Total | |
| | | Number of | | | Par | | | Paid-In | | | Unearned | | | Development | | | Stockholders' | |
| | | Shares | | | Value | | | Capital | | | Compensation | | | Stage | | | Equity | |
| | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2008 | | | 161,305,390 | | | | 161 | | | | 105,915 | | | | (313 | ) | | | (70,452 | ) | | | 35,311 | |
| Net loss | | | - | | | | - | | | | - | | | | - | | | | (13,755 | ) | | | (13,755 | ) |
| Common stock issued | | | 11,558,645 | | | | 11 | | | | 4,349 | | | | - | | | | - | | | | 4,360 | |
| Nonvested shares issued | | | 990,000 | | | | 2 | | | | 285 | | | | 34 | | | | - | | | | 321 | |
| Nonvested shares withheld for taxes | | | (17,075 | ) | | | - | | | | (5 | ) | | | - | | | | - | | | | (5 | ) |
| Stock options issued | | | - | | | | - | | | | 844 | | | | - | | | | - | | | | 844 | |
| Warrants issued | | | - | | | | - | | | | 594 | | | | - | | | | - | | | | 594 | |
| Balance at December 31, 2009 | | | 173,836,960 | | | | 174 | | | | 111,982 | | | | (279 | ) | | | (84,207 | ) | | | 27,670 | |
| Net loss | | | - | | | | - | | | | - | | | | - | | | | (16,173 | ) | | | (16,173 | ) |
| Common shares issued | | | 117,170,416 | | | | 117 | | | | 36,888 | | | | - | | | | - | | | | 37,005 | |
| Nonvested shares issued | | | 251,667 | | | | - | | | | 118 | | | | 112 | | | | - | | | | 230 | |
| Nonvested shares withheld for taxes | | | (156,115 | ) | | | - | | | | (70 | ) | | | - | | | | - | | | | (70 | ) |
| Stock options exercised | | | 100,000 | | | | - | | | | 31 | | | | - | | | | - | | | | 31 | |
| Stock options issued | | | - | | | | - | | | | 429 | | | | - | | | | - | | | | 429 | |
| Balance at December 31, 2010 | | | 291,202,928 | | | $ | 291 | | | $ | 149,378 | | | $ | (167 | ) | | $ | (100,380 | ) | | $ | 49,122 | |
| Net loss | | | - | | | | - | | | | - | | | | - | | | | (21,245 | ) | | | (21,245 | ) |
| Common shares issued | | | 34,880,599 | | | | 35 | | | | 16,696 | | | | - | | | | - | | | | 16,731 | |
| Stock issued for note conversion | | | 14,315,789 | | | | 14 | | | | 6,786 | | | | - | | | | - | | | | 6,800 | |
| Nonvested shares issued | | | 1,753,134 | | | | 2 | | | | 1,086 | | | | (625 | ) | | | - | | | | 463 | |
| Nonvested shares withheld for taxes | | | (49,232 | ) | | | - | | | | (28 | ) | | | - | | | | - | | | | (28 | ) |
| Stock options issued | | | - | | | | - | | | | 399 | | | | - | | | | - | | | | 399 | |
| Balance at December 31, 2011 | | | 342,103,218 | | | $ | 342 | | | $ | 174,317 | | | $ | (792 | ) | | $ | (121,625 | ) | | $ | 52,242 | |
See the accompanying notes to consolidated financial statements.
FAR EAST ENERGY CORPORATION
Consolidated Statements of Cash Flows
(In Thousands)
| | | For the Years Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | | | | | | | | |
| Cash flows from operating activities: | | | | | | | | | |
| Net loss | | $ | (21,245 | ) | | $ | (16,173 | ) | | $ | (13,755 | ) |
| Adjustments to reconcile net loss to cash used in operating activities: | | | | | | | | | | | | |
| Depletion, depreciation and amortization | | | 1,045 | | | | 224 | | | | 182 | |
| Amortization of deferred financing costs | | | 253 | | | | 324 | | | | 692 | |
| Share-based compensation | | | 862 | | | | 659 | | | | 1,165 | |
| Changes in components of working capital: | | | | | | | | | | | | |
| Restricted cash | | | - | | | | 739 | | | | (739 | ) |
| Accounts receivable | | | (899 | ) | | | 266 | | | | (245 | ) |
| Inventory | | | (237 | ) | | | (78 | ) | | | (37 | ) |
| Prepaid expenses | | | (69 | ) | | | (138 | ) | | | 96 | |
| Deposits | | | (442 | ) | | | 245 | | | | (222 | ) |
| Accounts payable and accrued liabilities | | | 4,337 | | | | 4,192 | | | | 38 | |
| Loss on sale of assets | | | 1 | | | | 1 | | | | 5 | |
| Other, net | | | (28 | ) | | | (71 | ) | | | (5 | ) |
| Net cash used in operating activities | | | (16,422 | ) | | | (9,810 | ) | | | (12,825 | ) |
| | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | |
| Additions to oil and gas properties in China | | | (17,052 | ) | | | (4,698 | ) | | | (3,232 | ) |
| Additions to other properties | | | (804 | ) | | | (335 | ) | | | (123 | ) |
| Sales of other fixed assets | | | - | | | | - | | | | 2 | |
| Net cash used in investing activities | | | (17,856 | ) | | | (5,033 | ) | | | (3,353 | ) |
| | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | |
| Net proceeds from credit facility | | | 16,250 | | | | - | | | | - | |
| Net proceeds from exchangeable note | | | - | | | | - | | | | 10,000 | |
| Payment on exchangeable note | | | (3,200 | ) | | | - | | | | - | |
| Net proceeds from sale of common stock | | | 16,731 | | | | 37,005 | | | | 4,360 | |
| Net proceeds from exercise of options | | | - | | | | 31 | | | | - | |
| Deferred financing costs | | | - | | | | - | | | | (495 | ) |
| Net cash provided by financing activities | | | 29,781 | | | | 37,036 | | | | 13,865 | |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | (4,497 | ) | | | 22,193 | | | | (2,313 | ) |
| Cash and cash equivalents--beginning of period | | | 27,760 | | | | 5,567 | | | | 7,880 | |
| Cash and cash equivalents--end of period | | $ | 23,263 | | | $ | 27,760 | | | $ | 5,567 | |
| | | | | | | | | | | | | |
| Supplemental cash flow information: | | | | | | | | | | | | |
| Interest paid | | $ | 1,227 | | | $ | - | | | $ | - | |
| | | | | | | | | | | | | |
| Noncash investing and financing transactions: | | | | | | | | | | | | |
| Common stock issued to convert notes payable | | $ | 6,800 | | | $ | - | | | $ | - | |
| Asset retirement and environmental obligations | | $ | 174 | | | $ | 105 | | | $ | 156 | |
See the accompanying notes to consolidated financial statements.
FAR EAST ENERGY CORPORATION
Notes to Consolidated Financial Statements
| 1. | Summary of Significant Accounting Policies |
Business. We were incorporated in the state of Nevada on February 4, 2000, and on January 10, 2002, we changed our name to Far East Energy Corporation ("FEEC"). The terms "we," "us," "our," and "our company" refer to FEEC and its subsidiaries. References to common stock refer to the common stock of FEEC. References to FEEB refer to Far East Energy (Bermuda), Ltd., our principal operating subsidiary. We are an independent energy company. FEEC, together with its subsidiaries, engages in the acquisition, exploration and development of coalbed methane ("CBM") gas properties solely in the People's Republic of China ("PRC"). Prior to December 31, 2011, we were classified as a development stage company and our activities were principally limited to the drilling, testing, and completion of and pilot development CBM wells and organizational activities. As of December 31, 2011, the Company received its first independent, third party reserve report providing a calculation of the Company’s proved, probable and possible reserves and thus emerged from development stage status as a result of the amount of proved reserves estimated in the reserve report and the fact that we have started generating revenues. Our activities have been limited to organizational activities, including developing a strategic operating plan, capital funding, hiring personnel, entering into contracts acquiring rights to explore for, develop, produce and sell oil and gas or coalbed methane, and drilling, testing and completion of exploratory wells. Gas sales commenced in the first quarter of 2011. See Note 14 – Subsequent Events.
Principles of Consolidation. Our consolidated financial statements include the accounts of our wholly-owned subsidiaries after the elimination of all intercompany accounts and transactions.
Use of Estimates. The preparation of our financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Items subject to such estimates and assumptions include: 1) oil and natural gas reserves; 2) cash flow estimates used in impairment tests of long-lived assets; 3) depreciation, depletion and amortization; 4) asset retirement obligations; and 5) income taxes. While we believe our estimates are appropriate, actual results can, and often do, differ from those estimates.
Cash and Cash Equivalents. We consider short-term investments with little risk of change in value because of changes in interest rates and purchased with an original maturity of three months or less to be cash equivalents.
Inventory. Inventory consists primarily of tubular goods and drilling equipment used in our operations and is carried at cost with adjustments made from time to time to recognize any reductions in value.
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. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Under Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 932, Extractive Activities – Oil and Gas ("ASC 932"), such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. 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 gain or loss on the sale of properties on a field basis. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method.
Unproved property costs are capitalized and reviewed periodically for impairment on a field basis, considering factors such as drilling and exploitation plans and lease terms. 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. Costs related to impaired prospects are charged to expense. An impairment expense could result if oil and gas prices decline in the future or if downward reserves revisions are recorded, as it may not be economical to develop some of these unproved properties. We also evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, foreign currency exchange rates, political stability in the countries in which the Company has an investment, and available geological and geophysical information. Any impairment assessed is charged to expense.
Estimates of future dismantlement, restoration, and abandonment costs. The accounting for future development and abandonment costs is determined by FASB ASC Topic 410, Asset Retirement and Environmental Obligations, which 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 liability is accreted each period through charges to depreciation, depletion and amortization. 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, estimates as to the proper discount rate to use and timing of abandonment.
Convertible Debts and Warrants. We applied FASB ASC Topic 815, Derivatives and Hedging ("ASC 815") and FASB ASC Topic 470, Debt ("ASC 470"), in recording the Exchangeable Note and warrants issued to Dart Energy in conjunction with a transaction between the parties. Derivative financial instruments, as defined in ASC 815, consist of financial instruments or other contracts that contain a notional amount and one or more underlying, require no initial net investment and permit net settlement. Derivative financial instruments may be free-standing or embedded in other financial instruments. Further, derivative financial instruments are initially, and subsequently, measured at fair value and recorded as liabilities or, in rare instances, assets. Convertible debt, as defined in ASC 470, generally includes an interest rate which is lower than the issuer could establish for nonconvertible debt, an initial conversion price which is greater than the market value of the common stock at the time of issuance, and a conversion price which does not decrease except pursuant to anti-dilution provisions. Also, under ASC 470, the portion of the proceeds from the issuance of the debt which is allocable to the warrant should be accounted for as additional paid-in capital. The allocation should be based on the relative fair values of the two securities at time of issuance.
Revenue Recognition. We derive revenue primarily from the sale of produced natural gas. Revenues, net of royalties, are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. The amount of gas sold may differ from the amount to which the Company is entitled based on its working interest or net revenue interest in the properties. A ready market for natural gas allows us to sell our natural gas shortly after production at the pipeline receipt point at which time title and risk of loss transfers to the buyer. Revenue is recorded when title is transferred based on our deliveries and net revenue interests. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.
Significant Customers. All of the Company’s production is sold to one customer, Shanxi Province Guoxin Energy Development Group Limited ("SPG"). In the event that this significant customer ceases doing business with us, we believe, but can provide no assurances, that there are potential alternative customers with whom we could establish new relationships and that those relationships would result in the replacement of the lost customer.
Income Taxes. Deferred income taxes are accounted for under the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statements carrying amounts and the tax basis of existing assets and liabilities. The effect on deferred taxes of a
change in tax rate is recognized in income in the period the change occurs. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized.
Environmental Matters. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when assessments and/or remediation are deemed probable and the costs can be reasonably estimated.
Net Loss Per Share. We apply FASB ASC Topic 260, Earnings Per Share ("ASC 260") for the calculation of basic and diluted earnings per share. Basic earnings per share includes no dilution and is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of securities that could share in our earnings.
Share-based Compensation. We measure the cost of employee services received in exchange for stock options based on the grant date fair value of the awarded options under FASB ASC Topic 718, Compensation – Stock Compensation ("ASC 718"). We determine the fair value of stock option grants using the Black-Scholes option pricing model. We determine the fair value of shares of nonvested stock (also commonly referred to as restricted stock) based on the last quoted price of our stock on the OTC Bulletin Board on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, we have reduced the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, as defined in ASC 718, if any, are recognized as an addition to paid-in capital.
Foreign Currency Transactions. Periodically, we assess the functional currencies of our Chinese subsidiaries to ensure that the appropriate currency is utilized in accordance with the guidance in FASB ASC Topic 830, Foreign Currency Matters ("ASC 830"). During the fourth quarter of 2006, we determined that the functional currency for our Chinese operations was U.S. Dollars, instead of the Chinese Renminbi ("RMB") as previously reported and utilized. Foreign currency transaction gains or losses, which resulted from transactions denominated in the Chinese RMB, were recorded in the Consolidated Statement of Operations.
Fair Values of Financial Instruments. Our company's financial instruments consist primarily of cash and cash equivalents, payables, and accrued payables. The carrying values of these financial instruments approximate their respective fair values as they are short-term in nature.
Credit Concentration. We have deposited with two financial institutions a total of approximately $7.7 million in cash at December 31, 2011, which exceeded the limit of the Federal Deposit Insurance Corporation. The funds were deposited in U.S. government agency supported funds. We did not require collateral from the financial institutions on these deposits. The current arrangements with the financial institutions are such that the funds are moved or swept at the end of every business day into different overnight investments. As of December 31, 2011, approximately $15.3 million of our cash was held in foreign bank accounts.
Reclassification. Certain reclassifications have been made to the consolidated statement of operations for the year ended December 31, 2009 and 2010 to be consistent with the 2011 presentation.
Adoption of New Accounting Pronouncement. In February 2010, the FASB issued ASU No. 2010-09 regarding subsequent events and amendments to certain recognition and disclosure requirements. Under this ASU, a public company that is a Securities and Exchange Commission (“SEC”) filer, as defined, is not required to disclose the date through which subsequent events have been evaluated. This ASU is effective upon the issuance of this ASU. The adoption of this ASU did not have a material impact on our financial statements.
2. Liquidity and Realization of Assets
All of our reserves are located in Shanxi Province, China. At December 31, 2011, our estimated net proved and net probable reserves were 54.6 billion cubic feet and 379.6 billion cubic feet of natural gas, respectively. At December 31, 2011, the standardized measure of our future net cash flows, discounted at 10 percent per annum, relating to our proved natural gas reserves was $65.4 million. See Supplemental Information to Consolidated Financial Statements.
Gas sales under the gas sales agreement with SPG commenced in the first quarter of 2011. We have funded our exploration and development activities primarily through the sale and issuance of common stock and proceeds received from the closing of the Facility Agreement. In September 2009, the Company filed with the SEC a shelf registration statement on Form S-3 for the offer and sale from time to time of up to $75 million of the Company's debt and equity securities. On March 16, 2011, we completed a transaction for the sale of 34.9 million shares of our common stock at $0.5025 per share for net proceeds of $16.7 million under our shelf registration statement. The amount remaining available under the registration statement at March 2, 2012 was approximately $9.0 million.
On November 28, 2011, FEEB entered into a Facility Agreement, as borrower, with Standard Chartered Bank (“SCB”), as lender, and the Company, as guarantor (the “Facility Agreement”). The Facility Agreement provides for a $25 million credit facility, the proceeds of which would be used for project costs with respect to the Shouyang Area in Shanxi Province, China, as well as for finance costs and for general corporate purposes approved by SCB. The Agreement has an initial 9-month term ending August 28, 2012, which may be extended by three months upon satisfaction of certain other conditions. See Note 3 – Facility Agreement.
On June 12, 2010, China United Coalbed Methane Corporation, Ltd. ("CUCBM"), our Chinese partner for the Shouyang production sharing contract ("PSC"), and SPG executed a gas sales agreement (the "Gas Sales Agreement"), to which we are an express beneficiary, to sell CBM produced in the CBM field (the "Shouyang Field") governed by the Shouyang PSC. Pursuant to the Gas Sales Agreement, SPG is initially required to purchase up to 300,000 cubic meters (10,584,000 cubic feet) per day of CBM (the "Daily Volume Limit") produced at the Shouyang Field on a take-or-pay basis, with the purchase of any quantities above such amount to be negotiated pursuant to a separate agreement. At the request of FEEB and CUCBM to provide competitive pricing options for offtake of CBM production in excess of the Daily Volume Limit with assured offtake capacity, the Gas Sales Agreement obligates SPG to commit to having demand capacity to accept at least 1 million cubic meters (approximately 35 million cubic feet) per day from the Shouyang Field by 2015 but does not obligate FEEB or CUCBM to sell gas in excess of the Daily Volume Limit. The term of the Gas Sales Agreement is 20 years. The in-field gathering system and compression equipment were connected to the pipeline in early January 2011 and fully commissioned for sales by mid-March 2011. The gross gas production for 2011 was approximately 268 million cubic feet. Gross sales volumes were 158 million cubic feet for 2011. We believe that the sales rate will continue to increase as gas from additional wells is sold through the gathering system in the coming months.
Our current work programs satisfied the minimum exploration expenditures for our Shouyang and Yunnan PSCs for 2011. With respect to the Qinnan PSC, we have halted activities on the Qinnan Block pending regulatory approval or denial.
Management may seek to secure capital by exploring potential strategic relationships or transactions involving one or more of our PSCs, such as a joint venture, farmout, merger, acquisition or sale of some or all of our assets, by obtaining debt, project or equity-related financing. However, there can be no assurance that we will be successful in entering into any strategic relationship or transaction, securing capital or raising funds through debt, project or equity-related financing. In addition, the terms and conditions of any potential strategic relationship or transaction or of any project financing are uncertain, and we cannot predict the timing, structure or other terms and conditions or the consideration that may be paid with respect to any transaction or offering of securities and whether the consideration will meet or exceed our offering price. Under certain circumstances, the structure of a strategic transaction may require the approval of the Chinese authorities, which could delay closing or make the consummation of a transaction more difficult. There can be no assurance that the Chinese authorities will provide the approvals necessary for a transaction or transfer. There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our unproved oil and gas property costs.
Based on our planned work programs, which include an accelerated pace of drilling in 2012 (subsequent to September 30, 2011, we slowed the pace of drilling down while negotiating the 2011 Shouyang PSC Modification Agreement), if we do not secure additional capital through additional debt, project or equity-related financing, or enter into an agreement with a strategic partner, we believe that the funds currently available to us should provide sufficient cash to fund our planned expenditures under the Shouyang PSC and other minimum operating costs through the end of July 2012 or if necessary such funds could provide sufficient cash to last through the end of 2012 if the pace of drilling is revised and other steps are taken to preserve cash.
The global financial crisis, despite having abated to a certain extent, has created liquidity problems for many companies and financial institutions, and international capital markets have stagnated, especially in the United States and Europe. A continuing downturn in these markets could impair our ability to obtain, or may increase our costs associated with obtaining, additional funds through financing, the sale of our securities or otherwise.
There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the value of our unproved exploratory well costs. However, in addition to revenue generated, management believes that we will continue to be successful in securing any funds necessary to continue as a going concern.
3. Facility Agreement
On November 28, 2011, FEEB entered into the Facility Agreement, as borrower, with SCB, as lender, and the Company, as guarantor. The Facility Agreement provides for a $25 million credit facility, the proceeds of which would be used for project costs with respect to the Shouyang Area in Shanxi Province, China, as well as for finance costs and for general corporate purposes approved by SCB. The Agreement has an initial 9-month term ending August 28, 2012, which may be extended by three months upon satisfaction of certain other conditions. The Company made an initial draw of $17.9 million in anticipation of the first half 2012 operations and to pay finance costs and related expenses, and additional draws may be made under the Agreement in amounts specified from time to time. Loans under the Facility Agreement will bear interest at LIBOR plus a margin rate of 9.5% during the initial period and 10.0% thereafter, and mandatory costs, if any, to compensate SCB for certain Hong Kong regulatory compliance costs. At December 31, 2011, the total amount drawn under the Facility Agreement was $17.9 million and the related accrued interest was $0.2 million. In connection with and as security for the Facility Agreement, FEEB and/or the Company entered into certain other ancillary agreements dated November 28, 2011, including a Share Pledge Agreement, an Account Charge Agreement, an Assignment of Shareholder Loans and a Subordination Agreement (the “Ancillary Agreements”). Under the Ancillary Agreements, the Company pledged its shares in FEEB and granted a security interest in certain intercompany debt to SCB, and FEEB granted a security interest in certain bank accounts to SCB. Pursuant to the terms of the Facility Agreement, in the event we fail to receive approval from the MofCom of the 2011 Shouyang PSC Modification Agreement (defined below), we may not be able to draw down the full amount of available funds otherwise available under the Facility Agreement. The failure to receive such notice on or before May 31, 2012 will constitute an event of default under the Facility Agreement. Upon notice of an event of default under the Facility Agreement, SCB would have the right to accelerate all amounts outstanding under the Facility Agreement. Since December 31, 2011, a draw of $2.1 million has been made under the Facility Agreement.
The Company incurred approximately $1.6 million in financing costs in connection with entering into the Facility Agreement. The costs related to the Facility Agreement were capitalized as deferred financing costs and amortized over the term of the Facility Agreement. The effective interest rate for the Facility Agreement is 23.2% per annum. Amortization expense for the year ended December 31, 2011 was $181,000.
4. Transactions with Dart Energy
In 2009, we entered into a series of transactions related to our Qinnan Block with Dart Energy, formerly known as Arrow Energy International Pte Ltd. In connection with these transactions, one of our wholly owned subsidiaries, FEEB, and Dart Energy entered into a Farmout Agreement (the "Farmout Agreement") under which, subject to certain conditions, FEEB would assign to Dart Energy 75.25% of its rights in the Qinnan PSC in Shanxi Province
(the "Assignment"). The Assignment was not carried out and FEEB terminated the Farmout Agreement in November 2011.
In conjunction with the Farmout Agreement, FEEB issued an Exchangeable Note, $10 million principal amount, to Dart Energy for $10 million in cash and a warrant to Dart Energy for 7,420,000 shares of our common stock, at an exercise price of $1.00 per share ("Warrant"). The Warrant was not exercised and expired in December 2009.
Of the $10 million in cash received from Dart Energy for the Exchangeable Note, $2 million was to be set aside to be used exclusively to satisfy FEEB's existing exploration and development commitments in connection with the Qinnan PSC. This restricted portion of the proceeds was recorded as restricted cash on the consolidated balance sheet until it was fully utilized for exploration expenditures related to the Qinnan PSC by the end of the quarter ended September 30, 2010.
The Exchangeable Note had an initial principal amount of $10 million and bore interest at a rate of 8% per annum, which began to accrue on October 16, 2009. Dart Energy had the right at any time to exchange the Exchangeable Note in whole or in part for shares of the Company’s common stock at an exchange rate of 21,052.63 shares per $10,000, or $0.475 per share (the "Exchange Rate"), of principal and interest. In February 2011, Dart Energy exercised its right to exchange a total of $6.8 million in principal amount under the Exchangeable Note for 14,315,789 shares of Common Stock. Dart Energy has informed the Company that it has sold all of the acquired shares through block trades with institutional investors.
On September 15, 2011, the Company fulfilled its obligations under the Exchangeable Note by paying in full the remaining $3,200,000 principal balance on the Exchangeable Note plus the $1,226,577 in accrued interest, and the Company elected to terminate the Farmout Agreement on November 11, 2011.
We applied ASC 815 and ASC 470 in the recording of the transaction with Dart Energy. We determined the fair value of the Warrant using a combination of the Black-Scholes-Merton valuation technique and a Monte Carlo simulation. The significant assumptions used in the valuation were as follows:
| | | Black-Scholes -Merton | | | Monte Carlo Simulation | |
| Volatility | | | 124.60 | % | | | 110.16 | % |
| Risk free interest rate | | | 0.67 | % | | | 0.83 | % |
| Expected dividend yield | | | - | | | | - | |
| Expected term | | 0.99 year | | | 1.51 years | |
Based on the combination of the Black-Scholes-Merton valuation technique and the Monte Carlo simulation, the Warrant was valued at $624,612 at time of issuance. The amount was recorded as a discount to the Exchangeable Note in the liabilities section and as additional paid-in capital in the Stockholders’ Equity section of the Consolidated Balance Sheets. The debt discount is accreted as interest expense periodically over the term of the Exchangeable Note. Accretion expense for the years ended December 31, 2011 and 2010 was $42,000 and $186,000, respectively.
The Company incurred approximately $0.5 million in direct costs in connection with entering into the transactions with Dart Energy. These direct costs were allocated between the Exchangeable Note and the Warrant in proportion to their respective fair values at time of issuance. The costs related to the Warrant were recorded as an offset to the value of the Warrant in paid-in capital. The costs related to the Exchangeable Note were capitalized as deferred financing costs and amortized based on the effective interest method over the term of the Exchangeable Note. The objective of that method is to arrive at a periodic interest cost which represents a level effective rate over the term of the Exchangeable Note on its face amount reduced by the unamortized discount and expense at the beginning of the period. The effective interest rate for the Exchangeable Note as calculated is 11.64% per annum. Amortization expense for the years ended December 31, 2011 and 2010 was $31,000 and $138,000, respectively.
5. Supplemental Cash Flow Information
We use the indirect method to present cash flows from operating activities. Cash paid for interest expense and income taxes for 2011 was $1.2 million and zero, respectively. Cash paid for interest expense and income taxes for 2010, and 2009 was zero. Other supplemental cash flow information for 2011, 2010 and 2009, is presented as follows (in thousands):
| | | 2011 | | | 2010 | | | 2009 | |
| Non-cash transactions: | | | | | | | | | |
| Amortization of deferred financing costs | | $ | 253 | | | $ | 324 | | | $ | 692 | |
| Non-cash share-based compensation | | | 862 | | | | 659 | | | | 1,165 | |
| Common stock issued to convert notes payable | | | 6,800 | | | | - | | | | - | |
| Asset retirement and environmental obligation | | | 174 | | | | 105 | | | | 156 | |
6. Oil and Gas Properties
All of the Company's oil and gas properties are located in the PRC. Based on the determination of proved reserves, the Company classified $66.3 million of its unproved oil and gas properties to proved oil and gas properties. The Company has $1.9 million remaining in unproved oil and gas properties. The costs associated with our oil and gas properties include the following (in thousands):
| | | At December 31, | |
| | | 2011 | | | 2010 | |
| Proved oil and gas properties | | $ | 66,361 | | | $ | - | |
| | | | | | | | | |
| Unproved leasehold costs | | | 275 | | | | 275 | |
| Unproved oil and gas properties | | | 1,624 | | | | 49,819 | |
| Total unproved oil and gas properties | | | 1,899 | | | | 50,094 | |
| Accumulated depreciation, depletion and amortization | | | (744 | ) | | | - | |
| | | | | | | | | |
| Total oil and gas properties, net | | $ | 67,516 | | | $ | 50,094 | |
Unproved Leasehold Costs. Unproved leasehold costs are composed of amounts we paid to the PRC's Ministry of Commerce of the People's Republic of China ("MofCom") and CUCBM pursuant to a PSC we entered into in 2002 with CUCBM to acquire the mineral rights in the Enhong and Laochang areas in the Yunnan Province.
Unproved Oil and Gas Properties. Unproved oil and gas property costs include only suspended well costs which are direct exploratory well costs pending determination of whether proved reserves have been discovered. Accounting guidance regarding capitalization of suspended well costs is provided by FASB ASC Topic 932. FASB ASC Topic 932 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. Capitalization of costs should be continued beyond one year in cases where reserves for the project are not yet proven, but the Company demonstrates sufficient continuing progress toward assessing those reserves. For the capitalized costs at December 31, 2011, our assessment indicated that our current work programs demonstrated our efforts in making sufficient continuing progress toward assessing the reserves in the areas for which the costs were incurred. Therefore, we have continued to capitalize these costs.
The following table reflects the net changes in capitalized exploratory well costs during 2011, 2010 and 2009 (in thousands):
| | | 2011 | | | 2010 | | | 2009 | |
| Beginning balance at January 1 | | $ | 49,819 | | | $ | 34,146 | | | $ | 30,562 | |
| Additions to unevaluated exploratory well costs pending the determination of proved reserves | | | 18,166 | | | | 15,673 | | | | 3,584 | |
| Reclassifications of wells, facilities,and equipment based on the determination of proved reserves | | | (66,361 | ) | | | - | | | | - | |
| Unevaluated exploratory well costs charged to expense | | | - | | | | - | | | | - | |
| Ending balance at December 31 | | $ | 1,624 | | | $ | 49,819 | | | $ | 34,146 | |
At December 31, 2011, the Company had costs of $1.1 capitalized for exploratory wells for a period of greater than one year after the completion of drilling.
7. Asset Retirement and Environmental Obligations
The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2011 and 2010 (in thousands):
| | | 2011 | | | 2010 | |
| Carrying amount at beginning of period | | $ | 491 | | | $ | 339 | |
| Liabilities incurred | | | 174 | | | | 105 | |
| Liabilities settled | | | - | | | | - | |
| Accretion expense | | | 74 | | | | 47 | |
| Revisions | | | - | | | | - | |
| Carrying amount at end of period | | $ | 739 | | | $ | 491 | |
| | | | | | | | | |
| Current portion | | $ | - | | | $ | - | |
| Noncurrent portion | | $ | 739 | | | $ | 491 | |
8. Other Property and Equipment
Other fixed assets, net include the following (in thousands):
| | | At December 31, | |
| | | 2011 | | | 2010 | |
| Other fixed assets | | $ | 2,071 | | | $ | 1,314 | |
| Accumulated depreciation | | | (858 | ) | | | (677 | ) |
| Other fixed assets, net | | $ | 1,213 | | | $ | 637 | |
Other fixed assets include leasehold improvements, equipment and furniture. Depreciation expense for the years ended December 31, 2011, 2010, and 2009 was approximately $227,000, $177,000, and $182,000, respectively.
Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from three to twenty years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.
9. Income Taxes
Deferred income taxes reflect the net tax effects of temporary differences between the recorded amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities as of December 31, 2011 and 2010 are as follows (in thousands):
| | | At December 31, | |
| | | 2011 | | | 2010 | |
| Deferred tax assets: | | | | | | |
| Net operating loss | | $ | 7,099 | | | $ | 4,411 | |
| Depreciable assets and other | | | 19 | | | | - | |
| Stock-based compensation | | | 741 | | | | 604 | |
| Total deferred tax assets | | | 7,859 | | | | 5,015 | |
| Total deferred tax liabilities | | | - | | | | (2 | ) |
| Net deferred tax assets | | $ | 7,859 | | | $ | 5,013 | |
| | | | | | | | | |
| Net deferred tax assets | | $ | 7,859 | | | $ | 5,013 | |
| Less: valuation allowance | | | (7,859 | ) | | | (5,013 | ) |
| | | $ | - | | | $ | - | |
Net operating loss, which can be carried forward for federal income tax purposes, was estimated to be approximately $20.9 million and $12.9 million at December 31, 2011 and 2010, respectively. The management has determined that it is unlikely that the NOL will be utilized before its expiration beginning in 2016. Accordingly, full valuation allowance is provided to comply with the provisions of FASB ASC Topic 740, Income Taxes (“ASC 740”).
Income taxes for financial reporting purposes differed from the amounts computed by applying the statutory federal income tax rates because Bermuda has no income tax that would apply to FEEB, and because of our recording of the valuation allowance for the losses generated by us. The net increase in the valuation allowance for the year ended December 31, 2011 was $2.8 million. The net increase in the valuation allowance for the year ended December 31, 2010 was $1.3 million. The increase for each year was primarily attributable to the net operating losses generated.
ASC 740 prescribes a minimum recognition threshold and measurement methodology that a tax position taken or expected to be taken in a tax return is required to meet before being recognized in the financial statements. It also provides guidance for derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We recognize interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of operations. There were no unrecognized tax benefits as of the date of adoption. There are no unrecognized tax benefits that if recognized would affect the tax rate for the year ended December 31, 2011. There is no interest or penalties recognized as of the date of adoption or for the year ended December 31, 2011.
The Company files income tax returns in the U.S. Federal jurisdiction and State of Texas. The 2008 through 2011 tax years generally remain subject to examination by federal and state tax authorities.
10. Commitments and Contingencies
Legal Proceedings. We are periodically named in legal actions arising from normal business activities. We evaluate the merits of these actions and, if we determine that an unfavorable outcome is probable and can be estimated, we will establish the necessary accruals. We do not anticipate any material losses as a result of commitments and contingent liabilities. We are involved in no material legal proceedings.
Shouyang Production Sharing Contract. We are the operator under a PSC entered into with CUCBM to develop the Shouyang Block in the Shanxi Province of the PRC. The term of the Shouyang PSC consists of an exploration period, a development period and a production period. 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. If the 2011 Shouyang PSC Modification Agreement is approved by MofCom, we anticipate being able to establish a number of areas that reasonably meet the criteria for certification of “Chinese” reserves under PRC law. Thereafter, to maintain rights to produce and develop a CBM discovery, we must compile an Overall Development Plan ("ODP") application and receive all necessary approvals for such plan. Upon receipt of approvals, we must commence development operations in accordance therewith. At such time, pursuant to the 2011 Shouyang PSC Modification Agreement, CUCBM elected to participate with a 30% participating interest share (other than development in 64.66 km2 of the Shouyang ODP Area, for which CUCBM has waived its right to elect a participating interest share). The development costs for such CBM discovery will be borne by us and CUCBM in proportion to the parties' respective participating interests. The Shouyang PSC provides for a gradual cost recovery mechanism whereby operational expenses will first be reimbursed out of 75% of revenues generated from CBM sales. Then, our exploration costs will be reimbursed in equal proportion to CUCBM pre-contract costs in the amount of $2,840,000, and thereafter, development costs incurred by the parties will be reimbursed in proportion to each party’s incurrence of such costs. The exploration period is divided into three phases called Phase I, Phase II and Phase III. We have exceeded our minimum work program obligations for all exploration period phases under the Shouyang PSC, provided, however, we have agreed to additional minimum work obligations in connection with the 2011 Shouyang PSC Modification Agreement, which exceed the minimum MLR requirements. We intend to continue voluntary pilot testing activities until we transfer portions of the contract area into the development period for certain CBM Fields in accordance with applicable provisions of the Shouyang PSC and Chinese law.
We were operating under an agreed extension of Phase III of the exploration period until June 30, 2011. We have reached an agreement with CUCBM regarding an additional formal extension of Phase III of the exploration period of the Shouyang PSC. However, the agreement will not be effective unless and until it is approved by the MofCom. Pending a determination with respect to the extension, we are continuing operations under our expanded pilot development work program as provided for in the Shouyang PSC as amended to date. We believe that the MofCom will approve the 2011 Shouyang PSC Modification Agreement, though there can be no assurance that the MofCom will do so. Further, in negotiating the extension and modification agreement, we were required to agree to certain other provisions to the Shouyang PSC which clarify relinquishment obligations and include additional obligations on Far East as operator and a reduction in acreage.
The minimum work expenditure requirements we agree to in our PSCs are denominated in RMB and, therefore, are subject to fluctuations in the currency exchange rate between the U.S. Dollar and the Chinese RMB. In addition to minimum work requirements under our PSCs, the MLR minimum expenditure requirements are a significant factor that influences our exploration work program. Under the Shouyang PSC, we were required to pay certain fees totaling $0.5 million in 2011, which counted toward the satisfaction of the 2011 minimum exploration expenditure requirements. These fees include assistance fees, training fees, fees for CBM exploration rights and salaries and benefits. In 2012, the MLR minimum expenditure requirements will be $2.6 million if the relinquishment agreed upon in the 2011 Shouyang PSC Modification Agreement is approved.
Qinnan Production Sharing Contract. We are the operator under a PSC to develop the Qinnan Block in the Shanxi Province that is in the process of being assigned by CUCBM to China National Petroleum Company ("CNPC"). The term of the Qinnan PSC consists of an exploration period, a development period and a production period. 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. If any CBM field is discovered, the development costs for that CBM field will be borne by us and CUCBM in proportion to the respective participating interests. At that time, we will recover that share of the up-front exploration costs allocable to our Chinese partner
through a gradual cost recovery mechanism. The exploration period is divided into three phases called Phase I, Phase II and Phase III. We have completed our Phase I, Phase II and Phase III work program obligations under the PSC, and intend to continue pilot development and exploration activities in Phase III until we transfer into the development period.
Although the Qinnan PSC does not expire until July 31, 2032, the stated date for expiration of the exploration period for the Qinnan PSC occurred on June 30, 2009. We are continuing to pursue an extension of the exploration period of the Qinnan PSC, but we cannot be optimistic at this time. We believe the underlying exploration period should be extended due to events beyond our reasonable control, namely the lengthy transfer of rights taking place from CUCBM to CNPC. At CNPC’s request, we have provided certain operational and financial information about our Company to assist them in the decision making process for recognizing an extension of the exploration period in Qinnan. CNPC has completed an accounting audit pursuant to the Qinnan PSC of our expenditures for 2007 and 2008. We also provided to CNPC at their request our work plan for 2010 for Qinnan. In January 2011, we received a formal notice from CNPC that it has purportedly received all Chinese approvals with respect to the transfer of rights from CUCBM to CNPC, and CNPC has requested we execute a modification agreement to confirm CNPC as our Chinese partner company for the Qinnan PSC. In connection with that notice, we received a form of assignment agreement, assigning the PSC from CUCBM to CNPC. We modified it to include a formal recognition of the existence of force majeure regarding the delays caused by the incomplete transfer of the PSC to CNPC. Currently, we have not received any response from CNPC or CUCBM regarding our proposed amendments to the draft assignment agreement and we have not signed a formal document confirming the assignment of CUCBM’s rights to CNPC or its designee. Due to the inability to hold a formal Joint Management Committee ("JMC") meeting or to have the effective involvement of our Chinese partner, we believe that our efforts to continue CBM Operations in the Qinnan block have been materially hindered. Technically, the exploration period under the Qinnan PSC expired on June 30, 2009; however, we have maintained the position that the doctrine of force majeure under the Qinnan PSC entitled us to an extension. We continue to discuss this situation with CUCBM and PetroChina, and as recently as January 2012 have submitted a notice of force majeure in accordance with the Qinnan PSC. There can be no assurance that we will be successful in extending the exploration period of the Qinnan PSC or that a new PSC will be granted. Additionally, in connection with obtaining this extension or a new PSC, we may be required to commit to certain expenditures or to modify the terms or respective ownership interests and/or acreage in the applicable PSC. However, if we are unable to secure sufficient funds to commit to these expenditures, it may adversely affect our ability to extend the Qinnan PSC.
Under the Qinnan PSC, we have committed to satisfy certain annual minimum exploration expenditure requirements. As with the Shouyang PSC, our minimum exploration expenditure requirement is based on the minimum exploration expenditure requirements of CNPC established by the MLR. The MLR sets its requirements by applying a minimum expenditure per square kilometer to the total acreage encompassed by each PSC. The annual minimum exploration expenditure requirement under the Qinnan PSC is approximately $3.7 million in the aggregate based on the currency exchange rate between the U.S. Dollar and the Chinese RMB as of December 31, 2011. These expenditure requirements are denominated in the RMB and, therefore, are subject to fluctuations in the currency exchange rate between the U.S. Dollar and the Chinese RMB. Because the stated expiration date for the exploration period for the Qinnan PSC occurred on June 30, 2009, and we have not yet received an extension, we have halted activities associated with the Qinnan Block pending receipt of an extension, should one ultimately be granted.
Under the PSCs, we are required to make the following yearly payments to our Chinese partner companies. As indicated below, certain amounts may change from year to year.
| Annual Payments | | Shouyang PSC | | | Qinnan PSC | |
| Exploration Period | | | | | | |
| Salary and Benefit | | | | | | |
| 2012 | | $ | 231,542 | | | $ | 151,686 | |
| 2011 | | | 218,436 | (1) | | | 143,100 | |
| | | | | | | | | |
| Exploration Permit Fee | | | 140,136 | | | | 165,529 | |
| Training Fee | | | 60,000 | | | | 60,000 | |
| Assistance Fee | | | 50,000 | | | | 50,000 | |
| | | | | | | | | |
| Development & Production Period | | | | | | | | |
Signature Fee (2) | | | 150,000 | | | | 150,000 | |
| Training Fee | | | 150,000 | | | | 150,000 | |
| Assistance Fee | | | 120,000 | | | | 120,000 | |
(1) The increase from 2011 to 2012 is due to the increase of standard amount of the CUCBM's professionals’ salary and benefit under the amended Shouyang PSC. The salary and benefits for CUCBM professionals during the development and production periods is to be determined by negotiation with CUCBM.
(2) Due within 30 days after first approval of the ODP following the exploration period.
Yunnan Production Sharing Contract. We have been the operator under one Yunnan PSC with CUCBM to develop two areas in the Yunnan Province: Enhong and Laochang. The term of the Yunnan PSC 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. We completed Phase I and, during the third quarter of 2009, the MofCom approved a modification agreement to extend Phase II of the exploration period for the Yunnan PSC to June 30, 2011 from June 30, 2009. Thus, although the Yunnan PSC does not expire until January 1, 2033, the stated date for expiration of the exploration period for the Yunnan PSC occurred on June 30, 2011. During the fourth quarter of 2011, we negotiated and signed the 2011 Yunnan PSC Modification Agreement with CUCBM, which CUCBM subsequently submitted to the MofCom for approval. The terms of the Yunnan modification agreement are substantially similar to those in the 2011 Shouyang PSC Modification Agreement, save differences in relinquishment and the participating interest percentages of the parties. Although we anticipate that we will receive all necessary governmental approvals for the 2011 Yunnan PSC Modification Agreement, we cannot be certain that they will be approved and become effective. In such instance, we would be operating under a technical extension of the Yunnan PSC for the completion of prior pilot development work programs as necessary to receive final ODP approval no later than June 30, 2013, however, we do not have CUCBM or any governmental acknowledgement or agreement regarding the viability of such extension.
During the exploration period, we must bear all exploration costs for discovering and evaluating CBM-bearing areas. If the 2011 Yunnan PSC Modification Agreement is approved, our work commitment to complete Phase II consists of drilling a total of eight wells during the entire exploration period, as extended, spending at least $0.8 million (4,850,000 RMB) per year as the minimum exploration expenditure. In December 2010 we mobilized a drilling company to fracture stimulate 5 wells that we had drilled to test the number 7+8 and number 19 coal seams in Laochang area. These two seams have good gas content based on lab analysis and significant thickness to merit testing for commercial production. Stimulation operations were completed on January 19, 2011 and the frac company demobilized from the field. However, bad weather prevented the equipment from reaching the field in time to put the wells on production before the Chinese New Year holiday. Therefore, the planned operations were suspended until February 15, 2011 to allow for the roads to improve and the crews to return from the holiday. The dewatering operation started on March 18, 2011 in all five wells of the clustered pilot. With casing pressure of 0.41 Mpa and fluid level several hundred meters above the top of the targeted coal seams, a small amount of gas was produced and flared. Recently, gas production from one of the pilot wells has remained steady at a rate around 20
Mcf (550-600 m3) per day; with the peak daily rate as high as 65 Mcf (1,850 m3). Production from the pilot has continued for about five months; however, there can be no assurance that production will continue to increase or sustain current levels. After initial testing, it was determined that this CBM Field possesses one of the higher-rank coals in China, which means that the coal in this CBM Field contains more carbon and typically results in a much higher energy content and frequently higher gas content. Accordingly, the Company plans to continue the pilot and further testing.
Under the Yunnan PSC, we have committed to satisfy certain annual minimum exploration expenditure requirements. Our minimum exploration expenditure requirements for the blocks subject to the PSC are based on the minimum exploration expenditure requirements of CUCBM established by the MLR and our negotiated agreement to extend the Yunnan PSC exploration period. The MLR sets its requirements by applying a minimum expenditure per square kilometer to the total acreage encompassed by the PSC. The annual minimum exploration expenditure requirement is approximately $1.7 million in the aggregate in 2011, based on the currency exchange rate between the U.S. Dollar and the Chinese RMB as of December 31, 2011. These requirements are denominated in the RMB, and, therefore, are subject to fluctuations in the currency exchange rate between the U.S. Dollar and the Chinese RMB. The MLR minimum expenditure requirements are a significant factor that influences our exploration work program. Under the Yunnan PSC, we were required to pay certain fees totaling $0.4 million in 2011, which were to be counted toward the satisfaction of the 2011 minimum exploration expenditure requirements. These fees include assistance fees, training fees, fees for CBM exploration rights and salaries and benefits. In 2012, the MLR minimum expenditure requirements will be $0.8 million if the relinquishment agreed upon in the 2011 Yunnan PSC Modification Agreement is approved. Based on the modification agreement, the unfulfilled exploration work commitment will be added to the minimum exploration work commitment for the following year. If the Company terminates the Yunnan PSC and there exists an unfulfilled balance on the minimum exploration work commitment, the Company will be required to pay the balance to CUCBM.
Minimum Commitments. At December 31, 2011, total minimum commitments from long-term non-cancelable operating leases and other purchase obligations are as follows (in thousands):
| | | Amount | |
| 2012 | | $ | 26,797 | |
| 2013 - 2014 | | | 5,641 | |
| 2015 - 2016 | | | 1,314 | |
| 2017 and beyond | | | 739 | |
| Total minimum commitments | | $ | 34,491 | |
11. Employee Savings Plan
At December 31, 2011, we maintained a defined contribution plan covering all of our U.S. employees. Employees participating in the plan may select from several investment options. We match the participant's contribution up to a maximum of four percent of the participant's salary. The amounts contributed by the participants and us vest immediately. We expensed $68,000, $50,000, and $40,000 under this plan for 2011, 2010 and 2009, respectively.
12. Share-Based Compensation
We grant shares of nonvested stock of common stock and options to purchase common stock to employees, members of the board of directors and consultants under our shareholder-approved 2005 Stock Incentive Plan (the "2005 Plan"). Options granted under the 2005 Plan must carry an exercise price equal to or above the market value of the stock at the grant date, and a term of no greater than ten years. The 2005 Plan provides that, unless otherwise agreed, shares of nonvested stock granted under the 2005 Plan must be forfeited upon termination of service. We issue new shares when options are exercised or shares are granted. Our option grants under the 2005 Plan to date have generally utilized these terms: exercise price above or equal to average market price on the date of the grant; vesting periods up to four years from date of grant; term of up to ten years; and forfeiture of unexercised vested options after 60-90 days after termination of employment with the Company. Our shares of nonvested stock granted under the 2005 Plan to date have utilized vesting periods of up to three years.
Grants prior to the adoption of the 2005 Plan and inducement grants associated with hiring of new employees and appointment of new directors are issued outside of the 2005 Plan. These grants of options included varying terms, some differing from the above.
During the first half of 2011, we awarded options to purchase up to 1,785,000 shares of our common stock and 1,669,800 nonvested shares under the 2005 Plan to employees and members of the board of directors; and options to purchase up to 250,000 shares of our common stock and 190,000 nonvested shares outside the 2005 Plan to a new employee and a consultant.
At the annual meeting of stockholders of the Company held on October 11, 2011, the Company's stockholders approved an amendment to the 2005 Plan which increased the number of shares of common stock issuable from 12,500,000 shares to 22,000,000 shares and increased the number of shares of common stock that may be granted as restricted stock (nonvested shares), restricted stock units or any other stock-based awards from 3,900,000 to 8,000,000 shares. As of December 31, 2011, we had 16,509,199 shares available for awards under the 2005 Plan, of which 4,206,699 shares could be issued as nonvested shares or other full-valued stock-based awards.
The following table summarizes share based compensation costs recognized under ASC 718 for 2011, 2010 and 2009 (in thousands):
| | | 2011 | | | 2010 | | | 2009 | |
| General and administrative | | $ | 691 | | | $ | 532 | | | $ | 930 | |
| Exploration costs | | | 171 | | | | 127 | | | | 235 | |
| Tax benefit | | | - | | | | - | | | | - | |
| Total share-based compensation costs, net of tax | | $ | 862 | | | $ | 659 | | | $ | 1,165 | |
We utilized certain assumptions in determining the fair value of options using the Black-Scholes option pricing model. Expected volatility is based upon historical volatility. The risk-free interest rate is based on observed U.S. Treasury rates at date of grant, appropriate for the expected lives of the options.
No stock options were granted during 2010. Compensation expenses for the stock option grants determined under ASC 718 for 2011 and 2009 were calculated using the Black-Scholes option pricing model with the following assumptions:
| | | 2011 | | | 2009 | |
| Dividend yield | | | 0 | % | | | 0 | % |
| Expected volatility | | | 92 | % | | | 85 - 89 | % |
| Risk-free interest rate | | | 2.3 | % | | | 1.5 - 1.7 | % |
| Expected life of options (years) | | | 6 | | | | 5.5 - 6 | |
| Weighted average fair value per share at grant date | | $ | 0.44 | | | $ | 0.17 | |
The total intrinsic value of options exercised during 2010 was $12,000. Approximately $31,000 of cash was received from the exercise of options during 2010. No options were exercised during 2011 or 2009.
The aggregate intrinsic value for options outstanding at December 31, 2011 is zero. The weighted average remaining life for the outstanding options is 5.21 years. A summary of options outstanding as of December 31, 2011 is as follows:
| | | | | | Options Outstanding | | | | Options Exercisable | |
| | Range of Exercise Prices | | | | Number Outstanding | | | | Weighted Average Remaining Contractual Life (Years) | | | | Weighted Average Exercise Price | | | | Number Exercisable | | | | Weighted Average Exercise Price | |
| $ | 0.28 to $0.45 | | | | 1,259,333 | | | | 7.21 | | | $ | 0.28 | | | | 1,375,667 | | | $ | 0.37 | |
| $ | 0.46 to $0.70 | | | | 4,786,500 | | | | 6.63 | | | | 0.63 | | | | 2,389,833 | | | | 0.67 | |
| $ | 0.71 to $0.99 | | | | 683,000 | | | | 5.37 | | | | 0.81 | | | | 683,000 | | | | 0.81 | |
| $ | 1.00 to $1.99 | | | | 850,000 | | | | 3.33 | | | | 1.21 | | | | 850,000 | | | | 1.21 | |
| $ | 2.00 to $2.37 | | | | 2,945,000 | | | | 2.57 | | | | 2.01 | | | | 2,945,000 | | | | 2.01 | |
| | | | | | 10,523,833 | | | | 5.21 | | | | 1.04 | | | | 8,243,500 | | | | 1.17 | |
The following table summarizes activity in shares of nonvested stock for 2011:
| | | Shares of Nonvested Stock | | | Weighted Average Grant Date Fair Value | |
| Outstanding at beginning of year | | | 779,083 | | | $ | 0.37 | |
| Granted | | | 1,859,800 | | | | 0.58 | |
| Vested | | | (380,686 | ) | | | 0.41 | |
| Forfeited | | | (106,666 | ) | | | 0.53 | |
| Withheld for Taxes | | | (49,232 | ) | | | 0.56 | |
| Outstanding at end of year | | | 2,102,299 | | | | 0.54 | |
The fair value of restricted stock that vested during the years ended December 31, 2011, 2010 and 2009 was approximately $169,000, $379,000, and $82,000, respectively, based on the closing prices on the dates of vesting. At December 31, 2011, we had approximately $1.3 million in total unrecognized compensation cost related to share-based compensation, of which $0.7 million was related to shares of nonvested stock grants and was recorded in unearned compensation on our consolidated balance sheets. This cost is expected to be recognized over a weighted average period of 2.0 years at December 31, 2011.
13. Stockholders' Equity
Common Stock. Holders of our common stock are entitled to one vote for each share held on all matters submitted to a vote of stockholders and do not have cumulative voting rights. Accordingly, holders of a majority of the shares of common stock entitled to vote in any election of directors may elect all other directors standing for election. Holders of common stock are entitled to receive proportionately any dividends that may be declared by our board of directors, subject to any preferential rights of outstanding preferred stock. In the event of our liquidation, dissolution or winding up, holders of common stock will be entitled to receive proportionately any of our assets remaining after the payment of liabilities and subject to the prior rights of any outstanding preferred stock. Holders of common stock have no preemptive, subscription, redemption or conversion rights.
Shelf Registration. In September 2009, we filed with the SEC a shelf registration statement on Form S-3 for the offer and sale from time to time up to $75 million of our debt and equity securities. The amount available under the registration statement at March 2, 2012 was approximately $9.0 million.
Issuances of Common Stock and Warrants. The table below summarizes placements of our shares of common stock and warrants since the inception of the Company and warrants outstanding at December 31, 2011:
| | | Shares | | | | | | | | | | |
| | | Common | | | | | | Proceeds | | | Warrants Outstanding at December 31, 2011 | |
| | | Stock | | | Warrant | | | Gross | | | Net | | | Amount | | | Exercise Price | | | Expiration | |
| Company | | | | | | | | | | | | | | | | | | | | | |
| Formation | | | 40,500,000 | | | | - | | | $ | 53,000 | | | $ | 53,000 | | | | - | | | | - | | | | - | |
| Shares issued | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2002 | | | 5,250,500 | | | | - | | | | 3,413,000 | | | | 3,051,000 | | | | - | | | | - | | | | - | |
| 2003 | | | 10,595,961 | | | | 8,903,270 | | | | 6,607,000 | | | | 5,382,000 | | | | - | | | | - | | | | - | |
| 2004 | | | 18,186,471 | | | | 11,042,215 | | | | 15,962,000 | | | | 14,621,000 | | | | - | | | | - | | | | - | |
| 2005 | | | 14,893,292 | | | | 150,000 | | | | 13,404,000 | | | | 12,469,000 | | | | - | | | | - | | | | - | |
| 2006 | | | 25,514,511 | | | | - | | | | 25,881,000 | | | | 24,953,000 | | | | - | | | | - | | | | - | |
| 2007 | | | 11,485,452 | | | | 4,019,908 | | | | 15,000,000 | | | | 14,814,000 | | | | 4,019,908 | | | $ | 2.61 | | | Aug 2012 | |
2008 (1) | | | 24,000,000 | | | | 8,400,000 | | | | 12,000,000 | | | | 11,808,000 | | | | 8,400,000 | | | $ | 1.00 | | | May 2013 | |
2009 (2) | | | 11,558,645 | | | | 12,043,458 | | | | 14,900,855 | | | | 13,898,173 | | | | 4,623,458 | | | $ | 1.25 | | | Dec. 2014 | |
2010 (3) | | | 117,170,416 | | | | 4,951,616 | | | | 39,831,749 | | | | 37,036,759 | | | | 4,951,616 | | | $ | 0.54 - $0.80 | | | 2014 & 2015 | |
2011 (4) | | | 49,196,388 | | | | - | | | | 17,527,500 | | | | 16,696,009 | | | | - | | | | - | | | | - | |
| | | | 328,351,636 | | | | 49,510,467 | | | | 164,580,104 | | | | 154,781,941 | | | | 21,994,982 | | | | | | | | | |
(1) The issuance of Common Stock and Warrants were consummated pursuant to a registered offering that closed in the second quarter of 2008. The warrants issued pursuant to this registered offering will terminate on the earlier to occur of: (a) the expiration date indicated in the respective warrant agreement and (b) the date fixed for redemption under the respective warrant agreement. We may elect to redeem the warrants (in whole or in part) if the shares of the Company's common stock trade at a price equal to or in excess of $2 per share for fifteen or more consecutive trading days.
(2) The issuance of Common Stock and Warrants were consummated pursuant to a registered offering that closed in the second quarter of 2008. The warrants issued pursuant to this registered offering will terminate on the earlier to occur of: (a) the expiration date indicated in the respective warrant agreement and (b) the date fixed for redemption under the respective warrant agreement. We may elect to redeem the warrants (in whole or in part) if the shares of the Company's common stock trade at a price equal to or in excess of $1.875 per share for fifteen or more consecutive trading days. Additionally, on March 13, 2009, FEEB issued an Exchangeable Note, $10 million principal amount, to Dart Energy for $10 million in cash and Dart Energy received Warrants to purchase 7,420,000 shares of Common Stock, which expired in December 2009.
(3) A Registered offering closed in March 2010 and Warrants to purchase up to 4.9 million shares of Common Stock were issued pursuant to this registered offering. The Warrants that were issued in the registered offering that closed in March 2010 expire on March 11, 2015 for investors who subscribed for Warrants and on November 4, 2014 for the placement agent who participated in the March 2010 registered offering. Another registered offering was closed in August 2010 for shares of Common Stock.
(4) In February 2011, Dart Energy exercised its right to exchange a total of $6.8 million in principal amount under the Exchangeable Note (referenced in footnote 2 of this table) for 14,315,789 shares of Common Stock. A registered offering was closed in March 2011 for shares of Common Stock.
Basic and Diluted Shares Outstanding. Our basic and diluted numbers of shares outstanding in each of the three years presented were the same because we had net losses. There were (1) 10,523,833, 9,075,500, and 9,952,167 options as of December 31, 2011, 2010 and 2009, respectively; and (2) 21,994,982, 21,994,982, and 17,241,680 warrants as of December 31, 2011, 2010 and 2009, respectively.
Resale Restrictions. On December 31, 2011, we had 342,103,218 shares of common stock outstanding, of which 6,150,565 shares, or 1.8%, were subject to resale restrictions.
Preferred Stock. Our board of directors has the authority, without further action by the stockholders, to issue up to 500,000,000 shares of preferred stock in one or more series and to designate the rights, preferences, privileges and restrictions of each series. The issuance of preferred stock could have the effect of restricting dividends on the common stock, diluting the voting power of the common stock, impairing the liquidation rights of the common stock or delaying or preventing our change in control without further action by the stockholders. We have no present plans to issue any shares of preferred stock.
Warrants. The following table summarizes warrant transactions for the years ended December 31, 2011, 2010 and 2009.
| | | 2011 | | | 2010 | | | 2009 | |
| Outstanding at beginning of year | | | 21,994,982 | | | | 17,241,680 | | | | 12,618,222 | |
| Issued related to Current year's share placements | | | - | | | | 4,951,616 | | | | 12,043,458 | |
| Exercised | | | - | | | | - | | | | - | |
| Expired | | | - | | | | (198,314 | ) | | | (7,420,000 | ) |
Outstanding at end of year (1) | | | 21,994,982 | | | | 21,994,982 | | | | 17,241,680 | |
| (1) | The same amount of shares of our common stock authorized was reserved for the exercise of the warrants. |
Stock Options. In May 2005, our stockholders approved the 2005 Plan, which permits the granting of incentive stock options, stock appreciation rights, restricted stock, restricted stock units and other stock-based awards to employees, consultants and members of the board of directors. Our shareholders voted in December 2007 to add 4,000,000 shares of common stock to the 2005 Plan. At the annual general meeting of stockholders of the Company held on July 15, 2009, the Company's stockholders approved an amendment to the 2005 Plan which increased the number of shares of common stock issuable from 7,500,000 shares to 12,500,000 shares and increased the number of shares of common stock that may be granted as nonvested stock, nonvested stock units or any other stock-based awards from 2,400,000 to 3,900,000 shares.
At the annual meeting of stockholders of the Company held on October 11, 2011, the Company's stockholders approved an amendment to the 2005 Plan which increased the number of shares of common stock issuable from 12,500,000 shares to 22,000,000 shares and increased the number of shares of common stock that may be granted as restricted stock (nonvested shares), restricted stock units or any other stock-based awards from 3,900,000 to 8,000,000 shares.
During the first half of 2011, we awarded options to purchase up to 1,785,000 shares of our common stock and 1,669,800 nonvested shares under the 2005 Plan to employees and members of the board of directors; and options to purchase up to 250,000 shares of our common stock and 190,000 nonvested shares outside the 2005 Plan to a new employee and a consultant. As of December 31, 2011, we had 16,509,199 shares available for awards under the 2005 Plan, of which 4,206,699 shares could be issued as nonvested shares or other full-valued stock-based awards.
The weighted average remaining life of options exercisable at the end of the year is 4.23 years. The following table summarizes stock option transactions for the years ended December 31, 2011, 2010 and 2009:
| | | 2011 | | | 2010 | | | 2009 | |
| | | Shares Underlying Options | | | Weighted Average Exercise Price | | | Shares Underlying Options | | | Weighted Average Exercise Price | | | Shares Underlying Options | | | Weighted Average Exercise Price | |
| |
| |
| |
| Outstanding at beginning of year | | | 9,075,500 | | | $ | 1.18 | | | | 9,952,167 | | | $ | 1.14 | | | | 11,320,500 | | | $ | 1.25 | |
| Granted | | | 2,035,000 | | | | 0.58 | | | | - | | | | - | | | | 1,906,000 | | | | 0.40 | |
| Exercised | | | - | | | | - | | | | (100,000 | ) | | | 0.31 | | | | - | | | | - | |
| Canceled | | | (400,000 | ) | | | 2.28 | | | | (316,667 | ) | | | 0.82 | | | | - | | | | - | |
| Forfeited | | | (186,667 | ) | | | 0.52 | | | | (420,000 | ) | | | 0.63 | | | | (433,333 | ) | | | 0.54 | |
| Expired | | | - | | | | - | | | | (40,000 | ) | | | 2.00 | | | | (2,841,000 | ) | | | 1.16 | |
| Outstanding at end of year | | | 10,523,833 | | | | 1.04 | | | | 9,075,500 | | | | 1.18 | | | | 9,952,167 | | | | 1.14 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Options exercisable at end of year | | | 8,243,500 | | | | 1.17 | | | | 7,620,667 | | | | 1.32 | | | | 6,636,167 | | | | 1.41 | |
14. Subsequent Events
Subsequent events have been evaluated through the date financial statements were filed with the SEC. There were no items that would have a material impact to the consolidated financial statements presented in this Form 10-K.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Oil and Gas Reserve Information (Unaudited)
1. Modernization of Oil and Natural Gas Reporting Requirements
The reserve estimates as of December 31, 2011 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance issued by the Financial Accounting Standards Board. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s “Modernization of Oil and Gas Reporting” rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.
The above-mentioned rules include updated definitions of proved oil and gas reserves, proved undeveloped oil and gas reserves, oil and gas producing activities, and other terms used in estimating proved oil and gas reserves. Proved oil and gas reserves as of December 31, 2011were calculated based on the gas price of US$6.35/Mcf, (thousand standard cubic foot) in accordance with the gas sales agreement dated June 12 2010 and Chinese Government policy. The prices are based on the average price received and US dollar-RMB exchange rate on the first day of each month in 2011. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. The authoritative guidance broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of oil and gas producing activities to include the extraction of non-traditional resources, including bitumen extracted from oil sands as well as oil and gas extracted from shales.
| | 2. Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities |
Costs incurred in the acquisition and development of oil and gas assets are presented below for the years ended December 31, 2011, 2010 and 2009 (in thousands):
| | | 2011 | | | 2010 | | | 2009 | |
| Property acquisition costs: | | | | | | | | | |
| Proved | | $ | - | | | $ | - | | | $ | - | |
| Unproved | | | - | | | | - | | | | - | |
| Exploration | | | 5,967 | | | | 5,117 | | | | 4,501 | |
| Development costs | | | 16,878 | | | | - | | | | - | |
| Total costs incurred | | $ | 22,845 | | | $ | 5,117 | | | $ | 4,501 | |
3. Capitalized Oil and Gas Costs
Aggregate capitalized costs related to oil and gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below as of December 31, 2011 and 2010 (in thousands):
| | | 2011 | | | 2010 | |
| Capitalized costs: | | | | | | |
| Proved properties | | $ | 66,361 | | | $ | - | |
| Unproved properties | | | 1,899 | | | | 50,094 | |
| Less: accumulated depreciation, depletion, amortization and impairment | | | (744 | ) | | | - | |
| Net capitalized costs | | $ | 67,516 | | | $ | 50,094 | |
Unproved properties, which are not subject to amortization, are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the amortization calculation.
4. Proved Oil and Gas Reserves
An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within China, for the years ended December 31, 2011, is as follows:
| | | Year Ended December 31, 2011 | |
| | | Gas (MMcf) | | | Oil (MBbls) | | | NGL (MBbls) | | | Total (MMcfE) | |
| | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | | | | | | |
| Beginning of year | | | - | | | | - | | | | - | | | | - | |
| Revisions of previous estimates | | | - | | | | - | | | | - | | | | - | |
| Extensions, discoveries and other additions | | | 54,868 | | | | - | | | | - | | | | 54,868 | |
| Divestitures of reserves | | | - | | | | - | | | | - | | | | - | |
| Purchases of minerals in place | | | - | | | | - | | | | - | | | | - | |
| Production | | | (269 | ) | | | - | | | | - | | | | (269 | ) |
| End of year | | | 54,599 | | | | - | | | | - | | | | 54,599 | |
| | | | | | | | | | | | | | | | | |
| Proved developed reserves: | | | | | | | | | | | | | | | | |
| Beginning of year | | | - | | | | - | | | | - | | | | - | |
| End of year | | | 13,505 | | | | - | | | | - | | | | 13,505 | |
| Proved undeveloped reserves: | | | | | | | | | | | | | | | | |
| Beginning of year | | | - | | | | - | | | | - | | | | - | |
| End of year | | | 41,094 | | | | - | | | | - | | | | 41,094 | |
For the year ended December 31, 2011, the Company added 54.9 MMcf through extensions, discoveries and additions of wells in the Shouyang Block in Shanxi Province. It was determined for year ended December 31, 2010 that we were not able to predict exactly when we would recognize significant revenues and pending assessments to determine whether sufficient quantities of economically recoverable proved reserves would be found. The gas price used is US$6.35/Mcf, (thousand standard cubic foot) in accordance with the gas sales agreement dated June 12, 2010 and Chinese Government policy. The prices are based on the average price received and US dollar-RMB exchange rate on the first day of each month in 2011.
5. Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2011 are based on average price received and US dollar-RMB exchange rate on the first day of each month in 2011. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves, less the tax basis of the Company. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from
actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2011(in thousands):
| | | 2011 | | | 2010 | | | 2009 | |
| | | | | | | | | | |
| Future cash inflows | | $ | 384,279 | | | $ | - | | | $ | - | |
| Future production costs | | | (114,868 | ) | | | - | | | | - | |
| Future development costs | | | (76,844 | ) | | | - | | | | - | |
| Future income tax expenses | | | (10,024 | ) | | | - | | | | - | |
| Future net cash flows | | | 182,543 | | | | - | | | | - | |
| 10% discount for estimated timing of cash flows | | | (119,979 | ) | | | - | | | | - | |
| Standardized measure of discounted future net cash flows | | $ | 62,564 | | | $ | - | | | $ | - | |
| | | | | | | | | | | | | |
| Standardized measure of discounted future net cash flows, beginning of year | | $ | - | | | | - | | | | - | |
| Changes in the year resulting from: | | | | | | | | | | | | |
| Sales, less production costs | | | 3,295 | | | | - | | | | - | |
| Revisions of previous quantity estimates | | | - | | | | - | | | | - | |
| Extensions, discoveries and other additions | | | 65,407 | | | | - | | | | - | |
| Net change in prices and production costs | | | - | | | | - | | | | - | |
| Changes in estimated future development costs | | | - | | | | - | | | | - | |
| Previously estimated development costs incurred during the period | | | - | | | | - | | | | - | |
| Purchases of minerals in place | | | - | | | | - | | | | - | |
| Accretion of discount | | | - | | | | - | | | | - | |
| Divestiture of Reserves | | | - | | | | - | | | | - | |
| Net change in income taxes | | | (2,843 | ) | | | - | | | | - | |
| Timing differences and other | | | (3,295 | ) | | | - | | | | - | |
| Standardized measure of discounted future net cash flows, end of year | | $ | 62,564 | | | $ | - | | | $ | - | |
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Quarterly Financial Information (In Thousands, Except Per Share Data):
| | | Quarter Ended | | | | |
| | | March 31 | | | June 30 | | | September 30 | | | December 31 | | | Year | |
| 2011 | | | | | | | | | | | | | | | |
| Revenues | | $ | 31 | | | $ | 250 | | | $ | 268 | | | $ | 309 | | | $ | 858 | |
| Total expenses | | | 4,571 | | | | 4,450 | | | | 5,048 | | | | 6,517 | | | | 20,586 | |
| Net loss | | | (4,919 | ) | | | (4,460 | ) | | | (5,133 | ) | | | (6,733 | ) | | | (21,245 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Basic and diluted | | | | | | | | | | | | | | | | | | | | |
| - Earnings per share | | $ | (0.02 | ) | | $ | (0.01 | ) | | $ | (0.01 | ) | | $ | (0.02 | ) | | $ | (0.06 | ) |
| - Weighted average shares outstanding | | | 305,818 | | | | 342,212 | | | | 342,209 | | | | 342,119 | | | | 333,214 | |
| 2010 | | | | | | | | | | | | | | | | | | | | |
| Revenues | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Total expenses | | | 3,232 | | | | 3,297 | | | | 3,188 | | | | 5,014 | | | | 14,731 | |
| Net loss | | | (3,524 | ) | | | (3,614 | ) | | | (3,587 | ) | | | (5,448 | ) | | | (16,173 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Basic and diluted | | | | | | | | | | | | | | | | | | | | |
| - Earnings per share | | $ | (0.02 | ) | | $ | (0.02 | ) | | $ | (0.02 | ) | | $ | (0.02 | ) | | $ | (0.07 | ) |
| - Weighted average shares outstanding | | | 176,407 | | | | 185,609 | | | | 228,123 | | | | 291,203 | | | | 220,671 | |
SCHEDULE II
FAR EAST ENERGY CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
For Years Ended December 31, 2011, 2010 and 2009
(In thousands)
| | | | | | Additions | | | | | | | |
| | | Balance at Beginning of Period | | | Charged to Cost and Expense | | | Charged to Other Accounts | | | | | | Balance at End of Period | |
| | | | |
| Description | | Deductions | |
| 2011 deferred tax valuation allowance | | $ | 5,013 | | | $ | 2,846 | | | $ | - | | | $ | - | | | $ | 7,859 | |
| 2010 deferred tax valuation allowance | | | 3,727 | | | | 1,286 | | | | - | | | | - | | | | 5,013 | |
| 2009 deferred tax valuation allowance | | | 2,436 | | | | 1,291 | | | | - | | | | - | | | | 3,727 | |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.
Management's Report on Internal Control over Financial Reporting
Management's report on internal control over financial reporting as of December 31, 2011 is included on page 51 of this report. Additionally, our independent registered public accounting firm, JonesBaggett LLP, that audited our consolidated financial statements included in this report, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2011, which is included on page 53 of this report.
Changes in Internal Controls
In connection with the evaluation described above, our management, including our Chief Executive Officer and Chief Financial Officer, identified no change in our internal control over financial reporting that occurred during the fiscal quarter ended December 31, 2011, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B. OTHER INFORMATION
Not Applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Executive Officers and Board of Directors
The table below sets forth the names and ages of each of the members of our board of directors (the “Board”) and our executive officers, as well as the positions and offices held by such persons. A summary of the background and experience of each of these individuals is set forth after the table.
| Name | Age | Position |
| Donald A. Juckett | 67 | Chairman of the Board |
| Michael R. McElwrath | 60 | President, Chief Executive Officer and Director |
| William A. Anderson | 72 | Director |
| C. P. Chiang | 69 | Director |
| John C. Mihm | 69 | Director |
| Lucian L. Morrison | 74 | Director |
| Thomas E. Williams | 59 | Director |
| Bruce N. Huff | 61 | Chief Financial Officer |
Donald A. Juckett has served as a director since May 2004 and as Chairman of the Board since August 5, 2009. Dr. Juckett serves on the Compensation Committee of the Board. Dr. Juckett has more than fifteen years of experience in bilateral activities with Chinese state companies and Chinese government officials. He has broad bilateral experience involving technology and energy policy agreements, representing the U.S. Department of Energy with many countries. In November 2005, after retiring from the U.S. Department of Energy, Dr. Juckett established the Washington, D.C. Office of Geoscience and Energy for the American Association of Petroleum Geologists, the largest geosciences professional association in the world. He continues serving as Founding Director for the AAPG, Washington office. Prior to that, Dr. Juckett was self-employed as an industry consultant. He served at the U.S. Department of Energy from 1988 until his retirement in 2003. At his retirement, Dr. Juckett was Director of the Office of Natural Gas Import and Export Activities in the Office of Fossil Energy. During his tenure with the Department, he served as a member of the Senior Executive Service and held positions as the Director of Natural Gas and Petroleum Technology, Director of the Office of Geoscience Research and Acting Deputy Assistant Secretary for Natural Gas and Petroleum Technology. Dr. Juckett managed a portfolio of international projects, including technology bilateral agreements with China, Russia, Venezuela, Ukraine, Bangladesh, Canada and Mexico. Beginning in 1998, Dr. Juckett played a leading role in establishing and managing the U.S./China Oil Gas Industry Forum. In his technology management positions at the Department, he was responsible for research, development and technology transfer for both conventional and non-conventional oil and gas resources (including coalbed methane). From 1974 to 1988, Dr. Juckett worked for Phillips Petroleum Company, now known as ConocoPhillips, Inc. in management positions, including responsibility for exploration technologies support of five worldwide divisions. Those technology responsibilities ranged from geochemistry to satellite imagery. Dr. Juckett earned a B.S. degree in chemistry from the State University of New York-Oswego and a Ph.D. in chemistry from the State University of New York-Albany.
The Board selected Dr. Juckett to serve as a director because of his extensive senior management experience in the international oil and gas industry and his experience in the U.S. Department of Energy involving international projects and agreements, as well as his fifteen years of experience in bilateral activities with Chinese state companies and Chinese government officials. He brings extensive energy industry, international operations and management experience to the Board.
Michael R. McElwrath has served as the Company’s President and Chief Executive Officer since October 2003. He became a director in October 2003 and served as Chairman of the Board from October 2003 until January 2005. Mr. McElwrath also served as Secretary and Treasurer from October 2003 until March 2005. Mr. McElwrath has worked in or with the energy industry for over 30 years. He was employed as Vice President of Hudson Highland (formerly known as TMP Worldwide, a parent company of Monster.com), an executive search firm, from 1999 until joining the Company in October 2003. He also served as Acting Assistant Secretary of Energy in the George H.W. Bush (41st President of the United States) Administration, Director of the National Institute for Petroleum and Energy Research, Director of British Petroleum’s outsourced exploration and production lab for the Americas and Deputy Assistant Secretary for Policy for the U.S. Department of Interior in the Reagan Administration. Prior to joining the Reagan Administration, Mr. McElwrath practiced oil and gas and corporate law for approximately ten years. 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, the Research Partnership to Secure Energy for America (RPSEA), the World Affairs Council, and the National Association of Corporate Directors.
The Board selected Mr. McElwrath to serve as a director because his position as Chief Executive Officer provides strategic leadership for the Board. His extensive senior management experience in the oil and gas industry as well as in the United States government gives the Board the benefit of his management and operational insight. With Mr. McElwrath’s extensive executive experience, he brings strong financial and operational expertise to the Board.
William A. Anderson has served as a member of the Company’s Board since October 2007. Mr. Anderson is the chairman of the Audit Committee of the Board and has been designated as an “audit committee financial expert.” He also serves on the Compensation Committee of the Board. Mr. Anderson served as a consultant for Eastman Dillon Oil and Gas Association from 2006 through 2010. From 1989 through 2005, he was a founder and partner of Weller, Anderson & Co. Ltd., a full-service stock brokerage firm. Prior to founding Weller in 1989, Mr. Anderson held several senior executive positions, including President of HARC Technologies, President of Rainbow Pipeline Company, President of Farmers Oil Company, Chief Financial Officer of ENSTAR Corporation, and General Partner and Senior Vice President of Blyth, Eastman, Dillon & Co. Mr. Anderson has extensive corporate board experience, having served as a director, committee chairman and/or committee member for a number of organizations, including Rancher Energy Corp., Tom Brown, Inc., Equisales Associates, Inc., Dyson Corporation, NationsBank Houston, Northern Trust Bank of Texas, American Income Life Insurance Company, Wing Corporation and Seven J-Stock Farm, Inc. He holds an MBA from the Harvard Business School and a B.S. in Business Administration from the University of Arkansas.
The Board selected Mr. Anderson to serve as a director because of his extensive senior management experience in both the oil and gas and financial industries, as well as his experience as a member of several corporate boards and as an executive. Mr. Anderson qualifies as an audit committee financial expert and brings strong financial expertise and experience to the Board.
C.P. Chiang has served on the Board since December 2006. He also serves on the Nominating and Corporate Governance Committee of the Board. From 2001 until his retirement in 2006, Mr. Chiang served as the China Project Manager/Country Manager of Burlington Resources, an energy company engaged in exploration, production, refining and marketing oil and gas, where he was responsible for managing the operations and activities of Burlington Resources in China and worked closely and negotiated with various Chinese governmental organizations. Throughout his 40 year career in the oil and gas industry, Mr. Chiang has held various engineering and management positions with oil and gas companies including British Gas E&P, Inc., Tenneco Oil Production and Exploration and Exxon Oil Company, now known as Exxon Mobil Corporation. Mr. Chiang earned a B.S. degree in mining engineering from National Cheng Kung University in Taiwan and an M.S. degree in petroleum engineering from New Mexico Institute of Mining and Technology.
The Board selected Mr. Chiang to serve as a director because of his extensive experience in the oil and gas industry, specifically in China, a key region to the Company’s operations. Mr. Chiang has held various management and engineering positions with multiple oil and gas companies. Mr. Chiang brings extensive operational and executive experience and expertise to the Board.
John C. Mihm has served as a director since May 2004. He served as Chairman of the Board from January 2005 through June 2007. Mr. Mihm currently serves on the Audit Committee and the Nominating and Corporate Governance Committee of the Board. He serves on the board of eProjectManagement and HNNG, a company involved in removing nitrogen from natural gas, and also serves as HNNG’s Chief Operating Officer. Mr. Mihm is the owner and President of JCM Consulting, PLLC, which provides services in the engineering, construction, and project management field. From 1964 until his retirement in 2003, Mr. Mihm worked for Phillips Petroleum Company, now known as ConocoPhillips, Inc., in various management positions, finally serving as Senior Vice President of Technology and Project Development. Mr. Mihm’s career includes over 20 years of work experience in China in offshore development and onshore coalbed methane exploration, working closely with China National Petroleum Corporation, China National Offshore Oil Corporation and SINOPEC on several joint ventures and employee development programs. He is a past board member of The Society of Petroleum Engineers and the ASME Foundation. Mr. Mihm is a registered professional engineer in Texas and Oklahoma. Mr. Mihm earned a B.S. degree in chemical engineering from Texas Tech University and serves on or has served on advisory boards at Texas Tech University, Oklahoma State University, University of Tulsa, University of Texas, Colorado School of Mines, Georgia Tech and University of Trondheim.
The Board selected Mr. Mihm to serve as a director because it believes that he has extensive experience in the oil and gas industry, specifically in offshore development in China and onshore coalbed methane exploration in the United States. He also has worked closely with a number of key oil and gas companies in China. Mr. Mihm brings extensive financial, engineering, operational and management experience to the Board.
Lucian L. Morrison was appointed to the Board in January 2008. Mr. Morrison is the chairman of the Compensation Committee of the Board. He also serves as a member of the Audit Committee of the Board and has been designated as an “audit committee financial expert.” Mr. Morrison currently serves as a director, audit committee member, compensation committee member and investment committee member of Erie Indemnity Company. Additionally, Mr. Morrison served as a director of Encore Trust Company from 2005 to 2007 and of Encompass Services, Inc. from 1997 to 2003. He founded Heritage Trust Company in 1979 and served as its CEO until 1990 when he sold it to Northern Trust Bank of Texas. He served as director and chairman of the Trust Committee of Northern Trust Bank of Texas from 1990 until 1992. He co-founded Sentinel Trust Company in 1997 and continues to serve as a consultant to the company and its other founders, and a director and a member of the company’s investment committee. From 1998 to 2002, he was chairman of Wing Corporation, a private exploration and production company. Mr. Morrison serves as an independent trustee and consultant in trust, estate, probate and qualified plan matters and also manages oil and gas properties in Texas. He is also a development board member of the University of Texas Houston Health Science Center. He holds a J.D. from the University of Texas School of Law, a graduate degree from the Southern Methodist University Southwestern Graduate School of Banking, Trust Division and a B.B.A. in Accounting from the University of Texas School of Business Administration.
The Board selected Mr. Morrison to serve as a director because of his extensive senior management experience in the financial industry, his experience managing oil and gas properties and his experience serving on various boards of directors. Mr. Morrison qualifies as an audit committee financial expert and brings extensive financial expertise and experience to the Board, and also qualifies as an audit committee financial expert.
Thomas E. Williams has served as a director since February 2004. Mr. Williams is the chairman of the Nominating and Corporate Governance Committee of the Board and serves on the Audit Committee of the Board. Mr. Williams served as Chairman of the Board from June 2007 through August 2009. He was Managing Director and President of Nautilus International LLC, an offshore drilling technology solutions provider, until the end of 2011 and is a consultant and Sr. Advisor to Environmentally Friendly Drilling Project, a project Mr. Williams initiated in 2005. From 2000 until 2007, Mr. Williams served as Vice President, Research and Business Development of Noble Technology Services, a wholly-owned subsidiary of Noble Corporation, a provider of diversified drilling and other services to the oil and gas industry. Mr. Williams also served as President of Maurer Technology Inc., a leading drilling R&D and engineering technology company and a wholly-owned subsidiary of Noble Corporation. He held senior executive positions at the U.S. Departments of Energy and Interior during the George H.W. Bush Administration from 1989 to 1993. From 1993 to 2000, he was Business Development Director at Westport Technology Center in Houston, an upstream oil and gas research company. He was a co-founder and served on the Board of Cementing Solutions, Inc., an oil and gas cementing services and technology company based in Houston, Texas. He has been in the oil and gas industry for over 30 years, having owned and operated an oil and
gas exploration, production and consulting company prior to joining the Department of Energy. Mr. Williams has authored more than 100 energy publications, presentations and articles and serves on a number of oil and gas organizations, associations and boards including the Research Partnership to Secure Energy for America (RPSEA), Independent Petroleum Association of America, the Society of Petroleum Engineers, American Association of Drilling Engineers, DeepStar Consortium Contributors Advisory Board, Nautilus International, Petris Technologies and the Environmentally Friendly Drilling Consortium. He has a B.S. degree in business from Campbellsville College.
The Board selected Mr. Williams to serve as a director because it believes that he has extensive experience in the oil and gas industry in both the public and private sector. Mr. Williams brings extensive management and operational experience to the Board.
Bruce N. Huff was appointed as the Company’s Chief Financial Officer on April 19, 2010. Previously, Mr. Huff served as the Company’s Chief Financial Officer from May 2004 until his resignation in September 2007. Prior to joining the Company in 2004, Mr. Huff spent 13 years at Harken Energy Corporation, an oil and gas exploration, development and production company, beginning as Senior Vice President and Chief Financial Officer and eventually becoming the President and Chief Operating Officer in 1998. From October 2007 through October 2008, Mr. Huff served as Chief Financial Officer of Opal Energy Corp, an oil and gas exploration company focusing on natural gas exploration in the Gulf Coast of Texas. He then served as an independent consultant for various oil and gas companies from October 2008 until rejoining the Company in April 2009 as the Company’s Vice President – Capital Development, assisting the Company in raising funds for its drilling and exploration programs. He is a graduate of Abilene Christian University and a Certified Public Accountant.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our officers, directors and persons who own more than ten percent of our common stock to file reports of ownership and changes in ownership with the SEC. Officers, directors and greater than ten percent stockholders are required by the SEC’s regulations to furnish us with copies of all Section 16(a) reports they file. Based solely on our review of the copies of such forms received by us, we believe that all filing requirements applicable to our officers, directors and greater than ten percent stockholders for the year ended December 31, 2011.
Code of Ethics
We have adopted a code of ethics entitled “Code of Business Conduct,” which applies to all employees, including our chief executive officer and chief financial officer. The full text of our Code of Business Conduct is published on our website, at www.fareastenergy.com, under the “Investor Relations” caption. We intend to disclose future amendments to, or waivers from, certain provisions of this code on our website within four business days following the date of such amendment or waiver. Information contained on the website is not part of this report.
Audit Committee
The Audit Committee was established in accordance with Section 3(a)(58)(A) of the Exchange Act and assists the Board and management of the Company in ensuring that we consistently act with integrity and accuracy in financial reporting. The Board has adopted a written charter for the Audit Committee. The Audit Committee’s responsibilities include:
| | · | selecting and reviewing our independent registered public accounting firm and their services; |
| | · | reviewing and discussing with appropriate members of management the audited financial statements, related accounting and auditing principles, practices and disclosures; |
| | · | reviewing and discussing our quarterly financial statements prior to the filing of those quarterly financial statements; |
| | · | establishing procedures for the receipt of, and response to, any complaints received regarding accounting, internal accounting controls, or auditing matters, including anonymous submissions by employees; |
| | · | reviewing the accounting principles and auditing practices and procedures to be used for the audit of our financial statements and reviewing the results of those audits; and |
| | · | monitoring the adequacy of our operating and internal controls as reported by management and the independent registered public accounting firm. |
William A. Anderson is the chairman of the Audit Committee and the other members of the Audit Committee are John Mihm, Lucian L. Morrison and Thomas E. Williams. The Board has determined that each member of the Audit Committee is independent within the meaning of the NYSE Amex Company Guide and satisfies the NYSE Amex listing standards financial sophistication requirements. The Board has determined that both William A. Anderson and Lucian L. Morrison are “audit committee financial experts” as that term is defined under Item 407 of Regulation S-K. The Board of Directors has adopted a written charter for the Audit Committee, and a current copy of the charter is available on our website at www.fareastenergy.com under the “Investor Relations” caption.
ITEM 11. EXECUTIVE COMPENSATION
Compensation Committee Interlocks and Insider Participation
Lucian Morrison, Donald A. Juckett and William A. Anderson serve on the Compensation Committee. Our independent directors are, and we expect they will continue to be, the only members of the Compensation Committee. None of our directors or executive officers has a relationship with us or any other company that the SEC defines as a compensation committee interlock or insider participation that should be disclosed to stockholders.
Report of the Compensation Committee
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis below with management, and based on reviews and discussions, the Compensation Committee recommended to the Board, and the Board has approved, that it be included in this report and in our 2012 Proxy Statement.
Lucian Morrison, Chairman of the Compensation Committee
William A. Anderson
Donald A. Juckett
COMPENSATION DISCUSSION AND ANALYSIS
Process for Determining Compensation
It is the responsibility of the Compensation Committee of our Board to set compensation for executive officers and directors, to establish and administer an overall compensation program that promotes the long-term interests of the Company and our stockholders, and to evaluate performance of executive officers
The Compensation Committee uses information supplied by various sources, which can include information provided by Company management and outside compensation consultants, to assist it in determining compensation for our executive officers. Management’s role is primarily to provide information relevant to performance measurement of the Company and our executives. At the request of the Compensation Committee, our Chief Executive Officer provides informal evaluations of the performance of the executives that report directly to him and may make recommendations as to base compensation and performance awards for these individuals. Additionally, our Chief Executive Officer works with the Compensation Committee in determining appropriate criteria for evaluating individual and Company performance. Due to the small size of our company, the Compensation Committee is able to make or specifically approve virtually all decisions regarding executive compensation and, therefore, the delegation of the committee’s authority in this regard is very limited. The Compensation Committee has engaged the compensation consulting firm of Towers Watson, from time-to-time, to provide various analyses related to our stock plan and compensation levels since 2004. Towers Watson was selected by the Compensation Committee and reports directly to it. They have performed no other work for us and have no other outside relationship to the Company’s directors or officers.
Compensation Philosophy and Objectives
In setting overall total compensation for executive officers, the Compensation Committee strives to achieve and balance the following objectives:
| | · | hiring and retaining executive officers with the background and skills to help us achieve our company’s objectives; |
| | · | aligning the goals of executive officers with those of the stockholders and the Company; |
| | · | motivating executive officers to achieve the Company’s important short, medium and long-term goals; |
| | · | conserving cash by setting compensation levels consistent with market conditions and taking into consideration the Company’s financial condition; and |
| | · | providing sufficient ongoing cash compensation to retain executives in a competitive marketplace. |
The philosophy we use in setting compensation levels and structures is based on the following principles:
| | · | compensation for our executive officers should be strongly linked to strategic and operational performance; |
| | · | compensation should consist of an increasingly higher percentage of compensation that is at risk and subject to performance-based awards as an executive officer’s range of responsibility and ability to influence the Company’s results increases; |
| | · | compensation should be fair and competitive in relation to the marketplace and our financial condition; |
| | · | employment retention incentives should be used to equalize our employment opportunities with those of more mature companies, to the extent appropriate; |
| | · | sense of ownership and long-term perspective should be reaffirmed through our compensation structure; and |
| | · | outstanding achievement should be recognized. |
Setting Executive Compensation
The Compensation Committee annually reviews and approves the base salaries, bonuses and equity awards of our executive officers. During 2011, our executive officers consisted of:
| | Name | Position |
| | Michael R. McElwrath | President, Chief Executive Officer and Director |
| | Bruce N. Huff | Chief Financial Officer |
We use a combination of compensation elements in our executive compensation program, including:
| | · | cash incentive bonuses; |
| | · | post-termination compensation; and |
Salaries and bonuses are our primary forms of cash compensation. We try to provide a reasonable amount of cash compensation to our employees to retain their executive talent in a competitive marketplace. We provide short-term incentives by awarding annual cash bonuses determined by the Compensation Committee on a discretionary basis. The bonuses reward achievement of short-term goals and allow us to recognize individual and team achievements. The cash portion of our compensation structure consists of a higher percentage of salary as compared to bonus. Cash incentive bonuses and equity awards are our two forms of performance-based compensation.
We provide long-term incentives through equity awards, which have consisted of stock options and grant awards of restricted stock that vest over time. Equity awards are a non-cash form of compensation. We believe equity awards are an effective way for us to reward achievement of long-term goals, conserve cash resources and create a sense of ownership in our executives. Options become valuable only as long-term goals are achieved and our stock price rises. They provide our executive officers with a personal stake in the performance of the Company’s equity even before vesting. Similarly, restricted stock awards that vest over time reward increases in our stock price while also providing a retention incentive to foster a sense of ownership even in a negative stock market environment. In most years, a large percentage of the total compensation paid to our executive officers consists of equity awards because we believe this is consistent with our philosophy of paying for performance and requiring more compensation to be at risk for employees at the highest level.
Our executive officers have also entered into employment agreements that have defined termination benefits, which we believe, in part, compensate for the potentially lower annual salary at our company as compared to more mature companies by providing security. Our employment agreements as well as our equity awards generally provide compensation to our executive officers if they are terminated within 24 months of a change in control of the Company, which helps encourage our executives to devote a maximum amount of their time and energies to the
Company through a change of control and beyond, while compensating them for the reduction in job security during a period of transition. The competitive compensation and the employment agreements foster an environment of relative security within which we believe our executives will be able to focus on achieving Company goals. For further discussion of the employment agreements with our executive officers, see “Narrative to Summary Compensation Table and Grants of Plan-Based Awards Table – Employment Agreements with Executive Officers.”
Total Compensation and Description and Allocation of Its Components
Total Compensation. The Compensation Committee reviews total compensation for executive officers annually when they evaluate existing salaries and determine annual cash bonuses.
The Compensation Committee blends the components of compensation to achieve a total compensation package that is weighted toward the equity component. This is consistent with our objective of emphasizing equity awards and conserving cash.
Generally, equity awards for executive officers have historically constituted a larger percentage of total compensation. During 2011, the Company granted both options and restricted stock to executive officers. For further information, see “2011 Summary Compensation Table,” “2011 Grants of Plan-Based Awards Table” and “Narrative to Summary Compensation Table and Grants of Plan-Based Awards Table.”
Decisions regarding salary increases, bonus awards and equity awards are ultimately at the discretion of the Compensation Committee. However, in making these decisions, the committee considers the achievements of the Company in the previous fiscal year, such as the obstacles overcome in our exploration efforts, the successful negotiation of critical commercial documents such as the PSC modification agreements and gas sales agreements, the progress toward commercial gas production and revenues, the successful capital raises to funding for the Company’s ongoing activities, and reasonable management of expenditures.
In addition to the Company’s achievements, the Compensation Committee reviews the accomplishments and performance of the individual executive officers. For 2011, in reviewing the Company and individual performance and as part of the determination of compensation, the Compensation Committee considered, among other things, the Company and individual performance factors described below:
During its review of the 2011 performance criteria, the Compensation Committee gave approximately twenty percent of the weight of its evaluation of each executive officer based on the Company performance factors. The remainder of the evaluation of each executive officer was based on individual performance factors and other considerations. These performance factors were also discussed with the applicable executive officers. The performance factors had a significant impact on the Compensation Committee’s decisions regarding discretionary adjustments to the cash incentive bonuses for 2011, although they were not given any numerical weight in determining the amount of such bonuses. The committee also considered the 2011 performance factors in determining salary increases for 2012.
In 2012, the Compensation Committee plans to continue to implement guidelines under which performance at the executive level can be measured with simplicity and transparency and performance awards can be granted in relation to those performance measures. For an early stage company, appropriate, reliable performance measures can be difficult to identify. However, we will seek to identify measurements that are appropriate to an early stage company and which will relate to the achievement of Company goals, particularly in the areas of drilling and production and appropriate management of our cash resources. For 2012, the Compensation Committee intends to set performance measures based on both Company and individual performance factors and to adopt target bonuses based on a percentage of the executive’s base salary. The committee expects that the maximum bonus that an executive may earn will be set at a specified percentage of the executive’s base salary. The executive’s ability to earn that maximum bonus or percentage of salary is largely dependent upon achievement of individual performance factors for the year. The committee believes these performance factors will be a very strong factor in making bonus decisions and may influence salary adjustments and equity awards. However, the Compensation Committee plans to continue to use its discretion in making these compensation decisions.
Salaries. The Compensation Committee reviews salaries for our executive officers annually near the beginning of the year and, in most years, adjustments to salaries, if any, have been made effective as of January 1 of that year. Initial base salaries are set forth in the executive’s employment agreement. The level of salary is determined by market factors when the executive officer is hired and are adjusted as necessary during the annual review of salary. Infrequently, specific circumstances may prompt a salary change outside the usual review schedule. The Compensation Committee evaluates adjustments to salary based, in part, on the Company and individual performance criteria. If an executive has changed or increased his level of responsibility within the Company, the Compensation Committee also considers a commensurate change in salary.
In February 2011, the Compensation Committee approved a salary increase of 20% for Michael R. McElwrath and a salary increase of 20% for Bruce N. Huff. These increases were made to maintain market competitiveness, without targeting any specific percentile, and to adjust for increases in cost of living. In January 2012, the Compensation Committee approved salary increases of 5% for Michael R. McElwrath and Bruce N. Huff. These salary increases were made to maintain market competiveness, without targeting any specific percentile, and to adjust for increases in cost of living and this percentage increase was at or below the percentage increases at the Company generally.
Bonuses. The Compensation Committee awards cash incentive bonuses each year, typically early in the first quarter, for performance during the previous fiscal year. For 2011, the Compensation Committee set performance measures based on both Company and individual performance factors and adopted target incentive bonuses based on a percentage of the executive’s base salary. In the case of Mr. McElwrath the target incentive bonus was set at 65% of his base salary for the applicable year; and for Mr. Huff the target incentive bonus was set at 45% of base salary for the applicable year. The executive’s ability to earn that maximum bonus or percentage of salary was largely dependent upon achievement of individual and company performance factors. These standards were established for Mr. McElwrath and for Mr. Huff in the first quarter of 2011. These performance measures were a very strong factor in making the bonus decisions and influenced equity awards. However, the Compensation Committee continues to use its discretion in making these compensation decisions.
In January 2012, the Compensation Committee approved a $257,985 cash bonus for Michael R. McElwrath in an amount equal to 65% of Mr. McElwrath’s stated 2011 base salary and a $121,500 cash bonus for Bruce N. Huff in an amount equal to 45% of Mr. Huff’s stated 2011 base salary after considering the following performance factors:
Mr. McElwrath
| Performance Factors | Target | Actual |
| Company Performance Factor | | |
| Safety – 0 fatalities and 0 - 2 days away from work cases (DAFWC) | 20% | 20% |
| Individual Performance Factors | | |
| Obtain Shouyang exploration period extension of not less than 2 years and relinquish no more than 33% of acreage | 30% | 30% |
| Successful capital raise of $15 - 30 million | 30% | 30% |
| Production of 1,000 – 3,000 mcfpd at 12/31/2011 | 10% | 0% |
| Substantial progress towards joint venture or other strategic transaction (subjective determination) | 10% | 10% |
| Additional Performance Goals (not weighted) | | |
| Secure SEC and Chinese reserves report | | Attained |
| Maintain strong business relationships at senior with Chinese counterparties | | Attained |
| Take necessary steps to move towards ODP in Shouyang block | | Attained |
| | | |
| Total | 100% | 90%(1) |
(1) In light of Mr. McElwrath’s attainment of the additional performance goals, the Compensation Committee used its discretion to increase his cash incentive bonus for 2011 from 58.5% to 65% of his stated base salary.
Mr.Huff
| Performance Factors | Target | Actual |
| Company Performance Factor | | |
| Safety – 0 fatalities and 0 – 2 days away from work cases (DAFWC) | 20% | 20% |
| Individual Performance Factors | | |
| Successful capital raise of $15 – 30 million | 30% | 30% |
| Compile materials necessary for SEC reserves report (subjective determination) | 10% | 7.5% |
| Successfully manage preparation of all financial statements and timely SEC filings (subjective determination) | 10% | 10% |
| Maintain sufficient internal controls over financial reporting (subjective determination) | 10% | 10% |
| Assure compliance with all financial instruments | 5% | 5% |
| Manage cash position of the Company: provide timely cash projections to the CEO, Board and auditors: manage ongoing maintenance of cash flow projections and project economics to support financing transaction and operational planning (subjective determination) | 5% | 5% |
| Provide timely support for investor relations (subjective determination) | 5% | 5% |
| Establish and maintain a satisfactory system of control, coordination and up-to-date- tracking of all contracts and agreements, transaction documents, stock options, restricted stock, warrant agreements and shareholder transactions, and all other corporate documents (subjective determination) | 5% | 2.5% |
| | | |
| Total | 100% | 95%(1) |
(1) In light of Mr. Huff’s strong performance with financial planning and transaction execution, the Compensation Committee used its discretion to increase his cash incentive bonus for 2011 from 42.75% to 45% of his stated base salary.
The Compensation Committee used similar methodology to determine the cash incentive bonuses for the other senior managers of the Company.
Equity Awards. Equity awards are an important component in our compensation structure, particularly because we are an early stage company and it is important for us to conserve cash resources. Equity awards may be granted at a date other than the date that salary and bonus decisions are made but are typically granted during the first quarter of the year. Beginning in 2007, the Compensation Committee began to use grants of restricted stock in addition to awards of non-qualified stock options in its equity award component of compensation and has continued the process of utilizing both equity vehicles in its annual equity awards.
Choice of equity vehicles. We use grants of options to purchase our common stock for the equity awards granted to our executive officers. Stock options effectively align our executives’ goals with those of stockholders and motivate executive officers to achieve our long-term goals. Our option agreements typically include both time-vesting and termination forfeiture terms, which assist us in inducing the employment and retention of executive officers by providing a financial incentive related to retention. The Compensation Committee plans to continue to utilize options awards.
In addition, the Compensation Committee also utilizes restricted stock for equity awards. The committee considered that the use of this form of equity in some cases, rather than options, would reduce dilution to our existing stockholders, provide equity participation in our Company to these executives and reduce the overall number of shares granted. The Compensation Committee believes that decreasing the dilutive effect related to our equity awards will assist in preserving the economic value of our existing stockholders. The committee also
believes that shares of time-vesting restricted stock will encourage achievement of long-term goals and retention of key executives in a similar manner as option awards while also providing a retention incentive to foster a sense of ownership even in a negative stock market environment. The Compensation Committee plans to continue to grant options and/or restricted stock in the future to our executive officers.
Determining the size of the equity award. We use equity awards as both a reward for past performance and an incentive for future performance. The Compensation Committee has historically approved discretionary equity award grants to executive officers during the first quarter of the year.
Each of our executive officers received a grant of equity awards upon joining the Company, providing them with an initial equity stake and a long-term incentive. The size of these initial grants is determined primarily by market factors, with such grants offered as an inducement to accept our offer of employment. Although it has typically granted additional awards annually, the Compensation Committee is not bound to make continuing equity awards to executive officers, and in fact, does not in every case. Factors considered by the committee in determining whether an executive receives an award of options and/or restricted stock and the size and vesting schedule of that award include the following:
| | · | the performance indicators and the events and accomplishments used to determine total compensation, as described above; |
| | · | the cumulative number of shares and terms (including option exercise price) of previous equity awards, which may, in the view of the Compensation Committee, be sufficient to achieve the goals of the equity award program for a given individual, without supplement in a particular year; |
| | · | the estimated fair value of the award (using the Black-Scholes option pricing model for options) and its impact on the executive’s total compensation; |
| | · | the estimated impact of the expense of the award on reported income in the year of the award and subsequent years; |
| | · | the stockholder dilution, including overhang of existing options and warrants for our common stock; |
| | · | the shares remaining available for grants under the 2005 Plan; and |
| | · | the tax consequences related to the vesting of the equity awards. |
2005 Stock Incentive Plan awards. Since its approval by our stockholders in 2005, with certain exceptions described below, we have granted options and restricted shares to executive officers under the 2005 Plan. Our grants to executive officers under the 2005 Plan have historically had a vesting period of three to four years from date of grant and a term of up to ten years. Typically, our option awards provide for forfeiture of unexercised options after a period of 60 to 90 days after the applicable executive’s termination of employment with the Company.
Awards granted outside the 2005 Plan. Prior to the adoption of the 2005 Plan, grants of options to executives included varying terms, some differing from the above. Since the adoption of the 2005 Plan, we generally do not grant any awards outside the 2005 Plan except for inducement equity awards. These awards contained terms similar to those made under the 2005 Plan. The Compensation Committee may continue to grant options and/or restricted stock outside of the 2005 Plan, particularly for inducement grants to newly appointed executive officers and directors.
Expense recognition. All compensatory options and restricted stock are expensed over time in accordance with generally accepted accounting principles. For information on the equity award expense recognized in 2011 for each executive officer, see “Summary Compensation Table - Option Awards” and “Summary Compensation Table - Restricted Stock Awards.” For further details regarding 2011 equity grants to our named executive officers, see the
“Grants of Plan-Based Awards” table. For further information on the 2005 Plan, see “Narrative to Summary Compensation Table and Grants of Plan-Based Awards Table - 2005 Stock Incentive Plan” and “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters – Equity Compensation Plan Information.”
Procedures for granting equity awards. We have generally granted any equity awards to our executive officers annually during the first quarter of each fiscal year or at employment. Since the adoption of the 2005 Plan, options are dated and assigned exercise prices as of the nearest trading date to the meeting of the Compensation Committee in which such awards were approved. Exercise prices for option grants during 2011 have been set at the fair market value on the date of grant or higher. For purposes of determining exercise prices for our stock option awards, the fair market value of our common stock, on a given date, means the average of the closing bid and asked prices of the shares of common stock as reported that day on the OTC Bulletin Board. We intend to continue this practice. We attempt to avoid issuing options near the time of any expected significant movement in our stock price by taking care, within reason, not to schedule these meetings in proximity to upcoming or recent announcements of significance, such as earnings releases or other public announcements relating to current or future profitability. Scheduling of meetings of the Compensation Committee is also impacted by availability of personnel and the need to make timely hiring decisions and cannot be perfectly aligned with regard to public announcements. Under the 2005 Plan, the Chief Executive Officer, as long as he is a member of the Board, has the authority to grant equity awards of up to an aggregate of 200,000 shares of common stock in each calendar year to employees that are not subject to the rules promulgated under Section 16 of the Exchange Act. The exercise prices for such grants made by the Chief Executive Officer are to be based on the date the award agreement is signed, which is as soon as possible after the decision to make the award is settled. In practice, all awards have usually been approved by the Compensation Committee.
Awards have also been granted to new executive officers and incumbent directors on or near the date of hire or election. Our current practice is to grant, date and price options to new executives on the date of hire, which is not the date of their acceptance of our offer of employment, but rather, the first day they report for work at the Company. Similar to option awards, our current practice is to grant and date restricted stock awards on the first day the executive reports for work at the Company. Grants to newly elected directors are generally awarded at the first meeting of the Compensation Committee after their election.
Post Termination Compensation. We have employment agreements with all of our named executive officers. All of our executive employment contracts provide some form of termination benefits. As an early stage company whose future may be uncertain, we believe it is necessary to provide contractual assurance of continued employment to our executives, and that without such assurances, our recruitment efforts would not be as successful.
Our executive employment agreements provide for termination benefits, including in certain cases upon a change in control. These clauses assist us in attracting and retaining executive officers and are designed to provide stable leadership for the Company during any potential or actual change of control. With the assurance of these benefits, we believe our executives will be better able to objectively evaluate offers to purchase the Company or other forms of potential change of control. The clauses also encourage continuation of the leadership and experience of our key executives after a change in control, at least through a period of transition.
For further discussion of the terms of each employment agreement, see “Narrative to Summary Compensation Table and Grants of Plan-Based Awards Table – Employment Agreements with Named Executive Officers.”
Perquisites and Other Benefits. We provide health insurance to our executive officers, which is the same as that provided to our other U.S. employees. We also provide matching contributions for those U.S. employees who contribute to a Simple Individual Retirement Account (“Simple IRA”), matching up to 3% of annual salary, subject to certain caps provided by tax regulation. These benefits were approved by the Compensation Committee when adopted. We also provide additional pay to our U.S. executive officers working in China to compensate those executives for living outside the U.S. The additional payments will be determined based on what we believe market compensation is when each is hired.
Tax and Accounting Considerations
Section 162(m) of the Code generally disallows a tax deduction to public companies for compensation in excess of $1 million paid to any executive officer unless such compensation is paid pursuant to a qualified performance-based compensation plan. All compensation awarded to our executive officers in 2011 is expected to be tax deductible. The Compensation Committee considers such deductibility and the potential cost to the Company when granting awards and considering salary changes.
We account for equity awards under the provisions of Statement of Financial Accounting Standard No. 123 (revised 2004), Share-Based Payment (“FAS No. 123(R)”). We charge the estimated fair value of option and restricted stock awards to income over the time of service provided by the employee to earn the award, typically the vesting period. The fair value of options is measured using the Black-Scholes option pricing model. The fair value of restricted stock awards is measured by the closing price of our common stock on the date of the award, with no discount for vesting period or other restrictions. The compensation expense to the Company under FAS No. 123(R) is one of the factors the Compensation Committee considers in determining equity awards to be granted, and also may influence the vesting period chosen.
Named Executive Officer Compensation
With respect to the 2011 total compensation of Mr. McElwrath and Mr. Huff, 63% of total compensation was attributable to the elements of salary and annual cash bonus and 37% of total compensation was attributable to non-cash equity elements. The allocation between cash and non-cash compensation for our executive officers was within the range of allocations that the Compensation Committee considers appropriate.
COMPENSATION TABLES AND ADDITIONAL INFORMATION
The following table sets forth a summary of compensation paid to our Chief Executive Officer and Chief Financial Officer, and one other of the most highly paid persons serving as executive officers (the “Named Executive Officers”) for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, 2009.
2011 Summary Compensation Table
| Name and Principal Position | Year | | Salary | | | Bonus | | | | Stock Awards (1) | | | Option Awards (1) | | | All Other Compen-sation | | | | Total | |
| Michael R. McElwrath | 2011 | | $ | 388,631 | | | $ | 257,985 | | (2) | | $ | 252,184 | | | $ | 131,610 | | | $ | 1,531 | | (3) | | $ | 1,031,941 | |
| President and Chief | 2010 | | | 330,750 | | | | 255,000 | | (4) | | | - | | | | - | | | | 18,069 | | | | | 603,819 | |
| Executive Officer | 2009 | | | 330,750 | | | | 40,000 | | | | | 123,750 | | | | 48,819 | | | | 4,575 | | | | | 547,894 | |
| Bruce N. Huff | 2011 | | | 264,375 | | | | 121,500 | | (2) | | | 147,900 | | | | 76,773 | | | | 3,375 | | (3) | | | 613,923 | |
| Chief Financial Officer | 2010 | | | 203,125 | | | | 151,250 | | (5) | | | 121,000 | | | | - | | | | 9,400 | | | | | 484,775 | |
| | 2009 | | | 106,250 | | | | 10,000 | | | | | 13,750 | | | | 20,270 | | | | 4,650 | | | | | 154,920 | |
K. Andrew Lai (6) | 2010 | | | 70,375 | | | | - | | | | | - | | | | - | | | | 7,284 | | | | | 77,659 | |
| Chief Financial Officer | 2009 | | | 195,000 | | | | - | | | | | 13,750 | | | | 20,270 | | | | 2,844 | | | | | 231,864 | |
| (1) | The amounts in this column reflect the value of stock or option awards, as applicable, granted to each Named Executive Officer as determined in accordance with FASB ASC Topic 718. See Note 12 to the consolidated financial statements included in Part II of this report for assumptions used in valuing these awards and the methodology for recognizing the related expense. All options awards are for the purchase of our common stock. Stock awards are grants of restricted stock with time-based vesting conditions. The Company did not grant any option awards during 2010. Mr. McElwrath did not receive any stock awards during 2010. |
| (2) | The bonus for Mr. McElwrath and Mr. Huff is for performance in 2011, none of which was paid during the year of performance. |
| (3) | Represents the cost of matching funds to the Named Executive Officer’s account in the Company’s defined contribution savings plan. |
| (4) | The amount of bonus for Mr. McElwrath in 2010 is made up of two elements: (1) a $215,000 incentive bonus paid in 2011 for performance during 2010, and (2) a $40,000 retention bonus paid during 2010 as required under Mr. McElwrath’s then effective employment agreement, which has since been amended to, among other things, eliminate the fixed retention bonus. |
| (5) | The amount of bonus for Mr. Huff in 2010 is made up of two elements: (1) $101,250 incentive bonus paid in 2011 for performance during 2010, and (2) a $50,000 signing bonus awarded in conjunction with Mr. Huff’s appointment as Chief Financial Officer in April, 2010. |
| (6) | Mr. Lai resigned as Chief Financial Officer of the Company effective April 19, 2010. |
Grants of Plan-Based Awards in 2011
The following table provides information on equity awards granted during 2011:
| Name | | Grant Date (1) | | All Other Stock Awards: Number of Shares of Stock or Units (#) | | | All Other Option Awards: Number of Securities Underlying Options (#) (2) | | | Exercise or Base Price of Option Awards ($ / Sh) (2) | | | Grant Date Fair Value of Stock and Option Awards ($) | |
| Michael R. McElwrath | | 02/07/11 | | | 434,800 | | | | 300,000 | | | | 0.58 | | | | 252,184 | |
| Bruce N. Huff | | 02/07/11 | | | 255,000 | | | | 175,000 | | | | 0.58 | | | | 147,900 | |
Narrative to Summary Compensation Table and Grants of Plan-Based Awards Table
Employment Agreements with Name Executive Officers
We have employment agreements with our Named Executive Officers and those agreements are summarized below.
Agreement with Michael R. McElwrath. The Company has an employment agreement with Mr. McElwrath, which has been amended from time to time. Prior to December 7, 2010, Mr. McElwrath’s employment agreement entitled him to fixed, retention bonuses of not less than $20,000 every six months. On December 7, 2010, his employment agreement was amended and restated to extend the term to October 13, 2013 and to eliminate the fixed, retention bonuses. On October 10, 2011, the Company entered into an amended and restated employment agreement (the “McElwrath Second Amended and Restated Employment Agreement”) with Mr. McElwrath. The McElwrath Second Amended and Restated Employment Agreement provides for an annual base salary of not less than $396,900 on or after February 16, 2011. The McElwrath Second Amended and Restated Employment Agreement also provides that Mr. McElwrath will be eligible to receive performance bonuses payable between January 1 and the 13th of April of each year in an amount to be determined by the Compensation Committee in its discretion. During 2011, Mr. McElwrath’s annual base salary was increased to an annual of $396,900 from $330,750.
Unless further extended, the McElwrath Second Amended and Restated Employment Agreement terminates on October 13, 2014. The McElwrath Second Amended and Restated Employment Agreement provides that if Mr. McElwrath is terminated by the Company for Cause, the Company will pay his base salary and all amounts actually earned, accrued or owing as of the date of termination and he will be entitled to exercise all options granted to him under the McElwrath Second Amended and Restated Employment Agreement or otherwise to the extent vested and exercisable on the date of termination unless otherwise provided for in Mr. McElwrath’s option agreements.
If Mr. McElwrath’s employment is terminated by the Company (other than as a result of death, Disability or Cause), or if he terminates his employment for Good Reason (as defined in the McElwrath Second Amended and Restated Employment Agreement), he shall be entitled to the following:
| | · | a lump sum payment of (i) two times the sum of his base salary and bonus paid during the immediately preceding twelve-month period or (ii) 2.99 times the sum of his base salary and bonus paid during the immediately preceding twelve-month period, in the event the termination was in connection with a Change of Control; |
| | · | all amount actually earned, accrued or owing as of the date of termination; |
| | · | continued participation in the medical and dental insurance plans available to the Company’s executive officers in which the executive was participating on the date of termination for a specified period of time following termination; |
| | · | the exercise of all options and restricted stock awards granted to him to the extent vested and exercisable at the date of termination of his employment provided that, in the event the termination is in connection with a Change of Control, all options then granted would be immediately and fully vested and exercisable as of the date of the termination and all restrictions on restricted stock awards awarded would be removed and all rights to such stock vested as of the date of termination; and |
| | · | certain gross-up payments for any excise taxes. |
Pursuant to the McElwrath Second Amended and Restated Employment Agreement, during the term of Mr. McElwrath’s employment, the Company agreed to nominate Mr. McElwrath for election to the Board of Directors at each annual meeting of the stockholders called for the purpose of electing directors. Mr. McElwrath is entitled to terminate his employment for Good Reason (as defined in the McElwrath Second Amended and Restated Employment Agreement) if he is not nominated and elected as a director of the Company or is removed as a director by the Board of Directors or the stockholders of the Company (other than for Cause, death or Disability).
If Mr. McElwrath’s employment is terminated as a result of death or Disability, the Company will pay his base salary and all amounts actually earned, accrued or owing as of the date of termination and he or his estate will be entitled to exercise all options granted to him regardless of whether or not the option is vested and exercisable on the date of termination and all restrictions on restricted stock awards awarded will be removed and all rights to such stock vested as of the date of termination.
The McElwrath Second Amended and Restated Employment Agreement contains no covenant not-to-compete or similar restrictions after termination.
Agreement with Bruce N. Huff. On April 19, 2010, the Company appointed Bruce N. Huff as Chief Financial Officer of the Company and on June 9, 2010, the Company entered into an amended and restated employment agreement (the “Huff Employment Agreement”) with Mr. Huff. On June 9, 2010, the Company amended the Huff Employment Agreement to, among other things, ensure compliance with the applicable provisions of the tax code relating to deferred compensation (the “Huff First Amendment”). Mr. Huff’s annual base salary for 2011 was increased to $270,000 from $225,000.
Unless further extended, the Huff Employment Agreement terminates on January 27, 2016. The Huff Employment Agreement provides that if Mr. Huff is terminated by the Company for Cause (as defined in the Huff Employment Agreement), the Company will pay his base salary and all amounts actually earned, accrued or owing as of the date of termination and he will be entitled for a period of three months after termination to exercise all options granted to him under his employment agreement or otherwise to the extent vested and exercisable on the date of termination. The Huff Employment Agreement further provides that if Mr. Huff voluntarily terminates his employment with the Company, the Company will pay his base salary and all amounts actually earned, accrued or owing as of the date of termination and he will be entitled for a period of one year after termination to exercise all options granted to him under his employment agreement or otherwise to the extent vested and exercisable on the date of termination.
If Mr. Huff’s employment is terminated by the Company (other than as a result of death, Disability (as defined in the Huff Employment Agreement) or Cause), or if he terminates his employment for Good Reason (as defined in the Huff Employment Agreement), he shall be entitled to the following:
| | · | a lump sum payment of (i) his base salary paid during the immediately preceding twelve-month period or (ii) two times the sum of his base salary paid during the immediately preceding twelve-month period in the event the termination occurs within 24 months after a Change of Control; |
| | · | all amounts actually earned accrued or owing as of the date of termination; and |
| | · | for a period of twelve months following the termination of Mr. Huff’s employment, all options granted to him to the extent vested and exercisable at the date of termination of Employee’s employment subject to certain restrictions contained in the Huff Employment Agreement. |
If Mr. Huff’s employment is terminated as a result of death or Disability, the Company will pay his base salary and all amounts actually earned, accrued or owing as of the date of termination and, within one year following the termination, he or his estate will be entitled to exercise all options granted to him to the extent the option is vested and exercisable and all such options not exercised within such one year period shall be forfeited.
The Huff Employment Agreement contains no covenant not-to-compete or similar restrictions after termination.
Agreement with K. Andrew Lai. On October 1, 2008, the Company entered in an amended and restated employment agreement (the “Lai Employment Agreement”) with Mr. Lai pursuant to which Mr. Lai agreed to serve as the Company’s Chief Financial Officer. On April 13, 2010, Mr. Lai notified the Company that he would resign as Chief Financial Officer effective April 19, 2010 to pursue other endeavors. Under the Lai Employment Agreement, he was entitled to all amounts actually earned, accrued or owing to him as of the date of termination. He was also entitled for a period of three (3) months after termination to exercise all options granted to him under the Lai Employment Agreement or otherwise to the extent vested and exercisable on April 15, 2010; provided, however, that certain of Mr. Lai’s options that provide for the purchase of up to a total of 100,000 shares of common stock will remain exercisable until April 19, 2012. On April 28, 2010, Mr. Lai exercised 100,000 options.
The Lai Employment Agreement contained no covenant not-to-compete or similar restrictions after termination.
2005 Stock Incentive Plan
The 2005 Plan permits the Compensation Committee to grant stock options, including incentive stock options (“ISOs”) and non-qualified stock options, stock appreciation rights, restricted stock, restricted stock units and other stock-based awards. Under the current version of the 2005 Plan, the Company may grant awards with respect to 22,000,000 shares, of which 8,000,000 shares may be granted as restricted stock, restricted stock units or any other stock-based awards. Unless sooner terminated by the Board or the Compensation Committee, the 2005 Plan will terminate on May 27, 2015.
The purpose of the 2005 Plan is to (1) aid the Company in attracting, securing and retaining employees of outstanding ability, (2) attract members to the Board, (3) attract consultants to provide services to the Company, as needed, and (4) motivate such persons to exert their best efforts on behalf of the Company.
The 2005 Plan is administered by the Compensation Committee. The 2005 Plan provides that if the Chief Executive Officer of the Company is a member of the Board, the Board may authorize him or her to grant awards of up to an aggregate of 200,000 shares of common stock in each calendar year to participants who are not subject to the rules promulgated under Section 16 of the Exchange Act.
The total number of shares of common stock that will be available for grants of ISOs is 2,600,000 shares and the total number of shares of common stock that will be available for grants of unrestricted shares of common stock, restricted stock, restricted stock units or any other stock-based awards is 8,000,000 shares. The maximum number of shares with respect to which awards of any and all types may be granted during a calendar year to any participant is limited, in the aggregate, to 1,500,000 shares. The 2005 Plan also provides that the maximum amount of a performance-based award to any Covered Employee (as defined in the 2005 Plan) for any fiscal year of the Company will be $1,000,000. Shares which are subject to awards which terminate, expire, are cancelled,
exchanged, forfeited, lapse or are settled for cash may be utilized again with respect to awards granted under the Plan.
With respect to any options that are awarded, the exercise price pursuant to which common stock may be purchased will be determined by the Compensation Committee, but will not be less than the fair market value (as defined in the 2005 Plan) of the common stock on the date the option is granted. Under the 2005 Plan, fair market value, on a given day, is defined as the mean of the closing bid and asked prices of the common shares as reported that day on the OTC Bulletin Board. No option shall be exercisable more than 10 years after the date of grant. The 2005 Plan also grants the Compensation Committee discretion to accelerate vesting or extend the time available for exercise of options after termination of an executive so long as termination is not for cause (as determined by the Compensation Committee).
Outstanding Equity Awards at Fiscal Year-End
The following table sets forth the number of unexercised options segregated by those that were exercisable and those that were unexercisable as of December 31, 2011, and the number of vested and unvested shares of restricted stock.
| | | | | OPTION AWARDS | | | | STOCK AWARDS | |
| Name | | Grant Date | | Number of Securities Underlying Unexercised Options Exercisable (#) | | | | Number of Securities Underlying Unexercised Options Unexercisable (#) | | | | Option Exercise Price ($) | | Option Expiration Date | | | | Number of Shares or Units of Stock That Have Not Vested (#) | | | | Market Value of Shares or Units of Stock That Have Not Vested ($) | |
| Michael R. McElwrath | | 01/29/02 | | | 60,000 | | (1) | | | - | | | | | 0.65 | | 01/29/12 | | | | | - | | | | | - | |
| | | 10/13/03 | | | 480,000 | | (1) | | | - | | | | | 0.65 | | 10/13/13 | | | | | - | | | | | - | |
| | | 12/23/04 | | | 200,000 | | (1) | | | - | | | | | 2.00 | | 12/23/14 | | (4) | | | - | | | | | - | |
| | | 02/02/06 | | | 500,000 | | (1) | | | - | | | | | 2.00 | | 02/02/16 | | | | | - | | | | | - | |
| | | 12/27/07 | | | 500,000 | | | | | - | | | | | 1.30 | | 10/13/13 | | | | | - | | | | | - | |
| | | 02/11/08 | | | 540,000 | | (3) | | | - | | | | | 0.69 | | 02/10/18 | | | | | - | | | | | - | |
| | | 04/15/09 | | | 100,000 | | | | | 50,000 | | (3) | | | 0.28 | | 04/15/19 | | | | | 150,000 | | (3) | | | 31,500 | |
| | | 04/15/09 | | | 73,333 | | | | | 36,667 | | (3) | | | 0.65 | | 04/15/19 | | | | | - | | | | | - | |
| | | 02/07/11 | | | - | | | | | 300,000 | | (3) | | | 0.58 | | 02/07/21 | | | | | 434,800 | | (3) | | | 91,308 | |
| Bruce N. Huff | | 12/23/04 | | | 240,000 | | (1) | | | - | | | | | 2.00 | | 12/23/14 | | | | | - | | | | | - | |
| | | 04/15/09 | | | 100,000 | | (2) | | | - | | | | | 0.28 | | 04/15/19 | | | | | - | | | | | - | |
| | | 04/19/10 | | | - | | | | | - | | | | | - | | 04/19/20 | | | | | 137,500 | | (5) | | | 28,875 | |
| | | 02/07/11 | | | - | | | | | 175,000 | | (3) | | | 0.58 | | 02/07/21 | | | | | 255,000 | | (3) | | | 53,550 | |
| K. Andrew Lai | | 01/29/07 | | | - | | | | | - | | (6) | | | - | | 01/29/17 | | | | | - | | (6) | | | - | |
| | | 02/11/08 | | | - | | | | | - | | (6) | | | - | | 02/10/18 | | | | | - | | (6) | | | - | |
| | | 10/01/08 | | | - | | | | | - | | (6) | | | - | | 10/01/18 | | | | | - | | (6) | | | - | |
| | | 04/15/09 | | | - | | | | | - | | (6) | | | - | | 04/15/19 | | | | | - | | (6) | | | - | |
| (1) | These options vested 20% on grant date, and 20% on the four subsequent anniversaries of the grant date thereafter. |
| (2) | This grant of restricted stock or options, as applicable, vested in three equal annual installments with the first installment vesting on the grant date, and the next two installments vesting on the two (2) subsequent anniversaries of the grant date thereafter. |
| (3) | This grant of restricted stock or options, as applicable, vest in three (3) equal annual installments beginning on the first anniversary grant date. |
| (4) | These options vested 20% on grant date, and 20% on each grant date anniversary thereafter. On January 14, 2009, the original expiration date of December 23, 2009 of this option was extended to December 23, 2014. |
| (5) | These options vest 25% on the grant date, and 25% on the three (3) subsequent anniversaries of the grant date thereafter. |
| (6) | As a result of the resignation of Mr. Lai on April 19, 2010, Mr. Lai forfeited unvested options to purchase up to 28,000 shares of common stock awarded on January 29, 2007, unvested options to purchase up to 60,000 shares of common stock awarded on February 11, 2008, unvested options to purchase up to 33,333 shares of common stock awarded on October 1, 2008, unvested options to purchase up to 66,667 shares of common stock awarded on April 15, 2009 and 15,000, 15,000 and 33,333 unvested shares of restricted stock awarded on February 11, 2008, October 1, 2008 and April 15, 2009, respectively. Mr. Lai forfeited vested options to purchase up to 232,000 shares of common stock since not exercised prior to July 19, 2010. Mr. Lai exercised vested options to purchase 100,000 shares of common stock during 2010. |
Potential Payments Upon Termination or Change in Control
For a description of the potential payments to our Named Executive Officers upon termination or a change in control, see “Narrative to Summary Compensation Table and Grants of Plan-Based Awards Table — Employment Agreements with Executive Officers” above. For further discussion of the determination of termination benefits, see “Compensation Discussion and Analysis — Total Compensation and Description and Allocation of Its Components — Post-Termination Compensation.”
Quantification of termination benefits. The following table quantifies the termination benefits due to our Named Executive Officers, in the event of their termination for various reasons, including any termination occurring within 24 months following a change of control. The amounts were computed as if each executive officer’s employment terminated on December 31, 2011.
2011 Potential Termination Benefits for Named Executive Officers
| | | | | | Termination for Other than Cause, Death, or Disability | |
| Executive Officer/Element of Compensation | | Termination due to Death or Disability | | | or by Executive for Good Reason | | | within 24 Months Following a Change of Control | |
| Michael R. McElwrath | | | | | | | | | |
| Salary and bonus | | $ | - | | | $ | 1,293,233 | | | $ | 1,933,383 | |
Equity awards (1) | | | 122,808 | | | | - | | | | 122,808 | |
Benefits(2) | | | - | | | | 64,328 | | | | 85,558 | |
Tax Gross-up (3) | | | - | | | | - | | | | 402,909 | |
| Total Mr. McElwrath | | $ | 122,808 | | | $ | 1,357,561 | | | $ | 2,544,658 | |
| | | | | | | | | | | | | |
| Bruce N. Huff | | | | | | | | | | | | |
| Salary | | $ | - | | | $ | 225,000 | | | $ | 450,000 | |
Equity awards (1) | | | - | | | | - | | | | 82,425 | |
| Total Mr. Huff | | $ | - | | | $ | 225,000 | | | $ | 532,425 | |
| (1) | Equity awards are quantified at the intrinsic value on December 31, 2011 of all options and restricted stock that was not fully vested and exercisable, but would become exercisable, under the terms of the Name Executive Officer’s employment agreement, due to the form of termination specified in the column heading. The intrinsic value of options is determined by calculating the difference between the closing market price of our common stock on December 31, 2011, which was $0.21 per share, and the exercise price of the option, and multiplying that difference by the number of options exercisable at that given exercise price. The intrinsic values of all the options are then totaled. The intrinsic value of restricted stock is equal to the number of shares times the closing price of our common stock on December 31, 2011. |
| (2) | Benefits quantified include the incremental cost to the Company of continuing health care benefits (based on December 2011 premium rates) and the cost of the Company’s matching contributions. |
| (3) | Tax gross-up refers to reimbursement for any excise tax (and taxes on the imputed income attributable to the reimbursement for the excise tax and tax gross-up) the Named Executive Officer is required to pay under Section 4999 of the Code for excess parachute payments. This amount reflects the estimated gross-up payments that would be due to Mr. McElwrath as if he had been terminated on December 31, 2011. |
Directors’ Compensation
The following table summarizes compensation paid to non-employee directors for 2011. Mr. McElwrath is the only employee serving as a director and he does not receive any additional compensation for his service on the Board.
| 2011 Director Compensation | |
| Name | | Fees Earned or Paid in Cash | | | Stock Awards (1) | | | Option Awards (1) | | | Total | |
| Donald A. Juckett | | $ | 46,000 | | | $ | 58,000 | | | $ | 35,096 | | | $ | 139,096 | |
| | | | | | | | | | | | | | | | | |
| William A. Anderson | | | 47,500 | | | | 58,000 | | | | 35,096 | | | | 140,596 | |
| | | | | | | | | | | | | | | | | |
| C. P. Chiang | | | 32,500 | | | | 58,000 | | | | 35,096 | | | | 125,596 | |
| | | | | | | | | | | | | | | | | |
| John C. Mihm | | | 35,500 | | | | 58,000 | | | | 35,096 | | | | 128,596 | |
| | | | | | | | | | | | | | | | | |
| Lucian Morrison | | | 41,000 | | | | 58,000 | | | | 35,096 | | | | 134,096 | |
| | | | | | | | | | | | | | | | | |
| Thomas E. Williams | | | 42,500 | | | | 58,000 | | | | 35,096 | | | | 135,596 | |
| (1) | Stock Awards and Option Awards are quantified in the table according to the amount included in 2011 share-based compensation expense for the awards granted to each named director through the end of fiscal year 2011. See Footnote 12 to the Consolidated Financial Statements which is included in Part II of this report for assumptions used in valuing these awards and the methodology for recognizing the related expense. The expense has been modified in accordance with SEC rules to eliminate forfeiture assumptions in computing the expense for the year. There were no actual forfeitures during 2011 by any of the named directors. All options are for the purchase of our common stock. All stock awards are grants of restricted stock representing time-vesting shares of our common stock. |
The table below provides information regarding the outstanding stock option and restricted stock awards for each of our directors as of December 31, 2011.
| 2011 Outstanding Equity Awards for Directors | |
| Name | | Number of Securities Underlying Unexercised Options (#) | | | Number of Shares of Stock That Have Not Vested (#) | |
| | | | | | | |
| Donald A. Juckett | | | 520,000 | | | | 100,000 | |
| William A. Anderson | | | 290,000 | | | | 100,000 | |
| C. P. Chiang | | | 280,000 | | | | 100,000 | |
| John C. Mihm | | | 520,000 | | | | 100,000 | |
| Lucian Morrison | | | 268,000 | | | | 100,000 | |
| Thomas E. Williams | | | 520,000 | | | | 100,000 | |
The Company pays its non-employee directors cash compensation for their service on the Board. In January 2007, the Board approved a standard compensation arrangement for directors, effective January 1, 2007. On April 15, 2009, the Compensation Committee amended the standard compensation arrangement to increase the fees for Board and committee telephone meetings from $500 each to $1,500 and $1,000, respectively. The current standard compensation arrangement, as amended, is set forth below.
| Schedule of Directors' fees |
| | | | | |
| Annual cash retainer | | $ | 15,000 | | annually |
| Board meetings in person | | | 1,500 | | for each meeting |
| Board meetings by telephone | | | 1,500 | | for each meeting |
| Committee meetings in person | | | 1,000 | | for each meeting |
| Committee meetings by telephone | | | 1,000 | | for each meeting |
| Committee Chairman retainer | | | 5,500 | | annually |
| Audit Committee Chairman retainer | | | 12,000 | | annually |
| Board Chairman retainer | | | 12,000 | | annually |
The Company also reimburses directors for the reasonable expenses they incur to attend Board, Board committee and/or investor relations meetings. In addition, in 2008, the Board approved a policy providing for an annual grant of options to each non-employee director to purchase a target level of 40,000 shares of common stock, which have an exercise price equal to fair market value on date of grant, a term of ten years and will vest in their entirety on the first anniversary of the date of grant. The actual number of options granted from year to year may be adjusted upwards or downwards based on the business judgment of the Board. The fair market value, on a given date, is the mean of the closing bid and asked prices of the common shares as reported that day on the OTC Bulletin Board. These grants are expected to be made during the first quarter each fiscal year. The Company did not grant any options to its directors during 2011.
In addition to the annual grants of options to directors described above, we typically grant options to directors upon their initial appointment or election as a director. The options will vest over three years, with 25% vested immediately and an additional 25% vesting on the first, second and third anniversary of the date of grant. If upon or within 24 months of a Change of Control (as defined in the 2005 Plan) a director’s service in their capacity as a director of the Company is terminated, then all options granted to the director will immediately and fully vest and be exercisable as of the date their service is terminated.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Security Ownership
The following table sets forth, as of March 2, 2012, certain information with respect to the beneficial ownership of our common stock by (a) each stockholder beneficially owning more than 5% of the Company’s outstanding common stock; (b) each director of the Company who is a stockholder of the Company; (c) each of the Named Executive Officers who is a stockholder of the Company; and (d) all Named Executive Officers and directors of the Company as a group. Total shares outstanding on March 2, 2012 were 344,632,223. (1)
| Name of Beneficial Owner | | Amount and Nature of Beneficial Ownership of Common Stock | | | | Percent of Outstanding Common Stock | |
| Blackrock | | | 32,452,100 | | (2) | | | 9.4 | % |
| Prudential Jennison Associates LLC | | | 28,908,989 | | (3) | | | 8.4 | % |
| International Finance Corporation | | | 21,580,360 | | (4) | | | 6.2 | % |
| | | | | | | | | | |
| Named Executive Officers: | | | | | | | | | |
| Michael R. McElwrath | | | 4,801,261 | | (5) | | | 1.4 | % |
| Bruce Huff | | | 1,407,961 | | (6) | | | * | |
| | | | | | | | | | |
| Non-Executive Directors: | | | | | | | | | |
| Donald A. Juckett | | | 998,632 | | (7) | | | * | |
| William A. Anderson | | | 703,019 | | (8) | | | * | |
| C. P. Chiang | | | 650,000 | | (9) | | | * | |
| John C. Mihm | | | 1,064,579 | | (10) | | | * | |
| Lucian L. Morrison | | | 671,019 | | (11) | | | * | |
| Thomas E. Williams | | | 928,125 | | (12) | | | * | |
| | | | | | | | | | |
| All Directors and Executive | | | | | | | | | |
| Officers as a Group (8 persons) | | | 11,224,596 | | (13) | | | 3.3 | % |
_________________________________________________
* Less than 1%.
| (1) | The percentages in the table are calculated using the total shares outstanding plus the number of securities that can be acquired within 60 days of March 2, 2012, or a total of 344,632,223 shares. |
| (2) | The amount of beneficial ownership of the shares is based on a Schedule 13G filed with the SEC on February 9, 2012. Based on the Schedule 13G, BlackRock, Inc. and/or certain investment funds managed by BlackRock, Inc. and/or its affiliates may be deemed to be the beneficial owners of 32,452,100 shares of common stock as of December 31 2011. The address for BlackRock, Inc. is 40 East 52nd Street, New York, NY 10022. |
| (3) | The amount of beneficial ownership of the shares is based on a Schedule 13G filed with the SEC on February 14, 2012. Jennison Associates LLC (“Jennison”) is a wholly-owned subsidiary of Prudential Financial, Inc. (“Prudential”). Based on the Schedule 13G, Jennison may be deemed to be the beneficial owner of 28,908,989 shares of common stock as of December 31, 2011 acquired on behalf of its clients |
| | investment advisory accounts. Jennison reports sole voting power over 26,904,183 shares and shared dispositive power over 28,908,989 shares. Prudential may be deemed to have the power to exercise or to direct the exercise of such voting and/or dispositive power that Jennison may have with respect to our common stock portfolios managed by Jennison. Jennison does not file jointly with Prudential, as consequently, shares of our common stock reported on Jennison’s Schedule 13G may be included in the shares reported on the Schedule 13G filed by Prudential. The address for Jennison Associates LLC is 466 Lexington Avenue, New York, NY 10017. Prudential also filed a Schedule 13G with the SEC on February 14, 2012 in which it discloses beneficial ownership of 28,908,989 shares of our common stock. The address for Prudential Financial, Inc. is 751 Broad Street, Newark, New Jersey 07102-3777. |
| (4) | The amount of beneficial ownership of the shares is based on a Schedule 13G filed with the SEC dated June 20, 2008. Based on the Schedule 13G, International Finance Corporation may be deemed to be beneficial owners of 21, 580,360 shares outstanding as of June 20, 2008. The address for International Finance Corporation is 2121 Pennsylvania Avenue, N.W., Washington, D.C. 20433. |
| (5) | Includes 2,580,000 shares which Michael R. McElwrath may purchase pursuant to options which are exercisable within 60 days of March 2, 2012. Also includes 150,000 shares of restricted stock which vest in April 15, 2012; 289,867 shares of restricted stock which vest in two equal installments on February 7, 2013 and February 7, 2014 and 615,000 shares of restricted stock that vest in three equal installments on January 25, 2013, January 25, 2014 and January 25, 2015. |
| (6) | Includes 398,333 shares which Bruce N. Huff may purchase pursuant to options which are exercisable within 60 days of March 2, 2012. Also includes 137,500 shares of restricted stock which vest in two equal installments on April 19, 2012 and April 19, 2013; 170,000 shares of restricted stock which vest in two equal installments on February 7, 2013 and February 7, 2014 and 365,000 shares of restricted stock that vest in three equal installments on January 25, 2013, January 25, 2014 and January 25, 2015. |
| (7) | Includes 600,000 shares which Donald A. Juckett may purchase pursuant to options which are exercisable within 60 days of March 2, 2012 Also includes 66,667 shares of restricted stock which vest in two equal installments on February 7, 2013 and February 7, 2014 and 150,000 shares of restricted stock that vest in three equal installments on January 25, 2013, January 25, 2014 and January 25, 2015. |
| (8) | Includes 370,000 shares which William A. Anderson may purchase pursuant to options which are exercisable within 60 days of March 2, 2012. Also includes 66,667 shares of restricted stock which vest in two equal installments on February 7, 2013 and February 7, 2014 and 150,000 shares of restricted stock that vest in three equal installments on January 25, 2013, January 25, 2014 and January 25, 2015. Mr. Anderson disclaims beneficial ownership of 10,000 of these securities held by Anderson Securities Corp. except to the extent of his pecuniary interest therein, and the inclusion of these shares in this report shall not be deemed an admission of beneficial ownership of all of the reported shares for any purpose. |
| (9) | Includes 360,000 shares which C.P. Chiang may purchase pursuant to options which are exercisable within 60 days of March 2, 2012. Also includes 66,667 shares of restricted stock which vest in two equal installments on February 7, 2013 and February 7, 2014 and 150,000 shares of restricted stock that vest in three equal installments on January 25, 2013, January 25, 2014 and January 25, 2015. |
| (10) | Includes 600,000 shares which John C. Mihm may purchase pursuant to options which are exercisable within 60 days of March 2, 2012. Also includes 66,667 shares of restricted stock which vest in two equal installments on February 7, 2013 and February 7, 2014 and 150,000 shares of restricted stock that vest in three equal installments on January 25, 2013, January 25, 2014 and January 25, 2015. |
| (11) | Includes 348,000 shares which Lucian L. Morrison may purchase pursuant to options which are exercisable within 60 days of March 2, 2012. Also includes 66,667 shares of restricted stock which vest in two equal installments on February 7, 2013 and February 7, 2014 and 150,000 shares of restricted stock that vest in three equal installments on January 25, 2013, January 25, 2014 and January 25, 2015. |
| (12) | Includes 600,000 shares which Thomas E. Williams may purchase pursuant to options which are exercisable within 60 days of March 2, 2012. Also includes 66,667 shares of restricted stock which vest in two equal installments on February 7, 2013 and February 7, 2014 and 150,000 shares of restricted stock that vest in three equal installments on January 25, 2013, January 25, 2014 and January 25, 2015. |
| (13) | Includes 5,856,333 shares which may be purchased pursuant to options and warrants which are exercisable within 60 days of March 2, 2012 by our directors and executive officers. |
Equity Compensation Plan Information
The following table provides information regarding the equity compensation plans as of December 31, 2011.
| | | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | | Weighted average exercise price of outstanding options, warrants and rights | | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |
| Equity Compensation Plan Category | | (a) | | | (b) | | | (c) | |
Plans approved by security holders (1) | | | 5,730,833 | | | $ | 0.77 | | | | 16,509,199 | |
| Plans not approved by security holders | | | | | | | | | | | | |
- Inducement awards (2) | | | 1,068,000 | | | | 0.65 | | | | - | |
| - Investor Relations Consultant | | | 125,000 | | | | 0.86 | | | | - | |
- IRS 409A related grants (3) | | | 800,000 | | | | 1.60 | | | | - | |
- Prior to adoption of the 2005 Plan (4) | | | 2,800,000 | | | | 1.59 | | | | - | |
| Total | | | 10,523,833 | | | | 1.04 | | | | 16,509,199 | |
| (1) | For discussion of the 2005 Stock Incentive Plan (“2005 Plan”), which was approved by the security holders, see “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters - Narrative to Equity Compensation Plan Information —2005 Stock Incentive Plan.” |
| (2) | We awarded as inducement grants options to purchase shares of common stock to new board members and new employees outside the 2005 Plan. The grants carried a term of ten years. |
| (3) | We granted options to purchase shares of common stock in December 2007 which were replacements for options cancelled due to potential adverse tax consequences to the holders of the cancelled options under Section 409A of the Internal Revenue Code. The cancelled options had been granted prior to adoption of the 2005 Plan. The replacement stock options have terms between one and approximately six years, and exercise prices in the range of $1.30 to $2.09 per share. |
| (4) | We granted options to purchase shares of common stock prior to the adoption of the 2005 Plan, which are evidenced by individual stock option agreements. The options were granted to officers, directors and consultants and have a term of between five and ten years and an exercise price in the range of $0.65 to $2.00 per share. |
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Review of Related Person Transactions
In accordance with our audit committee charter, the Audit Committee reviews related person transactions. It is the Company’s policy that we will not enter into transactions that are considered related person transactions that are required to be disclosed under Item 404 of Regulation S-K unless the committee or another independent body of the board first reviews and approves the transactions.
Board Independence
The Board has determined that each director, except for Michael R. McElwrath, has no material relationship with the Company and is independent within the meaning of the NYSE AMEX listing standards.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Independent Registered Public Accounting Firm Fee Information
Audit Fees
The aggregate fees billed by JonesBaggett LLP (formerly Payne Smith & Jones, P.C.) for professional services rendered for the audit of our annual financial statements for the years ended December 31, 2011 and 2010 and for the review of the financial statements included in our Quarterly Reports on Form 10-Q for those years were $140,001 and $252,674 respectively.
Audit-Related Fees
JonesBaggett LLP did not render any audit-related professional services for the years ended December 31, 2011 and 2010.
Tax Fees
The aggregate fees billed by JonesBaggett LLP for professional services rendered for tax compliance, tax advice and/or tax planning for the year ended December 31, 2011 was $8,000. The fees were for the preparation of the 2010 corporate tax return. JonesBaggett LLP did not perform any tax compliance, tax advice and/or tax planning services during 2010.
All Other Fees
JonesBaggett LLP did not bill any other fees for professional products or services rendered to us, other than those described above under “Audit Fees,” “Audit-Related Fees” and “Tax Fees” for the years ended December 31, 2011 and 2010.
The Audit Committee pre-approved all of the audit and non-audit fees described above for the years ended December 31, 2011 and 2010.
Pre-Approval Policies and Procedures
In accordance with the Audit Committee Charter, the Audit Committee has established policies and procedures by which it approves in advance any audit and permissible non-audit services to be provided by our independent registered public accounting firm. Under these procedures, prior to the engagement of the independent registered public accounting firm for pre-approved services, requests or applications for the independent registered public accounting firm to provide services must be submitted to our chief financial officer or his designee and the Audit Committee and must include a detailed description of the services to be rendered. The chief financial officer or his designee and the independent registered public accounting firm must ensure that the independent registered public accounting firm is not engaged to perform the proposed services unless those services are within the list of services that have received the Audit Committee’s pre-approval and must cause the Audit Committee to be informed in a timely manner of all services rendered by the independent registered public accounting firm and the related fees.
Requests or applications for the independent registered public accounting firm to provide services that require case-by-case approval will be submitted to the Audit Committee (or any Audit Committee members who have been delegated pre-approval authority) by the chief financial officer or his designee. Each request or application must include:
| | · | a recommendation by the chief financial officer (or designee) as to whether the Audit Committee should approve the request or application; and |
| | · | a joint statement of the chief financial officer (or designee) and the independent registered public accounting firm as to whether, in their view, the request or application is consistent with the SEC’s and the Public Company Accounting Oversight Board’s requirements for independence. |
The Audit Committee will not permit the independent registered public accounting firm to provide services in connection with a transaction initially recommended by them, the purpose of which may be tax avoidance and the tax treatment of which may not be supported in the Code and related regulations. The Audit Committee also will not permit the independent registered public accounting firm to provide any services to the extent that the SEC has prohibited the provision of those services by the independent registered public accounting firm, which generally include:
| | · | bookkeeping or other services related to accounting records or financial statements; |
| | · | financial information systems design and implementation; |
| | · | appraisal or valuation services, fairness opinions or contribution-in-kind reports; |
| | · | internal audit outsourcing services; |
| | · | broker-dealer, investment adviser or investment banking services; |
| | · | expert services unrelated to the audit. |
| | The Audit Committee delegated authority to the chairman of the Audit Committee, to: |
| | · | pre-approve any services proposed to be provided by the independent registered public accounting firm and not already pre-approved or prohibited by the Audit Committee’s Pre-Approval Policy; |
| | · | increase any authorized fee limit for pre-approved services (but not by more than 20% of the initial amount that was pre-approved) before the Company or its subsidiaries engage the independent registered public accounting firm to perform services for any amount in excess of the fee limit; and |
| | · | investigate further the scope, necessity or advisability of any services as to which pre-approval is sought. |
The Chairman is required to report any pre-approval or fee increase decisions to the Audit Committee at the next Audit Committee meeting. The Audit Committee does not delegate to management any of the Audit Committee’s authority or responsibilities concerning the independent registered public accounting firm’s services.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
1. Financial Statements.
Our consolidated financial statements are included in Part II, Item 8 of this report:
| | Page |
| Report of Independent Registered Public Accounting Firm | 52 |
| Consolidated Balance Sheets | 54 |
| Consolidated Statements of Operations | 55 |
| Consolidated Statements of Stockholders' Equity | 56 |
| Consolidated Statements of Cash Flows | 57 |
| Notes to the Consolidated Financial Statements | 58 |
2. Financial statement schedules and supplementary information required to be submitted.
| Schedule II — Valuation and qualifying accounts. | 80 |
| Schedules other than that listed above are omitted because they are not applicable. |
3. Exhibits
A list of the exhibits filed or furnished with this report on Form 10-K (or incorporated by reference to exhibits previously filed or furnished by us) is provided in the Exhibit Index beginning on page 112 of this report. Those exhibits incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. Otherwise, the exhibits are filed herewith.
Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 13, 2012.
| | FAR EAST ENERGY CORPORATION |
| | | |
| | By: | /s/ Michael R. McElwrath |
| | | Michael R. McElwrath |
| | | Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed below by the following persons on behalf of the registrant and in the capacities with Far East Energy Corporation indicated and on March 13, 2012.
| | Signature | | Title |
| | | | |
| | /s/ Michael R. McElwrath | | Chief Executive Officer, |
| | (Michael R. McElwrath) | | President and Director (Principal Executive Officer) |
| | | | |
| | /s/ Bruce N. Huff | | Chief Financial Officer |
| | (Bruce N. Huff) | | (Principal Financial and Accounting Officer) |
| | | | |
| | * Donald A. Juckett | | Chairman of the Board |
| | (Donald A. Juckett) | | |
| | | | |
| | * William A. Anderson | | Director |
| | (William A. Anderson) | | |
| | | | |
| | * C. P. Chiang | | Director |
| | (C. P. Chiang) | | |
| | | | |
| | * Thomas E. Williams | | Director |
| | (Thomas E. Williams) | | |
| | | | |
| | * John C. Mihm | | Director |
| | (John C. Mihm) | | |
| | | | |
| | * Lucian L. Morrison | | Director |
| | (Lucian L. Morrison) | | |
| | | | |
| * | By: /s/ Bruce N. Huff | | |
| | (Bruce N. Huff) | | |
| | (Attorney-in-fact for persons indicated) | | |
INDEX OF EXHIBITS
| Exhibit Number | Description |
| | 3.1 | Articles of Incorporation of the Company, as amended (filed as Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004 filed on March 15, 2005 and incorporated herein by reference). |
| | 3.2 | Amended and Restated Bylaws of the Company (filed as Exhibit 3.1 to the Company's Current Report on Form 8-K filed on March 17, 2005 and incorporated herein by reference). |
| | 4.1 | Articles of Incorporation of the Company, as amended (included as Exhibit 3.1). |
| | 4.2 | Amended and Restated Bylaws of the Company (included as Exhibit 3.2). |
| | 4.3 | Specimen stock certificate (filed as Exhibit 4.5 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004 filed on March 15, 2005 and incorporated herein by reference). |
| | 4.4 | Form of Warrant (filed as Exhibit 4.1 to the Company's Current Report on Form 8-K filed on August 27, 2007 and incorporated herein by reference). |
| | 4.5 | Warrant Agreement, dated August 27, 2007, between the Company and Continental Stock Transfer & Trust Company (filed as Exhibit 4.2 to the Company's Current Report on Form 8-K filed on August 27, 2007 and incorporated herein by reference). |
| | 4.6 | Form of Warrant (filed as Exhibit 4.1 to the Company's Current Report on Form 8-K filed on May 30, 2008 and incorporated herein by reference). |
| | 4.7 | Warrant Agreement, dated May 30, 2008, between the Company and Continental Stock Transfer & Trust Company (filed as Exhibit 4.2 to the Company's Current Report on Form 8-K filed on May 30, 2008 and incorporated herein by reference). |
| | 4.8 | Warrant Agreement between the Company and Continental Stock Transfer & Trust Company (including the form of warrant) (filed as Exhibit 4.1 to the Company's Current Report on Form 8-K filed on December 22, 2009 and incorporated herein by reference). |
| | 4.9 | Form of Common Stock Purchase Warrant (filed as Exhibit 4.1 to the Company's Current Report on Form 8-K filed on March 9, 2010 and incorporated herein by reference). |
| | 4.10 | Form of Securities Purchase Agreement (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on March 9, 2010 and incorporated herein by reference). |
| | 10.1* | Amended and Restated Employment Agreement, dated December 23, 2004, between the Company and Michael R. McElwrath (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on December 28, 2004 and incorporated herein by reference). |
| | 10.2* | First Amendment to Amended and Restated Employment Agreement, dated April 16, 2007, between the Company and Michael R. McElwrath (filed as Exhibit 10.5 to the Company's Current Report on Form 8-K filed on April 19, 2007 and incorporated herein by reference). |
| | 10.3* | Second Amendment to Amended and Restated Employment Agreement, dated November 26, 2007, between the Company and Michael R. McElwrath (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on November 27, 2007 and incorporated herein by reference). |
| | 10.4* | Third Amendment to Amended and Restated Employment Agreement, dated March 7, 2008, between the Company and Michael R. McElwrath (filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed on March 13, 2008 and incorporated herein by reference). |
| | 10.5* | Fourth Amendment to Amended and Restated Employment Agreement, dated December 19, 2008, between the Company and Michael R. McElwrath (filed as Exhibit 10.72 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008 filed on March 30, 2009 and incorporated herein by reference). |
| | 10.6* | Fifth Amendment to Amended and Restated Employment Agreement, dated May 18, 2009, between the Company and Michael R. McElwrath (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on May 18, 2009 and incorporated herein by reference). |
| | 10.7* | Sixth Amendment to Amended and Restated Employment Agreement, dated December 7, 2010, between the Company and Michael R. McElwrath (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on December 13, 2010 and incorporated herein by reference). |
| | 10.8* | Amended and Restated Employment Agreement, dated October 10, 2011, between the Company and Michael R. McElwrath (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 13, 2011 (SEC File No. 000-32455 )). |
| | 10.9* | Amended and Restated Employment Agreement, dated June 9, 2010, between the Company and Bruce N. Huff (filed as Exhibit 10.75 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 filed on August 8, 2010 and incorporated herein by reference). |
| | 10.10* | Amendment to the Amended and Restated Employment Agreement, dated January 27, 2012, between the Company and Bruce N. Huff (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2012 (SEC File No. 000-32455 )). |
| | 10.8* | Far East Energy Corporation 2005 Stock Incentive Plan (filed as Appendix A to the Company's Proxy Statement on Schedule 14A filed on December 13, 2010 and incorporated herein by reference). |
| | 10.9* | Amended and Restated Nonqualified Stock Option Agreement, dated December 23, 2004, between the Company and Michael R. McElwrath (filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed on December 28, 2004 and incorporated herein by reference). |
| | 10.10* | Amended and Restated Nonqualified Stock Option Agreement, dated December 23, 2004, between the Company and Michael R. McElwrath (filed as Exhibit 10.4 to the Company's Current Report on Form 8-K filed on December 28, 2004 and incorporated herein by reference). |
| | 10.11* | Nonqualified Stock Option Agreement, dated December 23, 2004, between the Company and Michael R. McElwrath (filed as Exhibit 10.6 to the Company's Current Report on Form 8-K filed on December 28, 2004 and incorporated herein by reference). |
| | 10.12* | Second Amended and Restated Nonqualified Stock Option Agreement, dated December 27, 2007, between the Company and Michael R. McElwrath (filed as Exhibit 10.64 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007 filed on March 13, 2008 and incorporated herein by reference). The original option agreement was entered into on January 29, 2002. |
| | 10.13* | Second Amended and Restated Nonqualified Stock Option Agreement, dated December 27, 2007, between the Company and Michael R. McElwrath (filed as Exhibit 10.65 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007 filed on March 13, 2008 and incorporated herein by reference). The original option agreement was entered into on October 13, 2003. |
| | 10.14* | First Amendment to Non-Qualified Stock Option Agreement, dated December 19, 2008, between the Company and Michael R. McElwrath (filed as Exhibit 10.63 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008 filed on March 30, 2009 and incorporated herein by reference). |
| | 10.15* | Second Amended and Restated Nonqualified Stock Option Agreement, dated January 14, 2009, between the Company and Michael R. McElwrath (filed as Exhibit 10.64 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008 filed on March 30, 2009 and incorporated herein by reference). |
| | 10.16* | Amended and Restated Nonqualified Stock Option Agreement, dated January 14, 2009, between the Company and Don Juckett (filed as Exhibit 10.68 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008 filed on March 30, 2009 and incorporated herein by reference). |
| | 10.17* | Stock Option Agreement, dated May 24, 2004, between the Company and John C. Mihm (filed as Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004 filed on March 15, 2005 and incorporated herein by reference). |
| | 10.18* | Stock Option Agreement, dated February 24, 2004, between the Company and Thomas Williams (filed as Exhibit 10.16 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004 filed on March 15, 2005 and incorporated herein by reference). |
| | 10.19* | Amended and Restated Nonqualified Stock Option Agreement, dated December 27, 2007, between the Company and Thomas Williams (filed as Exhibit 10.61 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007 filed on March 13, 2008 and incorporated herein by reference). |
| | 10.20* | Second Amended and Restated Nonqualified Stock Option Agreement, dated January 14, 2009, between the Company and Thomas Williams (filed as Exhibit 10.65 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008 filed on March 30, 2009 and incorporated herein by reference). |
| | 10.21* | Third Amended and Restated Nonqualified Stock Option Agreement, dated January 14, 2009, between the Company and Thomas Williams (filed as Exhibit 10.66 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008 filed on March 30, 2009 and incorporated herein by reference). |
| | 10.22* | Non-Qualified Stock Option Agreement, dated October 1, 2007, between the Company and William A. Anderson (filed as Exhibit 10.52 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 filed on November 7, 2007 and incorporated herein by reference). |
| | 10.23* | Non-Qualified Stock Option Agreement, dated January 9, 2008, between the Company and Lucian L. Morrison (filed as Exhibit 10.58 to the Company's Annual Report on Form 10-K for the year ended |
| | | December 31, 2007 filed on March 13, 2008 and incorporated herein by reference). |
| | 10.24* | Form of Non-Qualified Stock Option Agreement for Far East Energy Corporation 2005 Stock Incentive Plan (filed as Exhibit 10.73 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008 filed on March 30, 2009 and incorporated herein by reference). |
| | 10.25* | Form of Non-Qualified Stock Option Agreement (filed as Exhibit 10.54 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007 filed on March 13, 2008 and incorporated herein by reference). |
| | 10.26* | Form of Incentive Stock Option Agreement for Far East Energy Corporation 2005 Stock Incentive Plan (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed on April 19, 2007 and incorporated herein by reference). |
| | 10.27* | Restricted Stock Agreement, dated December 27, 2007, between the Company and Michael R. McElwrath (filed as Exhibit 10.55 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007 filed on March 13, 2008 and incorporated herein by reference). |
| | 10.28* | Restricted Stock Agreement, dated December 27, 2007, between the Company and Thomas E. Williams (filed as Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007 filed on March 13, 2008 and incorporated herein by reference). |
| | 10.29* | Form of Restricted Stock Agreement for Far East Energy Corporation 2005 Stock Incentive Plan (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on March 23, 2007 and incorporated herein by reference). |
| | 10.30* | Form of Restricted Stock Agreement (filed as Exhibit 4.4 to the Company's Registration Statement on Form S-8 (File No. 333-148363) filed on December 27, 2007 and incorporated herein by reference). |
| | 10.31* | Form of Letter Agreement with the Company's non-employee directors (filed as Exhibit 10.4 to the Company's Current Report on Form 8-K filed on April 19, 2007 and incorporated herein by reference). |
| | 10.32 | Production Sharing Contract for Exploitation of Coalbed Methane Resources in Enhong and Laochang, Yunnan Province, the People's Republic of China, dated January 25, 2002, between China United Coalbed Methane Corp. Ltd. and the Company (filed as Exhibit 2(i) to the Company's Current Report on Form 8-K filed on February 11, 2002 and incorporated herein by reference). |
| | 10.33 | Modification Agreement for Product Sharing Contract for Exploitation of Coalbed Methane Resources in Enhong and Laochang, Yunnan Province, the People's Republic of China, dated October 20, 2005, between China United Coalbed Methane Corporation Ltd. and the Company (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on October 26, 2005 and incorporated herein by reference). |
| | 10.34 | Modification Agreement dated April 24, 2007 for Production Sharing Contract for Exploitation of Coalbed Methane Resources for the Enhong and Laochang Area in Yunnan Province, the People's Republic of China, dated December 3, 2002, between China United Coalbed Methane Corporation Ltd. and Far East Energy (Bermuda), Ltd. (filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed on April 27, 2007 and incorporated herein by reference). |
| | 10.35 | Modification Agreement for Production Sharing Contract for Exploitation of Coalbed Methane Resources in Enhong and Laochang Area, Yunnan Province, The People's Republic of China (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed on August 27, 2009 and incorporated herein by reference). |
| | 10.36 | Production Sharing Contract for Exploitation of Coalbed Methane Resources for the Qinnan Area in Shanxi Province, Qinshui Basin, the People's Republic of China, dated April 16, 2002, between China United Coalbed Methane Corporation Ltd. and the Phillips China Inc. (filed as Exhibit 10.21 to the Company's Annual Report on Form 10-K filed on March 15, 2005 and incorporated herein by reference). |
| | 10.37 | Application for the Extension of Phase Two of the Exploration Period under the Qinnan PSC, dated December 2, 2005, between the Company and China United Coalbed Methane Corporation Ltd. (filed as Exhibit 10.20 to the Company's Annual Report on Form 10-K for the year ended December 31, 2005 filed on March 14, 2006 and incorporated herein by reference). |
| | 10.38 | Application for the Extension of Phase Two of the Exploration Period under the Qinnan PSC, dated March 16, 2006, between the Company and China United Coalbed Methane Corporation Ltd. (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on March 17, 2006 and incorporated herein by reference). |
| | 10.39 | Approval Certificate from the Ministry of Foreign Trade and Economic Cooperation dated December 30, 2002 (filed as Exhibit 2(i) to the Company's Current Report on Form 8-K filed on January 13, 2003 and incorporated herein by reference). |
| | 10.40 | Memorandum of Understanding, dated March 18, 2003, between Phillips China Inc. and the Company |
| | | (filed as Exhibit 10.1 to the Company's Amendment No. 1 to its Quarterly Report on Form 10-QSB/A for the quarter ended June 30, 2003 filed on December 24, 2003 and incorporated herein by reference). |
| | 10.41 | Farmout Agreement Qinnan PSC, dated June 17, 2003, between Phillips China Inc. and the Company (filed as Exhibit 10.2 to the Company's Amendment No. 1 to its Quarterly Report on Form 10-QSB/A for the quarter ended June 30, 2003 filed on December 24, 2003 and incorporated herein by reference). |
| | 10.42 | First Amendment to Farmout Agreement Qinnan PSC, dated December 15, 2003, between Phillips China Inc. and the Company (filed as Exhibit 10.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004 filed on March 15, 2005 and incorporated herein by reference). |
| | 10.43 | Second Amendment to Farmout Agreement Qinnan PSC, dated December 17, 2004, between Phillips China Inc. and the Company (filed as Exhibit 10.01 to the Company's Current Report on Form 8-K filed on December 23, 2004 and incorporated herein by reference). |
| | 10.44 | Third Amendment to Farmout Agreement Qinnan PSC, dated December 19, 2005, between ConocoPhillips China Inc. and the Company (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on December 21, 2005 and incorporated herein by reference). |
| | 10.45 | Assignment Agreement Qinnan PSC, dated June 17, 2003, between Phillips China Inc. and the Company (filed as Exhibit 10.4 to the Company's Amendment No. 1 to its Quarterly Report on Form 10-QSB/A for the quarter ended June 30, 2003 filed on December 24, 2003 and incorporated herein by reference). |
| | 10.46 | Modification Agreement, dated April 24, 2007, for Production Sharing Contract for Exploitation of Coalbed Methane Resources for the Qinnan Area in Shanxi Province, Qinshui Basin, the People's Republic of China, dated April 16, 2002, by and among China United Coalbed Methane Corporation Ltd., ConocoPhillips China Inc. and Far East Energy (Bermuda), Ltd. (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed on April 27, 2007 and incorporated herein by reference). |
| | 10.47 | Farmout Agreement Shouyang PSC, dated June 17, 2003, between Phillips China Inc. and the Company (filed as Exhibit 10.3 to the Company's Amendment No. 1 to its Quarterly Report on Form 10-QSB/A for the quarter ended June 30, 2003 filed on December 24, 2003 and incorporated herein by reference). |
| | 10.48 | First Amendment to Farmout Agreement Shouyang PSC, dated December 15, 2003, between Phillips China Inc. and the Company (filed as Exhibit 10.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004 filed on March 15, 2005 and incorporated herein by reference). |
| | 10.49 | Second Amendment to Farmout Agreement Shouyang PSC, dated December 17, 2004, between Phillips China Inc. and the Company (filed as Exhibit 10.02 to the Company's Current Report on Form 8-K filed on December 23, 2004 and incorporated herein by reference). |
| | 10.50 | Third Amendment to Farmout Agreement Shouyang PSC, dated December 19, 2005, between ConocoPhillips China Inc. and the Company (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed on December 21, 2005 and incorporated herein by reference). |
| | 10.51 | Assignment Agreement Shouyang PSC, dated June 17, 2003, between Phillips China Inc. and the Company (filed as Exhibit 10.5 to the Company's Amendment No. 1 to its Quarterly Report on Form 10-QSB/A for the quarter ended June 30, 2003 filed on December 24, 2003 and incorporated herein by reference). |
| | 10.52 | Application for the Extension of Phase Two of the Exploration Period under the Shouyang PSC, dated December 2, 2005, between the Company and China United Coalbed Methane Corporation Ltd. (filed as Exhibit 10.46 to Company's Annual Report on Form 10-K for the year ended December 31, 2005 filed on March 14, 2006 and incorporated herein by a reference). |
| | 10.53 | Application for the Extension of Phase Two of the Exploration Period under the Shouyang PSC, dated March 16, 2006, between the Company and China United Coalbed Methane Corporation Ltd. (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed on March 17, 2006 and incorporated herein by reference). |
| | 10.54 | Modification Agreement, dated April 24, 2007, for Production Sharing Contract for Exploitation of Coalbed Methane Resources for the Shouyang Area in Shanxi Province, Qinshui Basin, the People's Republic of China, dated April 16, 2002, by and among China United Coalbed Methane Corporation Ltd., ConocoPhillips China Inc. and Far East Energy (Bermuda), Ltd. (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on April 27, 2007 and incorporated herein by reference). |
| | 10.55 | Modification Agreement for Production Sharing Contract for Exploitation of Coalbed Methane Resources for the Shouyang Area in Shanxi Province, Qinshui Basin, The People's Republic of China (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on August 27, 2009 and incorporated herein by reference). |
| | 10.56 | English translation of Shouyang Project Coalbed Methane Purchase and Sales Contract, dated June 12, |
| | | 2010, between China United Coalbed Methane Corporation, Ltd. and Shanxi Province Guoxin Energy Development Group Limited with Far East Energy (Bermuda), Ltd. as an express third party beneficiary (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on June 16, 2010 and incorporated herein by reference). |
| | 10.57 | English translation of Letter agreement, dated June 12, 2010, between Far East Energy (Bermuda), Ltd. and China United Coalbed Methane Corporation, Ltd. (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed on June 16, 2010 and incorporated herein by reference). |
| | 10.58 | Letter, dated June 11, 2010, from Far East Energy (Bermuda), Ltd. to China United Coalbed Methane Corporation, Ltd. (filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed on June 16, 2010 and incorporated herein by reference). |
| | 10.59 | Stock Subscription Agreement, dated August 24, 2007, between the Company and International Finance Corporation (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on August 27, 2007 and incorporated herein by reference). |
| | 10.60 | Stock Subscription Agreement, dated June 2, 2008, between the Company and International Finance Corporation (filed as Exhibit 10.64 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 filed on August 6, 2008 and incorporated herein by reference). |
| | 10.61 | Securities Purchase Agreement, dated March 13, 2009, among the Company, Far East Energy (Bermuda), Ltd., and Arrow Energy International Pte Ltd. (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on March 16, 2009 and incorporated herein by reference). |
| | 10.62 | Placement Agency Agreement, dated August 20, 2010, between the Company and Macquarie Capital (USA), Inc. (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on August 20, 2010 and incorporated herein by reference). |
| | 10.66 | Facility Agreement, dated November 28, 2011, among Far East Energy (Bermuda), Ltd., Far East Energy Corporation and Standard Chartered Bank (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 2, 2011 and incorporated herein by reference). |
| | | List of Subsidiaries of the Company. |
| | | Consent of JonesBaggett LLP. |
| | | Consent of Resource Investment Strategy Consultants. |
| | | Powers of Attorney. |
| | | Certification of Chief Executive Officer of the Company under Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | Certification of Chief Financial Officer of the Company under Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | Certification of Chief Executive Officer of the Company Pursuant to 18 U.S.C. Sec. 1350. |
| | | Certification of Chief Financial Officer of the Company Pursuant to 18 U.S.C. Sec. 1350. |
| | | Shouyang US SEC Reserves Report, dated as March 1, 2012, prepared by Resources Investment Strategy Consultants. |
| | 101.INS | XBRL Instant Document |
| | 101.SCH | XBRL Taxonomy Extension Schema Document |
| | 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document |
| | 101.LAB | XBRL Taxonomy Extension Label Linkbase Document |
| | 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
| | 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document |
____________
| * | Management contract or compensatory plan or arrangement. |
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