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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 2)

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

For the fiscal year ended December 31, 2009

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 1-10262

HKN, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code (817)424-2424

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  ¨ Yes  x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes o No x

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. x Yes  ¨ No.

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate Website, 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 o  No x

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/A or any amendment to this Form 10-K/A.  ¨

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 definition of “accelerated filer and large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes   x No

The aggregate market value of the voting Common Stock, par value $0.01 per share, held by non affiliates of the Registrant as of June 30, 2009 was approximately $25 million. For purposes of the determination of the above stated amount only, all directors, executive officers and 5% or more stockholders of the Registrant are presumed to be affiliates.

The number of shares of Common Stock, par value $0.01 per share, outstanding as of February 1, 2010 was 9,553,847.

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EXPLANATORY NOTE

This Amendment No. 2 on Form 10-K/A is being filed for the purposes of amending the following items of the Annual Report:

i.                  Item 1 (Business) — HKN is revising its disclosures as follows:

a.               to provide additional information regarding the minimum remaining terms of our leases pursuant to Item 1208(b) of Regulation S-K,

b.              to disclose the qualifications of the technical person primarily responsible for accepting the final report of the reserves estimates from our third-party engineers,

c.               to update our proved developed reserves as of December 31, 2008 as well as to include our proved undeveloped oil and gas reserve quantities for the years ended December 31, 2007, 2008, and 2009 and

d.              to remove any quantitative disclosure of Spitfire’s estimated reserves and to disclose the reasons why this information is not included.

ii.               Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) — HKN is revising its Critical Accounting Estimates and Assumptions to provide additional information regarding our income tax contingency.

iii.            Item 7A (Quantitative and Qualitative Disclosures about Market Risk) — HKN is revising Item 305 as “Not Applicable” in accordance with the scaled disclosure requirements available to smaller reporting companies for the year ended December 31, 2009.

iv.           Item 8 (Financial Statements and Supplementary Data) — HKN is revising footnote 16, Oil and Gas Disclosures, to remove any quantitative disclosure of Spitfire’s estimated standardized measure and to disclose the reasons why this information is not included.  HKN is also revising footnote 10, Income Taxes, to provide additional information regarding our income tax contingency.

v.              Item 15 (Exhibits and Financial Statement Schedules) — HKN is providing revised third-party reserve reports in accordance with Item 1202(a)(8) of Regulation S-K.

HKN previously filed Amendment No. 1 of Form 10-K/A on April 14, 2010 pursuant to Rule 12b-15 of the Securities Exchange Act of 1934, to amend its Annual Report on Form 10-K for the year ended December 31, 2009 by adding the information required by Items 10, 11, 12 and 13 of Part III relating to Directors and Executive Officers of the Registrant, Executive Compensation, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, and Certain Relationships and Related Transactions, respectively.

In order to preserve the nature and character of the disclosures as originally filed, except as specifically discussed in this Amendment No. 2 to the Annual Report on Form 10-K/A, no attempt has been made to modify or update such disclosures for events which occurred subsequent to the original filing on February 19, 2010. This Amendment No. 2 to the Annual Report on Form 10-K/A does not otherwise alter the disclosures set forth in the Amendment No. 1 of the Annual Report for the year ended December 31, 2009.

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The following discussion is intended to assist you in understanding our business and the results of our operations.  It should be read in conjunction with the Consolidated Financial Statements and the related notes that appear elsewhere in this report.  Certain statements made in our discussion may be forward looking.  Forward-looking statements involve risks and uncertainties and a number of factors could cause actual results or outcomes to differ materially from our expectations.  Unless the context requires otherwise, when we refer to “we,” “us” and “our,” we are describing HKN, Inc. and its consolidated subsidiaries on a consolidated basis.

PART I

ITEM 1. BUSINESS

Overview

Our business strategy is focused on enhancing value for our stockholders through the development of a well-balanced portfolio of energy-based assets.  Currently, the majority of the value of our assets is derived from our ownership in Gulf Coast oil and gas properties and in our coalbed methane prospects in Indiana and Ohio.  We consider these assets to be strategic for us, and our objective in 2010 is to build the value of these properties by:

·                  Monitoring and reducing operating costs

·                  Reducing operational, environmental, financial and third-party dependency risks

·                  Pursuing possibilities for “expanding our footprint” in these areas

·                  Performing economic upgrades and improvements

We are also seeking to identify further investment opportunities in undervalued energy-based assets or companies which could provide future value for our shareholders.

We were incorporated in 1973 in the State of California and reincorporated in 1979 in the State of Delaware. Our corporate offices are located at 180 State Street, Suite 200, Southlake, Texas 76092. Our telephone number is (817) 424-2424, and our web site is accessed at www.hkninc.com. We make available, free of charge, on our website, our Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers, Audit Committee Charter and Nominating and Corporate Governance Committee Charter as well as our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as is reasonably practical after such materials are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC).

Oil and Gas Development and Production Operations

During the three years ended December 31, 2009, we drilled or participated in the drilling of 22 oil and gas wells in North America, completing 20 of the wells drilled. During 2009, we participated in the completion of 2 development wells. As of December 31, 2009, we operate or own a non-operating working interest in 69 oil wells, 65 gas wells and 12 injection wells in the Gulf Coast area of the United States. All of our proved oil and gas reserves are concentrated in the Gulf Coast region of Louisiana and Texas.

Prospect Acreage - In addition to the producing property interests discussed above, we own, through certain wholly-owned subsidiaries, interests in a variety of domestic prospect acreage in the Creole, East Lake Verret and Lapeyrouse fields of Cameron, Assumption and Terrebonne Parishes, respectively, in Louisiana.

See Note 14 — “Other Information” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K for financial information about our oil and gas interests.

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Oil and Gas Customers

During 2009, one domestic customer, Shell, purchased approximately 61% of our consolidated oil and gas sales. During 2008, three domestic customers, Shell, Louis Dreyfus and Sequent, purchased approximately 56% of our consolidated oil and gas sales. During 2007, three domestic customers, Shell, Chevron and Noble, purchased approximately 60% of our consolidated oil and gas sales.

Oil and Natural Gas Marketing

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months.  Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation.  The spot market for oil and gas is subject to volatility as supply and demand factors fluctuate.  We may periodically enter into financial hedging arrangements with a portion of our oil and gas production.  In December 2009, we purchased a crude oil commodity floor contract at a premium of $30 thousand.  These activities are intended to support targeted price levels and to manage our exposure to price fluctuations.  See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Oil and Gas Properties and Locations

Production and Revenues — See also Note 16 — “Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K for certain information about our proved oil and gas reserves.  A summary of our ownership in our most significant producing properties at December 31, 2009 is as follows:

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The following table shows, for the periods indicated, operating information attributable to our oil and gas interests:

Acreage and Wells — At December 31, 2009, we owned interests in the following oil and gas wells and acreage.

Most of our proved undeveloped acreage is subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years.  We do not expect to lose any significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel.  However, based on our evaluation of prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.

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Drilling Activity - A well is considered “drilled” when it is completed. A productive well is completed when permanent equipment is installed for the production of oil or gas.  A dry hole is completed when it has been plugged as required and its abandonment is reported to the appropriate government agency. The following tables summarize certain information concerning our drilling activity:

Reserve Information - The process of estimating oil and gas reserves is complex and requires significant judgment as discussed in Item 1A, Risk Factors.  As a result, we have developed internal policies and controls for reviewing the reserve reports which are prepared by qualified third-party engineers, as defined by the Society of Petroleum Engineers’ standards.  We also require that the independent third-party reservoir engineers ensure that the proved reserve estimates are determined in accordance with SEC definitions and guidance.  Our internal policies assign responsibility for review of our third-party reserve reports to our Vice President of Exploration who has more than 20 years of experience in this field.

Our domestic reserve estimates at December 31, 2009, 2008 and 2007 have been prepared by Collarini Associates and Crest Engineering Services, Inc., both of which are independent, registered members of a professional engineering society in the state of Texas. We internally tested these reports to ensure the inputs and assumptions used are reasonable, as well as reviewed the qualifications of both Collarini and Crest. Proved oil and gas reserves are defined as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

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The reliability of reserve information is considerably affected by several factors. Reserve information is imprecise due to the inherent uncertainties in, and the limited nature of, the data based upon which the estimating of reserve information is predicated. Moreover, the methods and data used in estimating reserve information are often necessarily indirect or analogical in character rather than direct or deductive. Furthermore, estimating reserve information by applying generally accepted petroleum engineering and evaluation principles involves numerous judgments based upon the engineer’s educational background, professional training and professional experience.  The extent and significance of the judgments to be made are, in themselves, sufficient to render reserve information inherently imprecise.

After making an exhaustive effort, we were unable to obtain the reserve information necessary from our equity method investment in Spitfire since Spitfire’s most recent reserve report data is based on a calendar year end of March 31, 2009. After contacting Spitfire for updated reserve estimates as of December 31, 2009, they indicated these estimates are not available and would not be available to the public. In addition, their reserve report is not compiled in accordance with the SEC guidelines. Therefore, Spitfire has not been included in our estimated reserve quantities of proved oil and gas reserves as of December 2009 and 2008.

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(1)          All reserves were held within the United States for the years ended December 31, 2009, 2008 and 2007.

(2)          Our December 31, 2009 proved undeveloped reserves were comprised of 190 thousand barrels of crude oil and 185 thousand Mcf of natural gas, net. Proved undeveloped oil reserves increased 352% from our December 31, 2008 total of 42 thousand barrels of crude oil primarily as a result of the incorporation of 2008 positive drilling results which proved up several additional development locations in our third-party reserve estimates at December 31, 2009.  Proved undeveloped natural gas reserves decreased by 62% from December 31, 2008 estimates of 482 thousand Mcf primarily from the removal of undeveloped natural gas reserves at Main Pass 35 due to the uneconomic nature of the projects using 2009 twelve month average gas pricing. During the year ended December 31, 2009, the Company focused its capital program on development drilling and facility improvements and did not incur any capital expenditures or make any significant progress to convert any of our proved undeveloped reserves to proved developed reserves. As of December 31, 2009, no undeveloped reserves that were identified more than 5 years ago remain in our proved reserve portfolio.

At December 31, 2009, we had two fields, Main Pass and Creole Field, that contained 15% or more of our total proved reserves. The following table shows the production for these fields for the year ended December 31:

Coalbed Methane Prospects — Indiana and Ohio

At December 31, 2009, we currently hold two coalbed methane exploration and development agreements in Indiana and Ohio. The agreements provide for a phased delineation, pilot and development program with corresponding staged expenditures. Third party consultants with a long track record in successful coalbed methane development provide expert advice for these projects. These coalbed methane prospects provide for an area of mutual interest of approximately 400,000 gross acres in Indiana and 400,000 gross acres in Ohio. In association with the Indiana coalbed methane exploration and development agreement, we executed a coalbed methane lease during February 2010 for an area of 84,527 gross acres (54,943 net acres) within the Indiana prospect area.  This lease will expire in 2019, if not extended.  The Ohio coalbed methane exploration and development agreement expired during 2010, and management is currently considering whether to negotiate an extension of the Ohio agreement.  There are no proved reserves or production associated with the Indiana or Ohio coalbed methane prospects. We do not expect to lose any significant acreage associated with our coalbed methane prospects because of failure to develop or drill due to inadequate capital, equipment, or personnel.

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Currently, we are in the dewatering phase in which the pilot wells are produced to maximize fluid (water) production in order to lower reservoir pressure so that desorption of gas can occur in the pilot test wells on the Indiana Posey Contract area.  We continue to evaluate their progress.  With the decline in oil and gas commodity prices, resource plays, such as coalbed methane prospects, can become uneconomical in low price environments particularly since all well, facility and flowline costs as well as  operating costs during the dewatering/desorption process must be incurred before  revenues can generated. Our discretionary capital expenditures, including costs related to our coalbed methane prospects, may be curtailed at our discretion in the future. Such expenditure curtailments could result in us losing certain prospect acreage or reducing our interest in future development projects.

International Energy Investment — Global Energy Development PLC

At December 31, 2009 and 2008, we held an investment in Global Energy Development PLC (“Global”) through our ownership of approximately 34% of Global’s ordinary shares. We account for our ownership of Global shares as a cost method investment. Global is a petroleum exploration and production company focused on Latin America. Global’s shares are traded on the AIM, a market operated by the London Stock Exchange.  See Note 3 — “Other Investments” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K for further information. Additional information regarding Global’s operations may be found on their website, www.globalenergydevelopmentplc.com.

Canadian Energy Investment — Spitfire Energy, Ltd.

At December 31, 2009 and 2008, we held an investment in Spitfire Energy, Ltd. (“Spitfire”) through the ownership of approximately 25% and 27%, respectively, of Spitfire’s currently outstanding common shares. Spitfire is an independent public company (TSX-V; SEL) engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids in Western Canada.  At December 31, 2009, we owned 9.9 million common shares of Spitfire and 1.3 million warrants to acquire common shares of Spitfire. As a result of our ownership of Spitfire’s outstanding common shares, we are deemed to have the ability to exert significant influence over Spitfire’s operating and financial policies. Accordingly, we reflect our investment in Spitfire as an equity method investment.  During 2009, we sold approximately 1.2 million shares of Spitfire in the market for total proceeds of $212 thousand. Additional information regarding Spitfire’s operations may be found on their website, www.spitfireenergy.com.

Investment in BriteWater International, LLC (formerly UniPureEnergy)

In June  2009, we acquired a 19.5% interest in a private company, BriteWater International, LLC (“BWI”), formerly known as UniPureEnergy Acquisition, LLC (“UniPure Energy”), which holds patents to the emulsion breaking “OHSOL” technology.  This environmentally-clean process can be used to purify oilfield emulsions by breaking and separating the emulsions into oil, water and solids. This technology has been successfully tested using a mobile OHSOL unit in a demonstration in Prudhoe Bay, Alaska, which demonstrated the effectiveness of the OHSOL emulsion breaking technology to recover valuable hydrocarbons and reduce wastes. BWI is currently pursuing opportunities to commercialize the OHSOL technology by performing emulsion testing of the OHSOL plant equipment both internationally and domestically.

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Discontinued Operations — Canergy Management Company and Canergy Growth Fund

In 2008, we created the Canergy Growth Fund to invest in the Canadian junior oil and gas market.  As a result of the dramatic decline in the U.S. and foreign stock markets, and in order to avoid future additional significant losses, Canergy Growth Fund divested of all of its common stock holdings in Canadian junior oil and gas companies during 2008. With the continued economic volatility in 2009, we did not participate in any additional investments during 2009.  In the fourth quarter 2009, we chose to dissolve the Canergy Growth Fund and Canergy Management Company. The results of operations have been reclassified to discontinued operations in our Consolidated Financial Statements. See Note 13 — “Discontinued Operations” in the Notes to Consolidated Financial Statements contained in Part III, Item 8 of this Annual Report on Form 10-K for further information.

Energy-Based Trading Investments

In 2008, due to the dramatic volatility in the U.S. and international stock markets, we terminated all our common stock and common stock derivative contracts used for trading purposes. We had previously maintained an investment portfolio of investments in energy industry and foreign currency securities traded on domestic securities exchanges.  We did not participate in the trading of energy-based investments in 2009. Therefore, we had no total potential obligations or exposure associated with such instruments as of December 31, 2009.  See “Note 3 — Other Investments” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K for financial information regarding our trading activities.

Employees

At December 31, 2009, we had 16 employees. We have experienced no work stoppages or strikes as a result of labor disputes and consider relations with our employees to be satisfactory. We maintain group medical, dental, surgical and hospital insurance plans for our employees.

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PART II

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

The following discussion is intended to assist you in understanding our business and the results of our operations.  It should be read in conjunction with the Consolidated Financial Statements and the related notes that appear elsewhere in this report.  Certain statements made in our discussion may be forward looking.  Forward-looking statements involve risks and uncertainties and a number of factors could cause actual results or outcomes to differ materially from our expectations.  See “Cautionary Statements” at the beginning of this report on Form 10-K for additional discussion of some of these risks and uncertainties.  Unless the context requires otherwise, when we refer to “we,” “us” and “our,” we are describing HKN, Inc. and its consolidated subsidiaries on a consolidated basis.

BUSINESS OVERVIEW

Our business strategy is focused on enhancing value for our stockholders through the development of a well-balanced portfolio of energy-based assets.  Currently, the majority of the value of our assets is derived from our ownership in Gulf Coast oil and gas properties and in our coalbed methane prospects in Indiana and Ohio.  We consider these assets to be strategic for us, and our objective in 2010 is to build the value of these properties by:

·                  Monitoring and reducing operating costs

·                  Reducing operational, environmental, financial and third-party dependency risks

·                  Pursuing possibilities for “expanding our footprint” in these areas

·                  Performing economic upgrades and improvements

2009 Recap and 2010 Outlook

During 2009, commodity pricing for both crude oil and natural gas averaged well below pricing from the respective prior year period.  In 2009, industry-wide drilling costs did not reduce in comparison to the dramatic drop in commodity prices.  In order to allow our operations to continue to generate cash flow from operating activities, we focused on reducing our costs by cutting our operating expenses by 20% and our general and administrative costs by 39% over prior year.  However, oil and gas commodity prices during the year averaged approximately 43% and 60% lower, respectively, than 2008.  In 2010, our objective is to continue to maintain and/or improve our working capital and to increase our operating margin as compared to prior year.  We believe in the long-term fundamentals of our industry.

In 2009, we used our discretionary cash to simplify our capital structure by redeeming the remaining 44 thousand shares of our Series M Preferred Stock and six hundred shares of our G1 Preferred Stock for a total of approximately $4.4 million.  The Series M Preferred had an 8% cash coupon rate which was scheduled to increase to 10% in October 2009.  As of December 31, 2009, our Series M Preferred is no longer outstanding. In accordance with our share buyback program, in 2009, we also repurchased 708 thousand of our common shares in the market (approximately 7% of our outstanding shares) at a total cost of approximately $1.9 million.

During 2009, we enhanced the value of our Main Pass 35 field, located offshore Louisiana in the Gulf of Mexico, by performing various process and structural upgrades and improvements to the facility and its equipment.   We believe our Main Pass 35 asset has unique characteristics such as low-decline oil production, behind-pipe development potential as well as third-party oil, gas and water processing and handling services for neighboring fields in the area.  We consider our Main Pass 35 field a strategic asset for us in 2010.

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During 2009, we acquired an interest in a private company, BriteWater International, LLC (“BWI”), formerly known as UniPureEnergy Acquisition, LLC, which holds patents to the emulsion breaking “OHSOL” technology.  This environmentally-clean process can be used to purify oilfield emulsions by breaking and separating the emulsions into oil, water and solids.  This technology has been successfully tested using a mobile OHSOL unit in a demonstration in Prudhoe Bay, Alaska, which demonstrated the effectiveness of the OHSOL emulsion breaking technology to recover valuable hydrocarbons and reduce wastes.  We are currently pursuing opportunities to commercialize the OHSOL technology by performing emulsion testing of the OHSOL plant equipment both internationally and domestically.  We are deemed the primary beneficiary of BWI, and as a result, effective June 30, 2009 (the investment date) we began consolidating the assets and liabilities and results of operations of BWI as of the investment date.

We are also seeking to identify further investment opportunities in undervalued energy-based assets or companies which could provide future value for our shareholders.

Each year we evaluate our assets to determine which may have reached their full potential, do not have an expectation of near-term value enhancement or represent a disproportionate concentration of value in one asset and should be targeted for monetization.  In 2010, we are targeting certain of our non-strategic Gulf Coast oil and gas properties for divestiture in order to mitigate possible future losses of these end-of-life properties.

We continue to have access to capital, and we have a cash balance of approximately $7 million at December 31, 2009. We also anticipate our operating cash flow and other capital resources, if needed, will adequately fund our planned capital expenditures and other capital uses over the near-term.  Based on industry outlook for 2010, prices for oil and natural gas are expected to increase as compared to the prior year. In addition, with savings expected due to cost-cutting measures already implemented, we have budgeted our 2010 operations to remain cash-flow positive.

Capital Deployment Update

During 2009, we continued our efforts to deploy assets into energy-based opportunities to build annual measurable value and/or cash flow as follows:

·                  We deployed capital expenditures of approximately $831 thousand to enhance the value of our Main Pass 35 field through process, structural, environmental and operational improvements to the facility.

·                  We deployed capital expenditures of approximately $1.3 million for oil and gas exploratory and development drilling at our Creole Field, as well as other projects.

·                  In accordance with our share buyback program, in 2009, we repurchased 708 thousand of our common shares in the market (approximately 7% of our outstanding shares) for total proceeds of approximately $1.9 million.

·                  We simplified our capital structure by redeeming 44 thousand shares of our Series M Preferred Stock and six hundred shares of our G1 Preferred Stock for a total of approximately $4.4 million.  As of December 31, 2009, our Series M Preferred Stock is no longer outstanding.

Gulf Coast Oil and Gas Properties

During 2009, our results of operations reflect decreased oil and natural gas revenues as compared to 2008 as a result of decreased commodity prices.  During the current year, the realized price of oil averaged $58.48 per barrel (“Bbl”), approximately 43% lower than 2008.  Natural gas prices realized in 2009 averaged

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$3.97 per metric cubic foot (“Mcf”), approximately 60% lower than prior year.  Substantially all of our production is concentrated in twelve oil and gas fields along the onshore and offshore Texas and Louisiana Gulf Coast.    As of December 31, 2009, our net domestic production rate was averaging approximately 519 barrels of oil equivalent (“boe”) per day.

Our revenues are primarily derived from sales from our oil and gas properties. Approximately 54% of our production comes from our operated properties all located in the United States. These revenues are a function of the oil and gas volumes produced and the prevailing commodity price at the time of production, and certain quality and transportation discounts. The commodity prices for crude oil and natural gas as well as the timing of production volumes have a significant impact on our operating income. During 2009, our oil and gas revenues were comprised of approximately 85% oil sales and 15% natural gas production.

The following field data updates the status of our operations through December 31, 2009:

Main Pass, Plaquemines Parish — Louisiana

During 2009, we enhanced the value of our Main Pass 35 field, located offshore Louisiana in the Gulf of Mexico, by performing various process and structural upgrades and improvements to the facility and its equipment.  We believe our Main Pass 35 asset has unique characteristics such as low-decline oil production, behind-pipe development potential as well as third-party oil, gas and water processing and handling services for neighboring fields in the area.  We consider our Main Pass 35 field a strategic asset for us in 2010.

We have an average 91% interest in Main Pass 35 and are the field operator. This field contains a ten-platform facility complex including separation, injection, compression, processing and transportation terminals for oil, water and gas. The field also contains 66 wellbores (60 oil and 6 injection wells), of which 33 are active, and an eight mile oil transport line with pump/metering facilities. Our Main Pass 35 facility is located approximately six miles offshore in state waters off the Gulf Coast of Louisiana. We currently have license to 21 square miles of 3D seismic data covering the area held by productive leases. Gross production during 2009 averaged approximately 400 boe per day. In order to lower our gas lift expense in the field, we are currently planning a recompletion project of at least one gas zone soon after some required modifications to the gas sales line that services the field are completed.

Creole Field, Terrebonne Parish - Louisiana

We hold an average 15% non-operated working interest in this offshore field. Gross daily production from the wells (nine completions) was approximately 952 boe per day during 2009. Three completions in two wells drilled in late 2008 were put on production in 2009 after significant weather delays. In mid-2009, we participated with one of the other working interest owners in a revised third party reserve study. The study was based in large part on a new geologic interpretation which incorporated the latest drilling results and a significantly improved speculative 3D seismic volume.  As a result of this study, three new proved undeveloped locations, six new probable locations and twenty new possible locations have been identified and documented. Two re-entries, one major workover and one new well are anticipated in 2010.

Lapeyrouse Field, Terrebonne Parish — Louisiana

We hold an average non-operated working interest of approximately 12% in the production from nine wells in this field. Gross field production averaged approximately 198 boe per day for 2009.  Evaluation efforts by the operator are still ongoing with additional diagnostic work planned by the operator to address the field pressure decline and to utilize all available wellbores.  We are considering this field for divestiture in 2010, although no final decision has been made at this time.

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Lake Raccourci Field, Lafourche Parish — Louisiana

We hold an average 40% operated working interest in each of our Lake Raccourci wells. Gross production for this field averaged 78 boe per day for 2009. Production decreased significantly this quarterly period primarily due to the fact that the SL 14284-1 well ceased production in February 2009.  Diagnostic work indicated that the well ceased production due to sand build up in the tubing.  Coiled tubing work was carried out, but failed to restore production. We are currently evaluating the economic potential of a recompletion to the Tex 16 zone behind pipe, as well as several other zones in our two other producing wells in the field. We are considering this field for divestiture in 2010, although no final decision has been made at this time.

Point-a-la-Hache Field, Plaquemines Parish — Louisiana

We maintain a 25% operated working interest in one producing well in this field. Average gross production for 2009 was approximately 40 boe per day.  Production remains steady from this one well field.

East Lake Verret, Assumption Parish — Louisiana

We have an average 5% non-operated working interest in this field. Gross daily production from the two development wells on this project was approximately 699 boe per day during 2009.

Point-au-Fer Field, Terrebonne Parish — Louisiana

We own a 12.5% non-operated working interest in this approximate 56 square mile area. Gross production for this field was approximately 33 boe per day for 2009. Several prospects have been identified in the area, but due to the low oil and gas pricing, we expect additional drilling and work over activity will be delayed by the operator.

Branville Bay Field, St. Bernard Parish — Louisiana

We own a 12.5% non-operated working interest in two state leases in the Branville Bay area of Chandeleur Sound Block 71. Gross production for this field was approximately 221 boe per day for 2009.

BP 2D Texas Gulf Coast Project, Various Counties -  Texas

We own a 25% non-operated working interest in the Boquillas #1 well. Gross production from this well is steady and was approximately 170 boe per day for 2009.

NW Speaks Field, Lavaca County — Texas

We own approximately 2% to 7% in various leases in the NW Speaks area. Current gross production for this field averaged approximately 92 boe per day during 2009 from two wells.

Allen Ranch Field, Colorado County — Texas

We own an 11.25% non-operated working interest in this area. Gross production for this field was approximately 57 boe per day during 2009 primarily from the initial well, the Hancock Gas Unit #1 which is the only well currently producing from the field. Another development location has been identified, but future development of the field is currently on hold pending higher natural gas pricing.

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Raymondville Field, Willacy County — Texas

We own an average 22% non-operated working interest in this area. Current gross production for this field averaged approximately 336 boe per day during 2009. Field production continues to decline as fewer behind pipe zones remain. Several wells ceased production in 2009 and have no remaining recompletion potential.  We are considering this field for divestiture in 2010, although no final decision has been made at this time.

Lucky Field, Matagorda County - Texas

We own a 7.5% non-operated working interest in this area. Current gross production for this field averaged approximately 46 boe per day during 2009.

Coalbed Methane Prospects — Indiana and Ohio

We hold two exploration and development agreements in Indiana and Ohio which provide for an area of mutual interest of approximately 400,000 acres each respectively. The agreements provide for a phased delineation, pilot and development program, with corresponding staged expenditures. Contracted third parties with a long track record in successful Coalbed Methane development provide expert advice for these projects.

On the Indiana Posey Prospect, we completed Phase I — Core Samples work on the Indiana Prospect which consisted of obtaining and analyzing coal samples. Based on the positive outcome of the coring analysis, we elected into Phase II which consists of exploratory work.  During 2007, all five pilot producing wells were drilled, completed and put on pump-down production for gas desorption via newly installed pumps, lines and facilities. In addition, a produced water disposal well was drilled and completed to service the pilot wells.  Some gas production has begun and is being used throughout the field for fuel gas needs.  The extent of water influx is under evaluation to enhance desorption efforts.  In 2008, chemical treatments to enhance well fluid productivity was begun with fracture stimulation under evaluation as desorption pump-down continues. Also in 2008, a fracture stimulation was performed to increase desorption pumpdown rates. Alternative design stimulations are under evaluation as pumpdown continues as the initial fracture treatments are evaluated.

We elected to proceed with a second pilot well project. A monitor well was drilled, completed and tested for permeability determination in late 2007. During 2008, five pilot producers and the water disposal well were completed with specialized fracture stimulation completed in late fourth quarter 2008.  Currently, we are in the dewatering phase in which the pilot wells are produced to maximize fluid (water) production in order to lower reservoir pressure so that desorption of gas can occur in the pilot test wells on the Indiana Posey Contract area.  We continue to evaluate their progress.  Following an evaluation period of these two pilot areas, we will evaluate a Phase III — Development election and funding of a development well program as contemplated by the agreements.

On the Ohio Cumberland Prospect, we completed Phase I — Core Samples work on the Ohio Prospect which consisted of obtaining and analyzing coal samples. With regard to Phase II, we made an additional $500 thousand prospect acquisition payment and intend to fund the first of two pilot well projects on the Cumberland Prospect.  This Phase II project has been temporarily suspended until such time as oil and gas commodity pricing increases.  We continue to focus our efforts on the Indiana Posey Contract.

With low oil and gas commodity prices, resource plays, such as coalbed methane prospects, can become uneconomical particularly since all well, facility and flowline costs as well as operating costs during the dewatering/desorption process must be incurred before revenues can generated. Our discretionary capital expenditures, including costs related to our coalbed methane prospects, may be curtailed at our discretion in the

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future. Such expenditure curtailments could result in us losing certain prospect acreage or reducing our interest in future development projects.

INVESTMENT IN BRITEWATER INTERNATIONAL, LLC.

In June 2009, we acquired a 19.5% interest in a privately-held company, BWI, formerly referred to as UniPure, with a patented oilfield emulsion breaking “OHSOL” technology. We are deemed to be the primary beneficiary, and accordingly, we have consolidated the assets and liabilities of BWI as of the investment date. The results of operations for the six months ended December 31, 2009 have been consolidated in our results of operations. See Note 2 — Investment in BriteWater International, LLC.” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K for further information.

INVESTMENT IN GLOBAL

At December 31, 2009 and 2008, we owned approximately 34% of Global’s ordinary shares. At December 31, 2009 and 2008, our investment in Global was equal to the market value of our 11.9 million shares of Global’s common stock as follows (in thousands, except share amounts):

The foreign currency translation adjustment of approximately $789 thousand and the unrealized gain on investment of $24 thousand for these changes in market value between the two periods were recorded to other comprehensive income in stockholders’ equity during the year ending December 31, 2009.

Global’s asset base and financial information continue to be strong; therefore we intend to hold our shares of Global until the London market improves.  For information on Global’s operations and financial statements, visit their website at www.globalenergyplc.com.

INVESTMENT IN SPITFIRE

At December 31, 2009 and 2008, we held an investment in Spitfire through the ownership of approximately 25% and 27%, respectively, of Spitfire’s currently outstanding common shares. Spitfire is an independent public company (TSX-V; SEL) engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids in Western Canada.

At December 31, 2009, we owned 9.9 million common shares of Spitfire and 1.3 million warrants to acquire common shares of Spitfire.  As a result of our ownership of Spitfire’s outstanding common shares, we are deemed to have the ability to exert significant influence over Spitfire’s operating and financial policies. Accordingly, we reflect our investment in Spitfire as an equity method investment. Due to timing differences in our filing requirements and the lack of availability of financial information for the current quarterly period, we record our share of Spitfire’s financial activity on a three-month lag. During June 2008, our representatives on the Spitfire board of directors resigned due to scheduling and corporate strategy conflicts.

During 2009, we sold approximately 1.2 million of our Spitfire shares in the market for cash proceeds of $212 thousand.  In 2010, we may continue to sell a portion of our Spitfire shares in the market while we pursue strategic alternatives for this Canadian investment. For information on Spitfire’s operations and financial statements, visit their website at www.spitfireenergy.com.

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CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

Our consolidated financial statements have been prepared in accordance with U.S. GAAP which requires us to use estimates and make assumptions that affect the reported amounts of assets, liabilities, revenues and expenses.  Our estimates and assumptions are based on historical experience, industry conditions and various other factors which we believe are appropriate. Actual results could vary significantly from our estimates and assumptions as additional information becomes known.  The more significant critical accounting estimates and assumptions are described below.

Property and Equipment — We follow the full cost method of accounting for our investments in oil and natural gas properties. All costs incurred with the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. Under the full cost method of accounting, such costs may be incurred both prior to or after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion and equipment. Included in capitalized costs are general and administrative costs that are directly related to acquisition, exploration and development activities, and which are not related to production, general corporate overhead or similar activities. For the years 2009, 2008, and 2007, such capitalized general and administrative costs totaled $295 thousand, $248 thousand, and $904 thousand, respectively. General and administrative costs related to production and general overhead are expensed as incurred.

Proceeds from the sale of oil and natural gas properties are credited to the full cost pool, except in transactions where the proceeds received from the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss would be recognized.

Future development, site restoration, and dismantlement and abandonment costs, net of salvage values, are estimated property by property based upon current economic conditions and are included in our amortization of our oil and natural gas property costs.

The provision for depletion and amortization of oil and natural gas properties is computed by the unit-of-production method. Under this computation, the total unamortized costs of oil and natural gas properties (including future development, site restoration, and dismantlement and abandonment costs, net of salvage value), excluding costs of unproved properties, are divided by the total estimated units of proved oil and natural gas reserves at the beginning of the period to determine the depletion rate. This rate is multiplied by the physical units of oil and natural gas produced during the period.  Changes in the quantities of our reserves can significantly impact our provision for depletion and amortization of oil and natural gas properties.

The cost of unevaluated oil and natural gas properties not being amortized is assessed quarterly to determine whether such properties have been impaired. In determining impairment, an evaluation is performed on current drilling results, lease expiration dates, current oil and natural gas industry conditions, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.  At December 31, 2009, we had approximately $5.1 million allocated to our unevaluated coalbed methane properties.

Full-Cost Ceiling Test — At the end of each quarter, the unamortized cost of oil and natural gas properties, after deducting the asset retirement obligation, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using average monthly prices, discounted at 10%, and the lower of cost or fair value of unproved properties adjusted for related income tax effects.

The calculation of the ceiling test and the provision for depletion are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in

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projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify a revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Based on the twelve (12) month average commodity pricing in 2009 of $3.87 per Mmbtu for natural gas and $61.18 per barrel for crude oil, we did not have an impairment of our oil and natural gas properties under the full cost method of accounting. Due to the imprecision in estimating oil and natural gas revenues as well as the potential volatility in oil and natural gas prices and their effect on the carrying value of our proved oil and natural gas reserves, there can be no assurance that write-downs in the future will not be required as a result of factors that may negatively affect the present value of proved oil and natural gas reserves and the carrying value of oil and natural gas properties, including volatile oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve quantities and unsuccessful drilling activities. For a complete discussion of our proved oil and gas reserves, see Note 16 — “Oil and Gas Disclosures” in the Notes to the Consolidated Financial statements contained in Part II, Item 8 of the Annual Report of Form 10-K.

Fair Value of Financial Instruments — Financial instruments are stated at fair value as determined in good faith by management. Factors considered in valuing individual investments may include, without limitation, available market prices, reported net asset values, type of security, purchase price, purchases of the same or similar securities by other investors, marketability, restrictions on disposition, current financial position and operating results, and other pertinent information.

We carry our financial instruments including cash, our investment in ordinary shares of Global and our oil commodity derivative contracts at their estimated fair values. The fair value of our investment in the ordinary shares of Global is based on prices quoted in an active market.  The fair values of our oil commodity derivatives are based on pricing provided by our counter parties.

With the exception of our investment in common shares of Spitfire, which is accounted for as an equity method investment, all of our investments in equity securities have been designated as available for sale. Our investment in Global is classified as a non-current asset in our accompanying balance sheets. The associated unrealized gains and losses on our available for sale investments are recorded to other comprehensive income until realized and are reclassified into earnings using specific identification.

Equity Method Investments — For investments in which we have the ability to exercise significant influence but do not control, we follow the equity method of accounting. Our equity investment in Spitfire is classified as a non-current asset in our accompanying balance sheets. Initial investments are recorded at cost and adjusted by the proportionate share of the investee’s earnings and capital transactions. Our share of investee earnings and our share of their capital transactions are recorded to our income statement.  We evaluate these investments for other-than-temporary declines in value each quarter; any impairment found is recognized through earnings.

Translation of Non-U.S. Currency Amounts - Assets and liabilities of our equity investment in Spitfire Energy, whose functional currency is the Canadian dollar, are translated into U.S. dollars at exchange rates in effect at each balance sheet date. Revenue and expense items are translated at average exchange rates prevailing during the periods. Our investment in Global is also subject to foreign currency exchange rate risk as our ownership of Global’s ordinary shares are denominated in British sterling pounds. Translation adjustments are included in other comprehensive income until the investment is sold.

Consolidation of variable interest entities - ASC 810-10-25, Consolidation, requires the primary beneficiary of a variable interest entity’s (“VIE”) activities to consolidate the VIE and defines a VIE as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at

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risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the VIE’s activities.  We have determined that our investment in BWI meets the requirements of ASC 810-10-25, and we are the primary beneficiary, as defined. Accordingly, we have consolidated the assets and liabilities of BWI as of the investment date.  The results of operations for the six months ended December 31, 2009 are consolidated in our results of operations.

As of December 31, 2009, we owned less than a majority of the common shares of Global and did not possess the legal power to direct the operating policies and procedures of Global through our direct ownership, combined with the ownership by Lyford in Global shares. In addition, we have concluded that Global was not a VIE at December 31, 2009 as contemplated by ASC 810-10-25.

Proved Reserves - Our estimates of proved reserves are based on quantities of oil and gas reserves which current engineering data indicates are recoverable from known reservoirs under existing economic and operating conditions.  Estimates of proved reserves are key elements in determining our depletion and expense and our full cost ceiling limitation. Estimates of proved reserves are inherently imprecise because of uncertainties in projecting rates of production and timing of developmental expenditures, interpretations of geological, geophysical, engineering and production data and the quality and quantity of available data.  Changing economic conditions also may affect our estimates of proved reserves due to changes in developmental costs and changes in commodity prices that may impact reservoir economics.  We utilize independent reserve engineers to estimate our proved reserves annually.  See Note 16 - “Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K.

Income Taxes — We account for income taxes under the liability method. Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. We measure and record income tax contingency accruals in accordance with ASC 740, Income Taxes.

We recognize liabilities for uncertain income tax positions based on a two-step process. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates that it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step requires us to estimate and measure the tax benefit as the largest amount that is more than 50% likely to be realized upon ultimate settlement. It is inherently difficult and subjective to estimate such amounts, as we must determine the probability of various possible outcomes. We reevaluate these uncertain tax positions on a quarterly basis or when new information becomes available to management. These reevaluations are based on factors including, but not limited to, changes in facts or circumstances, changes in tax law, successfully settled issues under audit, expirations due to statutes, and new audit activity. Such a change in recognition or measurement could result in the recognition of a tax benefit or an increase to the tax accrual.

We classify interest related to income tax liabilities as income tax expense, and if applicable, penalties are recognized as a component of income tax expense. The income tax liabilities and accrued interest and penalties that are anticipated to be due within one year of the balance sheet date are presented as current liabilities in our consolidated balance sheets.

During 2008, we received a proposed adjustment to our federal tax liability for the calendar year 2005.  We filed a formal protest with the IRS Appeals Office during 2008.  In April 2009, we filed our supplement to the written protest which included a third party valuation report supporting the basis of our recognized gain recorded for ACE purposes.  Utilizing the process outlined above, we have recorded an

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income tax contingency for this item, including interest and penalties, of $225 thousand.  Although we intend to vigorously defend the proposed adjustment and strongly believe the third party valuation report supports our position and that we have meritorious defenses, if the IRS Appeals Office were to deny all of our protests and our assumptions and estimates associated with this income tax contingency are inaccurate, we could be liable for approximately $5.7 million in additional tax, penalties and interest.

Fair Value of Derivatives - We are exposed to risk from fluctuations in crude oil and natural gas prices.  To reduce the impact of this risk in earnings and to increase the predictability of our cash flow, from time to time we enter into certain derivative contracts, primarily collars and floors for a portion of our oil and gas operations.  Fair values of our commodity derivatives are obtained from the third-party broker / dealer portfolio appraisal statement and are used as the primary evidence for the fair value of the financial instrument. Our Spitfire warrants are not exchange-traded derivatives. Management estimates the fair value of these derivatives using the Black Scholes Valuation model.  We have not designated any of our derivative instruments as hedges under ASC 815, Derivates and Hedging. All gains and losses related to these positions are recognized in earnings.

Recent Accounting Pronouncements —  In December 2007, FASB issued guidance related to Business Combinations under ASC 805, Business Combinations, and guidance related to the accounting and reporting of noncontrolling interest under ASC 810-10-65-1, Consolidation. This guidance significantly changes the accounting for and reporting of business combination transactions and noncontrolling (minority) interests in consolidated financial statements. This guidance became effective January 1, 2009. We applied this guidance to our investment in BWI. Please see Note 2 — “Investment in BriteWater International, LLC” in the Notes to Consolidated Financial Statements for additional information.

In March 2008, the FASB issued guidance related to the disclosures about derivative instruments and hedging activities under FASB ASC 815-10-50, Derivatives and Hedging. This guidance requires companies to provide enhanced disclosures about (a) how and why they use derivative instruments, (b) how derivative instruments and related hedged items are accounted for under applicable guidance, and (c) how derivative instruments and related hedged items affect a company’s financial position, financial performance, and cash flows. These disclosure requirements are effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Our adoption of ASC 815-10-50 on January 1, 2009 did not have a material impact on our consolidated financial statements. See Note 5 — “Derivative Instruments” in the Notes to Consolidated Financial Statements for additional information.

In June 2008, the FASB issued guidance to evaluate whether an instrument (or embedded feature) is indexed to an entity’s own stock under ASC 815-40-15, Derivatives and Hedging. The guidance requires entities to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock in order to determine if the instrument should be accounted for as a derivative under the scope of ASC 815-10-15. This guidance is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We adopted ASC 815-40-15 beginning January 1, 2009.  We applied this guidance to the conversion feature in our Series M Convertible Preferred Stock (“Series M Preferred”). See Note 5 — “Derivative Instruments” in the Notes to Consolidated Financial Statements for additional information.

In November 2008, the FASB issued guidance related to accounting considerations for equity method investments under ASC 323-10-35, Investments — Equity Method and Joint Ventures. This guidance states that an equity method investor shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment. Any gain or loss to the investor resulting from an investee’s share issuance should be recognized in earnings. Previous to this, changes in equity for both issuances and repurchases were recognized in equity. This guidance is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We adopted ASC 323-10-35

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beginning January 1, 2009.  We applied this guidance to our equity investment in Spitfire Energy. See Note 4 — “Equity Investment in Spitfire Energy” in the Notes to Consolidated Financial Statements for additional information.

In December 2008, the Securities and Exchange Commission published a Final Rule, Modernization of the Oil and Gas Reporting Requirements. The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices will affect future impairment and depletion calculations. In January 2010, the FASB issued Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosure, to align the oil and gas reserve estimation and disclosure requirement of the SEC Final Rule with the ASC 932. The new disclosure requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. Our adoption of this Final rule for this annual reported dated December 31, 2009 affected our oil and gas disclosures but had no material effect on our financial position and results of operations. See Note 16 - “Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K.

In May 2009, the FASB issued guidance related to subsequent events under ASC 855-10, Subsequent Events. This guidance sets forth the period after the balance sheet date during which management or a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. It requires disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, whether that date represents the date the financial statements were issued or were available to be issued. This guidance is effective for interim and annual periods ending after June 15, 2009. We adopted ASC 855-10 in 2009 and have included the required disclosures in our consolidated financial statements. See Note 18 — “Subsequent Events” in the Notes to Consolidated Financial Statements for additional information.

In June 2009, the FASB issued an amendment to ASC 810-10, Consolidation. As a result, in December 2009, the FASB issued ASC 2009-17, Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities. This guidance amends ASC 810-10-15 to replace the quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a VIE with a primarily qualitative approach focused on identifying which enterprise has the power to direct the activities of a VIE that most significantly impact the entity’s economic performance. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE and requires additional disclosures about an enterprise’s involvement in VIEs. This guidance is effective as of the beginning of the reporting entity’s first annual reporting period that begins after November 15, 2009 and earlier adoption is not permitted. We are currently evaluating the potential impact, if any, of the adoption of ASC 2009-17 on our consolidated financial statements.

In June 2009, the FASB issued Accounting Standards Update No. 2009-01 which amends ASC 105, Generally Accepted Accounting Principles. This guidance states that the ASC will become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Once effective, the Codification’s content will carry the same level of authority. Thus, the U.S. GAAP hierarchy will be modified to include only two levels of U.S. GAAP: authoritative and non-authoritative. This is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We adopted  ASC 105 as of September 30, 2009 and thus have incorporated the new Codification citations in place of the corresponding references to legacy accounting pronouncements.

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In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at Fair Value, which amends ASC 820, Fair Value Measurements and Disclosures. This Update provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure the fair value using one or more of the following techniques: a valuation technique that uses the quoted price of the identical liability or similar liabilities when traded as an asset, which would be considered a Level 1 input, or another valuation technique that is consistent with ASC 820. This Update is effective for the first reporting period (including interim periods) beginning after issuance. Thus, we adopted this guidance as of September 30, 2009, which did not have a material impact on our consolidated financial statements.

RESULTS OF OPERATIONS

For the purposes of discussion and analysis, we are presenting a summary of our consolidated results of operations followed by more detailed discussion and analysis of our operating results.  The primary components of our net income / (net loss) from continuing operations for each of the years in the three year period ended December 31, 2009, were as follows (in thousands, except per-share data):

(1)          Oil and gas operating profit is calculated as oil and gas revenues less oil and gas operating expenses

(2)          The Canergy Fund and Canergy Management segments were deconsolidated from our financial statements during the fourth quarter of 2009. However, both the Canergy Fund and Canergy Management had no results from operations for the year ended December 31, 2009.

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The following is our discussion and analysis of significant components of our continuing operations which have affected our operating results and balance sheet during the periods included in the accompanying consolidated financial statements.

Operating Results:

Oil and Gas Revenues and Oil and Gas Expenses for the Year Ended December 31, 2009 Compared to December 31, 2008

In correlation with lower oil and gas commodity pricing in the markets during 2009, our oil and gas revenues decreased from $22.2 million in the prior year period to $10.2 million for the current year period.  This decrease was primarily due to the significantly lower oil and gas prices received during the period.

Our natural gas revenues decreased from approximately $6.9 million during 2008 to $1.5 million for 2009. The prices realized for natural gas sales decreased 60%, averaging $3.97 per mcf in during 2009 compared to $9.83 per mcf during 2008.  Natural gas production decreased 45% in 2009 as compared to the prior year period due primarily to decreased production from Lapeyrouse, Raymondville and Lake Raccourci fields.  These fields are under evaluation for possible divesture in 2010.

Our oil revenues decreased to approximately $8.7 million during 2009 from approximately $15.3 million during 2008. We realized a 43% decrease in oil prices received, decreasing from an average of $102.35 per barrel in 2008 to $58.48 per barrel in the current year.  Overall oil production remained fairly steady by only decreasing by 1% in 2009 as compared to the prior year due primarily to decreased oil production at our Lake Raccourci and Raymondville fields. These decreases were mostly offset by production gains from our Creole field.

Our oil and gas operating expense decreased 20%, decreasing from approximately $10.8 million during 2008 to $8.6 million during 2009 due primarily to lower operating costs at Main Pass 35, lower production taxes which resulted from lower prices realized on our oil and gas sales during the current year, as well as hurricane-related repair costs incurred during 2008.

Oil and Gas Revenues and Oil and Gas Expenses for the Year Ended December 31, 2008 Compared to December 31, 2007

Our oil and gas revenues increased from $20.4 million in 2007 to $22.2 million for 2008.  This increase was due to the higher oil and gas prices received during the period.

During August and September 2008, two hurricanes hit the Gulf of Mexico Coast effectively shutting in most of the oil & gas production in the Texas and Louisiana coastal area.  Production from our operated oil and gas properties (Main Pass 35, Lake Raccourci and Point a la Hache) along with most of our non-operated properties was shut-in during late August and September.  The estimated effect of the loss of net oil and gas revenue from the hurricanes was approximately $3.1million.

Our natural gas revenues decreased from $7.9 million in 2007 to $6.9 million in 2008. The prices realized for natural gas sales increased 23%, averaging $9.83 per mcf in 2008 compared to $7.99 per mcf during 2007. The effects of the hurricanes during August and September 2008 contributed to the decrease in our natural gas sales volumes during the year.

Our oil revenues increased to approximately $15.3 million during 2008 from approximately $12.5 million during 2007. We realized a 40% increase in oil prices received, increasing from an average of $72.95 per barrel in 2007 to $102.35 per barrel in 2008.  Overall oil production decreased 13% in 2008 as compared to the prior year due primarily to the effects of the hurricanes.

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Our oil and gas operating expense increased 25%, increasing from approximately $8.7 million during 2007 to $10.8 million during the year due primarily to $1.1 million related to our insurance deductible and repair costs in excess of insured values associated with the hurricanes.

Trading Revenues, net

We had no trading activity during the year ended December 31, 2009.  As a result of our trading activities of investments in energy industry securities in 2008 and 2007, we recognized the following net trading revenues (losses) (in thousands):

Fees, Interest and Other Income, net

Fees, interest and other income decreased from $2.4 million in 2008 to $2.2 million in 2009, primarily due to lower interest rates earned from cash and treasury securities during 2009 along with a gain from the sale of assets recognized during 2008.

Fees, interest and other income decreased from $3.2 million during 2007 to $2.4 million during 2008, primarily due to lower interest income rates during the year.

General and Administrative Expense

General and administrative expenses decreased 39% from $5.3 million for 2008 to $3.2 million for 2009 primarily due to continued cost cutting measures which resulted in overall lower salary and personnel costs along with decreased office and consultant expenses.

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General and administrative expenses decreased 11% from $6 million in 2007 to $5.3 million for 2008 primarily from overall lower salary and personnel costs due to fewer employees and lower bonuses during 2008 as compared to the prior year period.

Provision for Doubtful Accounts

We recognized a provision for doubtful accounts of approximately $183 thousand during 2009 compared to $41 thousand in 2008 primarily due to one of our oil and gas processing and handling customers filing Chapter 11 bankruptcy.  We recognized a benefit for doubtful accounts of $106 thousand in 2007.

Depreciation, Depletion, Amortization and Accretion Expense

Depreciation, depletion, amortization and accretion (DD&A) expense decreased 33% in 2009 when compared to prior year due to lower production volumes.  The average depletion rate per boe on our properties decreased from $17.22 per boe in 2008 to $15.21 per boe in 2009.

Depreciation, depletion, amortization and accretion (DD&A) expense decreased 14% during 2008 when compared to 2007 due to lower oil and gas production volumes. Our annual depletion rate per boe on our properties increased from $16.32 to $17.22 as a result of decreased proved reserve volumes at December 31, 2008.

Impairment of Investment in Spitfire

In 2008, we recognized a $4.6 million impairment of our equity investment in Spitfire based on the other-than-temporary decline in the fair value of Spitfire’s common shares. No such impairment was recognized in 2009 or 2007.

Other Losses

During 2009, 2008 and 2007, we recognized the changes in the fair value of our Spitfire warrants in other losses in our consolidated financials.

Full Cost Impairment

Due to a decline in oil and gas prices at December 31, 2008, we recorded a non-cash full cost pool impairment of approximately $19.9 million in 2008 related to our oil and gas properties under the full cost method of accounting. The valuation was based on the present value, discounted at ten percent, of our proved oil and gas reserves based on year-end prices. We had no full cost valuation impairments in 2009 or 2007.

Impairment of Long-Lived Assets

During 2008, we recognized an impairment of approximately $97 thousand for our Lake Raccourci facility, as the carrying value of such facility was in excess of its fair market value subsequent to the damage it sustained during the Hurricanes.  We had no impairments of long-lived assets in 2009 or 2007.

Income Tax Expense

We recognized an income tax benefit of $40 thousand during 2009 due to an adjustment made in the current period to our 2008 state and federal income tax liability.  During 2008, we recognized income tax

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expense of $271 thousand due primarily to an income tax contingency related to a proposed adjustment to our federal tax liability for the calendar year 2005.  See Note 10 — Income Taxes for further discussion.  We had no other income tax contingencies in the current year or 2007.

Accrual of Dividends related to Preferred Stock

All of our preferred stock issues contain dividend provisions. Dividends related to all of our preferred stock are cumulative and may be paid in cash or common stock at our option, depending on the respective preferred agreement. We accrue the dividends at their cash liquidation value and reflect the accrual of dividends as a reduction to net income (loss) to arrive at net income (loss) attributed to common stock. Accruals of dividends related to preferred stock for each of the three years ended December 31, 2009 are as follows:

Payments of Preferred Stock Dividends and Preferred Stock Redemptions

At December 31, 2009, 2008 and 2007, the following shares of our Preferred Stock issuances were outstanding:

Payment of Preferred Stock Dividends — During 2009, 2008 and 2007, we paid the accrued dividends related to preferred stock for the Series G1 and G2 Preferred with shares of our common stock issuing approximately 157, 249 and 83 shares, respectively, of our common stock as payment for the accrued dividends related to the Series G1 and G2 Preferred. The difference between the fair value of the shares of our common stock and the carrying value of the dividend liability, net of withholding taxes paid on behalf of the preferred shareholders, is considered a debt extinguishment gain of $18 thousand, $29 thousand and $9 thousand in 2009, 2008 and 2007, respectively, and is reflected as payment of preferred stock dividends as an increase to net income (loss) to arrive at net income (loss) attributed to common stock.

During the three years ended December 31, 2009, the accounting for the modification and payment of dividends of our preferred stocks were reflected as either increases or decreases to net income (loss) attributed

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to common stock.  In June 2009 upon issuance of our common shares, the conversion price of the Series M Preferred decreased from $13.22 to $11.85 per share. The incremental intrinsic value of the change in the Series M Preferred conversion price of $76 thousand is reflected as a payment of preferred stock dividends in our consolidated statement of operations for the year ended December 31, 2009.

The net effect of these preferred stock modifications and payments of preferred stock dividends for the three years ended December 31, 2009 is as follows:

LIQUIDITY AND CAPITAL STRUCTURE

Financial Condition

(1) Working capital is the difference between current assets and current liabilities.

The decreases in our current ratio and our working capital as of December 31, 2009 as compared to December 31, 2008 are primarily due to the discretionary use of cash for current year capital projects as well as repurchases of our common and preferred shares.  We deployed cash of $4.4 million to redeem 44,000 shares of our Series M Preferred and $1.9 million to repurchase shares of our common stock during 2009. We have no debt outstanding as of December 31, 2009. We deployed approximately $2.6 million during the 2009 period for capital projects.  The majority of these capital expenditures were used for upgrades and improvements at our Main Pass 35 facility as well as the completion of two producing wells at our Creole field, increasing both our reserves and production from this field.

During 2009, oil and natural gas prices declined sharply as compared to the prior year period. However, we reduced our controllable costs in order to maintain positive cash flow from operations during this low commodity pricing environment. We have a cash balance of approximately $7 million at December 31,

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2009. In 2010, we anticipate our operating cash flow and other capital resources, if needed, will adequately fund our planned capital expenditures and other capital uses over the near-term.  Based on industry outlook for 2010, prices for oil and natural gas are expected to be higher as compared to 2009.

We may continue to deploy cash for discretionary capital expenditures, long-term investments or seek to raise financing through the issuance of debt, equity and convertible debt instruments, if needed, for utilization of acquisition, development or investment opportunities as they arise. We may also reduce our ownership interest in Spitfire’s and Global’s common shares through strategic sales under certain conditions.

At December 31, 2009, if our remaining convertible preferred stock were converted and the put/call option was exercised, we would be required to issue the following amounts of our common stock:

(a) Certain conversion prices are subject to adjustment under certain circumstances.

Option to Issue Common Shares — In 2009, pursuant to the terms of our investment in BWI and the related Agreement, HKN and the other BWI unitholders granted to one another put and call options with respect to 3,050 units of BWI (or 30.5% of the outstanding units) in exchange for issuance of 725 thousand restricted shares of our common stock.  These options are exercisable only if certain conditions are satisfied prior to June 2012.  None of these conditions have been met as of December 31, 2009 or as of the date of this filing.  Please see Note 2 —“Investment in BriteWater International, LLC” for additional information of our investment.

Significant Ownership of our Stock

As of December 31, 2009, Lyford beneficially owned approximately 33% of the combined voting power of our common stock.  Lyford is in a position to exercise significant influence over the election of our board of directors and other matters.

Cash Flows

Net cash flow provided by operating activities during 2009 was $10.3 million, as compared to net cash used of $7.3 million in 2008. The increase in cash flow provided by operating activities as compared to the prior year period was primarily caused by a $9.5 million conversion of marketable securities into cash, collection of our previously outstanding hurricane insurance receivable, and a reduction in our operating, general and administrative costs as a result of cost-cutting efforts. Our cash on hand at December 31, 2009 totaled approximately $7 million.

Net cash used in financing activities during 2009 and 2008 totaled approximately $6.6 million and $4.6 million, respectively, due to repurchases of our preferred and common stock. Net cash used in investing

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activities during 2009 totaled approximately $2.3 million and was primarily comprised of capital expenditures associated with completion costs for two wells in our outside-operated Creole field and upgrades and improvements made at our Main Pass 35 facility.

Obligations and Commitments

Oil, Natural Gas and Coalbed Methane Commitments — During 2009, we expended approximately $2.6 million of capital expenditures and workovers in the United States. The majority of these capital expenditures were associated with completion costs for the Creole field in south Texas and upgrades and improvements made at our Main Pass 35 facility in offshore Louisiana.  During 2009, we limited our capital expenditures while oil and natural gas prices remained low.  In 2009, industry-wide drilling costs did not reduce in comparison to the dramatic drop in commodity prices.  In 2010, we expect to fund our capital expenditures with available cash on hand and through projected cash flow from operations.  Our capital expenditures for 2010 are discretionary and, as a result, will be curtailed if sufficient funds are not available. Such expenditure curtailments, however, could result in us losing certain prospect acreage or reducing our interest in future development projects.

BriteWater Contingencies — In 2009, BWI recorded a contingent liability of $800 thousand which may be payable to a vendor upon the conclusion of certain testing events of the OHSOL plant equipment. This contingent liability is included in other accrued liabilities within our consolidated condensed balance sheet.

Deferred Tax Liability — In 2009, upon our investment in BWI, we recorded a deferred tax liability in the amount of $729 thousand, calculated by applying the domestic statutory tax rates to the difference between the book purchase price and the estimated tax basis.  Information and research regarding the tax basis of the assets at the date of the acquisition is not complete at this time and the deferred tax may be adjusted as more information becomes available.

Operational Contingencies — Our operations are subject to stringent and complex environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations are subject to changes that may result in more restrictive or costly operations. Failure to comply with applicable environmental laws and regulations may result in the imposition of administrative, civil and criminal penalties or injunctive relief.

We recognize the full amount of asset retirement obligations beginning in the period in which they are incurred if a reasonable estimate of a fair value can be made. At December 31, 2009, our asset retirement obligation liability totaled approximately $6.2 million.

From time to time, we provide for reserves related to contingencies when a loss is probable and the amount is reasonably estimable.

Consolidated Contractual Obligations — The following table presents a summary of our consolidated contractual obligations and commercial commitments as of December 31, 2009 (in thousands):

(1) Our 2010 capital expenditures are discretionary and, as a result, will be curtailed if sufficient funds are not available.

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In addition to the above commitments, during 2009 and afterward, government authorities under our Louisiana state leases and other operators may also request us to participate in the cost of drilling additional exploratory and development wells. We may fund these future expenditures at our discretion. Further, the cost of drilling or participating in the drilling of any such exploratory and development wells cannot be quantified at this time since the cost will depend on factors out of our control, such as the timing of the request, the depth of the wells and the location of the property. As of December 31, 2009, we had no material purchase 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 structured 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, 2009, we were not involved in any unconsolidated SPE transactions. We have no off-balance sheet arrangements.

Treasury Stock — In January 2009, our Board of Directors authorized an amendment to the existing repurchase plan allowing us to repurchase an additional 1 million shares of our common stock. During the year ended December 31, 2009, we repurchased approximately 708 thousand shares of our common stock. This included a repurchase of 500 thousand shares of our common stock for $1.3 million from a shareholder in a privately negotiated transaction pursuant to our repurchase program. During the year ended December 31, 2009, we retired approximately 715 thousand treasury shares. As of December 31, 2009 approximately 530 thousand shares remained available for repurchase under our repurchase program.

During 2008, we repurchased 507 thousand shares of our common stock in the open market at a cost of approximately $4.4 million pursuant to our repurchase program. In 2008, we cancelled 500 thousand of these shares.  At December 31, 2008, we held 6,869 shares of treasury stock, and approximately 237 thousand shares remained available for repurchase under our repurchase program.

Redemption of Series M Preferred — During 2009, we redeemed all 44 thousand shares of our Series M Preferred with a liquidation value of $100 per share for $4.4 million in cash. In addition, we paid approximately $124 thousand in accrued dividends on these shares.

Redemption of Series G1 Preferred — During 2009, we redeemed six hundred shares of our Series G1 Preferred with a liquidation value of $100 per share and 18 Common stock for $5 thousand in cash. In addition, we paid approximately $2 thousand in accrued dividends on these shares.

Adequacy of Capital Sources and Liquidity

We believe that we have the ability to provide for our operational needs, our planned capital expenditures and possible investments through projected operating cash flow and cash on hand. Our operating cash flow would be adversely affected by continued declines in oil and natural gas prices, which can be volatile.  However, we have worked to reduce our controllable costs in order to maintain positive cash flow from operations during this low commodity pricing environment.  Should projected operating cash flow decline, we may further reduce our capital expenditures and possible investments and/or consider the issuance of debt, equity and convertible debt instruments, if needed, for utilization for the capital expenditure program or possible energy-based investment opportunities.  We may also continue to reduce our ownership interest in Spitfire’s and Global’s common shares through strategic sales under certain conditions.

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We have no debt outstanding at December 31, 2009.  If we seek to raise equity or debt financing to fund capital expenditures or other acquisition and development opportunities, those transactions may be affected by the market value of our common stock.  If the price of our common stock declines, our ability to utilize our stock either directly or indirectly through convertible instruments for raising capital could be negatively affected. Further, raising additional funds by issuing common stock or other types of equity securities could dilute our existing stockholders, which dilution could be substantial if the price of our common stock decreases. Any securities we issue may have rights, preferences and privileges that are senior to our existing equity securities. Borrowing money may also involve pledging some or all of our assets.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following financial statements appear on pages 33 through 67 in this Annual Report.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

HKN, Inc.

We have audited the accompanying consolidated balance sheets of HKN, Inc as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of HKN, Inc. as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), HKN, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 18, 2010 expressed an unqualified opinion on the effectiveness of HKN, Inc.’s internal control over financial reporting.

HEIN & ASSOCIATES LLP

Dallas, Texas

February 18, 2010

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HKN, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except for share amounts)