Edgar Filing: HARKEN ENERGY CORP

Form 10-K for Year Ended December 31, 2005

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2005

¨	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

HARKEN ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		95-2841597
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

180 State Street, Suite 200 Southlake, Texas		76092
(Address of principal executive offices)		(Zip Code)

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

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


Title of each class:		Name of each exchange on which registered:
Common Stock, Par Value $0.01 Per Share		American Stock Exchange

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 þ 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 ¨ No þ

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. þ Yes ¨ No.

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):


Large accelerated filer ¨		Accelerated filer þ		Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ 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, 2005 was approximately $96 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, 2006 was 223,660,648.

DOCUMENTS INCORPORATED BY REFERENCE

Specified portions of the registrant’s definitive Proxy Statement for the 2005 Annual Meeting of Shareholders, to be filed pursuant to Regulation 14A with the Securities and Exchange Commission not later than 120 days after the end of this fiscal year covered by this report, are incorporated by reference.

TABLE OF CONTENTS


		Page
PART I.

ITEM 1.	Business	4

ITEM 1A.	Risk Factors	19

ITEM 1B.	Unresolved Staff Comments	29

ITEM 2.	Properties	29

ITEM 3.	Legal Proceedings	30

ITEM 4.	Submission of Matters to a Vote of Security Holders	30

PART II.

ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31

ITEM 6.	Selected Financial Data	33

ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34

ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	61

ITEM 8.	Financial Statements and Supplementary Data	62

ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	116

ITEM 9A.	Controls and Procedures	116

PART III.

ITEM 10.	Directors and Executive Officers of the Registrant	120

ITEM 11.	Executive Compensation	120

ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120

ITEM 13.	Certain Relationships and Related Transactions	120

ITEM 14.	Principal Accounting Fees and Services	120

PART IV.

ITEM 15.	Exhibits and Financial Statement Schedules	121

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 Harken Energy Corporation and its consolidated subsidiaries on a consolidated basis.

PART I

ITEM 1.

BUSINESS

Overview

We are an independent oil and gas exploration, exploitation, development and production company who seeks to invest in energy-based growth opportunities. Our domestic operations are conducted through our wholly-owned subsidiary, Gulf Energy Management Company (“GEM”). GEM’s operations consist of exploration, exploitation, development, production and acquisition efforts in the United States, principally in the onshore and offshore Gulf Coast regions of South Texas and Louisiana, as well as coal bed methane exploration and development activities in Indiana and Ohio. We have exposure to international crude oil exploration and production operations through our holdings of approximately 34% of Global Energy Development PLC’s (“Global”) outstanding common shares. Global has exploration, development and production activities in Colombia and exploration activities in Panama and Peru.

For financial information for each of our operating segments, including information regarding consolidated revenues and total assets, see “Note 16 - Other Information” contained in the Notes to the Consolidated Financial Statements.

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.harkenenergy.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).

Our Investment in Global

In March 2002, Global completed a private placement equity offering of approximately 2 million shares of common stock and then proceeded to list its common shares on the AIM Market of the London Stock Exchange (“AIM”). This offering in 2002 reduced our interest in Global from 100% to approximately 92.77%. Since that time, we have strategically reduced our percentage interest in Global by private placements as opportunities have become available coincident with the increase of the trading price of Global’s common shares on AIM. During 2005, we sold common shares of Global in the market to a variety of purchasers throughout the year in exchange for total cash consideration, net of fees, of approximately $40 million and recorded total net gains on the sale of these shares of approximately $32.5 million. These sales of shares, along with the exercise of Global stock options and warrants during 2005, decreased our direct equity interest in Global from approximately 85% at December 31, 2004 to approximately 34% at December 31, 2005. Our equity interest in Global may be subject to further reduction due to a number of reasons including further option exercises, but we do not expect to recognize similar gains in the future due to our current intention not to sell large positions of our equity interest in Global. See Changes in Our Ownership of Global Shares below for detail of the changes in our ownership in Global during this year.

Possible Deconsolidation of Global

As discussed in Note 8 – “Changes in Harken’s Ownership in Global” in our Consolidated Financial Statements, in 2002 we issued to Lyford Investments Enterprises Ltd. (“Lyford”) warrants to purchase up to 7,000,000 shares of Global held by us at a price of 50 UK pence per share. Lyford’s representative, Alan Quasha, became a member of our board of directors and our Chairman in March 2003. In September 2005, Lyford exercised its warrants in exchange for cash proceeds to us of $6.4 million.

As of December 31, 2005, Lyford owned approximately 20% of the common shares of Global as a result of exercising its Global warrants. Also at December 31, 2005, Lyford beneficially owned approximately 30% of the combined voting power of our common stock. Therefore, our direct equity interest of approximately 34%, combined with Lyford’s approximate 20% equity interest in Global (which totals to a combined ownership percentage of 54%), was deemed to provide us with the legal power to control the operating policies and procedures of Global. As a result, we continued to consolidate the operations of Global as of December 31, 2005.

Lyford has informed us that it may liquidate a portion of its equity interest in Global through strategic sales under certain conditions. If Lyford reduces its equity ownership interest in Global, such that the combined equity interest in Global is less than 50%, we may no longer be deemed to hold the legal power to control the operating policies and procedures of Global. As a result, we would no longer report Global’s operating results in our consolidated financial statements, but we would account for our investment in Global on the equity method of accounting. Under the equity method of accounting, our investment in Global will be presented on a single line in the consolidated balance sheet. Likewise, our share of Global’s earnings will be reflected on a single line in the consolidated statement of operations.

2005 Consolidated Operations

Our consolidated revenues are primarily derived from production from GEM’s and Global’s oil and gas properties. GEM operates approximately 50% of its natural gas and crude oil properties which are all located in the United States. Global operates 100% of its crude oil producing properties, all located in Colombia. Our 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. From time-to-time GEM enters into hedging contracts to achieve more predictable cash flows and to reduce exposure to declines in market prices.

As of December 31, 2005 GEM had approximately 15.9 BCFe of proved oil and gas reserves net to our interest with discounted future net cash flows, discounted at 10%, of approximately $74 million. At December 31, 2005, GEM generated 35% of our consolidated oil and gas proved reserve volumes, and in 2005, GEM represented approximately 49% of our consolidated oil and gas revenues. In 2005, GEM’s oil and gas revenues were comprised of approximately 39% oil sales and 61% natural gas sales. Substantially all of GEM’s production is concentrated in four oil and gas fields along the onshore and offshore Texas and Louisiana Gulf Coast.

Revenues from Global are derived solely from Global’s Colombian oil production. As of December 31, 2005, Global had approximately 5 million barrels of international proved oil reserve volumes with discounted future net cash flows, discounted at 10%, of approximately $104 million. Approximately 1.7 million barrels of these proved oil reserve volumes and approximately $35 million of the discounted future net cash flows are attributable to our approximately 34% interest in Global. All of Global’s proved reserve volumes are located in Colombia. During 2005, Global produced approximately 443,000 net barrels of oil in Colombia generating oil revenues of approximately $19 million. Global represented 65% of our total consolidated proved reserves at December 31, 2005 and approximately 51% of our consolidated oil and gas revenues in 2005. Global’s activities in Panama and Peru, thus far, have been limited to technical evaluations of potential exploration areas.

GEM Exploration and Production Operations

GEM’s operations consist of exploration, exploitation, development, production and acquisition efforts in the United States, principally in the onshore and offshore Gulf Coast regions of South Texas and Louisiana, as well as coal bed methane exploration and development activities in Indiana and Ohio. During the three years ended December 31, 2005, GEM has drilled or participated in the drilling of 29 oil and gas wells in North America, completing 22 of the wells drilled. In 2003, we sold certain non-strategic producing properties and mineral interests, most of which were outside of GEM’s Gulf Coast operating focus. Such producing property and mineral interest sales during 2003 generated cash proceeds of approximately $24 million, which were used in part to support GEM’s exploration and development activities and repay debt obligations.

In 2005, GEM entered into two significant coalbed methane Exploration and Development Agreements in Indiana and Ohio. Each prospect provides for an area of mutual interest of approximately 400,000 acres. 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 (the “Technical Consultant”) for these projects. Effective November 2005, GEM extended its CBM projects to include an exploration and development coalbed methane project within the Triangle Prospect Area in Ohio, consisting of approximately 1,042 acres of land with the potential of acquiring additional acreage in subsequent phases of this project. See Note 2 – “Mergers, Acquisitions and Dispositions” in the Notes to the Consolidated Financial Statements for further discussion.

In addition, GEM is actively evaluating other strategic coalbed methane opportunities in pursuit of long-lived reserve prospects to compliment our current oil and gas portfolio.

GEM is continuing to seek joint venture and farmout opportunities to explore and develop its domestic oil and gas prospect portfolio. Consistent with our 2006 focus, GEM is seeking acquisition opportunities to expand their domestic operations.

As of December 31, 2005, GEM operates or owns a non-operating working interest in 68 oil wells, 88 gas wells and 17 injection wells in the United States. There were no domestic customers during 2003 and 2004 which individually represented 10% or more of our consolidated revenues. During 2005, one domestic customer purchased approximately 11% of our consolidated revenues.

Gulf Coast Operations - All of our North America oil and gas operations are held and managed by GEM. At December 31, 2005, through various wholly-owned subsidiaries, GEM owns operating and non-operating working interests in 44 gas wells located in various counties in Texas, concentrated in the Raymondville area of Willacy and Kennedy counties and the Allen Ranch field in Colorado County. In Louisiana, GEM owns operated and non-operated interests in 68 oil wells and 40 gas wells concentrated primarily in the Main Pass area offshore Plaquemines Parish, Lapeyrouse field in Terrebonne Parish and the Lake Raccourci area of LaFourche Parish. After the sale of certain of our Texas Panhandle operations during 2003, substantially all of GEM’s proved reserves are concentrated in the Gulf Coast region of Louisiana and Texas.

In 2005, GEM drilled or participated in the drilling of 11 exploratory and development wells and successfully completed eight of those wells. Additionally, as of December 31, 2005, one well at Allen Ranch field and one well at Lapeyrouse field, each having tested successfully at year-end 2005, are still pending facilities.

West Texas Operations - Prior to the 2003 sale of the Texas Panhandle properties, GEM operated or owned non-operated interests in 157 oil wells and 40 gas wells in Hutchinson and Gray Counties and 61 oil wells in Hockley County, all located in the Panhandle area of Texas. GEM and certain wholly-owned subsidiaries of GEM sold the majority of their oil and gas properties located in the Panhandle region of Texas in December 2003 for gross cash proceeds of approximately $7 million and, in March 2005, disposed of certain remaining Texas Panhandle interests for the purchaser’s assumption of plug and abandonment obligations related to the properties. GEM also owns interest in three non-operated Eddy County gas wells in New Mexico

Prospect Acreage - In addition to the producing property interests discussed above, GEM, through certain wholly-owned subsidiaries, owns interests in a variety of domestic prospect acreage in the Lake Raccourci and Lapeyrouse fields of LaFourche and Terrebonne Parishes, respectively, in Louisiana and in the Old Ocean field in Matagorda and Brazoria Counties of Texas.

See Note 16 – “Other Information” in the Notes to Consolidated Financial Statements for financial information about GEM.

Global Exploration and Development Operations – Colombia

Global’s Colombian operations are conducted through Harken de Colombia, Ltd., a wholly-owned subsidiary of Global. As of December 31, 2005 Global held three Association Contracts with Empresa Colombiana de Petroleos (Ecopetrol”), the state-owned Colombian oil company. During 2003, the Colombian government created a new agency, National Hydrocarbons Agency of the Republic of Colombia (“ANH”), to administer all contracts executed on or after January 1, 2004 relating to hydrocarbons exploration and production in Colombia. As of December 31, 2005, Global held four exclusive Exploration and Production Concession Contracts and one Technical Evaluation Agreement (“TEA”) with the ANH.

The Association Contracts are the Alcaravan Contract, awarded in 1992, the Bocachico Contract, awarded in 1994, and the Bolivar Contract, awarded in 1996. As described below, the Association Contracts provide for the potential participation in production by Ecopetrol.

The exclusive Exploration and Production Concession Contracts are the Rio Verde and the Los Hatos Contracts, both awarded in 2004, and the Luna Llena and Caracoli Contracts, awarded in December 2005. The Exploration and Production contracts with ANH represent royalty-based concession contracts that eliminated the potential for production participation of the Colombian government.

During 2005, Global signed a new exclusive Technical Evaluation Agreement (“TEA”) with the ANH for the evaluation of potential hydrocarbon resources in the Valle Lunar area located in the established Llanos Basin of eastern Colombia. The total original acreage covered by the TEA was approximately 2.1 million acres. As a result of Global’s election to convert a portion of the Valle Lunar into a new Exploration and Production Concession Contract, the Valle Lunar TEA acreage was reduced to approximately 1.7 million acres effective as of December 2005.

The Valle Lunar area has been subject to prior exploration activity by an international petroleum company in 1981 with two exploration wells reported as productive at that time. The Valle Lunar TEA targets medium heavy oil deposits and grants Global the option to sign a future exclusive Exploration and Production Concession Contract, typically 25 years in duration, for acreage within the TEA area that Global identifies as prospective and suitable for exploratory drilling and production operations. The TEA duration is 16 months. The TEA requires Global to complete within 12 months the reprocessing and interpretation of 800 linear kilometers of existing 2D seismic and certain other geophysical measurements and analysis, including the acquisition of aeromagnetic data. In September 2005, Global exercised its option to commence negotiations with ANH to convert a portion of the Valle Lunar TEA area into an Exploration and Production Concession Contract.

Global signed the Luna Llena Exploration and Production Concession Contract in December 2005 (the ‘Luna Llena Contract’). The Luna Llena Contract covers approximately 369,000 acres out of the original 2.1 million acres of the Valle Lunar TEA located in the Llanos Basin of eastern Colombia.

At December 31, 2005, Global has proved reserves attributable to each of its three Association Contracts, the Alcaravan, Bolivar and Bocachico Contracts as well as proved reserves in the Rio Verde and Luna Llena Contracts. In the Alcaravan Contract, Global has proved reserves in the Palo Blanco and Anteojos fields. In the Bolivar Contract, Global has proved reserves in the Buturama field. In the Bocachico Contract, Global has proved reserves in the Rio Negro field. In the Rio Verde Contract, Global has proved reserves in the Tilodiran and Macarenas fields. In the Luna Llena Contract, Global has proved reserves in the El Miedo field.

In April 2005, Global entered into a new crude oil sales contract with Petrobras Colombia Limited, a subsidiary of Petrobras, the state oil company of Brazil that covers all crude oil production tendered from Global’s Palo Blanco, Anteojos, Rio Verde, Torcaz and Bolivar fields in Colombia, net of royalties paid to the Colombian government and Ecopetrol’s portion of production from one well, the Cajaro #1. Petrobras, individually accounted for approximately 45% of our consolidated revenues in 2005. Ecopetrol, which formerly purchased the majority of Global’s crude oil production, individually accounted for over 29% and 37%, respectively, of our consolidated revenues in each of 2003 and 2004.

Global maintains a number of operating procedures and policies to address any heightened security concerns that may arise from a change or deterioration in the Colombian political situation. For further discussion of Global’s security concerns in Colombia, see “Risk Factors” set forth below.

Alcaravan Contract - The Alcaravan Association Contract (the “Alcaravan Contract”) gives Global the right to explore for, develop and produce oil and gas throughout approximately 24,000 acres in the Alcaravan area of Colombia, which is located in Colombia’s Llanos Basin approximately 140 miles east of Santa Fe de Bogotá. Global has completed the contractually required six year seismic and exploratory drilling program of the Alcaravan Contract (the “Exploration Period”).

In October 2001, Global received notification from Ecopetrol that Global could proceed with the sole risk development of the designated commercial area of the Palo Blanco field of the Alcaravan Association Contract. As such, the term of the Alcaravan Contract related to the productive areas has been extended for a period of 22 years from the date of the October 2001 election by Ecopetrol, subject to the entire term of the Alcaravan Contract being limited to no more than 28 years. Due to Ecopetrol’s election not to participate, Global elected to proceed with the development of the designated commercial area of the Palo Blanco field on a sole risk basis, whereby Global is entitled to receive Ecopetrol’s 50% share of production after deduction for the Colombian government’s 20% royalty interest, until Global has recovered 200% of its successful well costs expended as defined by the Alcaravan Contract, after which time Ecopetrol could elect to begin to receive its 50% working interest share of production. Accordingly, Global reflects its 80% interest in gross production from the designated Palo Blanco commercial area in the cash flows in its financial statements and reserve information. Global has retained the acreage covering those structure areas associated with the Palo Blanco and Anteojos discoveries.

In 2004, Ecopetrol declared the Cajaro #1 well commercial pursuant to the Alcaravan Contract terms. As of February 28, 2006, Global and Ecopetrol continue to negotiate the terms of Ecopetrol’s commerciality declaration, including the extent of the commercial area and the potential need for unitization of the Cajaro #1 commercial area and a portion of Global’s Los Hatos Contract with ANH which is adjacent to the Alcaravan Contract area. Global’s net revenue interest in the production from the Mirador discovery on the Cajaro #1 well, has been affected by Ecopetrol’s declaration of commerciality. In 2004, Global had been reimbursed by Ecopetrol out of Ecopetrol’s share of production, net of royalties, for 50% of all seismic costs and direct exploratory well costs (including costs related to dry holes) incurred prior to the point of Ecopetrol’s participation in the Cajaro #1 well. Since 2004, Global has allocated production from Cajaro #1 as follows: Ecopetrol, on behalf of the Colombian government, receives a royalty interest of 8% of all production, and all production (after royalty payments) attributable to the Alcaravan Association Contract area is allocated 50% to Ecopetrol and 50% to Global. Pursuant to the terms of the Alcaravan Contract, Ecopetrol and Global will be responsible for all future development costs and operating expenses in direct proportion to their interest in production. Based upon the extent of the area declared commercial in relation to the Cajaro #1 well by Ecopetrol, Global has advised Ecopetrol, ANH and the Ministry of Energy that Global’s Los Hatos Contract area which is adjacent to Global’s Alcaravan Contract, is being drained of Mirador formation oil reserves located beneath the Los Hatos Contract. Because two contract areas are being drained by one well, it is Global’s opinion that Colombian law requires the division of reserves and revenues be settled through a unitization proceeding. The unitization proceeding and its impact on Ecopetrol’s commerciality continues to be unresolved as of February 28, 2006. This proceeding will directly impact the Cajaro #1 net revenues and costs assigned to both Ecopetrol and Global. Although the ultimate results of the unitization proceeding cannot be determined at this time, Global, based on the proposed unitization maps limiting the Cajaro Commerciality area to 12 acres within the Alcaravan Contract and data presented by Ecopetrol, began reflecting an 82.3% interest in net production from the Cajaro #1 well from the Alcaravan Association Contract area in the cash flows in its financial statements and reserve information during the year ended December 31, 2005.

Alcaravan Contract Operations - Global has drilled eight wells on the Alcaravan acreage, five of which are currently producing. These five producing wells include the Estero #1, Estero #2, and Estero #5 wells, the Canacabare #1 well and the Cajaro #1 well. In January 2006, daily combined production from the Estero #1 and Estero #2 wells from the Palo Blanco field have averaged a total of approximately 354 gross barrels per day. At December 31, 2005, Global reflects proved reserves of approximately 1.5 million net barrels related to its interest in the Palo Blanco field. During 2005, Global produced a total of approximately 333,000 gross barrels of oil from its Palo Blanco field, and since inception and through December 31, 2005, Global has produced a cumulative total of approximately 2,565,000 gross barrels of oil from its Palo Blanco field.

In 2005, the Cajaro #1 well produced a total of 118,536 gross barrels of oil during the year. At December 31, 2005, Global reflects proved reserves of approximately 338,000 net barrels related to its interest in the Cajaro #1 well.

At December 31, 2005, Global also reflects proved reserves of approximately 223,000 net barrels related to its interest in the Anteojos prospect within the Alcaravan Contract area, which includes the Canacabare #1 well. Global’s net revenue interest in production that may be discovered on the Anteojos prospect will depend on whether or not Ecopetrol elects to participate. Upon the election by Ecopetrol to participate in a field and upon commencement of production from the field, Global will begin to be reimbursed by Ecopetrol out of Ecopetrol’s share of production, net of royalties, for 50% of all direct exploratory well costs incurred prior to the point of Ecopetrol’s participation. Production from a field in which Ecopetrol elects to participate will be allocated as follows: Ecopetrol, on behalf of the Colombian government, will receive a royalty interest of 5% of all production, and all production (after royalty payments) will be allocated 50% to Ecopetrol and 50% to Global. Ecopetrol and Global will be responsible for all future development costs and operating expenses in direct proportion to their interest in production. If Ecopetrol does not elect to participate, Global has the choice to proceed with the development of the prospect area on a sole-risk basis. If Global does proceed on a sole-risk basis, it will be entitled to receive Ecopetrol’s 50% share of production after deduction for Ecopetrol’s 5% royalty interest, until Global has recovered 200% of its successful well costs expended, after which time Ecopetrol could elect to receive its 50% working interest share of production.

Bocachico Contract — Under the Bocachico Association Contract (the “Bocachico Contract”), Global acquired the exclusive rights to conduct exploration and production activities and drilling on the Bocachico contract area, which covers approximately 54,600 acres in the Middle Magdalena Valley of Central Colombia. Global has fulfilled all of the exploration work requirements for the Bocachico Contract. The production sharing and term arrangements under the Bocachico Contract are substantially similar to those under the Alcaravan Contract.

Bocachico Contract Operations — From 1996 to 1998, Global drilled and completed three wells on the Bocachico Contract area, all in the Rio Negro prospect area. During 2005, the Torcaz wells averaged approximately 40 gross barrels of production per day from the Torcaz field. At December 31, 2005, Global reflected proved reserves of approximately 170,000 net barrels related to its interest in the Rio Negro field. There are no significant capital expenditures presently scheduled for the Rio Negro field in 2006.

Global received sole risk approval from Ecopetrol in the Rio Negro field in June 2003. Accordingly, Global reflects its 92% interest in gross production and cash flows in its financial statements and reserve revenue interest. In accordance with the current energy policy of Colombia, the royalty has been reduced from 20% to 8% based upon Global’s plans to undertake the Torcaz CO2 gas injection project in 2006. Colombian law provides for royalty reduction incentives when improved recovery programs such as gas injection are initiated in existing producing fields.

Bolivar Contract — Under the Bolivar Association Contract (the “Bolivar Contract”), Global acquired the exclusive rights to conduct exploration and production activities in the Bolivar Contract area, which covers approximately 59,000 acres in the Northern Middle Magdalena Valley of Central Colombia.

In February 2001, Global received notification from Ecopetrol that it had elected not to participate in the development of the Buturama field of the Bolivar Association Contract. Due to Ecopetrol’s election not to participate, Global has elected to proceed with the development of the field on a sole risk basis, whereby Global is entitled to receive Ecopetrol’s 50% share of production, after deduction of Ecopetrol’s recently reduced 8% royalty interest, until Global has recovered 200% of its successful well costs expended, after which time Ecopetrol could elect to begin to receive its 50% working interest share of production. Accordingly,

Global reflects its 92% interest in gross production and cash flows in its financial statements and reserve information. In addition, the term of the Bolivar Contract related to the productive areas has been extended for a period of 22 years from the date of such election by Ecopetrol, subject to the entire term of the Bolivar Contract being limited to no more than 28 years. In accordance with the current energy policy of Colombia, the royalty has been reduced from 20% to 8% based upon Global’s plans to undertake the Catalina Gas Injection project in early 2006. Colombian law provides for royalty reduction incentives when improved recovery programs such as gas injection are initiated in existing producing fields.

Global has completed all of the work obligations of the Bolivar Contract. The production sharing and term arrangements under the Bolivar Contract are substantially similar to the Alcaravan and Bocachico Contracts.

Bolivar Contract Operations — Global has drilled four wells on the Bolivar Contract area, the Catalina #1, which was found to be productive, but is no longer producing, the Olivo #1, which was drilled from the same surface location as the Catalina #1, and was also found to be productive. Two additional wells were unproductive.

At December 31, 2005, Global reflects proved reserves (primarily proved undeveloped) of approximately 2.6 million net barrels related to its interest in the Buturama field. Global plans to install a gas injection system to increase reservoir pressure in the Rosa Blanca formation in the Buturama field in 2006, for a total cost of completion of approximately $460,000. During 2005, the Olivo #1 produced a total of 25,147 gross barrels of oil and, since inception, Global has produced cumulative production of approximately 602,000 gross barrels of oil from this well. Production volumes for the Bolivar Contract area are currently derived from the Olivo #1 well, since the Catalina #1 well is shut-in. Global expects to continue to transport 100% of current and projected Bolivar area production through its current trucking operations.

Cajaro Contract — In December 2001, Global signed an Association Contract with Ecopetrol, covering the Cajaro Contract area. Under the Cajaro Contract, which became effective in February 2002, Global acquired the exclusive rights to conduct exploration and production activities in the Cajaro Contract area. In February 2003, Global commenced drilling operations on the initial well required to be drilled in Cajaro Association Contract, the Cajaro #1 well. Global drilled, completed and placed the Cajaro #1 well on production effective in June 2003. Certain production from the Cajaro #1 well relates to the Mirador formation located within and attributable to Global’s existing Alcaravan Contract as previously described. In August 2003, Global elected not to proceed with the second year of the Cajaro Association Contract and thereby elected to terminate that agreement without further obligation. The Cajaro #1 well is now considered part of the Alcaravan Contract.

Rio Verde Concession — In September 2004, Global signed an Exploration and Production Concession Contract with the National Hydrocarbons Agency of the Republic of Colombia for the Rio Verde area located in the central Llanos region. Global owns a 100% working interest in the contract subject only to an initial 10.5% royalty, this payment being divided between the Colombian Ministry of Energy and others. The initial size of the royalty will be adjusted if future production levels exceed 5,000 barrels of oil per day (“bopd”) per field. The contract duration is approximately 6 years for the exploration phase and 24 years for the exploitation phase.

The contract assigns Global exclusive exploration and production rights to 75,000 acres. Terms of the contract required Global during Phase 1 to equip for production two existing wells located on the Rio Verde acreage, the Tilodiran #1 and the Macarenas #1. These wells, drilled in 1986 and 1993 respectively, tested productive. Both of these wells were equipped for production in late 2004 and early 2005. Also during Phase 1 of the contract, Global was required to reprocess 300 kilometers of existing seismic data and acquire 50 kilometers of new 2D seismic data. As of December 31, 2005, Global had completed all the requirements of Phase 1.

Global has elected to enter Phase 2 of the contract and is currently drilling the one obligated exploration well (the Tilodiran #2) in early 2006. Additionally, Global must acquire a further 25 kilometers of 2D seismic data. Phases 3, 4 and 5, also optional, require one exploratory well to be drilled per Phase. Phases 2, 3, 4 and 5 have a time period of 12 months each. As of February 28, 2006, Global remained in compliance with the terms of the Rio Verde Concession.

Los Hatos Concession — In November 2004, Global signed an exclusive Exploration and Production Concession Contract with the National Hydrocarbons Agency of the Republic of Colombia for the Los Hatos area, located in the central Llanos region.

Global owns a 100% working interest of the contract subject only to an initial 8% royalty payable to the Colombian Ministry of Energy. The initial size of the royalty will be adjusted if future production levels exceed 5,000 bopd per field. The contract duration is approximately 6 years for the exploration phase and 24 years for the exploitation phase.

The contract grants Global exclusive exploration and production rights to 85,000 acres which are adjoined to the established, producing Palo Blanco field. Terms of the contract require Global during Phase 1 to drill one exploratory well. The time period for Phase 1 is 16 months.

According to the requirements under Phase 1, Global drilled and successfully completed the Los Hatos #1. Pursuant to the Ministry of Energy’s requirements, Global is conducting long term testing of the Los Hatos #1 well. As of February 28, 2006, these long term tests were not complete. Global will determine whether to proceed with Phase 2 of the Los Hatos Concession once the results of the long-term testing of Los Hatos #1 are analyzed. Phases 2, 3, 4 and 5, also optional, require one exploratory well to be drilled per Phase. Phases 2, 3, 4 and 5 have a time period of 12 months each.

Valle Lunar Concession – In May 2005, Global signed a new exclusive TEA with the ANH for the evaluation of potential hydrocarbon resources in the Valle Lunar area located in the established Llanos Basin of eastern Colombia. The total acreage covered by the TEA is approximately 2.1 million acres.

The Valle Lunar area has been subject to prior exploration activity by an international petroleum company in 1981 with two exploration wells reported as productive at that time. The Valle Lunar TEA targets medium heavy oil deposits and grants Global the option to sign a future exclusive Exploration and Production Concession Contract, typically 25 years in duration, for acreage within the TEA area that Global identifies as prospective and suitable for exploratory drilling and production operations. The TEA duration was 16 months. The TEA required Global to complete within 12 months the reprocessing and interpretation of 800 linear kilometers of existing 2D seismic and certain other geophysical measurements and analysis, including the acquisition of aeromagnetic data.

In September 2005, Global exercised its option to commence negotiations with ANH to convert a portion of the Valle Lunar TEA area into the Luna Llena Exploration and Production Contract (the “Luna Llena Concession”) and signed the contract in December 2005. Global will continue to hold the remaining Valle Lunar TEA acreage pursuant to the terms of the TEA.

Luna Llena Concession - The Luna Llena Contract covers approximately 369,000 acres out of the original 2.1 million acres of the Valle Lunar TEA located in the Llanos basin of eastern Colombia. The Luna Llena Concession acreage contains the identified El Miedo field which has substantial well tests and subsurface geologic control previously acquired by two international oil companies in the 1980’s. Oil

production tests were successful at that time. Global has completed engineering and geologic studies with regard to the El Miedo field.

Global holds 100% working interest of the Luna Llena Contract subject only to an initial 8% royalty, with the size of the royalty to be determined by future production levels. The contract duration is 30 years divided into an initial six-year exploration phase and a 24 year exploitation and production phase. Under the terms of the Luna Llena Contract, Global must within 18 months acquire 165 kilometers of 2D seismic data, reprocess 500 kilometers of existing seismic data, re-enter and test one existing well and drill two exploratory wells which cover the total geologic column. Global can then elect, if it so wishes, to proceed to phase two which also covers 18 months and requires re-entering another existing well or drilling another exploratory well. Phases three to five, all optional, are each 12 months and require the drilling of an exploratory well in each phase.

Caracoli Concession - In December 2005, Global signed a new exclusive Exploration and Production Concession Contract for the Caracoli area (the “Caracoli Contract”) with the ANH. The Caracoli Contract covers approximately 90,000 acres in the Catatumbo basin located in northeastern Colombia. This basin is a sub-basin of the prominent Maracaibo basin which extends in a southwesterly direction from Venezuela into Colombia. Global holds a 100% working interest in the Caracoli Contract subject only to an initial 10% royalty, with the size of the royalty to be determined by future production levels. The Contract duration is 30 years, divided into an initial 6-year exploration phase and a 24-year exploitation and production phase. Under the terms of the Caracoli Contract, Global must acquire within 12 months, 90 kilometers of 2D seismic data and reprocess 210 kilometers of existing seismic data. Global can elect, at its option, to proceed to phase 2, also 12 months, and drill one exploratory well and acquire limited amounts of additional seismic data. Phases 3 to 6, all optional and 12 months in length, require the drilling of an exploratory well in each phase. Global expects to fund the required work program with cash flow from its five existing productive contracts in Colombia.

Global Operations - Peru

Peru Operations - In April 2005, Global announced that the new License Contract between Global and Perupetro S.A. (“Perupetro”), the national oil company of Peru, for the Exploration and Exploitation of Hydrocarbons in the Block 95 Area located in the Marañon Basin of Northeastern Peru had been fully executed and was effective.

Global owns a 100% working interest in the License Contract area subject only to an initial 5% royalty. The size of the ongoing royalty is to be determined by future production levels. The Contract duration is approximately seven years for the initial exploration phases and 23 years for the exploitation phase. The Contract assigns Global exclusive exploration and production rights to approximately 1,255,000 acres. During Phase 1 of the contract, the terms require Global to complete, within 12 months, environmental impact studies and plans for the drilling of a well in the Bretaña field located in Block 95.

If Global elects to enter Phase 2 of the contract, Global must acquire approximately 4,800 square kilometers of micro-magnetic geophysical data in and around the Bretaña field and elsewhere throughout Block 95. Phase 2 has a time period of 12 months. Should Global elect to enter Phase 3, it will be required to drill one exploratory well within 24 months. Phase 4 of the exploration period has a duration of 12 months and requires the acquisition of 75 square kilometers of three dimensional seismic, while Phases 5 and 6 both have a duration of 12 months and require the drilling of one exploratory well per phase.

Global Operations – Panama

In September 2001, Global, through a wholly owned subsidiary, signed a TEA with the Ministry of Commerce and Industry for the Republic of Panama. The Panama TEA covered approximately 1.4 million gross acres divided into three blocks in and offshore Panama. Under the terms of the Panama TEA, Global performed certain work program procedures and studies and submitted them to the Panamanian government. The Panama TEA provided Global with an exclusive option to negotiate and enter into one or more contracts for the Exploration and Exploitation of Hydrocarbons with the Ministry of Commerce and Industry. Global completed all of its obligations under the Panama TEA and exercised its option to negotiate an Exploration and Exploitation Contract. As of February 28, 2006, the negotiations with the Panamanian government regarding the form and content of the Exploration and Exploitation Contract are still in progress.

Other Global Operations

Global is committed to broadening its exploration efforts while undertaking development and improved recovery program on its existing contracts. In addition to continuing to expand its operations in Colombia, Peru and Panama, Global may use its operational experience to expand its exploration efforts elsewhere in Latin America if suitable opportunities arise.

Global’s business strategy is to continue aggregating high potential acreage in Latin America while focusing on improving its cash flow by increasing its daily production volumes thereby allowing an increasing capital expenditure budget which is increasingly directed at exploration activities.

Properties and Locations

Production and Revenues – See also Note 18 – “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 GEM’s and Global’s ownership in its most significant producing properties is as follows:


	Average Working Interest		Average Revenue Interest
Lake Raccourci – Domestic	40	%	28	%
Lapeyrouse – Domestic	14	%	9	%
Raymondville – Domestic	27	%	19	%
Main Pass Block 35 – Domestic	90	%	72	%
Bayou Sorrel – Domestic	15	%	11	%
Allen Ranch, Texas – Domestic	11	%	8	%

Alcaravan Contract – Colombia	100	%	80-95	%
Bolivar Contract – Colombia	100	%	88-92	%*
Bocachico Contract – Colombia	100	%	92	%*
Rio Verde Contract – Colombia	100	%	89.5	%
Los Hatos Contract – Colombia	100	%	92	%

*	Based on improved recovery or natural gas development investment royalty reduction program.

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


	GEM Year Ended December 31,
	2001		2002		2003		2004		2005
Production:
Natural Gas (Mcf)		3,844,000		3,225,000		2,133,000		1,788,000		1,299,000
Oil (Bbls)		273,000		267,000		238,000		182,000		135,000
Revenues:
Natural Gas	$	16,643,000	$	10,753,000	$	11,524,000	$	11,044,000	$	11,056,000
Oil		6,708,000		6,617,000		7,229,000		7,290,000		7,108,000

Total	$	23,351,000	$	17,370,000	$	18,753,000	$	18,334,000	$	18,164,000

Unit Prices:
Natural Gas (per Mcf)	$	4.33	$	3.33	$	5.40	$	6.18	$	8.51
Oil (per Bbl)	$	24.57	$	24.78	$	30.38	$	40.05	$	52.65
Production costs per equivalent Mcfe	$	1.69	$	1.51	$	1.99	$	1.88	$	2.52
Amortization per equivalent Mcfe	$	1.52	$	1.44	$	1.47	$	2.35	$	2.74

	Global Year Ended December 31,
	2001		2002		2003		2004		2005
Sales:
Oil (Bbls)		500,000		465,000		394,000		366,000		443,000
Revenues:
Oil	$	8,291,000	$	7,619,000	$	8,556,000	$	10,974,000	$	19,045,000
Unit Prices:
Oil (per Bbl)	$	16.58	$	16.38	$	21.72	$	29.98	$	42.99
Production and transportation costs per equivalent barrel	$	5.87	$	4.38	$	6.09	$	6.95	$	12.06
Amortization per equivalent barrel	$	8.66	$	8.23	$	7.56	$	7.02	$	9.69

Acreage and Wells — At December 31, 2005, GEM and Global owned interests in the following oil and gas wells and acreage.


	GEM
	Gross Wells		Net Wells		Developed Acreage		Undeveloped Acreage
	Oil	Gas	Oil	Gas	Gross	Net	Gross	Net
State
Texas	—	44	—	8.05	8,227	3,445	6,473	1,654
Louisiana	68	40	55.08	6.51	9,111	2,728	15,627	4,248
Other	—	4	—	0.06	—	—	1,809	1,176

Total	68	88	55.08	14.62	17,338	6,173	23,909	7,078


	Global
	Gross Wells		Net Wells		Developed Acreage		Undeveloped Acreage
	Oil	Gas	Oil	Gas	Gross	Net	Gross	Net
Contract Area
Alcaravan	5	—	4.20	—	2,253	2,253	21,513	10,756
Bocachico	2	—	1.84	—	7,835	7,835	46,771	23,385
Bolivar	1	—	0.92	—	1,953	1,953	57,227	28,614
Rio Verde	2	—	1.79	—	160	160	74,840	74,840
Los Hatos	1	—	0.92	—	—	—	85,000	85,000

Total	11	—	9.67	—	12,201	12,201	285,351	222,595

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 GEM’s and Global’s drilling activity:


	GEM Number of Gross Wells Drilled
	Exploratory		Developmental		Total
	Productive	Drilled	Productive	Drilled	Productive	Drilled
2003	0	1	5	5	5	6
2004	2	4	7	8	9	12
2005	5	8	3	3	8	11

Total	7	13	15	16	22	29


	Number of Net Wells Drilled
	Exploratory		Developmental		Total
	Productive	Drilled	Productive	Drilled	Productive	Drilled
2003	—	0.03	1.18	1.18	1.18	1.21
2004	0.10	0.10	1.05	3.23	1.15	3.33
2005	0.75	0.93	0.16	0.16	0.91	1.09

Total	0.85	1.06	2.39	4.57	3.24	5.63


	Global Number of Gross Wells Drilled
	Exploratory		Developmental		Total
	Productive	Drilled	Productive	Drilled	Productive	Drilled
2003	1	1	—	—	1	1
2004	—	—	2	2	2	2
2005	2	2	1	1	3	3

Total	2	3	3	3	6	6


	Number of Net Wells Drilled
	Exploratory		Developmental		Total
	Productive	Drilled	Productive	Drilled	Productive	Drilled
2003	1.00	1.00	—	—	1.00	1.00
2004	—	—	2.00	2.00	2.00	2.00
2005	2.00	2.00	1.00	1.00	3.00	3.00

Total	3.00	3.00	3.00	3.00	6.00	6.00

Employees

As of December 31, 2005, we had 46 employees, including 12, 18 and 7 employees of GEM, Global and IBA and their subsidiaries, respectively. 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 life, medical, dental, surgical and hospital insurance plans for our employees.

Where You Can Find More Information About Harken Energy Corporation

We make available free of charge through our website at www.harkenenergy.com our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q. Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practical after we electronically file such material with, or furnish it to the SEC.

Safety, Health and Environmental Affairs Regulations

The Company is subject to various federal, state, local and international laws and regulations relating to occupational health and safety and the environment including regulations and permitting for air emissions, wastewater and storm-water discharges, the disposal of certain hazardous and nonhazardous wastes, and wetlands preservation. Failure to comply with these occupational health and safety and environmental laws and regulations or associated permits may result in the assessment of fines and penalties and the imposition of investigatory and remedial obligations.

With respect to GEM’s operations, various environmental protection laws and regulations have been enacted and amended in the United States during the past three decades in response to public concerns over the environment. GEM is subject to these various evolving environmental laws and corresponding regulations. In the United States, these laws and regulations are enforced by the U.S. Environmental Protection Agency, the Minerals Management Service of the U.S. Department of the Interior (MMS), the U.S. Coast Guard and various other federal, state and local environmental authorities. Similar laws and regulations, designed to protect the health and safety of our employees and visitors to its facilities, are enforced by the U.S. Occupational Safety and Health Administration and other state and local agencies and authorities. We must comply with the requirements of environmental laws and regulations applicable to its operations, including the Federal Water Pollution Control Act of 1972; the Resource Conservation and Recovery Act of 1976 (RCRA); the Clean Air Act of 1977; the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA); the Superfund Amendments and Reauthorization Act of 1986 (SARA); the Federal Insecticide, Fungicide, and Rodenticide Act of 1947 (FIFRA); the Hazardous Materials Transportation Act of 1975; and the Pollution Prevention Act of 1990.

Global’s operations are subject to similar international governmental controls and restrictions pertaining to the environment, occupational health and safety, and other regulated activities in the countries in which Global operates. Global believes its operations are in substantial compliance with existing international governmental controls and restrictions and that compliance with these international controls and restrictions has not had a material adverse affect on operations.

GEM and Global believe that operations and facilities are in general compliance with all applicable environmental and health and safety laws and regulations. GEM and Global have not had a history of any significant fines or claims in connection with environmental or health and safety matters. However, risks of substantial costs and liabilities are inherent in certain operations; because of this, there can be no assurance that significant costs and liabilities will not be incurred in the future. Changes in environmental and health and safety regulations could subject GEM and Global to more rigorous scrutiny. We cannot predict the extent to which its operations may be affected by future regulatory and enforcement policies.

Forward-Looking Statements

Certain Business Risks and Cautionary Statement for Purposes of the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995

Certain information included in this report, other materials filed or to be filed with the SEC, as well as information included in oral statements or other written statement made or to be made by us contain or incorporate by reference certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used herein, the words “budget,” “budgeted,” “assumes,” “should,” “goal,” “anticipates,” “expects,” “believes,” “seeks,” “plans,” “intends,” “projects” or “targets” and similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements. Where any forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that while we believe these assumptions or bases to be reasonable

and to be made in good faith, assumed facts or bases almost always vary from actual results and the difference between assumed facts or bases and actual results could be material, depending on the circumstances. It is important to note that actual results could differ materially from those projected by such forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the Risk Factors set forth below and the following: activity levels for oil and gas drilling, completion, workover, production and abandonment activities; volatility of oil and gas prices; foreign currency risks; operating risks inherent in oil and gas production; weather; our ability to implement our business strategy; uncertainties about estimates of reserves; environmental risks; and risks related to our foreign operations. All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph and set forth in the Risk Factors section below, and we undertake no obligation to publicly update or revise any forward-looking statements.

ITEM 1A.

RISK FACTORS

Because of the following factors, as well as other variables affecting our operating results, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods.

Risk factors associated with our financial condition:

If we fail to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act, we may not be able to accurately report our financial results.

Our management determined that we had a material weakness in internal control over financial reporting as of December 31, 2004 which was associated with the Company’s level of complex transactions and the lack of accounting personnel to ensure ongoing compliance with relevant accounting and financial reporting requirements. Subsequent to our remediation efforts during 2005, our management determined that we continued to have a material weakness in our internal control over financial reporting relating to the accounting for complex transactions as of September 30, 2005.

We concluded that the weakness in our internal controls disclosed in our Annual Report on Form 10-K for the year ended December 31, 2004 was the result of insufficient staff with technical accounting expertise to apply accounting requirements, as they relate to non-routine and highly complex transactions, in accordance with generally accepted accounting principles. During 2005, we hired additional experienced accounting personnel, specifically the Global Controller, the GEM Vice President—Finance and Chief Financial Officer, GEM Financial Reporting Manager and the Global Financial Analyst, as well as further realigned the financial reporting duties and responsibilities.

Despite our efforts to remediate the material weakness that existed in the Company’s internal control over financial reporting at December 31, 2004, we failed to maintain an effective system of internal control over financial reporting through September 30, 2005. During the third quarter of 2005, our consolidated companies and we continued to enter into highly complex transactions. Although we had implemented additional processes designed to address the accounting treatment for complex transactions; we could have other failures in our internal controls which may result in material misstatements in our financial statements and cause investors to lose confidence in our reported financial information.

During the quarter ended December 31, 2005, we implemented an additional procedure where all journal entries and related calculations which underlie these complex transactions are referenced to the

supporting accounting literature and accounting memoranda. Based on our evaluation conducted on our internal control over financial reporting as of December 31, 2005, we concluded that these controls were effective as of that date.

If we do not continue to meet the listing requirements of the American Stock Exchange, our common stock could be delisted.

The American Stock Exchange requires companies to fulfill certain requirements in order for their shares to continue to be listed. The securities of a company may be considered for delisting if the company fails to meet certain financial thresholds, including if the company has sustained losses from continuing operations and/or net losses in its five most recent fiscal years. As of December 31, 2005, we have sustained losses in five out of the last six fiscal years. There can be no assurance that we will not report additional losses in the future or that the American Stock Exchange will not delist our common stock. The potential delisting of our common stock could adversely affect our ability to raise capital in the future by issuing common stock or securities convertible into common stock.

We have a history of losses and may suffer losses in the future.

We have reported losses in four of the last five fiscal years, including a net loss of approximately $17.9 million for the year ended December 31, 2004. We have reported cumulative net losses of approximately $27 million over the last five fiscal years. Our ability to generate net income is strongly affected by, among other factors, our ability to successfully drill undeveloped reserves as well as the market price of crude oil and natural gas. If we are unsuccessful in drilling productive wells or the market price of crude oil and natural gas declines, we may report additional losses in the future. Consequently, future losses may adversely affect our business, prospects, financial condition, results of operations and cash flows.

Further sales of our interest in Global Energy Development plc would be expected to cause our revenues to decrease.

During the twelve months ended December 31, 2005, we sold certain of our common shares of Global through numerous individual transactions in the market to various purchasers throughout the year in exchange for total cash consideration, net of fees, of approximately $40 million. Other investors, including Lyford, exercised warrants and stock options to purchase additional shares of Global. As a result of the exercise of those warrants and stock options and through sales of our shares in Global, our direct ownership interest in Global decreased from 85% at December 31, 2004 to approximately 34% at December 31, 2005.

Global represented 65% of our total proved reserves at December 31, 2005 and approximately 51% of our consolidated oil and gas revenues in 2005.

method of accounting. Under the equity method of accounting, our investment in Global will be presented on a single line in the consolidated balance sheet. Likewise, our share of Global’s earnings will be reflected on a single line in the consolidated statement of operations.

Our financial condition may suffer if estimates of its oil and gas reserve information are adjusted, and fluctuations in oil and gas prices and other factors affect our oil and gas reserves.

Our oil and gas reserve information is based upon criteria mandated by the SEC, and reflects only estimates of the accumulation of oil and gas and the economic recoverability of those volumes. Our future production, revenues and expenditures with respect to such oil and gas reserves could be different from estimates, and any material differences may negatively affect our business, financial condition and results of operations.

Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions.

Because all reserve estimates are to some degree subjective, each of the following items may prove to differ materially from that assumed in estimating reserves:

•

the quantities of oil and gas that are ultimately recovered,

•

the production and operating costs incurred,

•

the amount and timing of future development expenditures, and

•

future oil and gas sales prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data.

The estimated discounted future net cash flows described in this Annual Report for the year ended December 31, 2005 should not be considered as the current market value of the estimated oil and gas reserves attributable to our properties from proved reserves. Such estimates are based on prices and costs as of the date of the estimate, in accordance with SEC requirements, while future prices and costs may be materially higher or lower. The SEC requires that we report our oil and natural gas reserves using the price as of the last day of the year. Using lower values in forecasting reserves will result in a shorter life being given to producing oil and natural gas properties because such properties, as their production levels are estimated to decline, will reach an uneconomic limit, with lower prices, at an earlier date. There can be no assurance that a decrease in oil and gas prices or other differences in our estimates of its reserve will not adversely affect our financial condition and results of operations.

If estimated discounted future net cash flows decrease, we may be required to take additional writedowns.

We periodically review the carrying value of our oil and gas properties under applicable full-cost accounting rules. These rules require a writedown of the carrying value of oil and gas properties if the carrying value exceeds the applicable estimated discounted future net cash flows from proved oil and gas reserves. Given the volatility of oil and gas prices, it is reasonably possible that the estimated discounted future net cash flows could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that additional writedowns of oil and gas properties could occur. Whether we will be required to take such a charge will depend on the prices for oil and gas at the end of any quarter and the effect of reserve additions or revisions, property sales and capital expenditures during such quarter.

Lyford owns a significant amount of our common stock and exercises significant control over us.

As of December 31, 2005, Lyford beneficially owned approximately 30% of the combined voting power of our outstanding common stock. Lyford is in a position to significantly influence decisions with respect to:

•

our direction and policies, including the election and removal of directors,

•

mergers or other business combinations,

•

the acquisition or disposition of our assets,

•

future issuances of our common stock or other securities,

•

our incurrence of debt, and

•

the payment of dividends, if any, on our common stock, and amendments to our certificate of incorporation and bylaws.

Lyford’s concentration of ownership may also have the effect of delaying, deferring or preventing a future change of control.

Risks associated with market conditions:

Our stock price is volatile and the value of any investment in our common stock may fluctuate.

Our stock price has been and is highly volatile, and we believe this volatility is due to, among other things:

•

the results of our drilling,

•

current expectations of our future financial performance,

•

commodity prices of oil and natural gas,

•

the volatility of the market in general.

For example, the common stock price has fluctuated from a high of $1.30 per share to a low of $0.16 per share over the three years ended December 31, 2005. This volatility may affect the market value of our common stock in the future. See Part II, Item 5: Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Future sales of our common stock pursuant to outstanding registration statements may affect the market price of our common stock.

There are currently several registration statements with respect to our common stock that are effective, pursuant to which certain of our stockholders may sell shares of common stock. Any such sale of stock may also decrease the market price of our common stock.

Any conversions Series M Preferred of Stock or exercise of warrants issued to holders of our Series L and Series M Preferred Stock involving a large issuance of shares of our common stock could result in a dilution of stockholders’ ownership percentage of our common stock and may result in a decrease in the market value of our common stock. In addition, we may elect to issue a significant number of additional shares of common stock for financing or other purposes, which could result in a decrease in the market price of our common stock.

We have issued shares of preferred stock with greater rights than our common stock and may issue additional shares of preferred stock in the future.

We are permitted under our charter to issue up to 10 million shares of preferred stock. We can issue shares of our preferred stock in one or more series and can set the terms of the preferred stock without seeking any further approval from our common stockholders. Any preferred stock that we issue may rank ahead of our common stock in terms of dividend priority or liquidation premiums and may have greater voting rights than our common stock. At December 31, 2005, we had outstanding 1,600 shares of Series G1 Preferred, 1,000 shares of Series G2 Preferred and 50,000 shares of Series M Preferred. These shares of preferred stock have rights senior to our common stock with respect to dividends and liquidation. In addition, such preferred stock may be converted into shares of common stock, which could dilute the value of common stock to current stockholders and could adversely affect the market price of our common stock. At December 31, 2005, each share of Series G1 Preferred, Series G2 Preferred and Series M Preferred, may be converted into shares of common stock at conversion prices of $12.50, $3.00 and $0.59 per share of common stock, respectively, for each $100.00 liquidation value of a share of such preferred stock, plus the amount of any accrued and unpaid dividends.

Risks associated with our operations:

Oil and gas price fluctuations in the market may adversely affect the results of our operations.

The results of our operations are highly dependent upon the prices received for our oil and natural gas production. Substantially all of our sales of oil and natural gas are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and natural gas production are dependent upon numerous factors beyond our control. These factors include the level of consumer product demand, governmental regulations and taxes, the price and availability of alternative fuels, the level of foreign imports of oil and natural gas and the overall economic environment. Significant declines in prices for oil and natural gas could have a material adverse effect on our financial condition, results of operations and quantities of reserves recoverable on an economic basis. Any significant decline in prices of oil or gas could have a material adverse effect on our financial condition and results of operations. Recently, the price of oil and natural gas has been volatile. For example, during 2004, based on NYMEX pricing, the price for a bbl of oil ranged from a high of $55.46 to a low of $32.48 and the price for a Mcf of gas ranged from a high of $8.725 to a low of $4.570. During 2005 the price for a bbl of oil ranged from a high of $69.82 to a low of $42.13 and the price for a Mcf of gas ranged from a high of $15.38 to a low of $5.79.

Our operations require significant expenditures of capital that may not be recovered.

We require significant expenditures of capital in order to locate and acquire producing properties and to drill exploratory and exploitation wells. In conducting exploration, exploitation and development activities from a particular well, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, exploitation, development and production activities to be unsuccessful, potentially resulting in abandoning the well. This could result in a total loss of our investment. In addition, the cost and timing of drilling, completing and operating wells is difficult to predict.

The oil and gas we produce may not be readily marketable at the time of production.

Crude oil, natural gas, condensate and other oil and gas products are generally sold to other oil and gas companies, government agencies and other industries. The availability of ready markets for oil and gas that we might discover and the prices obtained for such oil and gas depend on many factors beyond our control, including:

•

the extent of local production and imports of oil and gas,

•

the proximity and capacity of pipelines and other transportation facilities,

•

fluctuating demand for oil and gas,

•

the marketing of competitive fuels, and

•

the effects of governmental regulation of oil and gas production and sales.

Natural gas associated with oil production is often not marketable due to demand or transportation limitations and is often flared at the producing well site. Pipeline facilities do not exist in certain areas of exploration and, therefore, any actual sales of discovered oil and gas might be delayed for extended periods until such facilities are constructed.

Our domestic operating strategic plan includes the acquisition of additional reserves through business combinations.

Our domestic operations have shifted from primarily an exploration and development focus to an acquisition and exploitation growth strategy. We are seeking acquisition opportunities to expand our domestic operations and increase our oil and gas reserves in North America. We may not be able to consummate future acquisitions on favorable terms. Additionally, any such future transactions may not achieve favorable financial results. Inherent in any future acquisitions are certain risks, such as the difficulty of assimilating operations and facilities of the acquired business, which could have a material adverse effect on our operating results, particularly during the period immediately following such acquisition.

Future business combinations may also involve the issuance of shares of our common stock, which could have a dilutive effect on stockholders’ percentage ownership. We may not have a sufficient number of authorized shares to issue in any such business combinations and we may need to obtain stockholder approval to authorize additional shares for issuance. Further, the use of shares in business combinations will reduce the number of shares available for the redemption of existing convertible notes and preferred stock.

In addition, acquisitions may require substantial financial expenditures that will need to be financed through cash flow from operations or future debt and our equity offerings, and we may not be able to acquire companies or oil and gas properties using its equity as currency. In the case of cash acquisitions, we may not be able to generate sufficient cash flow from operations or obtain debt or equity financing sufficient to fund future acquisitions of reserves.

We may suffer losses through futures trading.

In February 2006, we reduced our investment in IBA. Through our remaining investment in IBA, however, we may be investing capital in the trading of energy futures contracts. The results of these investments can be significantly impacted by factors such as the volatility of the relationship between the value of futures contracts and the cash prices of the underlying commodity, counterparty contract defaults, and

general volatility of the capital markets. The changes in the market value of such futures contracts may fluctuate significantly from time to time, and gains or losses on any particular futures contract may contribute to fluctuations in our quarterly results of operations and may lead to additional losses related to our investment in IBA.

We may encounter operating hazards that may result in substantial losses.

We are subject to operating hazards normally associated with the exploration and production of oil and gas, including blowouts, explosions, oil spills, cratering, pollution, earthquakes, labor disruptions and fires. The occurrence of any such operating hazards could result in substantial losses to us due to injury or loss of life and damage to or destruction of oil and gas wells, formations, production facilities or other properties. We maintain insurance coverage limiting financial loss resulting from certain of these operating hazards. We do not maintain full insurance coverage for all matters that may adversely affect our operations, including war, terrorism, nuclear reactions, government fines, treatment of waste, blowout expenses and business interruptions. Losses and liabilities arising from uninsured or underinsured events could reduce our revenues or increase our costs. There can be no assurance that any insurance will be adequate to cover losses or liabilities associated with operational hazards. We cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase.

During the third and fourth quarters of 2005, our operations in the Gulf of Mexico were affected by one tropical storm and two hurricanes that interrupted both production and certain drilling operations. As much as 75% of our Gulf Coast domestic production was shut in during September and approximately 13% of our pre-storm production level remains curtailed as of February 28, 2006. Restoration of curtailed production is also dependent on resumption of downstream infrastructure of third-parties and the availability of service and equipment contractors necessary for over-water transportation repairs.

We do not maintain full insurance coverage for all matters that may adversely affect our operations, including war, terrorism, nuclear reactions, government fines, treatment of waste, blowout expenses and business interruptions. Losses and liabilities arising from uninsured or underinsured events could reduce our revenues or increase our costs. There can be no assurance that any insurance will be adequate to cover losses or liabilities associated with operational hazards. We cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase.

Drilling oil and gas wells particularly in certain regions of the United States and foreign countries could be hindered by hurricanes, earthquakes and other weather-related operating risks.

Our operations in the Texas and Louisiana Gulf Coast area and our investment in Global which operates in Colombia, Peru and Panama are subject to risks from hurricanes and other natural disasters. Damage caused by hurricanes, earthquakes or other operating hazards could result in substantial losses to us. For example, during 2004 our domestic operations were affected by Hurricane Ivan resulting in reduced oil and gas volumes in the fourth quarter of 2004. During the third and fourth quarters of 2005, our Gulf Coast operations were affected by one tropical storm and Hurricanes Katrina and Rita. See “Risk Factors — We may encounter operating hazards that may result in substantial losses.”

We face strong competition from larger oil and gas companies, which could result in adverse effects on our business.

The exploration, exploitation and production business is highly competitive. Many of our competitors have substantially larger financial resources, staffs and facilities. Our competitors in the United States include numerous major oil and gas exploration and production companies. Our investment in Global may be affected as a result of the competition faced by Global in Colombia, Peru and Panama that includes such major oil and gas companies as BP Amoco, Exxon/Mobil, Texaco/Shell and Conoco/Phillips. These major oil and gas companies are often better positioned to obtain the rights to exploratory acreage for which we compete.

Our operations are subject to various litigation that could have an adverse effect on our business.

From time to time our subsidiaries are defendants in various litigation matters. The nature of our and our subsidiaries’ operations expose us to further possible litigation claims in the future.

There is risk that any matter in litigation could be adversely decided against us or our subsidiaries, regardless of our belief, opinion and position, which could have a material adverse effect on our financial condition and results of operations. Litigation is highly costly and the costs associated with defending litigation could also have a material adverse effect on our financial condition.

Compliance with, or breach of, environmental laws can be costly and could limit our operations.

Our operations are subject to numerous and frequently changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. We own or lease, and have in the past owned or leased, properties that have been used for the exploration and production of oil and gas and these properties and the wastes disposed on these properties may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, the Oil Pollution Act of 1990, the Resource Conservation and Recovery Act, the Federal Water Pollution Control Act and analogous state laws. Under such laws, we could be required to remove or remediate previously released wastes or property contamination. Laws and regulations protecting the environment have generally become more stringent and, may in some cases, impose “strict liability” for environmental damage. Strict liability means that we may be held liable for damage without regard to whether we were negligent or otherwise at fault. Environmental laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. Failure to comply with these laws and regulations may result in the imposition of administrative, civil and criminal penalties.

Although we believe that our operations are in substantial compliance with existing requirements of governmental bodies, our ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. Our current permits and authorizations and ability to get future permits and authorizations, particularly in foreign countries, may be susceptible, on a going forward basis, to increased scrutiny, greater complexity resulting in increased costs, or delays in receiving appropriate authorizations. In particular, Global has experienced and may continue to experience delays in obtaining permits and authorization in Colombia necessary for Global’s operations. Global is required to obtain an environmental permit or approval from the governments in Colombia, Peru and Panama prior to conducting seismic operations, drilling a well or constructing a pipeline in such foreign locations. Our investment in Global may be affected as a result of Global’s operations in foreign countries which have been delayed in the past and could be delayed in the future through the process of obtaining an environmental permit. Compliance with these laws and regulations may increase our costs of operations, as well as further restrict Global’s foreign operations.

Our investment in Global is subject to risks associated with foreign operations and involve substantial costs since the oil and gas industries in such countries are less developed.

The oil and gas industries in Colombia, Peru and Panama are not as developed as the oil and gas industry in the United States. As a result, our drilling and development operations in many instances take longer to complete and often cost more than similar operations in the United States. The availability of technical expertise, specific equipment and supplies is more limited in Colombia, Peru and Panama than in the United States. We expect that such factors will continue to subject Global’s international operations to economic and operating risks not experienced in our domestic operations.

Our investment in Global may be affected if Global fails to comply with the terms of certain contracts related to Global’s foreign operations, Global could lose its rights under each of those contracts.

The terms of each of the Colombian Association and Exploration and Production Contracts, the Technical Evaluation Agreement, the Peruvian License Contract and the anticipated Panamanian Concession Contract require that Global perform certain activities, such as seismic interpretations and the drilling of required wells, in accordance with those contracts and agreements. Global’s failure to timely perform those activities as required could result in the loss of Global’s rights under a particular contract, which would likely result in a significant loss being reflected in our investment in Global. As of December 31, 2005, Global was in compliance with the requirements of each of the existing Association and Concession Contracts and the Technical Evaluation Agreement.

Global may require significant additional financing for Global’s foreign operations, which financing may not be available.

We anticipate that full development of Global’s existing and future oil and gas discoveries and prospects in Colombia, Peru and Panama may take several years and require significant additional capital expenditures. If Global is unable to timely obtain adequate funds to finance these investments, Global’s ability to develop oil and gas reserves in these countries may be severely limited or substantially delayed. Such limitations or delay would likely result in substantial losses being reflected in our investment in Global.

We anticipate that amounts required to fund Global’s foreign activities, will be funded from Global’s existing cash balances, operating cash flows, third-party financing and from joint venture partners. The exact usage of other future funding sources is unknown at this time, and there can be no assurance that Global will have adequate funds available to finance its foreign operations.

Our investment in Global is subject to political, economic and other uncertainties.

Global, in which we hold a 34% equity interest as of December 31, 2005, currently conducts significant operations in Colombia, Peru and Panama and may also conduct operations in other foreign countries in the future. At December 31, 2005, approximately 65% of our consolidated proved reserve volumes and 51% of our consolidated revenues were related to Global’s Colombian operations. Exploration and production operations in foreign countries are subject to political, economic and other uncertainties, including:

•

the risk of war, revolution, border disputes, expropriation, renegotiation or modification of existing contracts, import, export and transportation regulations and tariffs resulting in loss of revenue, property and equipment,

•

taxation policies, including royalty and tax increases and retroactive tax claims,

•

exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over international operations,

•

laws and policies of the United States affecting foreign trade, taxation and investment, and

•

the possibility of being subjected to the jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States.

Central and South America have a history of political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in

termination of contract rights and expropriation of foreign-owned assets. Any such activity could result in a significant loss to Global.

Guerrilla activity in Colombia could disrupt or delay Global’s operations, and we are concerned about safeguarding Global’s operations and personnel in Colombia.

Colombia has suffered through more than 40 years of armed conflict between the government and leftist guerrilla groups, which has escalated from time to time during that time period. The current government has taken a strong approach against the guerilla movement after peace overtures by the preceding Colombian administration failed. The increased military action by the Colombian government directed against the rebel groups operating in Colombia may result in escalated guerilla activity. Also, the increased activity of right-wing paramilitary groups, formed in opposition to the left-wing guerilla groups, has contributed to the escalation in violence. The increase in violence has affected business interests in Colombia. Targeting such enterprises as symbols of foreign exploitation, particularly in the North of the country, the rebel groups have attempted to hamper production of hydrocarbons. The cumulative effect of escalation in the armed conflict and the resulting unstable political and security situation has led to increased risks and costs and the downgrading of Colombia’s country risk rating. Global’s oil and gas operations are in areas outside guerrilla control and with the exception of its increased security requirements, Global’s operations continue mostly unaffected, although from time to time, guerilla activity in Colombia has delayed Global’s projects there. This guerilla activity has increased over the last few years, causing delays in the development of Global’s fields in Colombia. Guerilla activity, such as road blockades, has also from time to time slowed Global’s deployment of workers in the field and affected our operations. In addition, guerillas could attempt to disrupt the flow of Global’s production through pipelines. In addition to these security issues, Global and our investment in Global have also become the subject of media focus in Colombia that may further compromise our security position in the country.

There can be no assurance that attempts to reduce or prevent guerilla activity will be successful or that guerilla activity will not disrupt Global’s operations in the future. There can also be no assurance that Global can maintain the safety of its operations and personnel in Colombia or that this violence will not affect its operations in the future. Continued or heightened security concerns in Colombia could also result in a significant loss to us as a consequence of our investment in Global.

The United States government may impose economic or trade sanctions on Colombia that could result in a significant loss to our investment in Global.

Colombia is among several nations whose progress in stemming the production and transit of illegal drugs is subject to annual certification by the State Department of the United States. Although Colombia was so certified in 2005, there can be no assurance that, in the future, Colombia will receive certification or a national interest waiver. The failure to receive certification or a national interest waiver may result in any of the following:

•

all bilateral aid, except anti-narcotics and humanitarian aid, would be suspended,

•

the Export-Import Bank of the United States and the Overseas Private Investment Corporation would not approve financing for new projects in Colombia,

•

United States representatives at multilateral lending institutions would be required to vote against all loan requests from Colombia, although such votes would not constitute vetoes, and

•

the President of the United States and Congress would retain the right to apply future trade sanctions.

Each of these consequences could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with our operations there. Any changes in the holders of significant government offices could have adverse consequences on Global’s relationship with the Colombian national oil company and the Colombian government’s ability to control guerrilla activities and could exacerbate the factors relating to Global’s operations discussed above. Any sanctions imposed on Colombia by the United States government could threaten Global’s ability to obtain necessary financing to develop the Colombian properties or cause Colombia to retaliate against Global, including by nationalizing our Colombian assets. Accordingly, the imposition of the foregoing economic and trade sanctions on Colombia would likely result in a substantial loss and a decrease in the price of our common stock. There can be no assurance that the United States will not impose sanctions on Colombia in the future or predict the effect in Colombia that these sanctions might cause.

We may suffer losses from exchange rate fluctuations.

We account for our Colombian, Peruvian and Panamanian operations using the U.S. dollar as the functional currency. The costs associated with our exploration efforts in Colombia, Peru and Panama have typically been denominated in U.S. dollars. A portion of Colombian revenues are denominated in Colombian pesos. To the extent that the amount of our revenues denominated in Colombian pesos is greater than the amount of costs denominated in Colombian pesos, we could suffer a loss if the value of the Colombian peso were to drop relative to the value of the U.S. dollar. Any substantial currency fluctuations could have a material adverse effect on our results of operations. In recent years the value of the Colombian peso relative to the U.S. dollar has declined. For example, the average exchange rate for the Colombian peso into U.S. dollars for December 2005 was .00039, as compared to an average of 0.00036 for December 2004 and December 2003.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

See Item 1. “Business” for discussion of oil and gas properties and locations.

We have offices in Houston and Southlake, Texas; Bernardsville, New Jersey; Bogotá, Colombia; Budapest, Hungary; and London, England. We lease approximately 29,778 (13,738 is currently subleased through November 2006 to an unaffiliated third party) square feet of office space in Houston, Texas, which lease runs through November 2006 and January 1, 2012, approximately 4,062 square feet in Southlake, Texas, which lease runs through April 2008, approximately 3,300 square feet in Bernardsville, New Jersey, which lease runs through September 2006, approximately 2,840 square feet of office space in Bogotá, Colombia, which lease runs through October 2006 approximately 2,000 square feet in Budapest Hungary which lease runs through March 2006, and approximately 230 square feet of office space in London, England, which lease runs through May 2006. The average annual cost of our leases are approximately $347,000. See “Liquidity and Capital Resources – Obligations and Commitments – Consolidated Contractual Obligations” contained in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 3.

LEGAL PROCEEDINGS

In late 2004, Harken de Colombia, Ltd, (“HDC”) determined that a property owner had instituted an action in Colombia against Grant Geophysical, Inc. a subcontractor to HDC, alleging that his property had been damaged by an amount of approximately $1.9 million as a result of certain seismic activities conducted by Grant Geophysical, Inc. on the claimant’s property. In June 2005, HDC was notified that the plaintiff had added HDC as a defendant in the lawsuit. Subsequent to this notice, HDC filed a motion to dismiss plaintiff’s claims against HDC. On July 15, 2005, the court determined to dismiss all claims alleged by plaintiff against HDC. On July 26, 2005, plaintiff filed an appeal of the court’s dismissal. HDC objected to the plaintiff’s appeal. On September 29, 2005, the court dismissed the plaintiff’s appeal and sustained the dismissal of all claims against HDC. HDC’s subcontract with Grant Geophysical, Inc. contains an indemnity provision requiring Grant Geophysical, Inc. to make HDC whole for any losses, including any losses associated with property damages. While the dismissal of plaintiff’s appeal was without prejudice to refiling, Harken believes, based on the court’s dismissal of the plaintiff’s appeal and the contract indemnity, that the ultimate outcome of this matter will not have a material adverse effect on its financial conditions and results of operations.

On May 31, 2005, the Colombian federal taxing authority, referred to by its Spanish acronym as “DIAN,” issued an Official Tax Assessment with regard to HDC’s tax return for 2001. The tax assessment includes a ‘presumptive income tax’ (PIT) equal to approximately $605,000 and an inaccuracy fine of $968,000. The described tax assessment is based on DIAN’s position that HDC understated its asset base for tax purposes in its 2001 Colombian tax return. The basis for DIAN’s position is that HDC had “productive” assets in 2001, namely the Alcaravan and Bolivar Association Contracts that should have been included in HDC’s asset base calculation. In August 2005, HDC filed its response to the tax assessment through the institution of a formal administrative proceeding. DIAN must respond within one year. As of February 28, 2006 DIAN has not officially responded to HDC’s objection. HDC intends to complete the administrative proceeding and object to DIAN’s conclusions on the following grounds: (a) Colombian statutes require that the asset base for PIT be calculated as of the end of the year preceding the tax year in question; and (b) as of the year ended December 31, 2000, the Alcaravan and Bolivar contracts were not productive assets for tax purposes. HDC faced a similar issue for its 2000 Colombian tax return. HDC refuted DIAN’s claim based on the arguments presented above, and ultimately the 2000 Colombian tax return issues were resolved in HDC’s favor. HDC has engaged the same outside lawyers and tax consultant to assist in this matter as were engaged in the 2000 tax return matter. Accordingly, Harken believes that any liability to Harken or its consolidated companies as a result of the tax assessment will not have a material adverse effect on Harken’s operations or financial condition.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the fourth quarter of 2005.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Price Range of Common Stock

Since March 18, 1991, our common stock has been listed on the American Stock Exchange and traded under the symbol HEC. At December 31, 2005, there were 2,020 holders of record of our common stock. If we do not continue to meet the listing requirements of the American Stock Exchange, our common stock could be delisted, for further discussion see Item 1A. “Risk Factors.”

The following table sets forth, for the periods indicated, the reported high and low closing sales prices of our common stock on the American Stock Exchange Composite Tape.


		Prices
		High	Low
2004 —	First Quarter	1.30	0.81
	Second Quarter	0.90	0.47
	Third Quarter	0.58	0.40
	Fourth Quarter	0.68	0.50
2005 —	First Quarter	0.58	0.42
	Second Quarter	0.53	0.38
	Third Quarter	0.84	0.45
	Fourth Quarter	0.75	0.56

Dividends

We have not paid any cash dividends on common stock since our organization, and we do not contemplate that any cash dividends will be paid on shares of our common stock in the foreseeable future. Dividends may not be paid to holders of common stock prior to all dividend obligations related to our Series G1 Preferred Stock, Series G2 Preferred Stock and Series M Preferred Stock being satisfied.

For discussion of dividends paid to holders of our preferred stock and the terms of our preferred stock outstanding, see Part II, Item 8, “Notes to Consolidated Financial Statements, Note 10 – Redeemable Preferred Stocks and Note 11 – Stockholders’ Equity.”

Equity Compensation Plans

Harken’s equity compensation plans were terminated during 2004. There are no shares currently authorized for issuance under the terminated plans.

Information on Share Repurchases

The following table provides information about purchases by the Company pursuant to previously announced buyback program during the three months ended December 31, 2005, of its Common Stock:


Period	Total Number of Shares Purchased	(Average Price Paid)	Total Number of Shares Purchased as part of Publicly Announced Program ⁽¹⁾
October 1, 2005 through October 31, 2005	1,614,400	.642204	1,614,400
November 1, 2005 through November 30, 2005	220,800	.626664	220,800
December 1, 2005 through December 31, 2005	579,500	.606150	579,500

Total			2,414,700

⁽¹⁾	In September 2005, the Company’s board of directors authorized a repurchase program for up to 10 million shares of our outstanding Common Stock. As of February 28, 2006, the repurchase program remained in effect.

ITEM 6.

SELECTED FINANCIAL DATA

The following table sets forth historical financial data derived from our audited Consolidated Financial Statements and should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and accompanying Notes to Consolidated Financial Statements.


	December 31,
	2001			2002			2003			2004			2005
Operating Data:
Revenues and other	$	32,466,000		$	25,355,000		$	27,290,000		$	29,742,000		$	40,134,000
Net income/(loss) before cumulative effect of change in accounting principle	$	(41,023,000	)	$	(9,807,000	)	$	(184,000	)	$	(17,894,000	)	$	42,980,000
Net income/(loss)	$	(41,023,000	)	$	(9,807,000	)	$	(997,000	)	$	(17,894,000	)	$	42,980,000
Net income/(loss) attributed to common stock	$	(44,201,000	)	$	(13,917,000	)	$	2,132,000		$	(18,409,000	)	$	42,393,000
Basic income/(loss) per common share:
Net income/(loss) before cumulative effect of change in accounting principle	$	(2.45	)	$	(0.64	)	$	0.03		$	(0.07	)	$	0.19
Net income/(loss)	$	(2.45	)	$	(0.64	)	$	0.02		$	(0.09	)	$	0.19
Diluted income/(loss) per common share:
Net income/(loss) before cumulative effect of change in accounting principle	$	(2.45	)	$	(0.64	)	$	(0.02	)	$	(0.07	)	$	0.18
Net income/(loss)	$	(2.45	)	$	(0.64	)	$	(0.03	)	$	(0.07	)	$	0.18
Balance Sheet Data:
Current assets	$	14,245,000		$	11,021,000		$	16,849,000		$	36,005,000		$	59,578,000
Current liabilities		10,867,000			44,544,000			8,962,000			14,160,000			14,415,000

Working capital	$	3,378,000		$	(33,523,000	)	$	7,887,000		$	21,845,000		$	45,163,000

Total assets	$	95,806,000		$	85,580,000		$	81,012,000		$	107,481,000		$	153,428,000
Long-term obligations:
Convertible notes payable	$	51,388,000		$	11,106,000		$	3,673,000		$	6,911,000		$	—
Share based compensation liability		—			—			—			6,120,000			10,687,000
Bank credit facilities		7,937,000			3,810,000			—			—			—
Investor term loan		—			5,000,000			—			—			—
Senior secured notes		—			—			2,020,000			—			—
Global senior convertible notes		—			—			—			—			12,500,000
Accrued preferred stock dividends		3,942,000			7,369,000			3,239,000			—			—
Asset retirement obligation		4,328,000			4,664,000			6,305,000			5,954,000			6,301,000
Global warrant liability		—			644,000			651,000			14,858,000			—
Other long-term obligations		1,130,000			—			—			—			—

Total	$	68,725,000		$	32,593,000		$	15,888,000		$	33,843,000		$	29,488,000

Stockholders’ equity	$	16,214,000		$	5,131,000		$	52,761,000		$	51,102,000		$	92,162,000
Series G1 preferred stock outstanding ⁽²⁾		446,000			403,000			325,000			14,000			2,000
Series G2 preferred stock outstanding ⁽²⁾		95,000			93,000			62,000			2,000			1,000
Series G3 preferred stock outstanding ⁽²⁾		—			—			77,000			—			—
Series G4 preferred stock outstanding ⁽²⁾		—			—			—			78,000			—
Series J preferred stock outstanding ⁽²⁾		—			—			—			50,000			—
Series L preferred stock outstanding ⁽²⁾		—			—			—			10,000			—
Series M preferred stock outstanding⁽²⁾		—			—			—			50,000			50,000
Weighted average common shares outstanding		18,063,584			21,742,163			112,694,654			201,702,235			219,639,798
Proved reserves at end of year ⁽¹⁾⁽³⁾:
Bbls of oil		7,626,000			8,779,000			5,725,000			5,606,000			6,282,000
Mcf of gas		39,393,000			34,508,000			14,214,000			13,327,000			8,453,000
Future net cash flows	$	104,166,000		$	236,756,000		$	136,212,000		$	178,167,000		$	247,627,000
Present value (discounted at 10% per year)	$	63,297,000		$	160,237,000		$	107,076,000		$	124,650,000		$	178,009,000

⁽¹⁾

These estimated reserve quantities, future net revenues and present value figures are related to proved reserves located in the United States and Colombia. No consideration has been given to probable or possible reserves. Oil and gas year end prices were held constant except where future price increases were fixed and determinable under existing contracts and government regulations.

Due to reduced oil and gas prices as of December 31, 2001, Harken recorded a consolidated non-cash valuation allowance of approximately $18.7 million during the year ended December 31, 2001.

⁽²⁾	See “Notes to Consolidated Financial Statements, Note 11 - Stockholders’ Equity and Note 10 - Redeemable Preferred Stocks” contained in Part II, Item 8, for further discussion of our preferred stock.

⁽³⁾	Includes amounts associated with a 14.38%, 14.65% and 66.25% minority interest of a consolidated subsidiary as of December 31, 2003, 2004 and 2005, respectively.

ITEM 7.

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

BUSINESS OVERVIEW

During 2005, our results of operations reflect increased consolidated oil and gas revenues through the benefit of increased oil and gas prices and significant gains from sales of certain of our holdings of common shares of Global Energy Development PLC (“Global”). These sales of shares, along with the exercise of Global stock options and warrants, decreased our direct equity interest in Global from approximately 85% at December 31, 2004 to approximately 34% at December 31, 2005. See 2005 Capital Structure - Changes in Our Ownership of Global Shares below for detail of the changes in our ownership in Global during the year.

Also in 2005, we simplified our capital structure by redeeming a significant portion of our outstanding preferred stock including the Series G4 Preferred, Series J Preferred, Series L Preferred and the majority of our Series G1 and Series G2 Preferred. We extinguished approximately $8.6 million principal amount in outstanding debt during 2005. In addition, through the sale of certain of our shares in Global in the market to a variety of purchasers throughout the year, on a consolidated basis, we held approximately $46 million in cash and short term investments at December 31, 2005. During 2006, we are focused on pursuing additional energy-based growth opportunities as well as continuing the development of our oil, gas and coalbed methane assets and investments.

Our domestic operations are conducted through our wholly-owned subsidiary, Gulf Energy Management Company (“GEM”). GEM’s operations consist of exploration, exploitation, development, production and acquisition efforts in the United States, principally in the onshore and offshore Gulf Coast regions of South Texas and Louisiana, as well as coal bed methane exploration and development activities in Indiana and Ohio. During 2005, GEM’s operations were adversely affected by an unusually active hurricane season in the Gulf Coast region. Both Hurricane Katrina and Hurricane Rita resulted in the shut-in of production and helped contribute to the decrease in GEM’s oil and gas production by approximately 27% during 2005 as compared to 2004. The efforts associated with evaluating and repairing damage and restoring oil and gas production took a significant amount of time and focus for GEM during 2005. In connection with our operated properties, we have scheduled property damage insurance, but not business interruption coverage. On our non-operated Louisiana properties, our property damage insurance coverage is provided through the respective property’s operator. See “GEM’s Operations – Effect of Recent Hurricanes in the Gulf of Mexico” below for additional information. GEM’s drilling program for 2005 was reduced as compared to its budgeted program due to the hurricanes and the reduced level of accessibility of equipment and services in the Gulf Coast region during the third and fourth quarters of 2005. GEM has budgeted approximately $17 million for its 2006 capital expenditure program which is expected to be funded through available cash on hand and generated future cash flows from operations. As of February 28, 2006, GEM has restored its oil and gas production to approximately 87% of its pre-hurricane production rate. Even with the reduced level of production associated with the Gulf Coast hurricanes in 2005, higher than average commodity prices, as compared to the past three years, offset the decreased production for GEM as compared to 2004.

During 2005, GEM was successful in diversifying its operations by entering into two significant coalbed methane exploration and development Agreements in Indiana and Ohio. Each prospect provides for an area of mutual interest of approximately 400,000 acres. The agreements provide for a phased delineation, pilot and development program, with corresponding staged expenditures. Contracted third parties with a long track record of successful coalbed methane development provide expert advice (the “Technical Consultant”) for these projects. See “GEM’s Operations – Coalbed Methane Prospects – Indiana and Ohio” below and Note 2 – “Mergers, Acquisitions and Dispositions” in the Notes to the Consolidated Financial Statements for further discussion. GEM is actively evaluating other strategic coalbed methane opportunities in pursuit of long-lived reserve prospects to compliment our current oil and gas portfolio.

Our international crude oil exploration and production operations are conducted through our 34% (as of December 31, 2005) ownership interest in Global. Global has exploration and production activities in Colombia and exploration activities in Panama and Peru. Revenues from Global are derived solely from its Colombian oil production. During the year ended December 31, 2005, Global increased their sales compared to the prior year period by selling approximately 443,000 net barrels of oil (after royalties and the Cajaro working interest allocation) in Colombia. These sales generated oil revenues of approximately $19 million and represented approximately 51% of our consolidated revenues for such period. Global’s activities in Panama and Peru, thus far, have been limited to technical evaluations of potential exploration areas.

Global acquired several new contracts and related acreage in Colombia and Peru during 2005. See Global’s Operations below for more detail regarding these new contracts.

During 2005, we were also engaged in minimal energy trading through our investment in International Business Associates (“IBA”), which focused primarily on trading energy futures or other energy based contracts, principally in the United States. During 2004, we invested $12.5 million in IBA in exchange for 12,500 convertible preferred shares of IBA representing a 48% beneficial ownership interest in that entity. During 2005, IBA had a low volume of trading activities and was unsuccessful in obtaining trading contracts overseas. As of December 31, 2005, IBA is no longer trading domestic contracts and is focusing on pursuing natural gas futures contracts overseas. In February 2006, IBA redeemed 7,500 shares of our IBA convertible preferred shares along with our 24 shares of IBA common stock in exchange of cash consideration of $7.5 million. We are currently evaluating strategic alternatives regarding our remaining investment in IBA.

INDUSTRY OUTLOOK:

The oil and gas industry experienced increasing commodity prices throughout 2005. Supply and geopolitical uncertainties, combined with strong demand, resulted in historically high prices for the industry. New York Mercantile Exchange (NYMEX) futures price for West Texas Intermediate (WTI) crude oil averaged $56.61 per barrel for the year, with a low price of about $42.13 per barrel occurring in the first quarter of 2005 and a high price point in excess of $69.82 per barrel in the third quarter of 2005. Crude oil prices were driven largely by weather, geopolitical instabilities in various producing regions, including the Middle East, Nigeria and Venezuela, as well as concerns that world oil production may be challenged to meet overall market demand. These concerns, coupled with rapidly growing demand, particularly in Asian markets, contributed to strong pricing and market volatility. The year ended with WTI crude oil prices at about $61.04 per barrel. U.S. natural gas pricing was also strong throughout the year, with NYMEX Henry Hub futures prices never falling below $5.79 per million British thermal units (MMBtu). The gas market continues to be driven by fundamental uncertainties regarding the industry’s ability to maintain supply in line with increasing demand. In spite of high gas storage inventories, pricing peaked during the fourth quarter of 2005 at around $15.38 per MMBtu. Late in the fourth quarter 2005, prices moderated in response to continued high inventory levels and mild winter conditions for much of the country. For the year, NYMEX natural gas prices averaged about $9.36 per MMBtu and ended the year at about $11.00 per MMBtu. The outlook for the commodity markets in 2006 calls for continued volatility. Many experts see prices for both oil and gas moderating, but remaining above historical levels.

GEM’S OPERATIONS:

Effect of Recent Hurricanes in the Gulf of Mexico

GEM’s Louisiana operations in 2005 were affected by one tropical storm and two hurricanes that interrupted both production and certain drilling operations. As much as 75% of GEM’s domestic production was shut in during September 2005 and approximately 13% of its pre-storm production level remains curtailed as of February 28, 2006. Partial production was restored at Backridge in November and at Main Pass in December 2005. GEM continues to inspect and repair damage to its eastern Gulf operations that remain shut-in which include, Point a la Hache and non-operated properties at Branville Bay and Port Arthur. Restoration of remaining curtailed production is also dependent on resumption of downstream infrastructure and the availability of service and equipment contractors necessary for over-water transportation and repairs.

Net income for GEM during 2005 reflects both slightly decreased revenue, due to the interruption of production, and the direct costs (principally shut-in operating expenses and estimated repair cost related to the hurricanes). We expect 2006 GEM operating results to reflect the restoration costs and the continuing effect of shut-in production from the hurricanes. In connection with our operated properties, we have scheduled property damage insurance, but not business interruption coverage. In 2005, GEM recognized net expenses, after insurance recoveries, in connection with repairs associated with the storms in the amount of $332,000 related to its operated property interests and approximately $40,000 in connection with its non-operated interests affected by the hurricanes. Insurance deductibles associated with two storms and property losses not covered by insurance comprised the recorded losses. On our non-operated Louisiana properties, our property damage insurance coverage is provided through the operator of each property.

Prior to Hurricanes Katrina and Rita and including new production initiated in 2005, GEM had increased its net domestic production rate to approximately 7.6 million cubic feet equivalent of natural gas per day compared to the rate averaged for the second quarter 2005 of 7.3 million cubic feet equivalent of natural gas per day. As of December 31, 2005, GEM properties were producing at approximately 5.7 million cubic feet equivalent per day. We do not anticipate returning to previous production levels prior to April 2006.

The following field data updates the status of GEM’s domestic operations through December 31, 2005.

Lapeyrouse Field, Terrebonne Parish – Louisiana

Hurricane impact. Damage to property interests (operated and non-operated) was minimal and production was fully restored in September 2005.

Field Activity. GEM holds an average non-operated working interest of 8.2% in eight wells in this field, including one additional well for 2005 that commenced production in May 2005. Following two workovers and one well deepening in the field completed in the fourth quarter 2005, gross field production has increased from 12.0 million cubic feet equivalent per day to approximately 20.0 million feet equivalent per day. In June 2005, GEM spudded a ninth well which resulted in a gas well completion in December 2005 (pending pipeline connection) that logged multiple pay zones consistent with the productive horizons in the other wells in the field. The initial production test was 2.4 million cubic feet equivalent of natural gas per day, with first production from this well expected in April 2006. GEM holds an approximately 40% operated working interest in this well.

Main Pass, Plaquemines Parish – Louisiana

Hurricane impact. Production was shut-in for 106 days until mid December 2005 due to damages to production facilities and limitations of the down-stream transmission infrastructure. Repairs to GEM’s facilities are ongoing and gross production in the field has returned to approximately 68% of pre-Katrina levels. Repair work on a second rental compressor damaged by the hurricane is expected to be completed by April 2006. GEM has a 90% interest in Main Pass and is the field operator. GEM’s eight-mile pipeline connecting the facility to the crude oil shore terminal was repaired and successfully tested, eliminating the need to secure alternative sales delivery services for Main Pass production.

Field Activity. During late 2005, GEM completed a major overhaul and rebuild of an additional compressor that had been off-line for the past four years. This investment in the unit increased gas lift in the Main Pass Field. Prior to Hurricane Katrina, production in the field had increased by approximately 100 bopd with an expectation of additional production from additional wells shut-in in prior years. Gross production for the field is now approximately 340 bopd and expected to reach approximately 500 bopd after repairs are complete. GEM continues its geological and geophysical study in the area, utilizing the recently acquired license to 21 square miles of 3D seismic data, covering the area held by production leases.

Raymondville Field, Willacy and Kenedy Counties – Texas

In 2005, GEM participated in an active recompletion campaign in this field with little success. It is expected that field production has peaked and will continue to decline. GEM has an average 27% non-operated working interest in this field.

Lake Raccourci Field, Lafourche Parish – Louisiana

Hurricane impact. Although both Hurricanes Katrina and Rita required the shut-in of production for short periods in August and September 2005, as of December 31, 2005, the field’s production had been restored to its pre-storm capacity. Also, repairs resulting from the storms were minimal and were completed in October 2005.

Field Activity. GEM holds a 40% operated working interest in each of its Lake Raccourci wells. GEM is presently seeking industry partners to drill a field extension well. This prospect is a result of continuing interpretation of GEM’s 60 square mile reprocessed 3D seismic database.

New 3D Seismic Licenses Acquired – Louisiana

GEM continues to evaluate seismic licenses acquired in 2004 covering approximately 155 square miles of 3D seismic data in three different surveys across south Louisiana. The largest database is in Terrebonne Parish and includes approximately 70 square miles. Approximately 56 square miles is in Cameron Parish, and approximately 29 square miles in Iberville Parish. A number of leads have developed in this continuing study. GEM is in the process of cataloging and prioritizing the seismic data.

South Beach Field, Chambers County – Texas

GEM has a non-operated working interest of 10% in this area. The initial well was drilled to a true vertical depth of 10,750 feet and completed in the fourth quarter of 2004. GEM also participated in a second well drilled during the first quarter of 2005. After experiencing long delays to tie-in to the transmission pipelines, production on the well commenced in August 2005.

Branville Bay Field, Plaquemines Parish – Louisiana

Hurricane impact. Damages to this non-operated property have been difficult to assess given the difficulty of access to the location. All wells in this field have been shut-in since Hurricane Katrina. Recently, the operator communicated that the repair of damage to its production facilities is required before this property can return to production. The operator has estimated its production facility will not be completed until April 2006.

Field Activity. GEM has a non-operated working interest of 12.5% in this area. The initial well was drilled to a total depth of 7,250 feet in 2004. The well was completed in the two logged productive sands, and production began in February 2005. A second well was completed to a total depth of 7,200 feet and was connected to the transmission pipeline in the third quarter of 2005.

Point a la Hache Field, Plaquemines Parish – Louisiana

Hurricane impact. Damages to this field by Hurricane Katrina are expected to be approximately $150,000 (before insurance), net to GEM’s 25% interest. The damages principally affected a leased production barge facility installed at the location in July 2005. Repair of the production barge has required its removal to a drydock to complete repairs which are not expected to be completed before April 2006.

Field Activity. The initial well, State Lease 18077 #1, was drilled to a true vertical depth of 10,300 feet in mid-December 2004. The well was logged productive, completed and tested in the lower sand of two sands that both logged productive. The well began producing in July 2005. GEM maintains a 25% operated working interest in the area.

Allen Ranch Field, Colorado County – Texas

GEM owns an 11.25% non-operated working interest in the area. The initial well, the Hancock Gas Unit #1, was drilled to a measured depth of 16,983 feet in late January 2005. The well was productive in four sands with first production in April 2005 and has been producing approximately 2,500 mcf per day. In September 2005, the well was fracture stimulated resulting in a production increase to 6,500 mcf per day. As a result of the success with the first well, the Hancock Gas Unit #2 was spudded in October 2005 as an offset to the first well. This second well was logged as productive in the same four sands as the initial well and two deeper zones have indications of potentially being productive also. With production casing set and fracturing operation pending, first production is expected in the first quarter of 2006.

Southeast Nada Field, Colorado County – Texas

GEM has a 17% non-operated working interest in this area. The initial well, the Popp et al #1, was drilled to a measured depth of 10,030 feet in late March 2005. The well was logged productive in two sands and began producing in May 2005.

Coalbed Methane Prospects – Indiana and Ohio

In 2005, GEM entered into two significant exploration and development agreements in Indiana and Ohio. Each prospect provides for an area of mutual interest of approximately 400,000 acres. 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. See Note 2 – “Mergers, Acquisitions and Dispositions” in the Notes to the Consolidated Financial Statements for further discussion.

On the Indiana Posey Prospect, the coring phase commenced in May 2005 with GEM’s funding of $446,000 for core drilling that was completed by the prospect operator in July 2005. In September 2005, after the submission of a Phase I core evaluation report by the Technical Consultant, GEM elected to proceed and fund pilot well drilling under Phase II of the agreement. With regard to Phase II, GEM made an additional $500,000 prospect acquisition payment and will fund a $1,280,000 AFE in 2006 for the first of two pilot well projects on the Indiana Prospect. GEM expects the drilling of the pilot wells will commence in the first quarter of 2006, including facilities costs, if necessary, to gather and sell any significant production. Under the agreement, a second pilot well project may be initiated by the funding of a second AFE by GEM for approximately $1,100,000. Following an extended evaluation period of the pilot wells, GEM will evaluate a Phase III election and funding of a development well program as contemplated by the agreements.

On the Ohio Cumberland Prospect, the coring phase commenced in May 2005 with GEM’s funding of $284,000 for core drilling that was completed by the prospect Operator in July 2005. Currently, the core samples are continuing to be analyzed. Depending on the final evaluation, (including the core evaluation report due from the Technical Consultant and the Operator), GEM may elect to proceed and fund a Phase II of pilot wells on this prospect.

Effective November 2005, GEM extended its CBM projects to include an exploration and development coalbed methane project within the Triangle Prospect Area in Ohio, consisting of approximately 1,042 acres of land with the potential of acquiring additional acreage in subsequent phases of this project. See Note 2 – “Mergers, Acquisitions and Dispositions” in the Notes to the Consolidated Financial Statements for further discussion.

In addition, GEM is actively evaluating other strategic coalbed methane opportunities in pursuit of long-lived reserve prospects to compliment our current oil and gas portfolio.

GLOBAL’S OPERATIONS:

Revenues from Global are derived solely from its Colombian oil production. During 2005, Global increased its sales compared to the corresponding prior year period due to increased crude oil prices as well as increased production.

In April 2005, Global entered into a new crude oil sales contract with Petrobras Colombia Limited, a subsidiary of Petrobras, the state oil company of Brazil, with an effective date of May 1, 2005. The non-exclusive contract offers Global improved terms through a reduced quality adjustment levy. Quality adjustment levies can fluctuate daily based upon market conditions and slight variances in production blend. The contract is for an initial one year period with an automatic renewal unless advance notice is received from either party and covers all crude oil production tendered from Global’s Palo Blanco, Anteojos, Rio Verde, Torcaz and Bolivar fields in Colombia, net of royalties paid to the Colombian government and Empresa Colombiana de Petroleos (“Ecopetrol’s”) portion of production from one well, the Cajaro #1.

In April 2005, Global announced that the new License Contract for the Exploration and Exploitation of Hydrocarbons in the Block 95 Area located in the Marañon Basin of Northeastern Peru between Global and Perupetro S.A. (“Perupetro”), the national oil company of Peru, (the “License Contract”) had been fully executed and was effective. Global owns a 100% working interest in the License Contract area subject only to an initial 5% royalty. The size of the ongoing royalty is to be determined by future production levels. The contract duration is approximately seven years for the initial exploration phases and 23 years for the exploitation phase. The contract assigns Global exclusive exploration and production rights to approximately 1,255,000 acres. During Phase 1 of the contract, the terms require Global to complete within 12 months, environmental impact studies and plans for the drilling of a well in the Bretaña field located in Block 95.

In May 2005, Global commenced work to acquire approximately 56 kilometers of new 2D seismic data within the area of its Rio Verde Exploration and Production Contract in Colombia. The seismic data is being acquired around the two producing wells located on the Rio Verde acreage, the Tilodiran #1 and Macarenas #1, in order to evaluate whether to drill additional wells within the contract area. In addition, a proportion of the seismic data is being acquired elsewhere in the contract area to consider future exploratory wells. The new seismic data will be processed alongside with the reprocessing of 300 kilometers of existing seismic data as required under the terms of the contract.

In May 2005, Global signed a new exclusive Technical Evaluation Agreement (“TEA”) with the National Hydrocarbons Agency of the Republic of Colombia (“ANH”) for the evaluation of potential hydrocarbon resources in the Valle Lunar area located in the established Llanos Basin of eastern Colombia. The total acreage covered by the TEA is approximately 2.1 million acres.

The Valle Lunar area has been subject to prior exploration activity by an international petroleum company in 1981 with two exploration wells reported as productive at that time. The Valle Lunar TEA targets medium heavy oil deposits and grants Global the exclusive option to sign a future Exploration and Production Concession contract, typically 25 years in duration, for acreage within the TEA area that Global identifies as prospective and suitable for exploratory drilling and production operations. The TEA duration is 16 months. The TEA requires Global to complete within 12 months the reprocessing and interpretation of 800 linear kilometers of existing 2D seismic data and certain other geophysical measurements and analysis, including the acquisition of aeromagnetic data.

In September 2005, Global exercised its exclusive option to commence negotiations with ANH to convert a portion of the Valle Lunar TEA area into the Luna Llena exploration and production contract and signed this contract in December 2005.

In October 2005, Global announced positive test results from its first exploratory well on the Los Hatos Exploration and Production Concession Contract area in Colombia. Global placed the Los Hatos #1 well on production in November 2005. Global now has production from five different contracts in Colombia.

In December 2005, Global signed a new exclusive exploration and production concession contract for the Caracoli area (the “Caracoli Contract”) with the ANH. The Caracoli Contract covers approximately 90,000 acres in the Catatumbo basin located in northeastern Colombia. This basin is a sub-basin of the prominent Maracaibo basin which extends in a southwesterly direction from Venezuela into Colombia. The Caracoli Contract brings the number of contracts Global now holds in Colombia to seven.

Global holds a 100% working interest in the Caracoli Contract subject only to an initial 10% royalty, with the size of the royalty to be determined by future production levels. The Contract duration is 30 years, divided into an initial 6-year exploration phase and a 24-year exploitation and production phase. Under the terms of the Caracoli Contract, Global must acquire within 12 months, 90 kilometers of 2D seismic data and reprocess 210 kilometers of existing seismic data. Global can elect, at its option, to proceed to phase 2, also 12 months, and drill one exploratory well and acquire limited amounts of additional seismic data. Phases 3 to 6, all optional and 12 months in length, require the drilling of an exploratory well in each phase. Global expects to fund the required work program with cash flow from its five existing productive contracts in Colombia.

2005 CAPITAL STRUCTURE

Simplification of Our Capital Structure

During 2005, we simplified our capital structure while seeking to increase the value of our investments in oil and gas assets. During the year ended December 31, 2005, we retired outstanding debt of approximately $8.6 million and preferred stock with a liquidation value of $15 million. In October 2005, Global issued a total of $12.5 million principal amount of its Variable Coupon Convertible Notes (“Global Notes”), which mature on October 30, 2012, in exchange for $12.5 million cash. The Global Notes are convertible into ordinary shares of Global at 305.8 UK pence per ordinary share to be converted at the agreed upon exchange rate of 1.78 US dollars per British sterling pound. Future possible conversions of the Global Notes into shares of Global’s common stock would dilute our ownership in Global.

Some of these capital structure changes involved the conversion of certain convertible debt and preferred stock into shares of our common stock. As a result, our common shares outstanding increased from 220 million shares outstanding at December 31, 2004 to approximately 224 million shares outstanding at December 31, 2005. At December 31, 2005, if our remaining outstanding debt, convertible preferred stock and common stock purchase warrants were exercised and/or converted, we would be required to issue the following amounts of our common stock:


Instrument	Conversion / Exercise Price ^(a)		Shares of Common Stock Issuable at December 31, 2005
Series M Preferred	$	0.59	8,474,576
Series G1 Preferred	$	12.50	12,800
Series G2 Preferred	$	3.00	33,333
Series L Warrants	$	0.67	3,182,836
Series M Warrants	$	0.57	4,385,965

Common Stock Potentially Issued Upon Conversion / Exercise			16,089,510

^(a)	Certain conversion and exercise prices are subject to adjustment under certain circumstances

As of December 31, 2005, on a consolidated basis, we had cash and short term investments of $46 million and working capital of $45 million (including $8 million cash held by Global). We had approximately $92 million in shareholders’ equity at December 31, 2005.

Changes in Our Ownership of Global Shares

During the year ended December 31, 2005, through warrant and share option exercises and the direct sales of our shares in Global, our ownership in Global has changed as follows:


		After the transaction
Transaction	Global Shares	Global Shares outstanding	Global Shares held by Harken	HEC’s Ownership percentage		Minority Interest ownership
Balance January 1, 2005		28,060,348	23,949,930
01/05 Sale of Global plc common shrs	25,000	28,060,348	23,924,930	85.26	%	14.74	%
01/05 Employee option exercise	66,819	28,127,167	23,924,930	85.06	%	14.94	%
04/05 Sale of Global plc common shrs	25,000	28,127,167	23,899,930	84.97	%	15.03	%
04/05 Sale of Global plc common shrs	50,000	28,127,167	23,849,930	84.79	%	15.21	%
04/05 Sale of Global plc common shrs	2,812,716	28,127,167	21,037,214	74.79	%	25.21	%
04/05 Sale of Global plc common shrs	1,264,600	28,127,167	19,772,614	70.30	%	29.70	%
05/05 Minority Interest warrant exercise	23,766	28,150,933	19,772,614	70.24	%	29.76	%
05/05 Sale of Global plc common shrs	25,000	28,150,933	19,747,614	70.15	%	29.85	%
05/05 Sale of Global plc common shrs	400,000	28,150,933	19,347,614	68.73	%	31.27	%
06/05 Minority Interest warrant exercise	299,294	28,450,227	19,347,614	68.01	%	31.99	%
06/05 Employee option exercise	15,721	28,465,948	19,347,614	67.97	%	32.03	%
06/05 Majority held warrant exercise	6,487,481	34,953,429	25,835,095	73.91	%	26.09	%
06/05 Sale of Global plc common shrs	65,000	34,953,429	25,770,095	73.73	%	26.27	%
06/05 Sale of Global plc common shrs	1,619,578	34,953,429	24,150,517	69.09	%	30.91	%
06/05 Sale of Global plc common shrs	100,000	34,953,429	24,050,517	68.81	%	31.19	%
06/05 Sale of Global plc common shrs	800,000	34,953,429	23,250,517	66.52	%	33.48	%
06/05 Sale of Global plc common shrs	1,000,000	34,953,429	22,250,517	63.66	%	36.34	%
06/05 Sale of Global plc common shrs	100,000	34,953,429	22,150,517	63.37	%	36.63	%
06/05 Sale of Global plc common shrs	245,374	34,953,429	21,905,143	62.67	%	37.33	%
06/05 Minority Interest warrant exercise	11,618	34,965,047	21,905,143	62.65	%	37.35	%
06/05 Sale of Global plc common shrs	100,000	34,965,047	21,805,143	62.36	%	37.64	%
07/05 Minority Interest warrant exercise	81,108	35,046,155	21,805,143	62.22	%	37.78	%
08/05 Minority Interest warrant exercise	84,275	35,130,430	21,805,143	62.07	%	37.93	%
09/05 Sale of Global plc common shrs	150,000	35,130,430	21,655,143	61.64	%	38.36	%
09/05 Sale of Global plc common shrs	30,000	35,130,430	21,625,143	61.56	%	38.44	%
09/05 Sale of Global plc common shrs	50,000	35,130,430	21,575,143	61.41	%	38.59	%
09/05 Sale of Global plc common shrs	150,000	35,130,430	21,425,143	60.99	%	39.01	%
09/05 Sale of Global plc common shrs	700,000	35,130,430	20,725,143	58.99	%	41.01	%
09/05 Sale of Global plc common shrs	1,749,501	35,130,430	18,975,642	54.01	%	45.99	%
09/05 Lyford Inv. warrant exercise	7,000,000	35,130,430	11,975,642	34.09	%	65.91	%
09/05 Sale of Global plc common shrs	25,000	35,130,430	11,950,642	34.02	%	65.98	%
10/05 Employee option exercise	75,000	35,205,430	11,950,642	33.95	%	66.05	%
10/05 Sale of Global plc common shrs	57,179	35,205,430	11,893,463	33.78	%	66.22	%
12/05 Employee option exercise	30,000	35,235,430	11,893,463	33.75	%	66.25	%

Throughout the year ended December 31, 2005, we have consolidated Global’s operating results with a minority interest recognized in our Statement of Operations for the percentage of Global that we did not own. Effective on the date of each transaction above, the proportionate interest in Global’s operations attributable to the minority interest was increased or decreased to give effect to the change in ownership.

Potential Change in Our Ownership of Global

At December 31, 2005 we owned approximately 34% of Global’s common stock. Our ownership in Global may be reduced if the Global Notes and stock options described above are converted or exercised. As of December 31, 2005, the following Global Notes and options were outstanding:


Instrument	Conversion/Exercise Price	Shares Issuable at December 31, 2005
Global Notes	305.8 UK pence	2,296,426
Global employee stock options	50 UK pence	2,967,636
Global employee stock options	54 UK pence	30,000
Global employee stock options	151 UK pence	780,000
Global employee stock options	265 UK pence	270,000

If all the Global Notes and stock options were exercised, our fully-diluted ownership of Global’s issued and outstanding ordinary common shares could decrease from approximately 34% to 29%.

Gain from Exercise of Global Warrants

As discussed in Note 8 – “Changes in Harken’s Ownership in Global” in the Notes to our Consolidated Financial Statements, in 2002 we issued to Lyford Investments Enterprises Ltd. (“Lyford”) warrants to purchase up to 7,000,000 shares of Global held by us at a price of 50 UK pence per share. Lyford’s representative, Alan Quasha, became a member of our board of directors and our Chairman in March 2003. In September 2005, Lyford exercised its warrants in exchange for cash proceeds of $6.4 million, and we recognized a Gain on Exercise of Global Warrants of approximately $28 million in the Consolidated Condensed Statement of Operations. This gain represents the difference between our proportionate net book value of our shares in Global as of the date of exercise and the cash proceeds received plus the fair value of the Lyford Warrant Liability immediately prior to exercise. We do not expect to recognize similar gains in the future.

Possible Deconsolidation of Global

As of December 31, 2005, Lyford owned approximately 20% of the common shares of Global as a result of its exercise of its Global warrants. Also at December 31, 2005, Lyford beneficially owned approximately 30% of the combined voting power of our common stock. Therefore, our direct equity interest of approximately 34%, combined with Lyford’s 20% equity interest in Global, (which totals to a combined ownership percentage of 54%), was deemed to provide us with the legal power to control the operating policies and procedures of Global. As a result, we continued to consolidate the operations of Global as of December 31, 2005.

Lyford has informed us that it may liquidate a portion of its equity ownership interest in Global through strategic sales under certain conditions. If Lyford reduces its equity ownership interest in Global, such that the combined equity interest in Global is less than 50%, we may no longer be deemed to hold the legal power to control the operating policies and procedures of Global. As a result, we would no longer report Global’s operating results in our consolidated financial statements, but we would account for our investment in Global on the equity method of accounting. Under the equity method of accounting, our investment in Global will be presented on a single line in the Consolidated Balance Sheet. Likewise, our share of Global’s earnings will be reflected on a single line in the Consolidated Statement of Operations.

Significant Ownership of our Stock

As of February 28, 2006, Lyford beneficially owned approximately 30% 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.

CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“US 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. See Note 1- “Summary of Significant Accounting Policies” contained in the Notes to Consolidated Financial Statements in Part II, Item 8 for further discussion of our critical accounting policies. The more significant critical accounting estimates and assumptions are described below.

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 depreciation, depletion and amortization 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 18 - “Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements.

Asset Retirement Obligations - Our asset retirement obligations represent our best estimate of the fair value of our future abandonment costs associated with our oil and gas properties, including the costs of removal and disposition of tangible equipment, site and environmental restoration. We estimate the fair value of our retirement costs in the period in which the liability is incurred, if a reasonable estimate can be made. The determination of the fair value of an asset retirement obligation generally involves estimating the fair value of the obligation at the end of the property’s useful life and then discounting it to present value using our credit adjusted, risk free rate of return. Estimating future asset removal costs is difficult and requires management to make estimates and judgments regarding the expected removal and site restoration costs, timing and present value discount rates. Changes in the estimated useful life and the fair value of the asset retirement obligation are imprecise since the removal activities will generally occur several years in the future and asset removal technologies and costs are constantly changing, as are political, environmental and safety considerations that may ultimately impact the amount of the obligations.

Derivative Instruments - We are exposed to the risk of 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 option floors) for a portion of our North American oil and gas production. As required by Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), we are required to record all derivative contracts at fair value in our balance sheet. Changes in fair value are required to be recorded in income or other comprehensive income, depending on the hedging designation and the hedge effectiveness. Our estimates of fair value are based on market quotes from third parties. While the fair values of our derivatives have fluctuated significantly, our estimates of fair value have historically been consistent with the settlement amounts.

Fair value of our debt and equity transactions - Many of our various debt and equity transactions require us to determine the fair value of a debt or equity instrument in order to properly record the transaction in our financial statements. We utilized independent third parties to assist us in determining the fair value of many of our transactions. Fair value is generally determined by applying widely acceptable valuation models, (e.g., the Black Scholes valuation model) using the trading price of the underlying instrument or by comparison to instruments with comparable maturities and terms.

Consolidation of variable interest entities - In January 2003, the FASB issued FASB Interpretation No. (“FIN”) 46, “Consolidation of Variable Interest Entities” (“FIN 46”), which requires the primary beneficiary of a variable interest entity’s (“VIE”) activities to consolidate the VIE. FIN 46 defines a VIE as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at 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. In December 2003, the FASB issued FIN 46(R), which supercedes and amends certain provisions of FIN 46. While FIN 46(R) retained many of the concepts and provisions of FIN 46, it also provides additional guidance related to the application of FIN 46, provides for certain additional scope exceptions, and incorporates several FASB Staff Positions issued related to the application of FIN 46. As of December 31, 2005, Harken owned less than a majority of the common shares of Global but did possess the legal power to direct the operating policies and procedures of Global through our direct ownership, combined with the 20% ownership by Lyford in Global shares. In addition, Harken has concluded that Global is not a VIE as contemplated by FIN 46(R). During the year ended December 31, 2005, we had an investment in a VIE named IBA, which we consolidated in accordance with FIN 46(R). See Note 4 – “Investment in International Business Associates, Ltd.” in the notes to the Consolidated Financial Statements for information regarding the consolidation of IBA.

RECENT ACCOUNTING PRONOUNCEMENTS

On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment”, (“SFAS 123(R)”), that will require compensation costs related to share-based payment transactions (e.g., issuance of stock options and restricted stock) to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, awards required to be classified as liabilities must be remeasured each reporting period. Compensation costs will be recognized over the period that an employee provides service in exchange for the award. SFAS No. 123(R) replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees (“APB25”).” For Harken, SFAS 123(R), as amended by SEC release 34-51558, is effective for the first annual reporting period beginning after June 15, 2005 and is applicable only to new awards or awards that have been modified, repurchased or cancelled after the effective date. Harken is evaluating the impact this new Standard will have on the Company.

On March 29, 2005, the SEC released Staff Accounting Bulletin 107 (“SAB 107”) providing additional guidance in applying the provisions of SFAS 123(R). SAB 107 should be applied when adopting SFAS 123(R) and addresses a wide range of issues, focusing on valuation methodologies and the selection of assumptions. In addition, SAB 107 addresses the interaction of SFAS 123(R) with existing SEC guidance.

RESULTS OF OPERATIONS

For the purposes of discussion and analysis, we present a summary of our consolidated results of operations followed by a more detailed discussion and analysis of our three segments.

Consolidated Statement of Operations Comparisons

Net income/(loss) and per-share amounts for each of the years in the three year period ended December 31, 2005, were as follows:


(Thousands of dollars, except per-share amounts)	2003			2004			2005
Net income / (loss)	$	(997	)	$	(17,894	)	$	42,980
Net income / (loss) attributed to common stock	$	2,132		$	(18,409	)	$	42,393
Net income / (loss) per share -
Basic	$	0.02		$	(0.09	)	$	0.19
Diluted	$	(0.03	)	$	(0.09	)	$	0.18

The primary components of our (1) net loss for the year ended December 31, 2004 compared to the net loss for the year ended December 31, 2003 and (2) net income for the year ended December 31, 2005 compared to the net loss for the year ended December 31, 2004, are outlined in the table below:


	Favorable (Unfavorable) Variance
(Thousands of dollars)	2004 compared to 2003			2005 compared to 2004
GEM operating profit ⁽¹⁾	$	1,224		$	(62	)
Global operating profit ⁽²⁾		2,280			5,264
IBA operating profit ⁽³⁾		(260	)		681
General and administrative expenses, net		(12	)		(4,480	)
Depreciation and amortization		(1,772	)		(656	)
Litigation and contingent liability settlements, net		1,125			—
Share-based compensation		(5,866	)		(540	)
Increase in Global warrant liability		(14,200	)		910
Accretion Expense		72			4
Interest expense and other, net		2,980			(1,075	)
Gain on exercise of Global warrants		—			28,341
Gains from exchanges and extinguishments of debt		(5,370	)		(155	)
Gain on sale of subsidiary stock		—			32,452
Gain/loss on investment		1,478			(990	)
Income tax expense/benefit		(763	)		(154	)
Cumulative effect of change in accounting principle		813			—
Other		1,374			1,334

		(16,897	)		60,874

⁽¹⁾	GEM’s operating profit is calculated as oil and gas revenues less oil and gas operating expenses.

⁽²⁾	Global’s operating profit is calculated as oil revenues less operating expenses, before reduction for minority interest.

⁽³⁾	IBA’s operating profit reflects net trading losses. IBA’s net trading losses for 2004 and 2005 are included in Interest and Other Income

GEM Operating Profit and Global Operating Profit

During 2004 and 2005 our operating profits were dramatically affected by rising commodity prices for natural gas and crude oil. Our average realized natural gas price per Million cubic feet (“MCF”) increased from $5.40 in 2003 to $6.18 in 2004 and to $8.51 in 2005, an increase of 14% in 2004 and 38% in 2005. Crude oil prices experienced similar increases. GEM’s average realized price for crude oil sales per barrel (“Bbl”) increased from $30.38 in 2003 to $40.05 in 2004 and to $52.65 in 2005. Global’s average realized price for crude oil sales per barrel increased from $21.72 in 2003 to $29.98 in 2004 and to $42.99 in 2005.

In 2005, our consolidated net natural gas production declined 27% to 1.3 billion cubic feet (“BCF”) and crude oil net production increased 5% to 578,000 Bbls. The 2005 decrease in GEM’s oil and gas production was due to Hurricane Katrina and Hurricane Rita which passed through the Louisiana Gulf Coast in August and September 2005 and substantially shut down offshore oil and gas wells and facilities for the majority of the third and fourth quarters of 2005. Production volumes from the Main Pass 35 field and facility were substantially reduced due to these severe storms. Substantially all of GEM’s oil and gas production is located along the Gulf of Mexico.

The increase in Global’s crude oil production in 2005 as compared to 2004 was primarily due to the addition of four new producing wells: The Estero #5, the Los Hatos #1, the Tilodiran #1, and the Macarenas #1.

IBA Operating Results:

IBA began trading natural gas contracts in the United States during late 2004 and continued its trading activities during the year ended December 31, 2005. IBA incurred net trading gains of approximately $421,000 for the year ended December 31, 2005. IBA’s net operating gains for the year ended December 31, 2005 are classified in Interest and other income in the Consolidated Statement of Operations. During 2005, IBA had a low volume of trading activities and was unsuccessful in obtaining trading contracts overseas. As of December 31, 2005, IBA is no longer trading domestic contracts.

General and Administrative Expenses

During 2004, our general and administrative costs, exclusive of share-based compensation expense, were approximately equal to those incurred in the prior year. Decreases in general and administrative expenses in 2004, as compared to 2003, which were attributable to a full year of savings for the staff reductions in 2003, lower insurance costs and a decrease in legal and bank commitments and agent fees were offset by administrative costs associated with IBA and an increase in professional and audit fees associated with implementation of the Sarbanes-Oxley 404 internal control compliance requirements.

General and administrative expenses, exclusive of share-based compensation expense, increased 49% to $13.7 million during 2005 as compared to 2004 due primarily to the consolidation of IBA. IBA’s general and administrative expenses for the year ended December 31, 2005 totaled approximately $2.8 million. Additional public company regulatory compliance efforts and corresponding additional financial and administrative personnel also contributed to the increased general and administrative costs in 2005 as compared to the prior year period.

Depreciation, Depletion and Amortization Expense

Depreciation, depletion and amortization (“DD&A”) expense increased approximately 20% to $10.7 million in 2004 as compared to 2003. DD&A of oil and gas properties is calculated on a unit of production basis in accordance with the full cost method of accounting for oil and gas properties. In 2004, although our consolidated oil and gas production decreased approximately 14%, the increase in DD&A in 2004 compared to 2003, is solely attributable to the increase in the DD&A rates per unit. In 2004, GEM’s average DD&A rate increased 60% to $2.35 per Mcf equivalent (“Mcfe”) primarily due to decreased oil and gas reserve volumes as a result of our December 2003 sale of the Panhandle properties. Global’s average DD&A rate decreased approximately 7% to $7.02 per barrel in 2004.

In 2005, GEM’s average DD&A rate increased 17% to $2.74 per Mcfe primarily due to decreased reserve volumes. Also in 2005, Global’s average DD&A rate increased 38% to $9.69 per barrel of oil produced due to increased capital expenditures in excess of added oil reserve volumes.

Litigation and Contingent Liability Settlements

During 2003 we settled various liabilities, contingencies and lawsuits, some of which were settled for amounts less than we had previously recorded. During 2003, we recorded an expense of $1.1 million associated with settlement related to the Rice lawsuit. During 2004 and 2005, we recorded no litigation and contingent liability expense amounts. As of December 31, 2005, we believe our reserves for litigation and contingent liabilities are adequate. For further discussion see Note 19 – “Commitments and Contingencies” in the Notes to Consolidated Financial Statements contained in Part II, item 8.

Share-Based Compensation Expense

During the third quarter of 2004, the Board of Directors of Global amended the Global share option plan to allow for the cashless exercise of options granted to employees under the plan. In accordance with APB25, as interpreted by FIN 44, Accounting for Certain Transactions Involving Stock Compensation, the modification resulted in variable plan accounting for the Global share option plan. Accordingly, Global is required to record compensation expense attributable to the vested options as of the date of the modification in an amount equal to difference between the exercise price of the options and Global’s stock price on the date of modification. Unrecognized compensation costs relating to the unvested options are recorded over the remaining vesting period. Additionally, if the Global share price is greater than the option exercise price, variable plan accounting requires compensation expense (or benefit) to be recognized for subsequent changes in Global’s share price.

As a result of the modification, during 2004, Global recorded share-based compensation expense of $5.9 million attributable to the vested options as of the date of the modification. The compensation expense was equal to difference between the exercise price of the options and Global’s stock price on the date of modification.

During 2005, Global recorded share-based compensation expense of approximately $6.4 million attributable to the vesting of certain unexercised options and the result of the increase in the Global share price during the year ended December 31, 2005. Share-based compensation is classified in General and administrative expenses in our Consolidated Statement of Operations.

As of December 31, 2005, the Global share option plan had approximately 4.0 million options outstanding. Under variable plan accounting, based on fluctuations in Global’s share price, this could result in significant volatility of our earnings in the future.

Global Warrant Liability

During 2005, Global’s common share price increased from approximately 150 UK pence at December 31, 2004 to approximately 263 UK pence at September 15, 2005. We engaged a third party firm to determine the fair value of the Global warrants held by outside parties, which was based in part, on the underlying share price of Global’s common stock. Based on this valuation, we recorded a loss of $13.3 million associated with the increase in the Global warrant liability during the year ended December 31, 2005.

As of December 31, 2004, the fair value of the Global warrant liability was estimated to be approximately $15 million. Accordingly, we recognized a loss in 2004 of $14 million for the increase in the fair value of the Global warrants held by outside parties during the year.

Interest Expense and Other

Interest expense and other includes the following for each of the years in the three-year period ended December 31, 2005:


(Thousands of dollars)	2003		2004		2005
Interest expense on debt instruments	$	1,829	$	273	$	327
Amortization of debt issuance costs		1,483		129		145
Foreign Currency Loss		—		—		756
All other		82		12		261

	$	3,394	$	414	$	1,489

Our annual interest expense and other has decreased significantly over the three-year period ended December 31, 2005 due primarily to the reduction of our overall debt balances. Interest and other expense decreased $3.0 million during 2004 compared to 2003. The decrease was almost exclusively due the full year impact of reduced levels of debt in 2004 versus 2003.

Interest expense and other increased during 2005 compared to the prior year period. During 2005, IBA recorded a foreign currency loss of approximately $636,000 associated with certain of its cash balances held in Euros and Hungarian Forints, and Global expensed a foreign currency loss of approximately $121,000. The U.S dollar is the functional currency for both Global and IBA’s operations. Also during 2005, GEM recorded $157,000 of expense associated with the reduction in values of its outstanding natural gas option floor and crude oil option floor contracts.

Gain on Exercise of Global Warrants

In September 2005, Lyford exercised all of its warrants in exchange for cash proceeds of $6.4 million. In the third quarter of 2005, we recognized a gain on the exercise of these warrants of approximately $28 million. We do not expect to recognize similar gains in the future. There were no similar gains during the year ended December 31, 2003 and 2004.

Gains from Extinguishments of Debt

During 2003, we recorded a gain of approximately $5.5 million from extinguishments of our outstanding 5% European Notes and Benz Convertible Notes. During the year ended December 31, 2004, we repaid the principal amount of our Senior Secured Notes, at a discount equal to approximately 18%, plus

accrued and unpaid interest and recorded a gain on extinguishments of approximately $325,000 in January 2004 in the Consolidated Statement of Operations. No gains from extinguishments of debt were recorded during the year ended December 31, 2005.

Gain on Sale of Subsidiary Stock

During the year ended December 31, 2005, we sold certain of our common shares of Global in the market to a variety of purchasers throughout the year in exchange for aggregate cash consideration, net of fees, of approximately $40 million. These sales of shares contributed to a decrease in our ownership in Global to approximately 34% as of December 31, 2005. In accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” (As Amended) and as a result of the sale of these shares, we recognized a gain of approximately $32 million equal to the amount by which the total sale proceeds exceeded our proportionate carrying value of Global. No gains on sale of subsidiary stock were recorded during the year ended December 31, 2003 and 2004.

Gain on Sale of Investment

During 2004, we sold all of our investment of 1,232,742 ordinary shares of New Opportunities Investment Trust (“NOIT”) on the Alternative Investment Market of the London Stock Exchange (“AIM”) for cash proceeds of approximately $1.6 million and recorded a realized Gain on sale of investment of approximately $1.0 million in our Consolidated Statement of Operations for the year ended December 31, 2004. No gains on investments were recorded during the year ended December 31, 2005.

Accrual of Dividends related to Preferred Stock

All of our preferred stock issues contain dividends provisions. Dividends related to all of our preferred stock are cumulative, and may be paid in cash or common stock, at our option. We accrue the dividends at their cash liquidation value and reflect the accrual of dividends as a reduction in 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, 2005 are as follows:


	2003		2004		2005
Series G1	$	2,862,000	$	1,804,000	$	65,000
Series G2		648,000		224,000		14,000
Series G3		166,000		81,000		—
Series G4		—		462,000		465,000
Series J		—		168,000		167,000
Series L		—		99,000		3,000
Series M		—		46,000		200,000

Total	$	3,676,000	$	2,884,000	$	914,000

Preferred Stock Redemptions

Inducement to Voluntarily Convert to Series G1 Convertible Preferred Stock and Series G2 Convertible Preferred Stock to Shares of Harken Common Stock – In October 2004, we offered all Series G1 Convertible Preferred (“Series G1 Preferred”) and Series G2 Convertible Preferred (“Series G2 Preferred”) shareholders an inducement to convert their Series G1 Preferred and G2 Preferred shares into shares of our common stock at a 20% premium to the original conversion terms of the Series G1 Preferred and G2 Preferred. In November 2004, holders of 281,447 shares of Series G1 Preferred and holders of 21,650 shares of Series

G2 Preferred tendered their shares under the inducement offer in exchange for 3.6 million shares of Harken common stock. At December 31, 2004, there were 13,925 shares of Series G1 Preferred and 2,500 shares of Series G2 Preferred outstanding.

Accounting for Inducement to Voluntarily Convert Series G1 Preferred and Series G2 Preferred to Shares of Harken Common Stock – In accordance with EITF Topic D-98, “Classification and Measurement of Redeemable Securities” (“EITF D-98”), Harken recognized the difference between the fair value of the common stock transferred to the holders of the Series G1 Preferred and Series G2 Preferred under the induced conversion terms and the fair value of the common stock issuable under the original conversion terms of $287,490 as a redemption of preferred stock in the Consolidated Statement of Operations for the year ended December 31, 2004, which is reflected as a increase to Net loss attributed to common stock.

Redemption of Series G1 Preferred - In July 2005, Harken entered into and completed transactions with certain holders of the Series G1 Preferred to redeem a total of 11,825 shares of Series G1 Preferred in exchange for $65,000 in cash.

Accounting for the Redemption of the Series G1 Preferred – In accordance with EITF Topic D-42, “The Effect on the Calculation of Earnings per Share for the Redemption or Induced Conversion of Preferred Stock” (“EITF D-42”) and EITF Topic D-53, “Computation of Earnings per Share for a Period That Includes a Redemption or an Induced Conversion of a Portion of a Class of Preferred Stock” (“EITF D-53”), during 2005, Harken recognized a credit to Payment of preferred stock dividends of approximately $489,000. This amount is reflected as a reduction of the Net income / (loss) attributed to common stock and is equal to the difference between the carrying amount of the Series G1 Preferred redeemed ($554,000) and the fair value of the consideration paid to the holders ($65,000 in cash).

Redemption of Series G2 Preferred - In August 2005, Harken entered into and completed transactions with certain holders of the Series G2 Preferred to redeem a total of 1,000 shares of Series G2 Preferred in exchange for $24,000 in cash.

Accounting for the Redemption of the Series G2 Preferred – In accordance with to EITF D-42 and EITF D-53, during 2005, Harken recognized a credit to Payment of preferred stock dividends of approximately $53,000. This amount is reflected as a reduction of the Net income / (loss) attributed to common stock and is equal to the difference between the carrying amount of the Series G2 Preferred redeemed ($77,000) and the fair value of the consideration paid to the holders ($24,000 in cash).

Issuance of Series G4 Cumulative Convertible Preferred Stock - In March 2004, Harken’s Board of Directors approved the authorization and issuance of up to 150,000 shares of the Series G4 Convertible Preferred stock (“Series G4 Preferred”). In April 2004, Harken issued 77,517 shares of the Series G4 Preferred to certain holders of the Series G1 Preferred and the Series G2 Preferred in exchange for 1,000 shares of Series G1 Preferred, 23,000 shares of Series G2 Preferred and $2.4 million in cash. We reflected the difference between the face amount of the Series G1 Preferred and the Series G2 Preferred, plus the $2.4 million in cash, less transaction fees, and the fair value of the Series G4 Preferred shares issued as Exchange of preferred stock of approximately $337,000 in the Consolidated Statement of Operations for the year ended December 31, 2004, which is reflected as a decrease to Net income / (loss) attributed to common stock.

Redemption of Series G4 Preferred - In September 2005, Harken entered into and completed transactions with certain holders of the Series G4 Preferred to redeem a total of 67,715 shares of Series G4 Preferred in exchange for $3.7 million in cash. In October 2005, Harken redeemed the remaining 9,802 shares of Series G4 Preferred in exchange for a combination of approximately 57,000 shares of Global stock held by Harken and $287,000 in cash. As of December 31, 2005, the Series G4 Preferred are no longer issued or outstanding.

Accounting for the Redemption of the Series G4 Preferred – In accordance with EITF D-42 and EITF D-53, during the year ended December 31, 2005, Harken recognized a debit to Payment of preferred stock dividends of approximately $204,000, which is equal to the carrying amount of the Series G4 Preferred redeemed, net of fees ($3.5 million) less the fair value of the consideration paid to the holders ($3.7 million in cash).

Redemption of the Series J Cumulative Convertible Preferred Stock – In August 2005, Harken entered into and completed a transaction with the holder of the Series J Cumulative Convertible Preferred (“Series J Preferred”) to redeem all of the outstanding 50,000 shares of Series J Preferred in exchange for $5.0 million in cash. As part of the agreement, the Series J Preferred holder waived its right to partial liquidated damages under the Series J Preferred Subscription Agreement, and any interest thereon, which arose from a previous registration default under the agreement. The Series J holder was an investor in Harken, but had no other relationship with the company, commercial or otherwise.

Accounting for the Redemption of the Series J Preferred - In accordance with EITF D-42 and EITF D-53, Harken recognized a charge to Exchange of preferred stock of approximately $225,000, which was equal to the fair value of the consideration paid to the holder ($5 million in cash) less the carrying amount of the Series J Preferred ($4,675,000) and the accrued liquidated damages for the Registration Event forgiven on the redemption of the Series J ($100,000).

Issuance of Series M Cumulative Convertible Preferred – In October 2004, we entered into a Conversion/Redemption Agreement (the “Agreement”) with the holders of the Series L Cumulative Convertible Preferred Stock (“Series L Preferred”), pursuant to which we modified the conversion terms of the Series L Preferred as a part of the agreement to issue the Series M Cumulative Convertible Preferred Stock (the “Series M Preferred”).

Accounting for the Redemption of the Series L – We reflected the difference between the total of the carrying amount of the Series L Preferred, including accrued dividends, plus the $5 million in cash, less transaction fees, and the total of the fair value of the Series M Preferred, the common stock warrants issued plus the consideration paid to redeem the Series L Preferred as Exchange of preferred stock of approximately $1.2 million in the Consolidated Statement of Operations for the year ended December 31, 2004. This charge is reflected as an increase to Net income / (loss) attributed to common stock.

Payment of Preferred Stock Dividends

During 2003, 2004 and 2005, we paid the accrued dividends related to preferred stock for the Series G1, G2 and G4 Preferred with shares of our common stock. In 2003, 2004 and 2005, we issued approximately 947,000, 742,000 and 162,000 shares, respectively, of our common stock as payment for the accrued dividends related to the Series G1, G2 and G4 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 of $6.8 million, $4.2 million and $233,000 in 2003, 2004 and 2005, 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. See Note 11 – “Stockholders’ Equity” in the Notes to the Consolidated Financial Statements contained in Part II, Item 8 for further discussion.

On the date of issuance, the Series L Preferred was convertible into shares of our common stock with a market value of approximately $498,000 greater than the proceeds we received that were attributed to the Series L Preferred. This represents a beneficial conversion feature, as defined in EITF 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios”,

and was reflected in 2004 as a Payment of preferred stock dividends as an increase to Net income / (loss) to arrive at Net income / (loss) attributed to common stock.

Also during 2004 and 2005, as a result of the issuance of certain equity securities and pursuant to the terms of the agreements, we adjusted the conversion prices of the Series J Preferred, Series L Preferred and Series M Preferred and the exercise price of our common stock warrants. We reflected Payments of preferred stock dividends totaling $215,000 and $90,000 in 2004 and 2005, respectively, related to these adjustments as an increase to Net income / (loss) to arrive at Net income / (loss) attributed to common stock.

The payment of preferred stock dividends for each issuance and transaction for each of the three years ended December 31, 2005 is as follows:


	2003			2004			2005
Series G1	$	5,989,000		$	3,521,000		$	541,000
Series G2		878,000			393,000			58,000
Series G3		(62,000	)		—			242,000
Series G4		—			290,000			(131,000	)
Series J		—			(154,000	)		(227,000	)
Series L		—			(558,000	)		(1,000	)
Series M		—			—			(155,000	)

Total	$	6,805,000		$	3,492,000		$	327,000

SEGMENT ANALYSIS

GEM Operations:

Our GEM segment comprises all of our exploration, development, production and acquisition efforts in the United States. GEM is headquartered in Houston, Texas. The following table sets forth GEM’s operating results for each of the years in the three-year period ended December 31, 2005:


(Thousands of dollars, except per-unit amounts)	2003		2004		2005
Oil and Gas Revenues	$	18,753	$	18,334	$	18,164

Operating profit	$	11,682	$	12,906	$	12,844

Net oil sold (thousands of bbls)		238		182		135
Net gas sold (thousands of mcf)		2,133		1,788		1,299
Average price of oil sold (per bbls)	$	30.38	$	40.05	$	52.65
Average price of gas sold (per mcf)	$	5.40	$	6.18	$	8.51
Average production & transportation costs (per mcfe)	$	1.99	$	1.88	$	2.52

Oil and Gas Revenues and Oil and Gas Expenses for the Year Ended December 31, 2004 Compared to December 31, 2003

GEM’s gas revenues decreased 4% to $11 million during 2004 compared to $11.5 million for 2003 due primarily to the sale of the Panhandle properties in December 2003 and the decrease in oil and gas volumes due to Hurricane Ivan which passed through the Louisiana Gulf Coast in September 2004 and shut down offshore oil and gas wells and facilities for a portion of the third and fourth quarters of 2004. Production volumes in September and October 2004 from the Lake Raccourci field and Main Pass 35 field and facility

were substantially reduced due to the severe storms. Oil and gas production volumes in 2004 decreased 681 Bcf equivalent (“Bcfe”), or approximately 19% compared to prior year (approximately 424 Bcfe of the decrease was attributable to the December 2003 sale of the Panhandle properties). The reduction in gas revenue was partially mitigated by new production from wells drilled during 2004 and the increase in natural gas prices during 2004. Our average realized natural gas price increased in 2004 approximately 14% to $6.18 per Mcf. All of GEM’s natural gas production is sold at spot rates, which makes us susceptible to short term swings in natural gas commodity prices.

In 2004, we experienced an insignificant increase in GEM’s oil revenues compared to prior year with an increase of $61,000 to $7.3 million in 2004. Oil production volumes decreased 24% to 182,000 barrels of oil in 2004 from 238,000 barrels of oil in 2003. In September and October 2004, we were forced to curtail oil production from the Main Pass 35 field and the Lake Raccourci field due to Hurricane Ivan. Weather related shut downs of Gulf Coast properties required extensive efforts and time to bring back on production. By late fourth quarter 2004, the majority of all of our Gulf Coast properties had resumed normal production. The reduction in GEM’s oil revenues in 2004 was partially mitigated by the increase in crude oil prices. Our average oil price increased 32% to $40.05 per barrel in 2004. All of GEM’s oil production is sold at spot rates, which makes us susceptible to short term swings in crude oil commodity prices.

GEM’s oil and gas operating expenses decreased 23% to $5.4 million during 2004 compared to $7.1 million during 2003 primarily due to lower production volumes. In addition, the Panhandle properties sold in December 2003 had higher operating costs per Mcfe, averaging approximately $2.36 per Mcfe in 2003.

Oil and Gas Revenues and Oil and Gas Expenses for the Year Ended December 31, 2005 Compared to December 31, 2004

GEM’s oil and gas revenues during 2005 relate to the operations in the onshore and offshore areas of the Texas and Louisiana Gulf Coast. During the year ended December 31, 2005, GEM’s oil and gas revenues decreased 1% to approximately $18.2 million compared to $18.3 million for the prior year primarily due to the decrease in sales and production volumes due to accelerated declines in certain field productivity as well as lost production due to Hurricanes Katrina and Rita. Decreases in production approximated 27% related primarily to a combination of normal production declines (approximately 12%) as well as lost production due to Hurricanes Katrina and Rita. Mitigating this decrease in revenues was an increase in average oil and gas commodity prices received as compared to the prior year period.

GEM’s gas revenues increased 1% to approximately $11.1 million during 2005 compared to approximately $ 11 million for 2004. GEM received an overall average price of $ 8.51 per Mcf of gas during 2005 compared to $6.18 per Mcf received during 2004. Gas production decreased 26%, affected by well decline reductions principally at three fields (Lapeyrouse, Lake Raccourci and Raymondville) and shut-in of production related to the hurricanes. Lapeyrouse has also been affected by delays in completing anticipated workovers. At Raymondville, despite an active recompletion campaign, field production peaked in 2004 and is expected to continue to decline. These production declines were slightly offset by GEM’s new production from wells drilled under GEM’s capital expenditure plan (primarily Allen Ranch, South Beach, Southeast Nada and Branville Bay). All of GEM’s natural gas production is sold at spot rates, which makes us susceptible to short term swings in natural gas commodity prices. GEM currently holds natural gas floor contracts with a strike price of $6.00 per MMBTU for 70,000 MMBTUs per month for the six-month period ending June 30, 2006.

GEM’s oil revenues decreased 3% to approximately $7.1 million during 2005 compared to approximately $ 7.3 million during 2004 due to an increase in oil prices received during 2005 which averaged $52.65 per barrel compared to $40.05 per barrel in the prior year. Decreases in oil production included normal production declines as well as lost production due to Hurricanes Katrina and Rita. All of GEM’s oil production is sold at spot rates, which makes us susceptible to short term swings in crude oil commodity prices. GEM

currently holds crude oil floor contracts with a strike price of $45.00 per barrel for 6,000 barrels per month for the twelve-month period ending December 31, 2006.

GEM’s oil and gas operating expense decreased 2% to approximately $5.3 million during 2005 compared to approximately $5.4 million during 2004 primarily due to decreased production at Main Pass which was shut-in for 106 days due to damages associated with Hurricane Katrina. Although aggregate operating costs for all properties decreased, higher per unit operating cost increases were attributable to property damage costs of $373,000 related to Hurricane Katrina, increased insurance expense (approximately $167,000) and the effect of minimum fixed operating costs during shut-in periods, principally at Main Pass.

Global Operations:

Global’s revenues relate to oil operations in Colombia with production from the Bolivar, Bocachico and Alcaravan Association Contract Areas and the Rio Verde and Los Hatos Concession Contracts. The following table sets forth Global’s operating results for each of the years in the three-year period ended December 31, 2005:


(Thousands of dollars, except per-unit amounts)	2003		2004		2005
Oil Revenues	$	8,556	$	10,974	$	19,045

Operating profit	$	6,158	$	8,438	$	13,702

Net oil sold (thousands of barrels)		394		366		443
Average price of oil sold (per barrel)	$	21.72	$	29.98	$	42.99
Average production & transportation costs (per barrel)	$	6.09	$	6.95	$	12.06

During the three year period ended December 31, 2005, Global has experienced increasing oil revenues, operating profits and oil production volumes. In 2004, Global’s revenues increased approximately 28% and increased an additional 74% in 2005. Operating profits increased 37% in 2004 and an additional 62% in 2005. Global’s operating profit, defined as revenues less lease operating expenses increased $2.3 million in 2004 as compared to prior year. The increases in operating profit and oil revenues were directly attributable to increases in realized crude oil prices. Global’s realized crude oil price increased 98% over the three year period ending December 31, 2005 to an average $42.99 per barrel in 2005. All Colombian crude oil production is sold at spot rates less quality adjustments.

Oil Revenues and Oil Expenses for the Year Ended December 31, 2004 Compared to December 31, 2003

In April 2004, Global perforated and tested the massive Ubaque zone in its Estero #4 well on Global’s Alcaravan Association Contract in Colombia. Production for the Estero #4 well began in May 2004. Global owns a 100% working interest in this well.

The increase in oil revenues in 2004 was mitigated due to a 7% decrease in production volumes attributable to declines in producing wells and workovers in late 2004 of certain wells that reduced oil production during the workover process. Oil production from newly drilled and completed wells drilled during 2004 helped to mitigate the overall decrease in volumes.

Middle American operating expenses increased 6% from approximately $2,398,000 in 2003 to approximately $2,536,000 in 2004, primarily due to workover costs mentioned above.

Oil Revenues and Oil Expenses for the Year Ended December 31, 2005 Compared to December 31, 2004

Global revenues during 2005 relate to Global’s oil operations in Colombia. Global’s Colombian oil revenues increased 74% from $11 million during 2004 to $19 million during the 2005 due to increased production along with increased oil prices, which averaged $42.99 per barrel during 2005 compared to $29.98 per barrel during 2004. Global’s oil production volumes increased 21% during 2005 compared to the prior year period primarily due to the new production from the Tilodiran #1, Macarenas #1, Estero #5 and Los Hatos #1 wells, mitigated by normal production declines.

Global’s operating expenses increased 111% from $2.5 million during the 2004 to $5.3 million for 2005, primarily due to higher diesel fuel and equipment rental costs, as well as workover costs.

IBA Operations:

As noted earlier, in September 2004 we invested $12.5 million in IBA. Our investment represented 100% of the working capital of IBA. Since we bear the majority of the risk and rewards of ownership and effectively control IBA, we consolidate their assets, liabilities and results of operations. As of December 31, 2005, IBA had no outstanding debt and their principal asset was $8.7 million in cash. At December 31, 2005, IBA’s cash balance represents approximately 19% of our consolidated cash and short-term investment balance.

During 2004 and 2005, IBA placed minimal gas futures trades resulting in trading loss of $260,000 and a gain of $421,000, respectively. In 2004 and 2005, IBA incurred $656,000 and $2.8 million in general and administrative expenses, respectively, primarily attributed to salaries, travel and professional fees associated with its trading operations. IBA’s net operating gains for 2005 are classified in Interest and Other Income in the Consolidated Statement of Operations. As of December 31, 2005, IBA has no outstanding derivative contracts and has suspended its trading operations. During 2005, IBA had a low volume of trading activities and was unsuccessful in obtaining trading contracts overseas. At December 31, 2005, certain of our investment remains outstanding, but we are currently evaluating strategic alternatives regarding our remaining investment in IBA.

LIQUIDITY AND CAPITAL RESOURCES

Financial Condition


	As of December 31,
(Thousands of dollars)	2004		2005
Current ratio		2.54 to 1		4.13 to 1
Working capital	$	21,845	$	45,163
Total debt	$	8,578	$	12,500
Total cash and short term investments less debt	$	20,054	$	33,735
Stockholders’ equity	$	51,102	$	92,162
Total debt to equity		0.17 to 1		0.14 to 1

During 2005, we simplified our capital structure while seeking to increase the value of our investments in oil and gas assets. During the year ended December 31, 2005, we retired outstanding debt of approximately $8.6 million and $15 million in liquidation value of preferred stock. We also sold through numerous individual transactions certain of our holdings of common shares of Global in exchange for total cash consideration, net of fees, of approximately $40 million. These sales of shares, along with the exercise of Global stock options and warrants, decreased our direct equity interest in Global from approximately 85% at December 31, 2004 to approximately 34% at December 31, 2005. In October 2005, Global issued a total of $12.5 million principal amount of its Global Notes, which mature on October 30, 2012, in exchange for $12.5 million cash. The Global Notes are convertible into ordinary shares of Global at 305.8 UK pence per ordinary

share. Future possible conversions of the Global Notes into shares of Global’s common stock would dilute our ownership in Global.

If we reduce our equity ownership interest in Global, we may no longer be deemed to hold the legal power to control the operating policies and procedures of Global. As a result, we would no longer report Global’s operating results in our consolidated financial statements, but we would account for our investment in Global using the equity method of accounting. Under the equity method of accounting, our investment in Global will be presented on a single line in the Consolidated Balance Sheet. Likewise, our share of Global’s earnings will be reflected on a single line in the Consolidated Statement of Operations.

Some of these capital structure simplifications involved the conversion of certain convertible debt and preferred stock into shares of our common stock. As a result, our common shares outstanding increased from 220 million shares outstanding at December 31, 2004 to approximately 224 million shares outstanding at December 31, 2005.

As of December 31, 2005, on a consolidated basis, we had cash and short term investments of $46 million and working capital of $45 million (in both cases including $8 million cash held by Global). Working capital is the difference between current assets and current liabilities. We had approximately $92 million in shareholders’ equity at December 31, 2005.

We may continue to seek to raise additional financing through the issuance of debt, equity and convertible debt instruments, if needed, for utilization for acquisition and development opportunities as they arise. Such additional financing may include debt obligations, common stock or preferred stock issued by one or more of our consolidated companies.

Cash Flows

Net cash flow used in operating activities in 2005 was $5.1 million, as compared to net cash flow from operating activities of $12.4 million in 2004, primarily as a result of a $15 million increase in short-term investments and changes in timing of collections of accounts receivable and payments of trade payables offset by increased oil and gas revenues. Our consolidated cash on hand and short term investments at December 31, 2005 totaled approximately $46 million.

Net cash used in financing activities during 2005 totaled approximately $4.3 million and related primarily to the extinguishment of $3.3 million of our 4.25% Notes, $9.5 million associated with the redemption of preferred stock, repurchase of treasury shares for $3.8 million offset by the issuance of Global Notes for $11.8 million, net fees. Net cash provided by investing activities during 2005 totaled approximately $12 million and was primarily comprised of approximately $16 million in capital expenditures for GEM and $17 million in capital expenditures for Global offset by approximately $45.5 million received for the sales of certain portions of our investment in the common shares of Global. During 2004, our cash flow from operations increased to $12.4 million as compared to $6.2 million in 2003 from increased oil and gas revenues in 2004 primarily as a result of increased commodity pricing.

Obligations and Commitments

GEM Capital Commitments – With the effects of Hurricanes Katrina and Rita in the Gulf Coast and the increased demand for oilfield services and equipment currently being experienced by GEM, the timing and cost of such activities delayed GEM’s participation in budgeted drilling activities in 2005. GEM’s 2006 capital expenditure budget includes efforts to increase its oil and gas reserves and coalbed methane prospects through acquisition, exploitation and development drilling activities. We anticipate GEM capital expenditures will total approximately $17 million during 2006. GEM’s 2006 capital expenditure budget focuses on the onshore and offshore Gulf Coast regions of Texas and Louisiana as well as the phased delineation, pilot and development program for its coalbed methane prospects. The majority of this budgeted capital amount will be

used to participate in the drilling of 15 to 20 exploratory and development wells along the Texas and Louisiana Gulf Coast. GEM expects to fund the budgeted 2006 capital expenditures with available cash on hand and through projected cash flow from operations in 2006. Possible weakening commodity prices, a decline in drilling success or substantial delays on bringing on production from wells drilled could cause reduced projected 2006 expenditures. However, GEM’s planned North American capital expenditures for 2006 are discretionary and, as a result, will be curtailed if sufficient funds are not available. Such expenditure curtailments, however, could result in GEM losing certain prospect acreage or reducing its interest in future development projects

Global Capital Commitments – Global anticipates international capital expenditures during 2006 will total approximately $26 million to develop its crude oil assets in Middle America. The majority of Global’s 2006 capital expenditure plans are targeted for its Colombian operations in the Bolivar Field, the Rio Verde Field, and the El Miedo Field, as well as seismic work at Valle Lunar and Caracoli under its existing Association and Exploration and Production Contracts in Colombia. Approximately $8.8 million of these capital expenditures result from commitments under the terms of certain of the Association and Exploration and Production Contracts entered into between Global’s subsidiary Harken de Colombia, Ltd. and Ecopetrol or the ANH. These contracts require Global to perform certain activities in Colombia in accordance with a prescribed timetable. As of February 28, 2006, Global was in compliance with the requirements of each of the Association and Exploration and Production Contracts. Global’s discretionary capital expenditures will be curtailed if sufficient funds are not available. Such expenditure curtailments, however, could result in Global losing certain prospect acreage or reducing its interest in future development projects.

Global Senior Convertible Notes — In October 2005, Global issued to qualified investors a total of $12.5 million principal amount of its Convertible Notes due 2012 (the “Global Notes”) in exchange for $12.5 million cash. The Global Notes are unsecured and rank equal to all other present and future unsecured indebtedness of Global. Accrued interest with an annual coupon of 5% for the first three years, 6% from October 2008 to October 2010 and 7% thereafter is payable quarterly in arrears on the Notes. The Global Notes are convertible into ordinary shares in Global at 305.8 UK pence per ordinary share. If not converted or previously redeemed, the Global Notes will be redeemed at their principal amount on October 30, 2012.

As of December 31, 2005 all Global Notes remain outstanding, and the total principal amount of $12.5 million is classified as long-term debt in the Consolidated Balance Sheet. Global does not have any debt covenants pursuant to the terms of the Global Notes.

Deconsolidation of Global — As noted above, Harken could cease consolidating the assets, liabilities and results of operations of Global in the near future. Harken has no liability or obligation to fund any portion of Global’s capital expenditures or debt obligations.

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, 2005, GEM’s and Global’s asset retirement obligation liability totaled approximately $6.3 million.

We are currently involved in various lawsuits and other contingencies, which in our opinion, will not result in a material adverse effect upon our financial condition or operations taken as a whole.

Consolidated Contractual Obligations – The following table presents a summary of our consolidated contractual obligations and commercial commitments as of December 31, 2005.


	Payments Due by Period
	2006		2007		2008		2009-2010		Thereafter		Total
Contractual Obligations
Office Leases⁽¹⁾	$	709,000	$	371,000	$	277,000	$	482,000	$	262,000	$	2,101,000
Global Commitments⁽²⁾		9,013,000		6,525,000		2,000		—		—		15,540,000
GEM Commitments⁽³⁾		—		—		—		—		—		—
Global Notes ⁽⁴⁾		—		—		—		—		12,500,000		12,500,000
Global Notes Interest		724,000		625,000		646,000		1,521,000		1,604,000		5,120,000
Asset Retirement Obligation		81,000		116,000		174,000		1,756,000		4,174,000		6,301,000

Total Contractual Cash Obligations	$	10,527,000	$	7,637,000	$	1,099,000	$	3,759,000	$	18,540,000	$	41,562,000

⁽¹⁾	Amount net of sublease arrangements.

⁽²⁾

Global’s Commitments include capital commitments and lease commitments. Global’s 2006 capital expenditures are budgeted for $26 million. Approximately $8.8 million of these capital expenditures result from commitments under the terms of certain of its Association and Exploration and Production Contracts in Colombia. However, the remaining capital expenditures are discretionary and, as a result will be curtailed if sufficient funds are not available. Such expenditure curtailments, however, could result in Global losing certain prospect acreage or reducing its interest in future development projects.

⁽³⁾

GEM’s 2006 capital expenditures are budgeted for $17 million. However, these capital expenditures are discretionary and, as a result, will be curtailed if sufficient funds are not available. Such expenditure curtailments, however, could result in GEM losing certain prospect acreage or reducing its interest in future development projects.

⁽⁴⁾

Represents the outstanding principal amounts owing under the Global Notes as of December 31, 2005. These obligations are payable or redeemable for cash or with shares of Global’s common stock (See Note 9 – “Convertible Notes Payable” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 for further discussion).

In addition to the above commitments, during 2006 and afterward, government authorities under GEM’s Louisiana state leases and operators under other North American operators may also request GEM to participate in the cost of drilling additional exploratory and development wells. GEM may fund these future domestic expenditures at their 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. Our discretionary capital expenditures for 2006 will be curtailed if we do not have sufficient funds available. If we do not have sufficient funds or otherwise choose not to participate, we may experience a delay of future cash flows from proved undeveloped oil and gas reserves. Such expenditure curtailments could also result in us losing certain prospect acreage or reducing our interest in future development projects. As of December 31, 2005, 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, 2005, we were not involved in any unconsolidated SPE transactions.

Adequacy of Capital Sources and Liquidity

We believe that we have the ability to provide for our 2006 operational needs and the 2006 capital program through projected operating cash flow, cash on hand, and our ability to raise capital. Our operating cash flow would be adversely affected by declines in oil and natural gas prices, which can be volatile. Should projected operating cash flow decline, we may reduce our capital expenditures program and/or consider the issuance of debt, equity and convertible debt instruments, if needed, for utilization for the capital expenditure program.

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 would further 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

We are exposed to market risk from movements in commodity prices, interest rates and foreign currency exchange rates. As part of an overall risk management strategy, we use derivative financial instruments to manage and reduce risks associated with changes in commodity prices.

Commodity Price Risk — GEM is a producer of hydrocarbon commodities, including crude oil, condensate and natural gas. GEM uses oil and gas derivative financial instruments, primarily floors with maturities of 24 months or less, to mitigate its exposure to fluctuations in oil and gas commodity prices on future crude oil and natural gas production. We have evaluated the potential effect that near term changes in commodity prices would have had on the fair value of its commodity price risk sensitive financial instruments at December 31, 2005.

In September 2005, GEM purchased a crude oil floor contract with a strike price of $45.00 per barrel for a notional amount of 6,000 barrels per month over a period of the contract from January 1, 2006 to June 30, 2006. GEM did not designate this derivative as a cash flow hedge under SFAS 133. This crude oil floor contract is reflected in Prepaid Expenses and Other Current Assets in the Consolidated Balance Sheet at December 31, 2005 with a fair value of approximately $21,000.

In September 2005, GEM purchased a natural gas floor contract with a strike price of $6.00 per MMBTU for a notional amount of 70,000 MMBTUs per month over a period of the contract from January 1, 2006 to June 30, 2006. GEM did not designate this derivative as a cash flow hedge under SFAS 133. This natural gas floor contract is reflected in Prepaid Expenses and Other Current Assets in the Consolidated Balance Sheet at December 31, 2005 with a fair value of approximately $16,000.

Interest Rate Risk — Consistent with the prior year, we invest cash in interest-bearing temporary investments of high quality issuers. Due to the short time the investments are outstanding and their general liquidity, these instruments are classified as cash equivalents in the consolidated balance sheet and do not represent a significant interest rate risk to us. Consistent with the prior year, we consider our interest rate risk exposure related to long-term debt obligations to not be material. As of December 31, 2005 all of our financing obligations carry a fixed interest rate per annum. We have no open interest rate swap agreements.

Foreign Currency Exchange Rate Risk — Consistent with the prior year, Global conducts international business in Colombia and is subject to foreign currency exchange rate risk on cash flows related to sales, expenses and capital expenditures that are denominated in Colombian pesos. However, because predominately all material transactions in Global’s existing foreign operations are denominated in U.S. dollars, the U.S. dollar is the functional currency for all operations. Consistent with the prior year, exposure from transactions in currencies other than U.S. dollars is not considered material.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following financial statements appear on pages 65 through 116 in this Annual Report.


		Page
Reports of Independent Registered Public Accounting Firms		63

Consolidated Balance Sheets — December 31, 2004 and 2005		65

Consolidated Statements of Operations — Years ended December 31, 2003, 2004 and 2005		66

Consolidated Statements of Stockholders’ Equity — Years ended December 31, 2003, 2004 and 2005		67

Consolidated Statements of Cash Flows — Years ended December 31, 2003, 2004 and 2005		68

Notes to Consolidated Financial Statements		69

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of Harken Energy Corporation:

We have audited the accompanying consolidated statements of operations, stockholders’ equity and cash flows of Harken Energy Corporation for the year ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of its operations and its cash flows of Harken Energy Corporation for the year ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 6 to the consolidated financial statements, effective January 1, 2003, Harken Energy Corporation changed its method of accounting for asset retirement obligations.

BDO SEIDMAN, LLP

Houston, Texas

March 25, 2004

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Harken Energy Corporation

We have audited the consolidated balance sheets of Harken Energy Corporation as of December 31, 2005 and 2004, and the related consolidated statements of income, retained earnings and cash flows for each of the two years in the period ended December 31, 2005. 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 Harken Energy Corporation as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2005, 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), management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that Harken Energy Corporation maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria) and our report dated February 23, 2006 expressed an unqualified opinion thereon.

HEIN & ASSOCIATES LLP

Dallas, Texas

February

23, 2006

HARKEN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS


	December 31,
	2004			2005
Assets
Current Assets:
Cash and temporary investments	$	28,632,000		$	31,235,000
Short term investments		—			15,000,000
Accounts receivable, net		6,305,000			11,720,000
Prepaid expenses and other current assets		1,068,000			1,623,000

Total Current Assets		36,005,000			59,578,000
Property and Equipment, net		69,483,000			91,087,000
Other Assets, net		1,993,000			2,763,000

	$	107,481,000		$	153,428,000

Liabilities and Stockholders’ Equity
Current Liabilities:
Trade payables	$	4,648,000		$	6,803,000
Accrued liabilities and other		5,798,000			5,091,000
Revenues and royalties payable		2,047,000			2,521,000
Convertible notes payable		1,667,000			—

Total Current Liabilities		14,160,000			14,415,000
Convertible Notes Payable		6,911,000			—
Asset Retirement Obligation		5,954,000			6,301,000
Global Warrant Liability		14,858,000			—
Share Based Compensation Liability		6,120,000			10,687,000
Global Senior Convertible Notes Payable		—			12,500,000
Minority Interest in Consolidated Subsidiary		2,896,000			17,363,000

Total Liabilities		50,899,000			61,266,000
Commitments and Contingencies (Note 19)
Temporary Equity:
Series J Preferred Stock, $1.00 par value; $5,000,000 and $0 liquidation value, respectively; 65,000 shares authorized; 50,000 and 0 shares outstanding, respectively		4,675,000			—
Series L Preferred Stock, $1.00 par value; $1,000,000 and $0 liquidation value, respectively; 65,000 shares authorized; 10,000 and 0 shares outstanding, respectively		805,000			—
Stockholders’ Equity:
Series G1 Preferred Stock, $1.00 par value; $1,393,000 and $160,000 liquidation value, respectively; 700,000 shares authorized; 13,925 and 1,600 shares outstanding, respectively		14,000			2,000
Series G2 Preferred Stock, $1.00 par value; $250,000 and $100,000 liquidation value, respectively; 100,000 shares authorized; 2,500 and 1,000 shares outstanding respectively		2,000			1,000
Series G4 Preferred Stock, $1.00 par value; $7,752,000 and $0 liquidation value, respectively; 150,000 shares authorized, 77,517 and 0 shares outstanding, respectively		78,000			—
Series M Preferred Stock, $1.00 par value; $5,000,000 liquidation value 50,000 shares authorized; 50,000 shares outstanding		50,000			50,000
Common stock, $0.01 par value; 325,000,000 shares authorized; 219,615,485 and 223,575,732 shares issued, respectively		2,196,000			2,236,000
Additional paid-in capital		450,473,000			446,643,000
Accumulated deficit		(399,280,000	)		(356,889,000	)
Accumulated other comprehensive income		119,000			119,000
Treasury stock, at cost, 2,605,700 and 0 shares held, respectively		(2,550,000	)		—

Total Stockholders’ Equity		51,102,000			92,162,000

	$	107,481,000		$	153,428,000

The accompanying Notes to Consolidated Financial Statements are

an integral part of these Statements.

HARKEN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2003			2004			2005
Revenues and other:
Oil and gas operations	$	27,309,000		$	29,308,000		$	37,209,000
Interest and other income, net		(19,000	)		434,000			2,925,000

		27,290,000			29,742,000			40,134,000

Costs and Expenses:
Oil and gas operating expenses		9,469,000			7,964,000			10,663,000
General and administrative expenses (including share-based compensation expense of ($0; $5,866,000; $6,406,000, respectively)		9,210,000			15,088,000			20,108,000
Depreciation and amortization		8,941,000			10,713,000			11,369,000
Increase in Global warrant liability		7,000			14,207,000			13,297,000
Litigation and contingent liability settlements, net		1,125,000			—			—
Accretion expense		460,000			388,000			384,000
Interest expense and other, net		3,394,000			414,000			1,489,000

		32,606,000			48,774,000			57,310,000
Gain on exercise of Global warrants		—			—			28,341,000
Gains from extinguishments of debt		5,525,000			155,000			—
Gain on sale of subsidiary shares		—			—			32,452,000
Gain on investment		(488,000	)		990,000			—

Income/(loss) before income taxes	$	(279,000	)	$	(17,887,000	)	$	43,617,000
Income tax (expense)/benefit		184,000			(579,000	)		(733,000	)

Income/(loss) before cumulative effect of change in accounting principle and minority interest	$	(95,000	)	$	(18,466,000	)	$	42,884,000
Minority interest of subsidiary		(89,000	)		572,000			96,000

Income/(loss) before cumulative effect of change in accounting principle	$	(184,000	)	$	(17,894,000	)	$	42,980,000
Cumulative effect of change in accounting principle		(813,000	)		—			—

Net income/(loss)	$	(997,000	)	$	(17,894,000	)	$	42,980,000

Accrual of dividends related to preferred stock		(3,676,000	)		(2,884,000	)		(914,000	)
Exchange of preferred stock		—			(1,123,000	)		—
Payment of preferred stock dividends/redemption of preferred stock		6,805,000			3,492,000			327,000

Net income/(loss) attributed to common stock	$	2,132,000		$	(18,409,000	)	$	42,393,000

Basic net income/(loss) per common share:
Income/(loss) per common share before cumulative effect of change in accounting principle	$	0.03		$	(0.09	)	$	0.19
Cumulative effect of change in accounting principle		(0.01	)		—			—

Net income/(loss) per common share	$	0.02		$	(0.09	)	$	0.19

Weighted average common shares outstanding		112,694,654			201,702,235			219,369,798

Diluted net income/(loss) per common share:
Income/(loss) per common share before cumulative effect of change in accounting principle	$	(0.02	)	$	(0.09	)	$	0.18
Cumulative effect of change in accounting principle		(0.01	)		—			—

Net income/(loss) per common share	$	(0.03	)	$	(0.09	)	$	0.18

Weighted average common shares outstanding		112,790,327			201,702,235			243,634,909

The accompanying Notes to Consolidated Financial Statements are

an integral part of these Statements.

HARKEN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands)


	Preferred Stock														Common Stock			Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total
	G1			G2			G3			G4			M		Common Stock			Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total
Balance, December 31, 2002	$	403		$	93		$	—		$	—		$	—	$	254		$	388,703		$	(1,452	)	$	(383,004	)	$	134		$	5,131
Issuance of common stock, net of offering costs		—			—			—			—			—		729			8,226			—			—			—			8,955
Conversion/redemption of convertible notes		(17	)		—			—			—			—		817			28,727			—			—			—			29,527
Issuance of preferred stock		(32	)		—			93			—			—		—			5,883			—			—			—			5,944
Repurchase of preferred stock - related party		(5	)		—			—			—			—		—			(43	)		—			—			—			(48	)
Conversions of preferred stock		(24	)		(31	)		(16	)		—			—		45			321			—			—			—			295
Payment of preferred stock dividends		—			—			—			—			—		9			210			—			6,805			—			7,024
Accrual of preferred stock dividends		—			—			—			—			—		—			—			—			(3,676	)		—			(3,676	)
Comprehensive income:
Unrealized holding gain on available for sale investment		—			—			—			—			—		—			—			—			—			606
Net loss		—			—			—			—			—		—			—			—			(997	)		—
Total comprehensive loss		—			—			—			—			—		—			—			—			—			—			(391	)

Balance, December 31, 2003	$	325		$	62		$	77		$	—		$	—	$	1,854		$	432,027		$	(1,452	)	$	(380,872	)	$	740		$	52,761
Issuance of common stock, net of offering costs		—			—			—			—			—		36			3,189			—			—			—			3,225
Issuance of common stock to repay debt		—			—			—			—			—		19			1,072			—			—			—			1,091
Conversion/redemption of convertible notes		—			—			—			—			—		7			311			—			—			—			318
Issuance of preferred stock and common stock warrants		—			—			—			—			50		—			7,355			—			(1,885	)		—			5,520
Conversions of preferred stock to common stock		(310	)		(37	)		(77	)		—			—		273			4,210			—			(289	)		—			3,770
Conversions of preferred stock to preferred stock		(1	)		(23	)		—			78			—		—			1,851			—			338			—			2,243
Payment of preferred stock dividends		—			—			—			—			—		7			611			—			4,206			—			4,824
Accrual of preferred stock dividends		—			—			—			—			—		—			—			—			(2,884	)		—			(2,884	)
Issuance of stock of subsidiary		—			—			—			—			—		—			(153	)		—			—			—			(153	)
Repurchase of treasury stock		—			—			—			—			—		—			—			(1,098	)		—			—			(1,098	)
Comprehensive income:
Reclassification of holding gain on available for sale investment into earnings		—			—			—			—			—		—			—			—			—			(606	)
Reclassification of derivative fair value into earnings		—			—			—			—			—		—			—			—			—			(15	)
Net loss		—			—			—			—			—		—			—			—			(17,894	)		—
Total comprehensive loss		—			—			—			—			—		—			—			—			—			—			(18,515	)

Balance, December 31, 2004	$	14		$	2		$	—		$	78		$	50	$	2,196		$	450,473		$	(2,550	)	$	(399,280	)	$	119		$	51,102
Adjustment of preferred stock conversion price		—			—			—			—			—		—			4			—			(90	)		—			(86	)
Conversions of debt/equity to common stock		—			—			—			—			—		122			5,630			—			—			—			5,752
Conversions of warrants to common stock		—			—			—			—			—		6			359			—			—			—			365
Redemption of preferred stock for cash		(12	)		(1	)		—			(78	)		—		—			(4,935	)		—			182			—			(4,844	)
Accrual of preferred stock dividends		—			—			—			—			—		—			—			—			(914	)		—			(914	)
Issuance of preferred stock dividends		—			—			—			—			—		2			38			—			233			—			273
Options/Warrants exercised for common stock		—			—			—			—			—		—			1,309			—			—			—			1,309
Treasury stock repurchase		—			—			—			—			—		—			—			(3,775	)		—			—			(3,775	)
Treasury stock cancellation		—			—			—			—			—		(90	)		(6,235	)		6,325			—			—			—
Comprehensive income:								—
Net income		—			—			—			—			—		—			—			—			42,980			—
Total comprehensive income																															42,980

Balance, December 31, 2005	$	2		$	1		$	—		$	—		$	50	$	2,236		$	446,643		$	—		$	(356,889	)	$	119		$	92,162

The accompanying Notes to Consolidated Financial Statements

are an integral part of these Statements.

HARKEN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2003			2004			2005
Cash flows from operating activities:
Net income / (loss)	$	(997,000	)	$	(17,894,000	)	$	42,980,000
Adjustments to reconcile net income / (loss) to net cash used in operating activities:
Depreciation and amortization		8,941,000			10,713,000			11,369,000
Accretion of asset retirement obligation		460,000			388,000			384,000
Gain on extinguishment of notes		(5,525,000	)		(155,000	)		—
Gain on investment		488,000			(990,000	)		—
Amortization of issuance costs		1,641,000			162,000			157,000
Share-based compensation		—			5,866,000			6,406,000
Increase in Global warrant liability		7,000			14,207,000			13,297,000
Gain on exercise of Global warrants		—			—			(28,341,000	)
Gain on sale of subsidiary shares		—			—			(32,452,000	)
Minority interest		89,000			(572,000	)		(96,000	)
Litigation and contingent liability settlements, net		1,125,000			—			—
Cumulative effect of change in accounting principle		813,000			—			—
Other		—			121,000			(1,177,000	)
Change in assets and liabilities:
Increase in short-term investments		—			—			(15,000,000	)
Decrease (increase) in accounts receivable and other		835,000			(4,124,000	)		(4,945,000	)
Increase (decrease) in trade payables and other		(1,643,000	)		4,656,000			2,321,000

Net cash provided by (used in) operating activities		6,234,000			12,378,000			(5,097,000	)

Cash flows from investing activities:
Net proceeds from sales of assets		7,315,000			(23,000	)		131,000
Capital expenditures		(7,947,000	)		(17,767,000	)		(33,630,000	)
Sale of shares in subsidiary		—			—			45,476,000
Sale of investment		—			1,592,000			—

Net cash provided by (used in) investing activities		(632,000	)		(16,198,000	)		11,977,000

Cash flows from financing activities:
Proceeds from issuances of long-term debt, net of issuance costs		4,791,000			4,893,000			(63,000	)
Proceeds from issuances of long-term debt by subsidiary, net of issuance costs		—			—			11,796,000
Proceeds from issuances of common stock, net of issuance costs		4,319,000			3,225,000			365,000
Proceeds from issuances of subsidiary common stock, net of issuance costs		—			—			581,000
Proceeds from issuances of preferred stock, net of issuance costs		5,847,000			16,144,000			—
Proceeds from issuances of European Notes, net of issuance costs		2,997,000			—			—
Repayments of debt, convertible notes and long-term obligations		(17,702,000	)		(2,489,000	)		(3,333,000	)
Payments of preferred dividends		—			(396,000	)		(381,000	)
Purchase of preferred stock		(58,000	)		—			(9,467,000	)
Treasury shares purchased		—			(1,098,000	)		(3,775,000	)

Net cash provided by (used in) financing activities Net cash provided by (used in) financing activities		194,000			20,279,000			(4,277,000	)

Net change in cash and temporary investments		5,796,000			16,459,000			2,603,000
Cash and temporary investments at beginning of period		6,377,000			12,173,000			28,632,000

Cash and temporary investments at end of period	$	12,173,000		$	28,632,000		$	31,235,000

The accompanying Notes to Consolidated Financial Statements

are an integral part of these Statements.

HARKEN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Harken Energy Corporation (Harken) (a Delaware Corporation) is an independent oil and gas exploration, exploitation, development and production company. Harken’s domestic operations are conducted through its wholly-owned subsidiary, Gulf Energy Management Company (“GEM”). GEM’s operations consist of exploration, exploitation, development, production and acquisition efforts in the United States, principally in the onshore and offshore Gulf Coast regions of South Texas and Louisiana, as well as coal bed methane exploration and development activities in Indiana and Ohio. Harken’s international crude oil exploration and production operations are conducted through its approximately 34% ownership interest (as of December 31, 2005) in Global Energy Development PLC (“Global”) . Global has activities in Colombia, Panama and Peru.

Harken was also engaged in minimal energy trading through its investment in International Business Associates (“IBA”), which focused primarily on trading energy futures or other energy based contracts, principally in the United States. During the year ended December 31, 2005, IBA had a low volume of trading activities and was unsuccessful in obtaining trading contracts overseas. See Note 4 – Investment in International Business Associates, Ltd. for further discussion.

Principles of Consolidation and Presentation - The Consolidated Financial Statements include the accounts of Harken and all of the companies that Harken through, its direct or indirect ownership, is provided the ability to control the operating policies and procedures. All significant intercompany balances and transactions have been eliminated. See Note 8 - Changes in Harken’s Ownership in Global and Note 4 - Investment in International Business Associates, Ltd. for further discussion.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and gas reserves which, as described in Note 5 – Oil and Gas Properties, have a material impact on the carrying value of oil and gas property. Actual results could differ from those estimates and such differences could be material. Certain prior year amounts have been reclassified to conform with the 2005 presentation.

Statement of Cash Flows - For purposes of the Consolidated Statements of Cash Flows, Harken considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Harken paid cash for interest in the amounts of $1,769,000, $219,000 and $197,000 during 2003, 2004 and 2005, respectively. All significant non-cash investing and financing activities are discussed in Notes 2 – Mergers, Acquisitions and Dispositions, Note 9 – Convertible Notes Payable and Note 11 – Stockholders’ Equity.

Compensating Balance Arrangements - Global, under its wholly owned subsidiary, HDC, is required to post with ANH formal letters of credit securing performance of current contractual exploration obligations. The formal letters of credit mandate HDC to maintain cash balances on deposit with the designated bank. If cash balances are withdrawn from the bank, then the letters of credit can be subject to forfeiture. At December 31, 2005, HDC had on deposit cash balances equal to $548,000 as collateral for these letters of credit.

Concentrations of Credit Risk - Although Harken’s cash and temporary investments and accounts receivable are exposed to potential credit loss, Harken does not believe such risk to be significant. Cash and temporary investments includes investments in certificates of deposit and money markets, placed with highly rated

financial institutions. Most of Harken’s accounts receivable are from a broad and diverse group of industry partners, many of which are major oil and gas companies and do not in total represent a significant credit risk.

Allowance for Doubtful Accounts - Accounts receivable are customer obligations due under normal trade terms. GEM and Global sell their oil and gas production to companies involved in the transportation and refining of crude oil and natural gas. GEM and Global perform continuing credit evaluations of their customers’ financial condition and although GEM and Global generally do not require collateral, letters of credit may be required from their customers in certain circumstances.

Senior management reviews accounts receivable to determine if any receivables will potentially be uncollectible. Harken includes any accounts receivable balances that are determined to be uncollectible, along with a general reserve, in the overall allowance for doubtful accounts. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. Based on the information available, Harken believes the allowance for doubtful accounts as of December 31, 2005 is adequate. However, actual write-offs could exceed the recorded allowance.

Property and Equipment - GEM and Global follow the full cost accounting method to account for the costs incurred in the acquisition, exploration, exploitation, development and production of oil and gas reserves. Production facilities are depreciated on a units-of-production method. Other property and equipment is depreciated on the straight-line method over the estimated useful lives of each asset, which range from four to twenty years.

Other Assets - Harken includes in other assets certain issuance costs associated with its debt instruments, as well as the cost of oilfield material and equipment inventory, and prepaid drilling costs. At December 31, 2004, other assets included $473,000 of oilfield material and equipment inventory and $1,010,000 of prepaid drilling costs. At December 31, 2005, other assets included debt issuance costs of $689,000, net of $15,000 of accumulated amortization, $445,000 of oilfield material and equipment inventory, and $1,629,000 of prepaid drilling costs and other. Debt issuance costs are amortized over the term of the associated debt instrument.

Capitalization of Interest - Harken capitalizes interest on certain oil and gas exploration and development costs which are classified as unevaluated costs, or which have not yet begun production. During 2003, Harken recorded interest expense of $3,312,000, net of $103,000 of interest which was capitalized to oil and gas properties. During 2004, Harken recorded interest expense of $402,000, net of $82,000 of interest which was capitalized to oil and gas properties. During 2005, Harken recorded interest expense of $472,000, net of $40,000 of interest which was capitalized to oil and gas properties.

General and Administrative Expenses - Harken reflects general and administrative expenses net of operator overhead charges and other amounts billed to joint interest owners. General and administrative expenses are net of $241,000, $238,000 and $203,000 for such amounts during 2003, 2004 and 2005, respectively. Share-based compensation expense is classified with general and administrative expenses. See Note 12 – Stock Option Plan for further discussion on share-based compensation expense.

Provision for Asset Impairments - Assets that are used in Harken’s operations, and are not held for resale, are carried at cost, less accumulated depreciation and amortization. Harken reviews its long-lived assets, other than its investment in oil and gas properties, whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When evidence indicates that operations will not produce sufficient cash flows to cover the carrying amount of the related asset, and when the carrying amount of the related asset cannot be realized through sale, a permanent impairment is recorded and the asset value is written down to fair value.

Revenue Recognition - GEM and Global use the sales method of accounting for natural gas and crude oil revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. The volumes sold may differ from the volumes to which GEM and Global are entitled based on their interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. There are no significant balancing arrangements or obligations related to Global’s and GEM’s operations.

Commodity Derivative Financial Instruments - GEM has entered into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its natural gas and crude oil production and cash flows. GEM has accounted for certain of its derivatives in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) which requires recognition of all derivatives as assets or liabilities at fair value. For derivatives designated as hedges of forecasted cash flows, GEM records the effective portion of the gain or loss on the derivative as a component of Other Comprehensive Income and reclassifies those amounts to earnings in the period the hedged cash flow affects earnings. GEM records in earnings any gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item. For derivative instruments not designated as hedging instruments, GEM records the entire change in fair value of the derivative instrument to earnings in Interest expense and other in the Consolidated Statement of Operations. For further discussion, see Note 15 – Derivative Instruments.

Direct Sales of Global Common Shares - During the year ended December 31, 2005, Harken sold certain of its common shares of Global through numerous individual transactions in the market to various purchasers throughout the year in exchange for total cash consideration, net of fees, of approximately $40 million. In accordance with Accounting Principles Board (“APB”) Opinion No. 18 (As Amended), “The Equity Method of Accounting for Investments in Common Stock” (“APB 18”) and as a result of the sale of these shares during 2005, Harken recognized total gains of approximately $32.5 million equal to the amount by which the net proceeds of each transaction exceeded Harken’s proportionate carrying value of Global as of the date of each transaction.

Accounting for Global Warrants - As part of Global’s issuance of warrants to its shareholders in August 2002, Global issued to its minority shareholders (“Global Warrants held by Minority Interest Owners”), warrants to purchase shares of Global stock at 60 UK pence per share. Also in 2002, Harken issued to Lyford Investments Enterprises (“Lyford”) warrants (the “Lyford Warrants”) to purchase up to 7,000,000 shares of Global held by Harken at a price of 50 UK pence per share. See Note 8 – Changes in Harken’s Ownership in Global for further discussion of these Global warrants.

Harken accounted for the Lyford Warrants and the Global Warrants held by Minority Interest Owners as derivatives in accordance with SFAS 133 and EITF 00-6, “Accounting for Freestanding Derivative Financial Instruments Indexed to, and Potentially Settled in, the Stock of a Consolidated Subsidiary” (“EITF 00-6”). Harken recorded the estimated fair value of the warrants as a liability at issuance and adjusted the liability to estimated fair value each period with any changes in value reflected in earnings.

The fair value of the warrants was calculated by a third-party firm based primarily on the underlying market price of Global’s common stock price. As a result of increases in Global’s common share price in 2004 and 2005 through the date of exercise of the warrants, Harken recorded losses of approximately $14 million and $13 million for the years ended December 31, 2004 and 2005, respectively, for the change in the fair value of these warrants.

In September 2005, upon exercise of the Lyford Warrants, and in accordance with EITF 00-6, Harken recognized a Gain on Exercise of Global Warrants of approximately $28 million in the Consolidated Statement of Operations representing the difference between Harken’s proportionate net book value of its shares in Global as of the date of exercise and the cash proceeds received plus the fair value of the Lyford Warrant Liability immediately prior to exercise.

Unlike the Lyford Warrants (which were a direct sale of Global shares held by Harken to Lyford), upon exercise of the Global Warrants held by Minority Interest Owners, the minority shareholders received their shares of Global through a share issuance directly from Global upon exercise of their warrants. Therefore Harken did not reflect any gain or loss on the exercise of Global Warrants held by Minority Interest Owners for the years ended December 31, 2004 and 2005.

Stock Options - Harken and Global account for their stock option plans in accordance with APB Opinion 25, “Accounting for Stock Issued to Employees” (“APB 25”) and related Interpretations. Under APB 25, if the exercise price of employee stock options equals or exceeds the market price of the underlying stock on the date of grant, generally, no compensation expense is recognized. In July 2004, the board of directors of Global modified the Global Share plan to include a cashless exercise feature which changed the plan from a fixed plan to a variable plan. Accordingly, Global recorded share-based compensation expense attributable to the vested options effective as of the date of the modification. The compensation expense was equal to the difference between the exercise price of the options and Global’s stock price on the date of modification. Compensation costs relating to the unvested options are recorded over the remaining vesting period. Additionally, since the Global share price was greater than the option exercise price, variable plan accounting requires compensation expense (or benefit) to be recognized for subsequent changes in Global’s share price for all options outstanding under the plan. During 2004 and 2005, Global recognized approximately $5.9 million and $6.4 million, respectively, of Share-based compensation expense relating to the variable Global share plan in the Consolidated Statement of Operations. See Note 12 – Stock Option Plan for further discussion of Global’s share-based employee compensation.

SFAS No. 123, “Accounting for Stock-Based Compensation,” (“SFAS 123”) requires Harken to provide pro forma information regarding net income / (loss) as if the compensation cost for Harken’s and Global’s stock option plans had been determined in accordance with the fair value based method prescribed in SFAS 123. In 2004 and after duly authorized action by Harken’s Board of Directors, Harken’s stock option plans were terminated. At December 31, 2004 and 2005, all of Harken’s previously issued and / or outstanding employee stock options had expired or were previously voluntarily surrendered.

To provide the required pro forma information, Harken estimates the fair value of each stock option at the grant date by using the Black-Scholes option-pricing model with the following weighted-average assumptions for the years ended December 31, 2003, 2004 and 2005, respectively: risk-free interest rates of 5.0%, 3.5% and 4.75%; dividend yields of 0%; volatility factors of the expected market price of Global common stock of 28%, 28.93%, and 45.09%; and a weighted-average expected life of the options of 10 years. For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options’ vesting period. All of the pro-forma information for the years ended December 31, 2004 and 2005 reflects the effects of Global’s employee stock-based compensation plans under the fair value method of SFAS 123.

The following table represents the pro forma effect on net income / (loss) and income / (loss) per share as if Harken and Global had applied the fair value based method and recognition provisions of SFAS 123 to stock-based employee compensation.


	Year Ended December 31,
	2003			2004			2005
	(in thousands, except for per share data)
Net income / (loss) attributed to common stock, as reported	$	2,132		$	(18,409	)	$	42,393
Add: Total share-based employee compensation recognized under intrinsic value based method for all amounts		—			5,866			6,406
Less: Related minority interest and foreign currency loss		—			(642	)		(3,583	)
Less: Total stock-based employee compensation determined under fair value based method for all amounts		(353	)		(369	)		(275	)

Pro forma net income / (loss) attributed to common stock	$	1,779		$	(13,554	)	$	44,941
Basic net income / (loss) per share, as reported	$	0.02		$	(0.09	)		0.19
Pro forma basic income / (loss) per share	$	0.02		$	(0.07	)		0.20
Diluted net income / (loss) per share, as reported	$	(0.03	)	$	(0.09	)		0.18
Pro forma diluted income / (loss) per share	$	(0.03	)	$	(0.07	)		0.18

Sales of Oil and Gas Properties - GEM and Global account for sales of oil and gas properties as adjustments of capitalized costs to the full cost pool, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the full cost pool.

Consolidation of Variable Interest Entity - In September 2004, Harken invested $12.5 million in IBA. See Note 4 – Investment in International Business Associates, Ltd., for further discussion of IBA. In exchange for Harken’s $12.5 million cash investment, Harken received 12,500 shares of nonvoting preferred stock along with warrants to purchase 48% of IBA’s common stock for a nominal amount. Harken also held 3 of 5 seats on IBA’s Board of Directors at December 31, 2005.

Harken’s investment in IBA is a variable interest, as defined in Financial Accounting Standards Board Interpretation (“FIN”) No. 46 (Revised December 2003) “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (“FIN 46R”). FIN 46R requires the consolidation of a variable interest entity (“VIE”), as defined, if a company will absorb a majority of the VIE’s expected losses, receive a majority of the VIE’s expected residual returns, or both. Harken has determined that the investment in IBA meets the requirements of FIN 46R, and Harken is the primary beneficiary, as defined. Therefore, Harken has consolidated the assets, liabilities and results of operations of IBA as of December 31, 2004 and 2005 and for the period from September 10, 2004, the closing date of the transaction, through December 31, 2004 and the year ended December 31, 2005.

Recent Accounting Pronouncements - On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment”, (“SFAS 123 (R)”), that will require compensation costs related to share-based payment transactions (e.g., issuance of stock options and restricted stock) to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, awards required to be classified as

liabilities must be remeasured each reporting period. Compensation costs will be recognized over the period that an employee provides service in exchange for the award. SFAS 123 R replaces SFAS 123 and APB 25. For Harken, SFAS 123 R, as amended by SEC release 34-51558, is effective for the first annual reporting period beginning after June 15, 2005 and is applicable only to new or unvested awards or awards that have been modified, repurchased or cancelled after the effective date. Harken is evaluating the impact this new Standard will have on the Company.

On March 29, 2005, the SEC released Staff Accounting Bulletin 107 (“SAB 107”) providing additional guidance in applying the provisions of SFAS 123R. SAB 107 should be applied when adopting SFAS 123R and addresses a wide range of issues, focusing on valuation methodologies and the selection of assumptions. In addition, SAB 107 addresses the interaction of SFAS 123R with existing SEC guidance.

On February 16, 2006, the FASB issued Statement 155, “Accounting for Certain Hybrid Instruments - an amendment of FASB Statements No. 133 and 140.” The statement amends Statement 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative, provides additional guidance on the applicability of Statement 133 and 140 to certain financial instruments and subordinated concentrations of credit risk. The new standard is effective for the first fiscal year that ends after September 15, 2006. Harken is currently evaluating the impact this new Standard will have on the Company.

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MERGERS, ACQUISITIONS AND DISPOSITIONS

Indiana Posey Prospect Acquisition - In March 2005 GEM entered into an exploration and development agreement (the “Indiana Posey Agreement”) with Indiana Posey L.P., a Texas limited partnership, for the joint exploration and development of coalbed methane within the Posey Prospect area consisting of approximately 400,000 acres in Posey, Gibson and Vanderburgh counties of Indiana. The Indiana Posey Agreement designates a third party, Ute Oil Company, d/b/a A.C.T. Operating Company, a Texas corporation, as the Operator to conduct the operations detailed in the Indiana Posey Agreement and in the corresponding joint operating agreement.

The Indiana Posey Agreement had an effective date of March 1, 2005 and provides for the project to be conducted in three separate phases. GEM’s obligations under the Indiana Posey Agreement include funding 100% of the initial $7.5 million in costs to carry out the joint exploration and development of the project in return for a non-operating 65% interest in the Posey Prospect Area. The Indiana Posey Agreement also provides that GEM is to receive a 82.5% net revenue interest.

In Phase I of the Indiana Posey Agreement, GEM was required to pay $500,000, as an initial prospect payment, to Indiana Posey L.P., which was paid immediately upon signing of the Indiana Posey Agreement. GEM was also required to fund an Authority for Expenditure (“AFE”) in the amount of $288,000 to cover work to be performed during Phase I within 10 days of receipt of request from Indiana Posey L.P. In May 2005, GEM elected to expand the scope of the Phase I coring work, and funded $446,000 in connection with the drilling and evaluation of five core samples for Phase I.

In September 2005, after the submission of a Phase I core evaluation report by the Indiana Posey L.P., GEM elected to proceed and fund pilot well drilling under Phase II of the Indiana Posey Agreement. With regard to the Phase II election, GEM made an additional $500,000 prospect acquisition payment and will fund a $1,280,000 AFE in 2006 for the first of two pilot well projects on the Indiana Prospect. Subsequently, a second pilot well project may be initiated by the funding of a second AFE by GEM for approximately $1,104,000. GEM expects the drilling of the pilot wells will commence in the first quarter of 2006. Additional pilot wells contemplated by the Agreement will depend on the timing and availability of the Operator.

Should GEM elect to proceed with Phase III, GEM will be required to pay the third and final prospect payment of $500,000 to Indiana Posey L.P. and to fund the related AFE costs. Phase III would continue until such time as GEM incurs $7.5 million in the carried interest amount costs as defined in the Indiana Posey Agreement. Subsequent to Phase III, GEM and Indiana Posey L.P.’s development of the project shall be governed by a joint operating agreement.

Ohio Cumberland Prospect Acquisition - In March 2005, GEM entered into an exploration and development agreement (the “Ohio Cumberland Agreement”) with Ohio Cumberland, L.P., a Texas limited partnership, for the joint exploration and development of coalbed methane within the Cumberland Prospect Area consisting of approximately 400,000 acres in Guernsey, Noble, Muskingum, Washington and Morgan Counties of Ohio. The Ohio Cumberland Agreement designates a third party, Ute Oil Company, d/b/a A.C.T. Operating Company, a Texas corporation, as the Operator to conduct the operations detailed in the Ohio Cumberland Agreement and in the corresponding joint operating agreement.

The Ohio Cumberland Agreement had an effective date of April 1, 2005 and provides for the project to be conducted in three separate phases. GEM’s obligations under the Ohio Cumberland Agreement include funding 100% of the initial $7.5 million in costs to carry out the joint exploration and development of the project in return for a non-operating 65% interest in the Cumberland Prospect Area. The Ohio Cumberland Agreement also provides that GEM is to receive a 82.5% net revenue interest.

In Phase I of the Ohio Cumberland Agreement, GEM was required to pay $500,000, as an initial prospect payment, to Ohio Cumberland, L.P. which was paid on the effective date of the agreement. GEM also funded an AFE in the amount of $284,000 in July 2005 to cover the initial coring phase for this prospect. Currently, the coring phase is continuing and expected to be completed (including the core evaluation report due from Ohio Cumberland, L.P. and the Operator) late in the first quarter of 2006. Currently, the core samples are continuing to be analyzed. Depending on the final evaluation, including the core evaluation report due from the Technical Consultant and the Operator), GEM may elect to proceed and fund a Phase II of pilot wells on this prospect.

Should GEM elect to proceed with Phase II, GEM will be required to pay $500,000, as a second prospect payment, to Ohio Cumberland, L.P. within 10 days of its election to proceed and to fund an AFE, in the amount of $1,277,500, divided into two payments: one for $970,150 to cover the first pilot project and the second payment in the amount of $307,350 for the facilities. Subsequently, GEM is to fund a separate AFE (in the amount of $1,104,000, divided into two payments: $454,000 for the facilities and $650,000 for the 5 pilot wells) within 10 days after spudding the last well on the first pilot project.

Should GEM elect to proceed with Phase III, GEM will be is required to pay the third and final prospect payment of $500,000 to Ohio Cumberland, L.P. and to fund the related AFE costs. Phase III would continue until such time as GEM incurs $7.5 million in the carried interest amount costs as defined in the Agreement. Subsequent to Phase III, GEM and Ohio Cumberland, L.P.’s development of the project shall be governed by a joint operating agreement.

In November 2005, GEM also executed an agreement with Ohio Triangle, L.P. wherein GEM will purchase a 65% non-operating working interest in additional coalbed methane acreage located in Ohio. GEM’s current plans are to drill three core holes commencing by the end of the first quarter 2006 in Phase I. Based on favorable results in Phase I, GEM has the option to purchase approximately 20,000 acres of coal rights and initiate a Pilot Program in Phase II. Following a review of Phase II results, GEM has the option to begin a development program during which GEM would provide 100% funding up to total expenditures of $7.5 million.

Sale of Certain Panhandle Oil and Gas Properties - In 2003, GEM sold the majority of its oil and gas properties located in the Panhandle region of Texas for a gross sales price of approximately $7.0 million,

subject to certain adjustments. GEM considered the Panhandle assets as non-core domestic assets since the majority of Harken’s domestic reserves and productions were located along the Gulf Coast regions of Texas and Louisiana. In December 2003, GEM used approximately $4.0 million of the Panhandle asset sales proceeds to repay all outstanding principal and interest under and to terminate its credit facility with Guaranty Bank FSB.

The sale of the Panhandle oil and gas properties did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the full cost pool. No gain or loss was recognized on this transaction as the entire amount of the proceeds (including any subsequent purchase price adjustments), was recorded as a reduction to the domestic full cost pool. During the year ended December 31, 2004, Harken paid approximately $23,000 in net purchase price adjustments related to the sale of these Panhandle oil and gas properties. This amount is reflected as a reduction of proceeds from sales of assets in the Consolidated Statement of Cash Flows for the year ended December 31, 2004. During the year ended December 31, 2005, Harken received, net purchase price adjustments of approximately $9,000 in net purchase price adjustments related to the sale of these Panhandle oil and gas properties. This amount is reflected as an increase in proceeds from sales of assets in the Consolidated Statement of Cash Flows for the year ended December 31, 2005.

Pro Forma Information - The following unaudited pro forma combined condensed statement of operations for the year ended December 31, 2003 gives effect to the sale of the Panhandle oil and gas properties as if it had been consummated at January 1, 2003. See information above for a discussion of this transaction. The above transaction was accounted for in the full cost pool, and accordingly, did not generate any gain or loss. The unaudited pro forma data is presented for illustrative purposes only and is not necessarily indicative of the operating results that would have occurred had the transactions been consummated at the dates indicated, nor are they indicative of future operating results. The unaudited pro forma data does not reflect the effect of the interest income earned from proceeds from asset sales.

Pro Forma Condensed Statement of Operations

For the Year Ended December 31, 2003

(unaudited)

(in thousands, except per share amounts)


	Harken Actual			Pro Forma Adjustments			Pro Forma
Oil and gas revenue	$	27,309		$	(4,523	) ⁽¹⁾	$	22,786
Other revenues		(19	)		—			(19	)

Total Revenues		27,290			(4,523	)		22,767

Oil and gas operating expenses		9,469			(2,275	) ⁽¹⁾		7,194
General and administrative expenses, net		9,210			—			9,210
Depreciation and amortization		8,941			1,355	⁽²⁾		10,296
Increase in Global warrant liability		7			—			7
Litigation and contingent liability settlements, net		1,125			—			1,125
Accretion expense		460			—			460
Interest expense and other, net		3,394			—			3,394

Total Expenses		32,606			(920	)		31,686

Gains from repurchases/exchanges of convertible notes		5,525			—			5,525

(Loss)/gain on investment		(488	)		—			(488	)

Income tax benefit		184			—			184

Loss before minority interest		(95	)		(3,603	)		(3,698	)
Minority interest in income of subsidiary		(89	)		—			(89	)
Cumulative effect of change in accounting principle		(813	)		—			(813	)

Net loss	$	(997	)	$	(3,603	)	$	(4,600	)
Preferred stock dividends		(3,676	)		—			(3,676	)
Payment of preferred stock dividend liability in common shares		6,805			—			6,805

Net income / (loss) attributed to common stock	$	2,132		$	(3,603	)	$	(1,471	)

Basic income / (loss) per common share	$	0.02					$	(0.01	)

Weighted average common shares outstanding		112,694,654						112,694,654

Diluted income / (loss) per common share	$	(0.03	)				$	(0.01	)

Weighted average common shares outstanding		112,790,327						112,694,654

Pro Forma Adjustments - Pro Forma Condensed Statement of Operations - Year Ended December 31, 2003

⁽¹⁾	Pro forma entry to adjust oil and gas revenues and operating expenses to reflect the sale of the Panhandle Properties.

⁽²⁾	Pro forma entry to reflect the increase in depreciation and amortization rate associated with the sale of the Panhandle Properties and the associated proved reserve volumes.

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INVESTMENTS

Included within cash, temporary investments and short term investments at December 31, 2004 and 2005 are certain investments in money market accounts and auction bonds. The cost of such investments totaled $9,715,000 and $32,600,000 (including $15,000,000 classified as short term investments) as of December 31, 2004 and 2005, respectively, with cost approximating fair value. The short-term investments consist of auction bonds at December 31, 2005. These instruments are classified as trading securities and recorded at fair value. Any unrealized gain or loss is recorded in operations.

In February 2004, Harken sold an investment that had been accounted for as an available for sale security in accordance with SFAS No. 115, “Accounting for Certain Investment in Debt and Equity Transactions” for cash proceeds of approximately $1.6 million and recognized a Gain on investment of $990,000 in the Consolidated Statement of Operations for the year ended December 31, 2004. Approximately $987,000 of the gain on sale of investment in 2004 was a recovery of Harken’s previously recognized losses in 2002 and 2003.

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INVESTMENT IN INTERNATIONAL BUSINESS ASSOCIATES, LTD.

In September 2004, Harken invested $12.5 million in a start-up energy trading company, IBA, in exchange for 12,500 shares of nonvoting preferred stock along with warrants to purchase 48% of IBA’s common stock for a nominal amount. No dividends will be paid on the preferred shares. Under the terms of the agreements, on or about February 15 of each year, as long as any of the preferred stock remains outstanding and if the annual net income of IBA equals or exceeds $2,000,000, the preferred shares will be redeemed by IBA in cash at the liquidation value at an amount equal to 50% of IBA’s available cash flow in the preceding calendar year. Until the preferred shares are redeemed in full, Harken has the right to nominate the majority of the Board of Directors of IBA. At December 31, 2005, Harken held three of the five IBA Board of Directors positions. Harken’s preferred stock investment represented almost 100% of IBA’s initial working capital as of December 31, 2004 and 2005.

In February 2006, IBA redeemed 7,500 shares of Harken’s IBA convertible preferred shares along with Harken’s 24 shares of IBA common stock in exchange of cash consideration of $7.5 million. Harken is currently pursuing strategic alternatives regarding our remaining investment in IBA.

During the years ended December 31, 2004 and 2005, IBA engaged in minimal trading of domestic natural gas future contracts. IBA’s derivative trading instruments are accounted for under SFAS 133. These instruments are recorded by IBA on a trade-date basis and are adjusted daily to current market value with gains and losses recognized in Interest and other income in the Consolidated Statement of Operations. IBA recognized net trading loss of $260,000 and net trading gain $421,000 for the years ended December 31, 2004 and 2005 respectively.

In accordance with FIN 46R, Harken has consolidated the assets, liabilities and results of operations of IBA as of December 31, 2004 and 2005 and for the period from September 10, the closing date of the transaction, through December 31, 2004 and the year ended December 31, 2005. IBA’s net loss included in the Consolidated Statement of Operations for the periods ended December 31, 2004 and 2005 was approximately $1 million and $3 million, respectively. Due to IBA’s low domestic trading volume in 2005, as of December 31, 2005, IBA has suspended its domestic trading activity and will focus on obtaining natural gas future contracts overseas.

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OIL AND GAS PROPERTIES

GEM and Global follow the full cost accounting method to account for the costs incurred in the acquisition, exploration, exploitation, development and production of oil and gas reserves. Under this method, all costs, including internal costs, directly related to acquisition, exploration, exploitation and development activities, are capitalized as oil and gas property costs. GEM and Global capitalized $272,000, $821,000 and $695,000 of internal costs directly related to these activities in 2003, 2004 and 2005, respectively. Such costs include certain office and personnel costs of the exploration field offices and do not include any corporate overhead. GEM and Global also capitalize costs of dismantlement, restoration and abandonment as required under SFAS No. 143, “Accounting for Asset Retirement Obligations”, (“SFAS 143”). See Note 6 – Asset Retirement Obligations and Note 18—Oil and Gas Disclosures for further discussion.

The capitalized costs of oil and gas properties, excluding unevaluated properties, are amortized on a country-by-country basis using a unit-of-production method (equivalent physical units of six Mcf of gas to each barrel of oil) based on estimated proved recoverable oil and gas reserves. Such amortization of GEM’s domestic oil and gas properties was $1.47, $2.35 and 2.74 per equivalent Mcf produced during 2003, 2004 and 2005, respectively. Amortization of Global’s oil properties was $7.56, $7.02 and $9.69 per equivalent barrel of oil produced during 2003, 2004 and 2005, respectively. The evaluated costs of oil and gas properties, net of accumulated depreciation and amortization, at December 31, 2004 and 2005 include approximately $18.5 million and $30 million, respectively, related to Colombia. See Note 7 – Global’s Middle American Operations for a discussion of Colombian operations.

Amortization of unevaluated property costs begins when the properties become proved or their values become impaired. Harken assesses realizability of unevaluated properties on at least an annual basis or when there has been an indication that an impairment in value may have occurred, such as for a relinquishment of Global’s contract acreage. Impairment of unevaluated prospects is assessed based on management’s intention with regard to future exploration and development of individually significant properties and the ability to obtain funds to finance such exploration and development. GEM and Global anticipate its unevaluated property costs to remain as unevaluated for no longer than three years.

Under full cost accounting rules for each cost center, capitalized costs of evaluated oil and gas properties, including asset retirement costs, less accumulated amortization and related deferred income taxes, may not exceed an amount (the “cost ceiling”) equal to the sum of (a) the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current economic and operating conditions, discounted at 10%, plus (b) the cost of properties not being amortized, plus (c) the lower of cost or estimated fair value of any unproved properties included in the costs being amortized, less (d) any income tax effects related to differences between the book and tax basis of the properties involved. If capitalized costs exceed this limit, the excess is charged to earnings.

Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.

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ASSET RETIREMENT OBLIGATIONS

GEM and Global recognize the present value of asset retirement obligations beginning in the period in which they are incurred if a reasonable estimate of a fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.

A summary of GEM’s and Global’s assets with required asset retirement obligations as of December 31, 2005 is as follows:


Asset Category	Asset Retirement Obligation Liability		Estimated Life
North American oil and gas producing properties	$	2,904,000	2-55	years
North American facilities and other property		2,598,000	12-29	years
Colombian oil producing properties		799,000	4-23	years

	$	6,301,000

Global reflects no asset retirement obligation for its Colombian facilities as upon the expiration of the related Association Contract, the ownership of such facilities reverts to Empresa Colombiana de Petroleos (“Ecopetrol”).

The following table describes all changes to GEM’s and Global’s asset retirement obligation liability during the years ended December 31, 2004 and 2005.


	2004			2005
Asset retirement obligation at beginning of year	$	6,305,000		$	5,954,000
Additions during the year		192,000			114,000
Deletions during the year		(507,000	)		(151,000	)
Changes in estimates		(424,000	)		—
Accretion expense		388,000			384,000

Asset retirement obligation at end of year	$	5,954,000		$	6,301,000

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GLOBAL’S MIDDLE AMERICAN OPERATIONS

Harken’s Middle America are conducted through its holdings of common shares in Global. Global’s ordinary shares are listed for trading on the Alternative Investment Market of the London Stock Exchange (“AIM”). At December 31, 2005, Harken held approximately 34% of Global’s ordinary shares. As of December 31, 2005 the fair value of Harken’s investment in Global was approximately $51 million. During the year ended December 31, 2005, Harken’s ownership decreased significantly, as further described in Note 8 – Changes in Harken’s Ownership in Global.

Colombian Operations – Global’s Colombian operations are conducted through Harken de Colombia, Ltd., a wholly-owned subsidiary of Global, which holds three exclusive Colombian Association Contracts with Ecopetrol and four Exploration and Production Concession Contracts and one Technical Evaluation Agreement (“TEA”) with the National Hydrocarbons Agency of the Republic of Colombia (“ANH”).

Association Contracts - The Association Contracts include the Alcaravan Contract, awarded in 1992, the Bocachico Contract, awarded in 1994, and the Bolivar Contract, awarded in 1996. As of December 31, 2005, the Alcaravan Contract covers an area of approximately 24,000 acres in the Llanos Basin of Eastern Colombia, the Bocachico Contract covers approximately 54,600 acres in the Middle Magdalena Valley of

Central Colombia, and the Bolivar Contract covers an area of approximately 59,000 acres in the Northern Middle Magdalena Valley of Central Colombia. As of December 31, 2005, Global was in compliance with the requirements of each of the Alcaravan, Bocachico and Bolivar Association Contracts.

Under the terms of the Alcaravan, Bocachico and Bolivar Association Contracts, if, during the first six years of each contract, Global discovers one or more fields capable of producing oil or gas in quantities that are economically exploitable and Ecopetrol elects to participate in the development of the field, or if Global chooses to proceed with the development on a sole-risk basis, the term of that contract will be extended for a period of 22 years from the date of such election by Ecopetrol, subject to the entire term of the Association Contract being limited to 28 years. Upon an election by Ecopetrol to participate in the development of a field and upon commencement of production from that field, Ecopetrol would begin to reimburse Global for 50% of Global’s successful well costs expended up to the point of Ecopetrol’s participation plus, in the case of the Bolivar Contract, 50% of all seismic and dry well costs incurred prior to the point of Ecopetrol’s participation. Ecopetrol, on behalf of the Colombian government, receives a 20% royalty interest (5% to 25% royalty interest on the Cajaro #1 well, under the Alcaravan Contract, depending on production levels) from all production. For fields in which Ecopetrol participates, all production (after royalty payments) will be allocated 50% to Ecopetrol and 50% to Global until cumulative production from all fields (or the particular productive field under certain of the Association Contracts) in the Association Contract acreage reaches 60 million barrels of oil. After a declaration of Ecopetrol’s participation, Global and Ecopetrol would be responsible for all future development costs and operating expenses in direct proportion to their interest in production. For any fields in which Ecopetrol declines to participate, Global is entitled to receive Ecopetrol’s 50% share of production, after deduction of Ecopetrol’s royalty interest, until Global has recovered 200% of its costs, after which time Ecopetrol could elect to begin to receive 50% working interest share of production and costs. In 2001 and 2002, Global was notified by Ecopetrol that Global could proceed with the development and production of the Buturama, Palo Blanco and Rio Negro fields on a sole risk basis.

In 2004, Ecopetrol advised Global that it had elected to declare the Cajaro #1 well of the Alcaravan Association Contract commercial. Effective as of October 2004, Ecopetrol began receiving a 50% working interest share of production, after deduction of the Colombian government’s 8% royalty interest on the Cajaro #1 well. As a 50% working interest owner, Ecopetrol will be responsible for 50% of any future development costs and operating expenses associated with the Cajaro #1 commercial field attributable to the Alcaravan Contract Area. As of February 28, 2006, Global and Ecopetrol continue to negotiate the terms of Ecopetrol’s commerciality declaration, including the extent of the commercial area and the potential need for unitization of the Cajaro #1 commercial area and a portion of Global’s recently acquired Los Hatos Concession Contract which abuts the Alcaravan Contract area. As of December 31, 2005, Global has been reimbursed by Ecopetrol out of Ecopetrol’s share of production, net of royalties, for 50% of all seismic costs and direct exploratory well costs (including costs related to dry holes) incurred prior to the point of Ecopetrol’s participation. Based upon the extent of the area declared commercial in relation to the Cajaro #1 well by Ecopetrol, Global has advised Ecopetrol, ANH and the Ministry of Energy that Global’s Los Hatos concession contract area, which is adjacent to Global’s Alcaravan contract, is being drained of Mirador formation oil reserves located beneath the Los Hatos contract. Because two contract areas are being drained by one well, it is our opinion that Colombian law requires the division of reserves and revenues be settled through a unitization proceeding. This proceeding will affect the Cajaro #1 net revenues and costs assigned to both Ecopetrol and Global. Although the ultimate results of the unitization proceeding cannot be determined at this time, Global, based on the proposed unitization maps and data presented by Ecopetrol, reflects 50% interest in net production from the Cajaro #1 well associated with the Alcaravan Contract Area, deemed to be 21%, in the cash flows in its financial statements and reserve information.

Exploration and Production Concession Contracts - The exclusive Exploration and Production Concession Contracts are the Rio Verde Contract and the Los Hatos Contract, both awarded in 2004, and the Luna Llena Contract and the Caracoli Contract, both awarded in December 2005. As of December 31, 2005,

Global was in compliance with the requirements of each of the Exploration and Production Concession Contracts.

The Rio Verde Contract assigns Global exclusive exploration and production rights to 75,000 acres located approximately 40 kilometers north of Global’s Palo Blanco complex. Global currently owns a 100% working interest in the Rio Verde Contract, and production, if any, is subject to an initial 10.5% percent royalty interest. The final size of the royalty is to be determined by future production levels. The contract duration is approximately six years for the exploration phase and 24 years for the following exploitation phase. The time period for Phase 1 of the Rio Verde Contract is 20 months. Global has completed the requirements of Phase 1 of the Rio Verde Contract as of December 31, 2005.

In 2005, Global elected to enter Phase 2 of the Rio Verde Contract and is currently drilling the one obligated exploration well. Additionally Global must acquire a further 25 kilometers of 2D seismic data. Phases 3, 4 and 5, also optional, require one exploratory well to be drilled per phase. Phases 2, 3, 4 and 5 have a time period of 12 months each.

The Los Hatos Contract area is located in the central Llanos region. Global owns 100% of the contract, subject only to an initial 8% royalty payable to the Colombian Ministry of Energy. The final size of the royalty is to be determined by future production levels. The contract duration is approximately 6 years for the exploration phase and 24 years for the exploitation phase.

The Los Hatos contract grants Global exclusive exploration and production rights to 85,000 acres which are adjoined to the established Palo Blanco field. The terms of the Los Hatos contract require Global during phase 1 to drill one exploratory well. The time period for phase 1 is 16 months. According to the requirements under Phase 1, Global drilled and successfully completed the Los Hatos #1. Phases 2, 3, 4 and 5, also optional, require one exploratory well to be drilled per phase. Phases 2, 3, 4 and 5 have a time period of 12 months each.

In December 2005, Global signed a new exclusive Exploration and Production Concession Contract for the Caracoli area (the “Caracoli Contract”) with the ANH. The Caracoli Contract covers approximately 90,000 acres in the Catatumbo basin located in northeastern Colombia. This basin is a sub-basin of the prominent Maracaibo basin which extends in a southwesterly direction from Venezuela into Colombia.

Colombian TEA - In May 2005, Global signed a TEA with the ANH for the evaluation of potential hydrocarbon resources in the Valle Lunar area located in the established Llanos Basin of eastern Colombia. The total acreage covered by the TEA is approximately 2.1 million acres.

The Valle Lunar area has been subject to prior exploration activity by an international petroleum company in 1981 with two exploration wells reported as productive at that time. The Valle Lunar TEA targets medium heavy oil deposits and grants Global the option to sign a future exclusive exploration and production concession contract, typically 25 years in duration, for acreage within the TEA area that Global identifies as prospective and suitable for exploratory drilling and production operations. The TEA duration is 16 months. The TEA requires Global to complete within 12 months the reprocessing and interpretation of 800 linear kilometers of existing 2D seismic and certain other geophysical measurements and analysis, including the acquisition of aeromagnetic data.

In September 2005, Global exercised its option to commence negotiations with ANH to convert a portion of the Valle Lunar TEA area into an exploration and production contract. Global signed the Luna Llena Exploration and Production Contract in December 2005.

At December 31, 2005, Global has proved reserves attributable to the Alcaravan, Bolivar and Bocachico Association Contracts and the Rio Verde and Luna Llena Exploration and Production Contract. In the Alcaravan Contract, Global has proved reserves in the Palo Blanco and Anteojos field, and, in the Bolivar Contract, Global has proved reserves in the Buturama field. In the Bocachico Contract, Global has proved reserves in the Rio Negro field. In the Rio Verde Exploration and Production Contract, Global has proved reserves in the Rio Verde and Macarenas fields. In the Luna Llena Contract, Global has proved reserve in the El Miedo field. Global has no proved reserves associated with natural gas at December 31, 2005.

Peruvian Operations - In April 2005, Global announced that the License Contract between Global and Perupetro S.A. (“Perupetro”), the national oil company of Peru, for the Exploration and Exploitation of Hydrocarbons in the Block 95 Area located in the Marañon Basin of Northeastern Peru (the “License Contract”) had been fully executed and was effective.

Global owns a 100% working interest in the License Contract area subject only to an initial 5% royalty. The size of the ongoing royalty is to be determined by future production levels. The License Contract duration is approximately seven years for the initial exploration phases and 23 years for the exploitation phase. The License Contract assigns Global exclusive exploration and production rights to approximately 1,255,000 acres. During Phase 1 of the contract, the terms require Global to complete, within 12 months, environmental impact studies and plans for the drilling of a well in the Bretaña field located in Block 95.

If Global elects to enter Phase 2 of the contract, Global must acquire approximately 4,800 square kilometers of micro-magnetic geophysical data in and around the Bretaña field and elsewhere throughout Block 95. Phase 2 has a time period of 12 months. Should Global elect to enter Phase 3, it will be required to drill one exploratory well within 24 months. Phase 4 of the exploration period has a duration of 12 months and requires the acquisition of 75 square kilometers of three dimensional seismic data, while Phases 5 and 6 each have a duration of 12 months and require the drilling of one exploratory well per phase.

Panamanian Operations – In September 2001, Global, through a wholly owned subsidiary, signed a TEA with the Ministry of Commerce and Industry for the Republic of Panama. The Panama TEA covered approximately 1.4 million gross acres divided into three blocks in and offshore Panama. Under the terms of the Panama TEA, Global performed certain work program procedures and studies and submitted them to the Panamanian government. The Panama TEA provided Global with an exclusive option to negotiate and enter into one or more contracts for the Exploration and Exploitation of Hydrocarbons with the Ministry of Commerce and Industry. Global completed all of its obligations under the Panama TEA and exercised its option to negotiate an Exploration and Exploitation Contract. As of December 31, 2005, the negotiations with the Panamanian government regarding the form and content of the Exploration and Exploitation Contract are still in progress.

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CHANGES IN HARKEN’S OWNERSHIP IN GLOBAL

During the year ended December 31, 2005, through the exercise of certain warrants and stock options by others and through various sales of Harken’s shares in Global, Harken’s direct ownership interest in Global decreased from approximately 85% at December 31, 2004 to approximately 34% at December 31, 2005.

At December 31, 2005, Lyford, a related party (see Note 14 – Related Party Transactions), owned approximately 20% of the common shares of Global. Also at December 31, 2005, Lyford beneficially owned approximately 30% of the combined voting power of Harken’s common stock. Therefore, Harken’s direct equity interest of approximately 34%, combined with Lyford’s 20% equity interest in Global, was deemed to provide Harken with the legal power to control the operating policies and procedures of Global, which required Harken to consolidate the operations of Global as of December 31, 2005.

Direct Sales of Global Common Shares – During the year ended December 31, 2005, Harken sold certain of its common shares of Global through numerous individual transactions in the market to various purchasers through the year in exchange for total cash consideration, net of fees, of approximately $40 million. In accordance with APB 18 and as a result of the sale of these shares during the year ended December 31, 2005, Harken recognized total gains of approximately $32.5 million, which was equal to the amount by which the net proceeds of each transaction exceeded Harken’s proportionate carrying value of Global as of the date of each transaction.

Exercise of Global Warrants held by Lyford - In July and August 2002, Harken issued a 10% Term Loan Payable (the “Investor Term Loan”) in the total principal amount of $5 million to Lyford in exchange for cash in the principal amount of the Investor Term Loan. The principal of Lyford is Phyllis Quasha, whose son, Alan G. Quasha, became a member of Harken’s board of directors and the Chairman of Harken in March 2003. Harken’s indebtedness to Lyford under the Investor Term Loan was repaid in full in March 2003.

In 2002, as additional consideration for the Investor Term Loan, as amended, Harken issued to Lyford, warrants to purchase up to 7,000,000 shares of Global held by Harken at a price of 50 UK pence per share. Prior to their exercise in September 2005, these warrants constituted approximately 20% of Harken’s holdings in Global’s outstanding shares.

Harken accounted for the Lyford Warrants as derivatives in accordance with SFAS 133 and EITF 00-6. Harken recorded the estimated fair value of the warrants as a liability at issuance and adjusted the liability to estimated fair value each period with any changes in value reflected in earnings.

The fair value of the warrants was calculated by a third-party firm based primarily on the underlying market price of Global’s common stock price. As a result of increases in Global’s common share price in 2004 and 2005 through the date of exercise, Harken recorded a loss of approximately $14 million and $13 million for the years ended December 31, 2004 and 2005, respectively, for the change in the fair value of the Lyford Warrants. Immediately prior to exercise of the Global Warrants held by Lyford in September 2005, these warrants were recorded as a liability of approximately $26.9 million.

In September 2005, Lyford exercised all of its warrants in exchange for cash proceeds of $6.4 million. In accordance with EITF 00-6, for the year ended December 31, 2005, Harken recognized a Gain on exercise of Global warrants of approximately $28 million in the Consolidated Statement of Operations, representing the difference between Harken’s proportionate net book value of its shares in Global as of the date of exercise and the cash proceeds received plus the fair value of the Lyford Warrant Liability immediately prior to exercise. At December 31, 2005, the Lyford Warrants are no longer outstanding.

Exercise of Global Warrants held by Minority Interest Owners – As part of Global’s issuance of warrants to its shareholders in August 2002, Global issued to its minority shareholders, warrants to purchase shares of Global stock at 60 UK pence per share. During the year ended December 31, 2005, all of Global’s minority interest owners exercised their warrants to purchase 500,061 shares of Global stock. At December 31, 2005, the Global Warrants held by Minority Interest Owners are no longer outstanding.

Harken was required to account for the Global Warrants held by Minority Interest Owners as derivatives in accordance with SFAS 133. As a result of increases in Global’s common share price, Harken recorded a loss of approximately $906,000 and $350,000 for the years ended December 31, 2004 and 2005, respectively, for the change in the fair value of these warrants.

Unlike the Lyford Warrants (referred to above), the exercise of which resulted in a direct sale of Global shares held by Harken to Lyford, the minority owners received their shares of Global through a share issuance directly from Global upon exercise of their warrants. Therefore Harken did not reflect any gain or loss on the exercise of Global Warrants held by Minority Interest Owners in the years ended December 31, 2004 and 2005.

Exercise of Global Warrants held by Harken - As part of Global’s issuance of warrants to its shareholders in August 2002, Global issued to Harken warrants to purchase 6,487,481 of Global’s ordinary common shares at 60 UK pence per share. In June 2005, Harken exercised all of its outstanding warrants to purchase 6,487,481 ordinary shares in Global for total cash consideration of approximately $7.1 million. These warrants had an expiration date of August 8, 2005.

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CONVERTIBLE NOTES PAYABLE

A summary of convertible notes payable is as follows:


	December 31, 2004			December 31, 2005
4.25% Convertible Notes	$	3,333,000		$	—
5% Senior Convertible Notes		5,245,000			—
Global Senior Convertible Notes		—			12,500,000

		8,578,000			12,500,000
Less: Current portion		(1,667,000	)		—

	$	6,911,000		$	12,500,000

Maturities of Long-term Debt – The Global Senior Convertible Notes are due and payable in November 2012.

4.25% Convertible Notes — In December 2003, Harken issued to qualified investors a total of $5 million principal amount of its unsecured 4.25% Convertible Notes due 2006 (the “4.25% Convertible Notes”), which were scheduled to mature in December 2006, in exchange for $5 million cash. Both principal and accrued interest on the 4.25% Convertible Notes were payable semi-annually in six equal installments at Harken’s option in cash or with shares of Harken common stock equal to 110% of the principal amount to be redeemed divided by the 30-day average market price of Harken’s common stock immediately prior to the semi-annual redemption date.

The first principal installment payment along with accrued interest was paid in cash as of June 30, 2004. In December 2004, in accordance with the terms of the 4.25% Convertible Notes, Harken paid the second principal installment of the 4.25% Convertible Notes with approximately 1.9 million shares of Harken common stock. The December 2004 principal installment of the 4.25% Convertible Notes was paid in accordance with the terms of the notes, for a number of shares of common stock equal to 110% of the sum of the outstanding principal amount of the notes to be redeemed plus accrued and unpaid interest thereon to the date of redemption, divided by approximately $0.53 (the average market price of the common stock over the 30 calendar days immediately preceding the date of the notice of the redemption).

In 2004, Harken recorded a loss on extinguishment of approximately $170,000 for the difference between the carrying value of the December 2004 installment of principal and accrued interest on 4.25% Convertible Notes and the fair market value of the 1.9 million shares of Harken common stock issued on the settlement date.

During May 2005, Harken repaid in full the outstanding principal and accrued interest of the 4.25% Convertible Notes of approximately $3.4 million in cash. At December 31, 2005, the 4.25% Convertible Notes are no longer outstanding.

5% Senior Convertible Notes — In August 2004, Harken issued to qualified investors $5.245 million aggregate principal amount of its 5% Senior Convertible Notes due June 30, 2009 (the “5% Notes”) in exchange for $5.245 million in cash. The 5% Notes were convertible into shares of Harken’s common stock at a conversion price of $0.52 per share, subject to adjustments in certain circumstances. The 5% Notes may also be converted in whole or in part, at Harken’s option, if at any time the average market price of Harken’s common stock, over any 20 consecutive business day period, equals or exceeds 125% of the conversion price ($0.65 per share). The 5% Notes bear interest at the rate of 5% per annum. Interest was payable semi-annually in arrears on December 31 and June 30, commencing December 31, 2004. In September 2005, according to terms pursuant to the original note agreement, Harken received voluntary conversion notices from certain holders of its 5% Notes totaling $3.3 million outstanding principal amount, and Harken subsequently issued approximately 6.5 million common shares to convert the related principal and accrued interest.

In September 2005, after meeting the market price criteria necessary, Harken issued a Mandatory Conversion Notice on its outstanding 5% Notes giving notice of its determination to exercise its rights to mandatorily convert all outstanding 5% Notes to shares of Harken common stock. As of November 4, 2005, the designated mandatory conversion date, Harken issued approximately 3.7 million shares of common stock to convert the remaining outstanding $1.9 million principal and accrued interest of the 5% Notes. No gain or loss was recorded for the mandatory conversion of the 5% Notes as this transaction did not qualify as debt extinguishment. As of December 31, 2005, the 5% Notes are no longer outstanding.

The Global Notes can be converted at any time by the holder into ordinary shares of Global at the conversion price of 305.8 UK pence per share, converted at the mandatory exchange rate of 1.78 U.S. dollars per British pound (the “Conversion Price”). At maturity, the outstanding Global Notes must be redeemed for cash at 100% of their principal value.

The Global Notes may be redeemed for cash, at Global’s option, at par, in whole or in part, at any time after October 30, 2008, upon not less than 30 days notice to the holders. Prior to October 31, 2008, the Global Notes may be redeemed for cash at 108% of the principal amount. In addition, Global may redeem the Global Notes in exchange for shares of Global common stock at the Conversion Price at any time if the average closing price for its shares has equaled or exceeded 125% of the Conversion Price for 20 consecutive days during any time after issuance.

The Global Notes contain a mandatory exchange rate of 1.78 U.S. dollars per British pound within the conversion feature in order to fix the number of Global common shares to be issued upon conversion of the Global Notes. This fixed exchange rate provision is an embedded derivative as defined by SFAS 133, and accordingly, must be bifurcated from the host instrument and recorded at fair value on the balance sheet. The value of the fixed exchange rate component was not material at December 31, 2005.

5% European Notes — On May 26, 1998, Harken issued a total of $85 million of its 5% European Notes, which matured on May 26, 2003. In accordance with the terms of the 5% European Notes, upon their maturity, Harken redeemed the remaining principal balance of approximately $7.3 million of the 5% European

Notes plus accrued interest by issuing approximately 24.8 million shares of Harken common stock. During 2003, Harken recognized total gains of approximately $5.3 million from the cash purchases and/or exchanges of other debt securities for the 5% European Notes in the accompanying Consolidated Statement of Operations.

Benz Convertible Notes — In December 1999, Harken issued $12 million principal amount of the Benz Convertible Notes in exchange for certain prospects acquired from Benz Energy, Incorporated. The Benz Convertible Notes originally were to mature on May 26, 2003.

In October 2003, in accordance with the terms of the Benz Convertible Notes, Harken redeemed each Benz Convertible Note outstanding on November 26, 2003, for shares of Harken common stock. In 2003, Harken recorded a gain on extinguishment of approximately $242,000 for the redemption of the outstanding Benz Convertible Notes for the difference between the carrying value of the Benz Convertible Notes and the fair market value of the 8.6 million shares of Harken common stock issued at the settlement date.

At December 31, 2005, the carrying amount of Global’s non-traded fixed-rate debt is approximately equal to its estimated fair value based on the discounted cash flows of principal and interest using an estimated available incremental borrowing rate as well as the market value of its underlying convertible common shares.

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REDEEMABLE PREFERRED STOCKS

Issuance of Series J Convertible Preferred Stock and Warrants –

In March 2004, Harken’s Board of Directors approved the authorization and issuance of up to 65,000 shares of a new series of convertible preferred stock, the Series J Preferred. In April 2004, in exchange for $5.0 million in cash, Harken issued

•

50,000 shares of Series J Preferred,

•

Warrants to purchase shares of Harken’s common stock; and

•

10,000 unit purchase warrants

The Series J Preferred had a liquidation value of $100 per share, was non-voting and was convertible at the holders’ option into common stock at a conversion price of $0.85 per share. This conversion price was subject to adjustment in the event Harken subsequently issued shares of its common stock at a price lower than this conversion price or in response to certain transactions that are in effect equity restructuring transactions. The Series J Preferred was also convertible by Harken, into freely tradable shares of Harken common stock at the conversion price, if for any period of thirty consecutive calendar days the average closing price of Harken common stock equaled or exceeded 150% of the conversion price ($1.28 per share).

Dividends - The holders of the Series J Preferred were entitled to receive dividends at an annual rate equal to 5% per share. All dividends on the Series J Preferred stock were payable quarterly in arrears, in cash or, at Harken’s option, in shares of Harken common stock. The Series J Preferred dividend and liquidation rights ranked junior to all claims of creditors, including holders of outstanding debt securities, but senior to the holders of Harken common stock and pari passu to the holders of any other series of Harken preferred stock, unless otherwise provided.

Warrants – In connection with the Series J Preferred, 2.9 million warrants were issued to purchase shares of Harken’s common stock. These warrants expired in April 2005 and had an exercise price of $0.92. The exercise price was subject to adjustment for the same circumstances that gave rise to adjustments to the conversion price of the Series J Preferred (see discussion above).

Unit Purchase Warrants - The unit purchase warrants issued in connection with the Series J Preferred had an exercise price of $100 per unit. Each unit consisted of one share of Series J Preferred and one warrant to purchase that number of shares of Harken’s common stock that equals 50% of the number of shares of Harken common stock into which one share of the Series J Preferred that is purchased, by exercise of the unit purchase warrant, may be converted. These unit purchase warrants expired in April 2005.

Accounting for the Series J Preferred and Warrants – In accordance with EITF Topic D-98 “Classification and Measurement of Redeemable Securities” (“EITF D-98”), the Series J Preferred contained certain provisions whereby redemption was deemed to be out of Harken’s control. Therefore the fair value of the Series J Preferred, of approximately $4.7 million was classified as temporary equity in the Consolidated Balance Sheet at December 31, 2004. The conversion option embedded in the Series J Preferred is not required to be bifurcated from the host instrument under EITF 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock” (“EITF 00-19”). Although the Series J Preferred does not meet the definition of a “conventional convertible instrument”, as contemplated by EITF 00-19 because the conversion price may be adjusted upon subsequent issuances of common stock by Harken, the fact that Harken has sole control over the event that would cause such an adjustment to the conversion price provides Harken with the de facto ability to determine that it will have sufficient shares available to satisfy the conversion option upon exercise by the holder.

In accordance with EITF 00-19, the common stock warrants were initially measured at fair value of $287,000 by an independent third party and are classified as permanent equity in the Consolidated Balance Sheet at December 31, 2004. The fair value allocated to the unit purchase warrants, approximately $38,000, was also classified as permanent equity in the Consolidated Balance Sheet at December 31, 2004. Classification in permanent equity for the warrants and unit purchase warrants is appropriate despite the possibility that the exercise price could be adjusted for the same reasons the conversion option embedded in the Series J Preferred are not required to be bifurcated and accounted for separately as a liability (see discussion above).

After allocating the net proceeds between the Series J Preferred, the common stock warrants and the unit purchase warrants, Harken determined no beneficial conversion feature existed.

Redemption of the Series J Preferred – In August 2005, Harken entered into and completed a transaction with the holder of the Series J Preferred to redeem all of the outstanding 50,000 shares of Series J Preferred in exchange for $5.0 million in cash. As part of the agreement, the Series J Preferred holder waived its right to partial liquidated damages under the Series J Preferred Subscription Agreement, and any interest thereon, which arose from a previous registration default under the agreement. None of Harken’s other debt or equity instruments were affected by this Registration Rights Agreement default. The Series J holder was an investor in Harken, but had no relationship wit the company. At December 31, 2005, the Series J Preferred are no longer issued and outstanding.

Accounting for the Redemption of the Series J Preferred – In accordance with EITF Topic D-42, “The Effect on the Calculation of Earnings per Share for the Redemption or Induced Conversion of Preferred Stock (“EITF D-42”),” and EITF Topic D-53, “Computation of Earnings per Share for a Period That Includes a Redemption or an Induced Conversion of a Portion of a Class of Preferred Stock (“EITF D-53”),” Harken recognized a charge to Redemption of preferred stock as an increase to Net loss attributed to common stock of approximately $225,000. This charge was equal to the fair value of the consideration paid to the holder ($5 million in cash) less the carrying amount of the Series J Preferred ($4,675,000) and the accrued liquidated damages for the registration event default forgiven on the redemption of the Series J ($100,000).

Adjustment of Series J Conversion Price and Warrant Exercise Price – In May 2004, as a result of Harken’s issuance of its Series L Convertible Preferred Stock (the “Series L Preferred”), the conversion price of the Series J Preferred was adjusted from $0.87 to $0.85. In accordance with Issue 7 of EITF Issue 00-27,

“Application of Issue 98-5 to Certain Convertible Instruments” (EITF00-27”), the number of the additional shares issuable upon conversion of the Series J Preferred multiplied by Harken’s stock price on the date of the original transaction was reflected as a Payment of preferred stock dividends of approximately $135,000, which was presented as an increase to Net loss attributed to common stock dividends in the Consolidated Statement of Operations for the year ended December 31, 2004. In addition, the original exercise price of the common stock warrants issued with the Series J Preferred was adjusted from $0.98 to $0.95. Later in 2004, as a result of Harken’s issuance of the 5% Notes and the Series M Convertible Preferred Stock (the “Series M Preferred”), the exercise price of the common stock warrants issued with the Series J Preferred was adjusted from $0.95 to $0.92. In accordance with SFAS 123 the incremental increase in the fair value of the warrant of approximately $26,000, was reflected as a Payment of preferred stock dividends, which was also presented as an increase to Net loss attributed to common stock in the Consolidated Statement of Operations for the year ended December 31, 2004.

Issuance of Series L Convertible Preferred Stock and Warrants –

In March 2004, Harken’s Board of Directors approved the authorization and issuance of up to 65,000 shares of convertible preferred stock, the Series L Preferred. In May 2004, Harken issued 50,000 shares of Series L Preferred stock and warrants to purchase shares of Harken common stock in exchange for $5 million in cash. Shares of the Series L Preferred had a liquidation value of $100 per share, were non-voting and were convertible at the holders’ option into Harken common stock at a conversion price of $0.71 per share. This conversion price was subject to adjustment in the event Harken subsequently issued shares of its common stock at a price lower than this conversion price or in response to certain transactions that are in effect equity restructuring transactions. See Series L Conversion / Redemption Agreement discussion below.

Dividends - The holders of the Series L Preferred were entitled to receive dividends at an increasing rate starting at 4% per share. All dividends on the Series L Preferred were payable semi-annually on June 30 and December 30. Dividends may be paid in cash or, at Harken’s option, in freely tradable shares of Harken common stock.

Warrants – In connection with the issuance of the Series L Preferred, 3.7 million warrants to purchase shares of Harken’s common stock were issued. These warrants expire in May 2006 and have an exercise price of $0.67. The exercise price was subject to adjustment for the same circumstances that gave rise to adjustments to the conversion price of the Series L Preferred (see discussion above).

Accounting for the Series L Preferred Stock and Warrants – In accordance with EITF D-98, events of default for the Series L Preferred contained certain provisions whereby redemption was deemed to be out of Harken’s control. Therefore at December 31, 2004, the remaining balance of the Series L Preferred of approximately $805,000 was classified as temporary equity in the Consolidated Balance Sheet. In accordance with EITF 00-19, the fair value allocated to the common stock warrants of approximately $976,000 was classified as permanent equity in the Consolidated Balance Sheet at December 31, 2004. The conversion option embedded in the Series L Preferred is not required to be bifurcated from the host instrument under EITF 00-19. Although the Series L Preferred does not meet the definition of a “conventional convertible instrument”, as contemplated by EITF 00-19 because the conversion price may be adjusted upon subsequent issuances of common stock by Harken, the fact that Harken has sole control over the event that would cause such an adjustment to the conversion price provides Harken with the de facto ability to determine that it will have sufficient shares available to satisfy the conversion option upon exercise by the holder. Classification in permanent equity for the warrants is appropriate despite the possibility that the conversion price could be adjusted for the same reasons the conversion option embedded in the Series L Preferred are not required to be bifurcated and accounted for separately as a liability.

However in October 2004, Harken modified the conversion terms, as described under Series L Conversion/Redemption Agreement below, such that Harken no longer had control over adjustments to the conversion price. However, the modified conversion terms contained a floor under which the conversion price would not drop under, and Harken assessed the maximum number of shares that could potentially be issued under the modified conversion terms. Harken determined it had sufficient authorized shares to allow issuance of such maximum number of shares. Accordingly, the conversion option under the modified terms is not required to be bifurcated from the host instrument under EITF 00-19.

The proceeds allocated to the Series L Preferred represented a discount to the market value of the underlying common stock. The discount of approximately $498,000 was treated as a beneficial conversion

feature and was recognized as a Payment of preferred stock dividends and presented as an increase to Net loss attributed to common stock in the Consolidated Statement of Operations for the year ended December 31, 2004.

Adjustment of Series L Conversion Price and Warrant Exercise Price – In August 2004, as a result of Harken’s issuance of its 5% Notes, the original conversion price of the Series L Preferred was adjusted from $0.72 to $0.71. In accordance with EITF 00-27, Issue 7, approximately $51,000 was recorded as a Payment of preferred stock dividends which was presented as an increase to Net loss attributed to common stock in the Consolidated Statement of Operations for the year ended December 31, 2004. In addition, the original exercise price of the common stock warrants issued with the Series L Preferred was adjusted from $0.68 to $0.67. The incremental increase in the fair value of the warrant of approximately $9,000 was reflected as a Payment of preferred stock dividends which was also presented as an increase to Net loss attributed to common stock in the Consolidated Statement of Operations for the year ended December 31, 2004.

Series L Conversion / Redemption Agreement - In October 2004, Harken entered into a Conversion/Redemption Agreement (the “Agreement”) with the holders of the Series L Preferred, pursuant to which Harken modified the conversion terms of the Series L Preferred as a part of the agreement to issue the Series M Preferred, as described below.

Pursuant to the Agreement, each holder of the Series L Preferred agreed to convert at least 20% of its holdings of Series L Preferred on each of October 8, 2004, November 2, 2004, December 1, 2004, December 30, 2004 and February 1, 2005, provided Harken met certain conditions. Harken agreed that the conversion price would be the volume weighted average price of the Harken’s common stock for the twenty consecutive trading days immediately preceding the applicable conversion date (not to be less than $0.25 per share). In 2004, a total of $4 million, plus accrued dividends, of the liquidation value of the Series L Preferred was converted into 7.4 million shares of Harken’s common stock. In February 2005, the remaining $1 million, plus accrued dividends, of the liquidation value of the Series L Preferred was converted into 2.1 million shares of Harken common stock. As of December 31, 2005, the Series L Preferred is no longer issued and outstanding.

Issuance of Series M Preferred - Concurrent with the Agreement, in October 2004, Harken sold 50,000 shares of its Series M Preferred and issued warrants to purchase up to 4,385,965 shares of Harken’s common stock at an exercise price equal to $0.57 per share. The aggregate purchase price for the Series M Preferred and the related warrants was cash consideration of $5,000,000.

The Series M Preferred has a liquidation value of $100 per share, is non-voting and is convertible at the holders’ option into common stock at a conversion price of $0.60 per share. This conversion price is subject to adjustment in the event Harken subsequently issued shares of its common stock at a price lower than this conversion price or in response to certain transactions that are in effect equity restructuring transactions. If for any period of thirty consecutive days the average closing price of Harken common stock during such period trades above $0.75 per share for 30 consecutive days, up to 25,000 shares of the Series M Preferred is convertible by Harken into freely tradable shares of Harken common stock at $0.60 per share. If the average daily volume weighted average price of Harken’s common stock during a period of thirty trading days equals or exceeds $0.90, Harken may convert all the Series M Preferred into freely tradable shares of Harken common stock at $0.60 per share.

Accounting for the Series L Conversion / Redemption and the Issuance of the Series M Preferred – In accordance with EITF D-42 and EITF D-53, Harken reflected the difference between the total of the carrying amount of the Series L Preferred, including accrued dividends, plus the $5 million in cash, less transaction fees, and the total of the fair value of the Series M Preferred, the common stock warrants issued plus the consideration paid to redeem the Series L Preferred as Redemption of preferred stock of approximately $1.2 million in the Consolidated Statement of Operations for the year ended December 31, 2004 which was presented as an increase to Net loss attributed to common stock.

Accounting for the Classification of the Series M Preferred Stock and Warrants – In accordance with EITF Topic D-98, the Series M Preferred does not contain provisions whereby redemption is deemed to be out of Harken’s control. Therefore the Series M Preferred is classified as permanent equity in the Consolidated Balance Sheet at December 31, 2004 and 2005. In accordance with EITF 00-19, the common stock warrants were initially measured at fair value and are classified as permanent equity in the Consolidated Balance Sheet at December 31, 2005. The conversion option embedded in the Series M Preferred is not required to be bifurcated from the host instrument under EITF 00-19. Although the Series M Preferred does not meet the definition of a “conventional convertible instrument”, as contemplated by EITF 00-19 because the conversion price may be adjusted upon subsequent issuances of common stock by Harken, the fact that Harken has sole control over the event that would cause such an adjustment to the conversion price provides Harken with the de facto ability to determine that it will have sufficient shares available to satisfy the conversion option upon exercise by the holder. Classification in permanent equity for the warrants is appropriate despite the possibility that the conversion price could be adjusted for the same reasons the conversion option embedded in the Series M Preferred are not required to be bifurcated and accounted for separately as a liability.

Adjustment of Series M Preferred Conversion Price – In March 2005, as a result of a default under the Registration Rights Agreement of the Series M Preferred, holders of the Series M Preferred received a one-time adjustment to the original conversion price of the Series M Preferred from $0.60 to $0.59. In accordance with EITF 00-27, Issue 7, approximately $90,000 is included as a Payment of preferred stock dividends as a decrease to Net income attributed to common stock in the Consolidated Statement of Operations for the year ended December 31, 2005. None of Harken’s other debt or equity instruments were affected by this Registration Rights Agreement default. In January 2006, Harken entered into an agreement with the holders of the Series M Preferred to extend the term of the Series M Preferred warrants due to the delay in the effectiveness of the associated registration statement.

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STOCKHOLDERS’ EQUITY

Common Stock - Harken has authorized 325 million shares of $.01 par common stock. At December 31, 2004 and 2005, Harken had 219,615,485 shares and 223,575,732 shares, respectively issued and outstanding. Dividends may not be paid to holders of Harken’s common stock prior to the satisfaction of all dividend obligations related to Harken’s Series G1, Series G2 and Series M Preferred stock.

Treasury Stock - At December 31, 2004, Harken had 2,605,700 shares of treasury stock. In May 2005, Harken’s Board of Directors approved the cancellation of the 2,605,700 shares of treasury stock which were previously outstanding as of December 31, 2004. Such treasury shares were cancelled in June 2005.

In 2005, Harken announced that its Board of Directors authorized certain stock repurchase programs allowing the Company to buy back up to a total of 14,000,000 shares of its common stock. For the year ended December 31, 2005, Harken repurchased approximately 6,422,000 shares of its common stock in the open market at a cost of approximately $3,775,000, pursuant to the repurchase programs. In December 2005, Harken’s Board of Director’s approved the cancellation of the 6,421,898 shares of treasury stock previously outstanding. At December 31, 2005, Harken had no shares of treasury stock outstanding.

Series G1 Convertible Preferred Stock - The Series G1 Convertible Preferred Stock (the “Series G1 Preferred”), which was issued in October 2000, has a liquidation value of $100 per share, is non-voting, and is convertible at the holder’s option into Harken common stock at a conversion price of $12.50 per share. The conversion option embedded in the Series G1 Preferred is not required to be bifurcated from the host instrument under EITF 00-19. Although the Series G1 Preferred does not meet the definition of a “conventional convertible instrument”, as contemplated by EITF 00-19 because the conversion price may be

adjusted upon subsequent issuances of common stock by Harken, the fact that Harken has sole control over the event that would cause such an adjustment to the conversion price provides Harken with the de facto ability to determine that it will have sufficient shares available to satisfy the conversion option upon exercise by the holder.

The Series G1 Preferred holders shall be entitled to receive dividends at an annual rate equal to $8.00 per share when, as and if declared by Harken’s Board of Directors. All dividends on the Series G1 Preferred are cumulative and payable semi-annually in arrears on June 30 and December 30. At Harken’s option, dividends may also be payable in Harken common stock valued at $12.50 per share. The Series G1 Preferred dividend and liquidation rights shall rank junior to all claims of creditors, including holders of outstanding debt securities, but senior to Harken common stockholders and to any subsequent series of Harken preferred stock, unless otherwise provided, except for the Series G1 Preferred and Series M Preferred, which shall rank equal to the Series G1 Preferred.

During January and February 2004, a total of approximately 208,000 shares of Harken common stock were issued to holders of Series G1 Preferred as payment for accrued dividends of $2.6 million in arrears as of December 31, 2003.

During 2004, Harken’s Board of Directors declared that a dividend be paid on all accrued and unpaid dividends on the Series G1 Preferred as of June 30, 2004 and December 31, 2004. The dividends were paid with shares of Harken common stock. As of the record date for such dividends, in May and November 2004, there were 295,372 and 13,925, shares respectively, of the Series G1 Preferred outstanding. In 2004, Harken had accrued a total of approximately $1.2 million of dividends in arrears related to the Series G1 Preferred, or approximately $8.00 per share of such preferred stock outstanding. In 2004, a total of approximately 99,000 shares of Harken common stock were issued to holders of the Series G1 Preferred. During 2005, Harken’s Board of Directors declared that a dividend be paid as of June 30 and December 31, 2005 to holders of the Series G1 Preferred. Such dividends at June 30, 2005 were to be paid with shares of common stock. As of the record date for such dividends, in May and December 2005, there were 13,925 and 1,600 shares, respectively, of the Series G1 Preferred outstanding. In June and December 2005, Harken had accrued a total of approximately $55,700 and $6,400, respectively, of dividends in arrears related to the Series G1 Preferred or approximately $8.00 per share of such preferred stock outstanding. In June 2005, a total of approximately 4,000 shares of Harken common stock were issued to holders of the Series G1 Preferred as payment of the June 2005 accrued dividends. In December 2005, Harken paid the dividends on the Series G1 Preferred accrued at December 31, 2005 in cash.

During the year ended December 31, 2004 and 2005, holders of 28,940 and 500 shares, respectively, of the Series G1 Preferred voluntarily elected to exercise their conversion option, and such holders were issued 231,651 and 4,000 shares, respectively of Harken common stock.

Series G2 Convertible Preferred Stock - In July 2001, Harken’s Board of Directors approved the issuance of shares of the Series G2 Preferred Stock (“Series G2 Preferred”), which has a liquidation value of $100 per share, is non-voting, and is convertible at the holder’s option into Harken common stock at a conversion price of $3.00 per share. The conversion option embedded in the Series G1 Preferred is not required to be bifurcated from the host instrument under EITF 00-19. Although the Series G2 Preferred does not meet the definition of a “conventional convertible instrument”, as contemplated by EITF 00-19 because the conversion price may be adjusted upon subsequent issuances of common stock by Harken, the fact that Harken has sole control over the event that would cause such an adjustment to the conversion price provides Harken with the de facto ability to determine that it will have sufficient shares available to satisfy the conversion option upon exercise by the holder.

The Series G2 Preferred is also convertible by Harken into shares of Harken common stock if for any period of twenty consecutive calendar days, the average of the closing prices of Harken common stock during such period shall have equaled or exceeded $3.75 per share.

The Series G2 Preferred holders shall be entitled to receive dividends at an annual rate equal to $8.00 per share when, as and if declared by the Harken Board of Directors. All dividends on the Series G2 Preferred are cumulative and payable semi-annually in arrears on June 30 and December 30. At Harken’s option, dividends may also be payable in Harken common stock at $3.00 per share of Harken common stock. The Series G2 Preferred dividend and liquidation rights shall rank junior to all claims of creditors, including holders of outstanding debt securities, but senior to Harken common stockholders and to any subsequent series of Harken preferred stock, unless otherwise provided. The Series G2 Preferred shall rank equal to the Series G1 Preferred and the Series M Preferred.

During January and February 2004, a total of approximately 164,000 shares of Harken common stock were issued to holders of Series G2 Preferred for accrued dividends in arrears of $493,000 related to the Series G2 Preferred as of December 31, 2003.

During 2004, Harken’s Board of Directors declared that a dividend be paid as of June 30, 2004 and December 31, 2004 to holders of the Series G2 Preferred. Such dividend to be paid with shares of common stock. As of the record date for such dividends, in May and November 2004, there were 27,150 and 2,500 shares, respectively, of the Series G2 Preferred outstanding. In June and December 2004, Harken had accrued a total of approximately $119,000 of dividends in arrears related to the Series G2 Preferred or approximately $8.00 per share of such preferred stock outstanding. In 2004, a total of approximately 40,000 shares of Harken common stock were issued to holders of the Series G2 Preferred as payment for the accrued dividends.

During 2005, Harken’s Board of Directors declared that a dividend be paid as of June 30 and December 31, 2005 to holders of the Series G2 Preferred. Such dividends at June 30, 2005 were to be paid with shares of common stock. As of the record date for such dividends, in May and December 2005, there were 2,000 and 1,000 shares, respectively, of the Series G2 Preferred outstanding. In June and December 2005, Harken had accrued a total of approximately $8,000 and $4,000, respectively, of dividends in arrears related to the Series G2 Preferred or approximately $8.00 per share of such preferred stock outstanding. In June 2005, a total of approximately 3,000 shares of Harken common stock were issued to holders of the Series G2 Preferred as payment for the accrued dividends. In December 2005, Harken paid the dividends on the Series G2 Preferred accrued at December 31, 2005 in cash.

During 2004 and 2005, holders of 14,500 and 500 shares, respectively, of the Series G2 Preferred voluntarily elected to exercise their conversion option, and such holders were issued 487,697 and 16,893 shares, respectively, of Harken common stock.

Inducement to Voluntarily Convert Series G1 Preferred and Series G2 Preferred to Shares of Harken Common Stock - In October 2004, Harken offered all Series G1 and G2 Preferred holders an inducement to convert their Series G1 and G2 Preferred shares into shares of Harken common stock. For a limited time, holders of Series G1 and G2 Preferred were able to convert their preferred shares into shares of Harken’s common stock at a 20% premium to the original conversion terms of the Series G1 and G2 Preferred.

The inducement offer adjusted the conversion terms to 120% of the number of common shares the holders of Series G1 and G2 Preferred would have received under the original conversion terms. In November 2004, holders of 281,447 shares of Series G1 Preferred and holders of 21,650 shares of Series G2 Preferred tendered under the inducement offer. In November 2004, Harken issued 3.6 million common shares in exchange for the tendered Series G1 and G2 Preferred. At December 31, 2004, there were 13,925 shares of Series G1 Preferred outstanding.

Accounting for Inducement to Voluntarily Convert Series G1 Preferred and Series G2 Preferred to Shares of Harken Common Stock – In accordance with EITF D-98, Harken recognized the difference between

the fair value of the common stock transferred to the holders of the Series G1 and G2 Preferred under the induced conversion terms and the fair value of the common stock issuable under the original conversion terms as Redemption of preferred stock in the Consolidated Statement of Operations for the year ended December 31, 2004 as a $287,490 increase to Net income / (loss) attributed to common stock.

Redemption of Series G1 Preferred – In July 2005, Harken entered into and completed transactions with certain holders of the remaining Series G1 Preferred to redeem a total of 11,825 shares of Series G1 Preferred in exchange for $65,000 in cash. At December 31, 2005, there were 1,600 shares of Series G1 Preferred issued and outstanding.

Accounting for the Redemption of the Series G1 Preferred – According to EITF D-42 and EITF D-53, during the year ended December 31, 2005, Harken recognized a credit to Redemption of Preferred Stock as an increase to Net income / (loss) attributed to common stock of approximately $489,000. This credit is equal to the carrying amount of the Series G1 Preferred redeemed ($554,000) less the fair value of the consideration paid to the holders ($65,000 in cash).

Redemption of Series G2 Convertible Preferred Stock – In August 2005, Harken entered into and completed transactions with certain holders of the remaining Series G2 Preferred to redeem a total of 1,000 shares of Series G2 Preferred in exchange for $24,000 in cash. At December 31, 2005, there were 1,000 shares of Series G2 Preferred issued and outstanding.

Accounting for the Redemption of the Series G2 Preferred – In accordance with EITF D-42 and EITF D-53, during the year ended December 31, 2005, Harken recognized a credit to Redemption of preferred stock as an increase to Net income attributed to common stock of approximately $53,000. This credit is equal to the carrying amount of the Series G2 Preferred redeemed ($77,000) less the fair value of the consideration paid to the holders ($24,000 in cash).

Issuance of Series G4 Convertible Preferred Stock — In March 2004, Harken’s Board of Directors approved the authorization and issuance of up to 150,000 shares of a series of convertible preferred stock, the Series G4 Preferred. In April 2004, Harken issued 77,517 shares of the Series G4 Preferred in exchange for approximately 1,000 shares of the Series G1 Preferred and 23,000 shares of the Series G2 Preferred and $2.4 million in cash. The Series G4 Preferred had a liquidation value of $100 per share, was non-voting and was convertible at the holders’ option into Harken common stock at a conversion price of $2.00 per share, subject to adjustments in certain circumstances. The Series G4 Preferred was also convertible by Harken into freely tradable shares of Harken common stock if for any period of twenty consecutive calendar days the average of the closing prices of Harken common stock equaled or exceeded $2.20 per share, initially.

The holders of the Series G4 Preferred were entitled to receive dividends, when as and if declared by the Board of Directors, at an annual rate equal to $8.00 per share. All dividends on the Series G4 Preferred were payable semi-annually in arrears in cash or, at Harken’s option, in shares of Harken’s common stock, payable on June 30 and December 31. At Harken’s option, the dividends could be paid in shares of Harken’s common stock valued at $2.00 per share. The Series G4 Preferred dividend and liquidation rights rank junior to all claims of creditors, including holders of outstanding debt securities, but senior to Harken common stockholders and pari passu to any other series of Harken preferred stock, unless otherwise provided.

During 2004, Harken’s Board of Directors declared that a dividend be paid as of June 30, 2004 and December 31, 2004 to holders of the Series G4 Preferred. Such dividends were paid with shares of common stock. As of the record date for such dividends, there were 77,517 shares of Series G4 Preferred, outstanding. As of December 31, 2004, Harken had accrued a total of approximately $462,000 of dividends in arrears related to the Series G4 Preferred or approximately $8.00 per share of such preferred stock outstanding. In December 2004, a total of approximately 231,000 shares of Harken common stock were issued to holders of the Series G4 Preferred as payment for the accrued dividends.

During 2005, Harken’s Board of Directors declared that a dividend be paid as of June 30, 2005 to holders of the Series G4 Preferred. Such dividends were to be paid with shares of common stock. As of the record date for such dividends, there were 77,517 shares of the Series G4 Preferred outstanding. In June 2005, Harken had accrued a total of approximately $310,000 of dividends in arrears related to the Series G4 Preferred or approximately $4.00 per share of such preferred stock outstanding. In June 2005, a total of approximately 155,000 shares of Harken common stock were issued to holders of the Series G4 Preferred as payment for the accrued dividends.

Accounting for the Series G4 Preferred Issuance – In April 2004 upon the issuance of the Series G4 Preferred, Harken reflected the difference between the face amount of the Series G1 Preferred and the Series G2 Preferred, plus the $2.4 million in cash, less transaction fees, and the fair value of the Series G4 Preferred shares issued as Exchange of preferred stock of approximately $337,000 in the Consolidated Statement of Operations for the year ended December 31, 2004. This amount is presented as a decrease to Net loss attributed to common stock. The valuation of the Series G4 Preferred stock was supported by an appraisal, performed by RP&C International Inc. (“RP&C”), and was based on the market value of the underlying conversion shares of Harken common stock as of the date of the exchange along with a discounted value associated with an assumed dividend yield.

Redemption of Series G4 Preferred – In September 2005, Harken entered into and completed transactions with certain holders of the Series G4 Preferred to redeem a total of 67,715 shares of Series G4 Preferred in exchange for $3.7 million in cash. In October 2005, Harken redeemed the remaining 9,802 shares of Series G4 Preferred in exchange for a combination of approximately 57,000 shares of Global stock held by Harken and $287,000 in cash. As of December 31, 2005, the Series G4 Preferred are no longer issued or outstanding.

Accounting for the Redemption of the Series G4 Preferred – In accordance with EITF D-42 and EITF D-53, during the year ended December 31, 2005, Harken recognized a charge to Payment of preferred stock dividends as an decrease to Net income / (loss) attributed to common stock of approximately $265,000. This charge is equal to the carrying amount of the Series G4 Preferred redeemed, net of fees ($4.1 million) less the fair value of the consideration paid to the holders ($4.3 million in cash).

Accounting for Payment of Series G1, Series G2 and Series G4 Preferred Dividends – Harken accounts for the payment of the Series G1 Preferred, the Series G2 Preferred and the Series G4 Preferred stock dividends with shares of Harken common stock as a liability extinguishment in accordance with APB opinion No. 26, “Early Extinguishment of Debt” (“APB26”). Accordingly, the difference between the carrying value of the preferred stock dividend liability and the fair market value of the shares of Harken common stock issued by Harken in payment of the liability is recognized as a Payment of preferred stock dividends in the Consolidated Statement of Operations as an increase, net of withholding taxes paid on behalf of the preferred shareholders, to Net income / (loss) attributed to common stock.

In January and February 2004, Harken settled the Series G1 and Series G2 Preferred stock dividend liability accrued at December 31, 2003 by issuing approximately 373,000 shares of Harken common stock. Accordingly, the difference between the carrying value of the preferred stock dividend liability at December 31, 2003, approximately $3.1 million, and the fair market value of the shares of Harken common stock issued by Harken in payment of the liability in January and February 2004, approximately $425,000, was recognized as a Payment of preferred stock dividends in the Consolidated Statement of Operations in 2004, which was reflected as a $2.6 million increase to Net income / (loss) attributed to common stock.

Also in 2004, Harken paid the dividends on the Series G1 Preferred, Series G2 Preferred and Series G4 Preferred accrued at June 30, 2004 and December 31, 2004 by issuing approximately 369,000 shares of

Harken common stock. The difference between the carrying value of the preferred stock dividend liability at June 30, 2004 and December 31, 2004, approximately $1.8 million, and the fair market value of the shares of Harken common stock issued by Harken in settlement of the liability in June and December 2004, approximately $193,000, is recognized as a Payment of preferred stock dividends in the Consolidated Statement of Operations as of December 31, 2004, which was reflected as a $1.6 million increase to Net income / (loss) attributed to common stock.

In 2005, Harken paid the dividends on the Series G1 Preferred, Series G2 Preferred and Series G4 Preferred accrued at June 30, 2005 by issuing approximately 162,000 shares of Harken common stock. The difference between the carrying value of the preferred dividend liability at June 30, 2005, approximately $373,000, and the fair market value of the shares of Harken common stock issued by Harken in settlement of the liability in June 2005, approximately $71,000, is recognized as a Payment of preferred stock dividends in the Consolidated Statement of Operations as of December 31, 2005 as a $302,000 increase to Net income / (loss) attributed to common stock. Harken paid the dividends on the Series G1 Preferred and Series G2 Preferred accrued at December 31, 2005, of approximately $10,000, with cash.

The number of common and preferred shares outstanding and shares held in treasury during 2004 and 2005 are as follows:


	Number of Shares
Description	Preferred G1		Preferred G2		Preferred G3		Series G4		Series J		Series L		Series M	Common		Treasury
Balance as of December 31, 2003	325,000		62,000		77,000		—		—		—		—	185,405,000		(606,000	)
Issuances of common stock	—		—		—		—		—		—		—	3,646,000		—
Issuances of preferred stock	—		—		—		—		50,000		50,000		50,000	—		—
Issuances of preferred dividends	—		—		—		—		—		—		—	742,000		—
Conversion/Redemption of Convertible Notes	—		—		—		—		—		—		—	2,611,000		—
Conversions of G1 Preferred	(310,000	)	—		—		—		—		—		—	2,979,000		—
Conversions of G2 Preferred	—		(37,000	)	—		—		—		—		—	1,349,000		—
Conversions of G3 Preferred	—		—		(77,000	)	—		—		—		—	15,502,000		—
Redemptions of L Preferred	—		—		—		—		—		(40,000	)	—	7,381,000		—
Conversions of G1 to G4 Preferred	(1,000	)	—		—		76,000		—		—		—	—		—
Conversions of G2 to G4 Preferred	—		(23,000	)	—		2,000		—		—		—	—		—
Treasury shares purchased	—		—		—		—		—		—		—	—		(2,000,000	)

Balance as of December 31, 2004	14,000		2,000		—		78,000		50,000		10,000		50,000	219,615,000		(2,606,000	)

Conversions of Convertible Notes	—		—		—		—		—		—		—	10,214,000		—
Issuances of preferred stock	—		—		—		—		—		—		—	162,000		—
Conversions/Redemptions of G1 Preferred	(12,000	)	—		—		—		—		—		—	4,000		—
Conversions/Redemptions of G2 Preferred	—		(1,000	)	—		—		—		—		—	17,000		—
Conversions/Redemptions of G4 Preferred	—		—		—		(78,000	)	—		—		—	—		—
Redemptions of L Preferred	—		—		—		—		—		(10,000	)	—	2,048,000		—
Exercise of L warrants	—		—		—		—		—		—		—	544,000		—
Redemptions of J Preferred	—		—		—		—		(50,000	)	—		—	—		—
Treasury shares purchased	—		—		—		—		—		—		—	—		(6,422,000	)
Treasury shares cancelled	—		—		—		—		—		—		—	(9,028,000	)	9,028,000

Balance as of December 31, 2005	2,000		1,000		—		—		—		—		50,000	223,576,000		—

Accumulated Other Comprehensive Income — At January 1, 2003, the balance in Other comprehensive income was the accumulated foreign currency translation adjustment relating to prior periods. Since 1998, Harken has accounted for its international operations using the U.S. dollar as the functional currency, and as such, foreign currency gains and losses are reflected in the Statement of Operations. During 2003, Harken recorded unrealized holding gains of $606,000 on its available for sale investment Other comprehensive income in stockholders’ equity in Harken’s Consolidated Balance Sheet at December 31, 2003. In February 2004, upon the sale of Harken’s available for sale investment, the accumulated holding gain of $606,000 in Other Comprehensive Income was realized in earnings.

Private Placement of Common Stock - In March 2004, Harken issued 3.6 million shares of Harken common stock in a private placement offering to two institutional investors for a total of $3.2 million in cash, less transaction costs. In connection with this private placement common stock offering, in March 2004, Harken issued to those investors, warrants to purchase 1.75 million shares of Harken’s common stock. These warrants expired in March 2005.

Issuance of Convertible Notes - In December 2003, Harken issued to qualified purchasers a total of $5 million of 4.25% Convertible Notes. At December 31, 2005, the 4.25% Convertible Notes are no longer issued and outstanding. During 2004, Harken extinguished certain amounts of the 4.25% Convertible Notes by issuing shares of Harken common stock based on the conversion price in accordance with the original terms of the note agreements. See Note 9—Convertible Notes Payable for further discussion.

In August 2004, Harken issued to qualified purchasers a total of $5.245 million aggregate principal amount of its 5% Notes which are convertible into shares of Harken common stock at a conversion price of $0.52, subject to adjustments in certain circumstances. During 2005, Harken converted the 5% Notes unto shares of its common stock. At December 31, 2005, the 5% Notes are no longer issued and outstanding. See Note 9 - Convertible Notes Payable for further discussion.

Stockholder Rights Plan — In April 1998, Harken adopted a rights agreement (the “Rights Agreement”) whereby a dividend of one preferred share purchase right (a “Right”) was paid for each outstanding share of Harken common stock. The Rights will be exercisable only if a person acquires beneficial ownership of 15% or more of Harken common stock (an “Acquiring Person”), or commences a tender offer which would result in beneficial ownership of 15% or more of such stock. When they become exercisable, each Right entitles the registered holder to purchase from Harken one one-thousandth of one share of Series E Junior Participating Preferred Stock (“Series E Preferred Stock”), at a price of $35.00 per one one-thousandth of a share of Series E Preferred Stock, subject to adjustment under certain circumstances. During 2002, Harken’s Board of Directors amended the Rights Agreement to exclude from the definition of an Acquiring Person certain parties who have received or would receive beneficial ownership pursuant to certain transactions.

Upon the occurrence of certain events specified in the Rights Agreement, each holder of a Right (other than an Acquiring Person) will have the right to purchase, at the Right’s then current exercise price, shares of Harken common stock having a value of twice the Right’s exercise price. In addition, if, after a person becomes an Acquiring Person, Harken is involved in a merger or other business combination transaction with another person in which Harken is not the surviving corporation, or under certain other circumstances, each Right will entitle its holder to purchase, at the Right’s then current exercise price, shares of common stock of the other person having a value of twice the Right’s exercise price.

Unless redeemed by Harken earlier, the Rights will expire on April 6, 2008. Harken will generally be entitled to redeem the Rights in whole, but not in part, at $.01 per Right, subject to adjustment. No Rights were exercisable under the Rights Agreement at December 31, 2005. The terms of the Rights generally may be amended by Harken without the approval of the holders of the Rights prior to the public announcement by Harken or an Acquiring Person that a person has become an Acquiring Person.

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STOCK OPTION PLAN

Harken and Global account for its stock option plans in accordance with APB 25 and related Interpretations. Under APB 25, if the exercise price of employee stock options equals or exceeds the market price of the underlying stock on the date of grant, generally, no compensation expense is recognized. In July 2004, the board of directors of Global modified the Global Share plan to include a cashless exercise feature which changed the plan from a fixed plan to a variable plan. Accordingly, Global recorded share-based compensation expense attributable to the vested options effective as of the date of the modification. The compensation expense was equal to the difference between the exercise price of the options and Global’s stock price on the date of modification. Compensation costs relating to the unvested options are recorded over the remaining vesting period. Additionally, since the Global share price was greater than the option exercise price, variable plan accounting requires compensation expense (or benefit) to be recognized for subsequent changes in Global’s share price for all options outstanding under the plan.

During the years ended December 31, 2004 and 2005, Global recognized total share-based compensation expense of approximately $5.9 million and $6.4 million, respectively, included in General and administrative expenses, in the Consolidated Statement of Operations attributable to the unexercised Global options as a result of increases in the Global share price.

Previously, Harken’s 1993 Stock Option and Restricted Plan authorized the grant of options to Harken employees and directors for up to 400,000 shares of Harken common stock. Harken’s 1996 Stock Option and Restricted Stock Plan authorized the grant of 1,852,500 shares of Harken common stock. All options granted under these plans had 10-year terms, vested and became fully exercisable at the end of four years of continued employment. In 2004, all of Harken’s previously issued and/or outstanding employee stock options had expired or were previously voluntarily surrendered. In 2004 and after duly authorized action by Harken’s Board of Directors, Harken’s stock option plans have been terminated.

Global’s 2002 Stock Option Plan authorized the grant of options to Global employees and directors for up to 4,155,000 shares of Global common stock. All options granted have 10-year terms, vest and become fully exercisable at the end of three years of continued employment. In June 2005, four current Harken employees resigned their respective officer positions of Global and were replaced with Global employees. Global’s Board of Directors, acting under the discretionary provisions of the Global Share Plan, approved a resolution which resulted in the Global options granted to those four individuals to become fully vested. In accordance with the terms of the Global Share Plan, as amended, the options granted to the four individuals expire on June 16, 2007.

The weighted average fair value of Harken’s options issued in 2003 and 2004 was $0.19 and $0.19 per share, respectively. The weighted average fair value of Global’s options issued in 2004 and 2005 was 151 UK pence and 265 UK pence share, respectively.

A summary of Harken’s and Global’s stock option activity, and related information for the years ended December 31, 2003, 2004 and 2005 follows (not in thousands):

Harken Energy Corporation (US dollars)


	Year Ended December 31,
	2003				2004				2005
	Options		Weighted- Average Exercise Price		Options		Weighted- Average Exercise Price		Options	Weighted- Average Exercise Price
Outstanding-beginning of year	1,444,485		$	20.45	6,000		$	21.40	—	$	—
Granted	50,000		$	0.23	—		$	—	—		—
Exercised	—		$	—	—		$	—	—		—
Forfeited	(1,488,485	)	$	19.78	(6,000	)	$	21.40	—		—

Outstanding-end of year	6,000		$	21.40	—		$	—	—	$	—
Exercisable-end of year	6,000		$	21.40	—		$	—	—	$	—

Global Energy Development (UK pounds sterling)


	Year Ended December 31,
	2003			2004				2005
	Options	Weighted- Average Exercise Price		Options		Weighted- Average Exercise Price		Options		Weighted- Average Exercise Price
Outstanding-beginning of year	3,375,000	£	0.50	3,375,000		£	0.50	4,023,000		£	0.70
Granted	—	£	—	780,000		£	1.51	270,000		£	2.65
Exercised	—	£	—	(132,000	)	£	0.50	(245,000	)	£	0.51
Forfeited	—	£	—	—		£	—	—		£	—

Outstanding-end of year	3,375,000	£	0.50	4,023,000		£	0.70	4,048,000		£	0.84
Exercisable-end of year	1,125,000	£	0.50	3,250,000		£	0.51	3,377,000		£	0.61

All stock options granted, exercised and outstanding as of the years ended December 31, 2004 and 2005 are related to Global.

100

(13)

INCOME TAXES

The total provision for income taxes/(benefit) consists of the following:


	Year Ended December 31,
	2003			2004		2005
	(in thousands)
Current Taxes:
Federal - AMT	$	53		$	18	$	18
State		—			—		—
Foreign - Colombia		(237	)		561		715
Deferred		—			—		—

Total	$	(184	)	$	579	$	733

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2003, 2004, 2005 to the amount of income tax expense (benefit) that would result from applying domestic federal statutory tax rates to pretax income:


	Year Ended December 31,
	2003			2004			2005
	(in thousands)
Statutory tax expense/(benefit)	$	(421	)	$	(5,887	)	$	14,862
Decrease in valuation allowance:
Net change in valuation allowance related to capital losses		—			—			(20,670	)
Other		56			2,109			2,611
Effect of foreign operations		(237	)		(400	)		(238	)
Interest expense disallowed for tax		383			99			87
Global warrant losses not recognized for tax		—			4,830			4,094
Minority interest and other		35			(172	)		(13	)

Total Tax Expense/(Benefit)	$	(184	)	$	579		$	733

At December 31, 2005, Harken had available for U.S. federal income tax reporting purposes, a net operating loss (NOL) carryforward for regular tax purposes of approximately $100,000,000 which expires in varying amounts during the tax years 2006 through 2025, an alternative minimum tax NOL carryforward of approximately $90,000,000 which expires in varying amounts during the tax years 2006 through 2025, and a statutory depletion carryforward of approximately $5,000,000 which can be carried forward indefinitely to offset future taxable income of Harken, subject to certain limitations imposed by the Internal Revenue Code. Additionally, at December 31, 2005, Harken has a capital loss carryforward of approximately $100,000,000 which will expire in 2009 and 2010. Current federal income tax law allows corporations to deduct capital losses only if they offset capital gains. In March 2003, Harken underwent a change in ownership, within the meaning of Internal Revenue Code Section 382 that will significantly restrict Harken’s ability to utilize its domestic NOLs and capital losses. At December 31, 2005, Harken had available for Colombian income tax reporting purposes a NOL carryforward of approximately $134,000,000 (US Dollars) that expires in varying

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amounts during the Colombian tax years 2006 through 2007. At December 31, 2005, Harken had available for UK income reporting purposes an NOL carryforward of approximately $6,000,0000 which will carryforward indefinitely.

Total deferred tax liabilities, relating primarily to U.S. oil and gas properties as of December 31, 2005, were approximately $2 million. Total deferred tax assets were approximately $144 million at December 31, 2005. The total net deferred tax asset is offset by a valuation allowance of approximately $142 million at December 31, 2005, resulting in no impact to results of operations. Deferred tax assets as of December 31, 2005 were as follows:


Year Ended December 31, 2005 (in thousands)
Domestic Net Operating Loss	$	34,200
Depletion Carryover		1,700
Deferred Liabilities		1,900
Foreign Net Operating Losses		47,600
Share Based Compensation		3,600
Book vs. Tax Equity in Subsidiary		20,700
Capital Loss Carryover		34,300

	$	144,000

Total deferred tax liabilities, relating primarily to U.S. oil and gas properties as of December 31, 2004, were approximately $800,000. Total deferred tax assets were approximately $85.6 million at December 31, 2004 and consisted of $37.3 million of domestic NOL’s, $45 million of foreign NOL’s, $2.1 million of share based compensation, and $1.2 million of depletion carryover. The total net deferred tax asset is offset by a valuation allowance of approximately $84.8 million at December 31, 2004, resulting in no impact to results of operations.

(14)

RELATED PARTY TRANSACTIONS

In January 2004, pursuant to agreements executed in December 2003, Harken forgave the repayment of outstanding short-term loans in the principal amounts of $80,000 and $25,000 respectively. These loans were originally made to a member of management and to a former member of management and related to the surrender of their Harken stock options. Harken reflected the forgiveness as a charge to earnings in 2003. Such loans were recourse loans secured by their options.

In 2001, Global elected to its Board of Directors a director who is also a director of RP&C International Inc. (“RP&C”). RP&C has historically provided financial and transaction consulting services to Harken. In connection with these services provided, RP&C has earned consulting and transaction fees and may continue to earn such fees in the future. During 2004 and 2005, Harken paid to RP&C approximately $927,000 and $1,054,000, respectively, for transaction costs associated with the sale of certain shares of Global and other transaction consulting services. In connection with these services provided, RP&C may continue to earn such fees in the future.

In September 2005, Lyford exercised its warrants to purchase 7,000,000 shares of Harken’s holdings of Global stock (See Note 8 - Changes in Harken’s Ownership in Global). As of December 31, 2005, Lyford beneficially owned approximately 30% 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. The

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principal of Lyford is Phyllis Quasha, whose son, Alan G. Quasha, is the Chairman of the Board of Directors of Harken.

(15)

DERIVATIVE INSTRUMENTS

GEM holds certain commodity derivative instruments which are effective in mitigating commodity price risk associated with a portion of its future monthly natural gas and crude oil production and related cash flows. GEM’s oil and gas operating revenues and cash flows are impacted by changes in commodity product prices, which are volatile and cannot be accurately predicted. GEM’s objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of its future natural gas sales and crude oil from the risk of significant declines in commodity prices.

During 2004, GEM held a natural gas collar contract consisting of a fixed price floor option of $3.00 per MMBTU and a fixed price cap option of $4.95 per MMBTU covering a notional amount of 70,000 MMBTUs per month. GEM had not designated the above derivative as a hedge under SFAS 133, therefore the derivative was marked to market each period. During 2004, the change in the fair value of the derivative of approximately $303,000 was reflected in Interest and other income in the Consolidated Statement of Operations. Such natural gas collar contract was settled at fair value in June 2004.

In December 2003, GEM purchased a crude oil floor contract with a strike price of $27.00 per barrel for a notional amount of 6,000 barrels per month over a period of the contract from January 1, 2004 through December 31, 2004. In March 2004, GEM terminated this crude oil floor contract and replaced it with a crude oil floor contract with a strike price of $28.00 per barrel for a notional amount of 6,000 barrels per month over a period of the contract from April 1, 2004 through December 31, 2004. In June 2004, GEM terminated this crude oil floor contract and replaced it with a crude oil floor contract with a strike price of $30.00 per barrel for a notional amount of 6,000 barrels per month over a contract period from July through December 2004. GEM designated this derivative as a hedge under SFAS 133. During the year ended December 31, 2004, approximately $105,000 is included as a decrease to Interest and other income in the Consolidated Statement of Operations to reflect the decrease in value of this crude oil floor contract associated with time value. Such crude oil floor contract was settled at fair value in December 2004.

In January 2004, GEM purchased a natural gas floor contract with a strike price of $4.00 per MMBTU for a notional amount of 90,000 MMBTUs per month over the period of the contract from July 1, 2004 through December 31, 2004. GEM designated this derivative as a hedge under SFAS 133. During the year ended December 31, 2004, approximately $54,000 is included as a decrease to Interest and other income in the Consolidated Statement of Operations to reflect the decrease in value of this natural gas floor contract associated with time value. Such natural gas floor contract was settled at fair value in December 2004.

In September 2004, GEM purchased a crude oil floor contract with a strike price of $30.00 per barrel for a notional amount of 6,000 barrels per month over a period of the contract from January 1, 2005 through December 31, 2005. In March 2005, GEM terminated this crude oil floor contract and replaced it with a crude oil floor contract with a strike price of $35.00 per barrel for a notional amount of 6,000 barrels per month over a period of the contract from April 1, 2005 through December 31, 2005. GEM designated this derivative as a cash flow hedge under SFAS 133. During the years ended December 31, 2004 and 2005, approximately $12,000 and $74,000, respectively, is included in Interest expense and other in the Consolidated Statement of Operations to reflect the decrease in value of this crude oil floor contract. This crude oil floor contract was settled at fair value at December 31, 2005.

In October 2004, GEM purchased a natural gas floor contract with a strike price of $5.00 per MMBTU for a notional amount of 70,000 MMBTUs per month over the period of the contract from January 1, 2005 to December 31, 2005. GEM designated this derivative as a cash flow hedge under SFAS 133. At December 31,

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2004, this hedge no longer qualified for hedge accounting treatment under SFAS 133. During the years ended December 31, 2004 and 2005, approximately $15,000 and $83,000, respectively, is included in Interest expense and other in the Consolidated Statement of Operations to reflect the change in fair value of this natural gas floor contract. This natural gas floor contract was settled at fair value at December 31, 2005.

Each of the above option floor contracts were originally designated as cash flow hedges of the exposure from the variability of cash flows from future specified production from certain of GEM’s property operations. Gains and losses from commodity derivative instruments are reclassified into earnings when the associated hedged production occurs.

In September 2005, GEM purchased a crude oil floor contract with a strike price of $45.00 per barrel for a notional amount of 6,000 barrels per month over a period of the contract from January 1, 2006 to June 30, 2006. GEM did not designate this derivative as a cash flow hedge under SFAS 133. This crude oil floor contract is reflected in Prepaid expenses and other current assets in the Consolidated Balance Sheet at December 31, 2005 with a fair market value of approximately $21,000.

In September 2005, GEM purchased a natural gas floor contract with a strike price of $6.00 per MMBTU for a notional amount of 70,000 MMBTUs per month over a period of the contract from January 1, 2006 to June 30, 2006. GEM did not designate this derivative as a cash flow hedge under SFAS 133. This natural gas floor contract is reflected in Prepaid expenses and other current assets in the Consolidated Balance Sheet at December 31, 2005 with a fair market value of approximately $16,000.

Neither Harken nor any of its consolidated companies holds any derivative instruments which are designated as either fair value hedges or foreign currency hedges. Settlements of GEM’s oil and gas commodity derivatives are based on the difference between fixed option prices and the New York Mercantile Exchange closing prices for each month during the life of the contracts. GEM monitors its crude oil production prices compared to New York Mercantile Exchange prices to assure its commodity derivatives are effective hedges in mitigating its commodity price risk.

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(16)

OTHER INFORMATION

Quarterly Data — (Unaudited) — The following tables summarize selected quarterly financial data for 2004 and 2005 expressed in thousands, except per share amounts:


	Quarter Ended												Total Year
	March 31			June 30			September 30			December 31			Total Year
2004
Revenues and other	$	6,677		$	8,158		$	8,308		$	6,599		$	29,742
Gross profit		4,566			5,817			6,305			4,656			21,344
Increase/(decrease) in fair value of Global warrant liability		—			12,481			(1,120	)		2,846			14,207
Share-based compensation expense		—			—			4,167			1,699			5,866
Net income / (loss)		1,511			(12,025	)		(1,274	)		(6,106	)		(17,894	)
Net income / (loss) attributed to common stock		3,409			(11,491	)		(2,750	)		(7,577	)		(18,409	)
Basic income / (loss) per common share		0.02			(0.06	)		(0.01	)		(0.04	)		(0.09	)
Diluted income / (loss) per common share		0.02			(0.06	)		(0.01	)		(0.04	)		(0.09	)
2005
Revenues and other	$	7,347		$	11,601		$	11,568		$	9,618		$	40,134
Gross profit		5,151			8,825			7,620			4,950			26,546
Increase/(decrease) in fair value of Global warrant liability		3,796			4,402			5,099			—			13,297
Share-based compensation expense		2,020			2,448			6,907			(4,969	)		6,406
Net income / (loss)		(6,216	)		15,688			32,810			698			42,980
Net income / (loss) attributed to common stock		(6,610	)		15,691			32,666			646			42,393
Basic income / (loss) per common share		(0.03	)		0.07			0.15			0.00			0.19
Diluted income / (loss) per common share		(0.03	)		0.06			0.14			0.00			0.18

Significant Customers — In 2003 and 2004, Ecopetrol, which purchases the majority of Global’s Colombian oil production, represented, 29% and 30%, respectively, of Harken’s consolidated revenues. In 2005, Braspetro purchased the majority of Global’s Colombian oil production which represented approximately 45% of Harken’s consolidated revenues. In addition, management does not feel that the loss of a significant domestic purchaser would significantly impact the operations of GEM due to the availability of other potential purchasers for its oil and gas production.

Operating Segment Information — Harken divides its operations into four operating segments which are managed and evaluated as separate operations. GEM, a wholly-owned subsidiary of Harken, manages its domestic operations held through its other domestic wholly-owned subsidiaries. GEM’s operating segment currently relates to exploration, development, production and acquisition efforts in the United States. GEM operates primarily through traditional ownership of mineral interests in the various states in which it operates. GEM’s oil and gas production is sold to established purchasers and generally transported through existing and well-developed pipeline infrastructure.

Global’s operating segment currently relates to exploration, development, production and acquisition efforts in Colombia, Peru and Panama. Global’s production cash flows have been discovered through extensive drilling operations conducted under Association and Exploration and Production Contracts with the state-

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owned oil and gas companies/ministries in the respective countries. During the year ended December 31, 2004 and 2005, none of Global’s segment revenues related to Peru or Panama.

Harken’s investment in IBA represents its third operating segment. IBA formerly engaged in trading minimal gas futures contracts in the United States.

Harken’s fourth operating segment, (“HEC Corporate”), operates and manages Harken’s investments in GEM, Global and IBA. HEC Corporate also manages public company compliance and may seek to raise financing through the issuance of debt, equity and convertible debts instruments, if needed, for the utilization of acquisition and development opportunities as they arise.

Harken’s accounting policies for each of its operating segments are the same as those for its consolidated financial statements. There were no intersegment sales or transfers for the periods presented. Revenues and expenses not directly identifiable with any segment, such as certain general and administrative expenses, are allocated by Harken based on various internal and external criteria including an assessment of the relative benefit to each segment.

See Note 18 – Oil and Gas Disclosures for geographic information regarding GEM’s and Global’s long-lived assets. Harken’s financial information, expressed in thousands, for each of its operating segments is as follows for each of the three years in the period ended December 31, 2005:


	For the Twelve Months Ending December 31, 2003
	HEC Corp			GEM			Global			IBA			Total
Operating revenues	$	—		$	18,753		$	8,556		$	—		$	27,309
Oil and gas operating expenses		—			7,071			2,398			—			9,469
Interest and other income		(139	)		25			95			—			(19	)
Depreciation and amortization		510			5,294			3,137			—			8,941
Litigation and contingent liability settlements, net		—			1,125			—			—			1,125
Increase in Global warrant liability		7			—			—			—			7
Interest expense and other, net		2,594			690			110			—			3,394
Gain on exercise of Global warrants		—			—			—			—			—
Gain on sale of subsidiary shares		—			—			—			—			—
Income tax expense		53			—			(237	)		—			(184	)
Segment income/(loss)		(3,002	)		1,386			619			—			(997	)
Capital expenditures		128			4,299			4,149			—			8,576
Total Assets		7,675			46,941			26,396			—			81,012

	For the Twelve Months Ending December 31, 2004
	HEC Corp			GEM			Global			IBA			Total
Operating revenues	$	—		$	18,334		$	10,974		$	—		$	29,308
Oil and gas operating expenses		—			5,428			2,536			—			7,964
Interest and other income		454			371			(185	)		(206	)		434
Depreciation and amortization		502			6,802			3,400			9			10,713
Increase in Global warrant liability		14,207			—			—			—			14,207
Interest expense and other, net		474			(62	)		2			—			414
Gain on exercise of Global warrants		—			—			—			—			—
Gain on sale of subsidiary shares		—			—			—			—			—
Income tax expense		(8	)		—			561			26			579
Segment income/(loss)		(16,733	)		3,591			(3,855	)		(897	)		(17,894	)
Capital expenditures		94			8,676			8,891			106			17,767
Total Assets		10,889			51,781			33,108			11,703			107,481

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	For the Twelve Months Ending December 31, 2005
	HEC Corp		GEM		Global			IBA			Total
Operating revenues	$	—	$	18,164	$	19,045		$	—		$	37,209
Oil and gas operating expenses		—		5,320		5,343			—			10,663
Interest and other income		755		227		1,292			651			2,925
Depreciation and amortization		99		5,923		5,300			47			11,369
Increase in Global warrant liability		12,040		—		1,257			—			13,297
Interest expense and other, net		126		410		316			637			1,489
Gain on exercise of Global warrants		28,341		—		—			—			28,341
Gain on sale of subsidiary shares		32,452		—		—			—			32,452
Income tax expense		15		—		715			3			733
Segment income/(loss)		45,658		3,423		(3,284	)		(2,817	)		42,980
Capital expenditures		48		15,691		17,854			37			33,630
Total Assets		26,236		62,911		55,377			8,904			153,428

(17)

EARNINGS (LOSS) PER SHARE

Basic earnings per share includes no dilution and is computed by dividing income or loss attributed to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if security interests were exercised or converted into common stock.

The following table sets forth the computation of basic and diluted earnings / (loss) per share for the years ended December 31, 2003, 2004 and 2005.


	2003							2004							2005
(in thousands,except per share data)	Net (loss) Attributed to Common Stock			Weighted -Average Shares	Per- Share (Loss)			Net loss Attributed to Common Stock			Weighted -Average Shares	Per-Share (Loss)			Net earnings Attributed to Common Stock		Weighted -Average Shares	Per-Share earnings
Basic earnings per share	$	2,132		112,695	$	0.02		$	(18,409	)	201,702	$	(0.09	)	$	42,393	219,370	$	0.19
Effect of dilutive securities:
5% European Notes ^(A)		(5,254	)	95		(0.05	)		—		—		—			—	—		—
Preferred Stock ^(B)		—		—		—			—		—		—			844	24,265		(0.01	)

Diluted earnings per share	$	(3,122	)	112,790	$	(0.03	)	$	(18,409	)	201,702	$	(0.09	)		43,237	243,635		0.18

^(A)	Represents 5% European Notes extinguished in March and May 2003. Gains on these transactions have been treated as a reduction to income attributed to common stock as such gains would not have occurred had these securities been converted by the holder.

^(B)	Represent dividends paid to and redemptions of Harken’s preferred stock instruments. These increases (decreases) to income attributed to common stock would not have occurred had these securities been converted by the holder.

Not included in the calculation for diluted earnings per share were 6,000 employee stock options outstanding during the year ended December 31, 2003. Harken’s 4.25% Convertible Notes, 5% Convertible Notes, 7% European Notes, Benz Convertible Notes and Series G-1, G-2, G-3, G-4, J, L and M Preferred Stock were also excluded from the calculation of diluted earnings per share as their effect would have been antidilutive. The inclusion of these options would have been antidilutive since they were not “in the money” at the end of the respective years. Since Harken incurred net losses attributed to common stock for 2004, no dilution of the net losses per share would have resulted from the assumed conversions of the convertible notes and convertible preferred stock, discussed above.

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(18)

OIL AND GAS DISCLOSURES

Costs incurred in property acquisition, exploration and development activities, expressed in thousands:


	Year Ended December 31,
	2003		2004		2005
GEM costs incurred:
Acquisition of properties Evaluated	$	—	$	—	$	—
Exploration		337		366		3,936
Development		2,764		7,595		10,296
Cumulative effect of asset retirement costs		1,326		—		—

Total domestic costs incurred	$	4,427	$	7,961		14,232

GLOBAL costs incurred:
Exploration	$	323	$	40	$	827
Development		3,470		8,365		16,014
Cumulative effect of asset retirement costs		356		—		—

Total Middle American costs incurred	$	4,149	$	8,405	$	16,841

Global costs during 2003 include $139,000 and $184,000 of costs related to Peru and Panama, respectively. Global costs during 2004 include $35,000 and $5,000 of costs related to Peru and Panama respectively. Global costs during 2005 include $794,000 and $33,000 of costs related to Peru and Panama respectively.

Capitalized Costs Relating to Oil and Gas Producing Activities, expressed in thousands:


	As of December 31,
	2003			2004			2005
Capitalized costs:
Unevaluated Peru properties	$	701		$	736		$	1,530
Unevaluated Panama properties		488			493			526
Unevaluated GEM properties		1,923			914			4,247
Evaluated Colombia properties		188,219			196,649			212,684
Evaluated domestic properties		153,863			163,055			173,584
Colombian production facilities		15,931			16,210			17,273
GEM production facilities		508			508			1,273

Total capitalized costs		361,633			378,565			411,117
Less accumulated depreciation and amortization		(299,791	)		(309,833	)		(320,832	)

Net capitalized costs	$	61,842		$	68,732		$	90,285

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Results of Operations from Oil and Natural Gas Producing Activities

(thousands of dollars)


	Year Ended December 31,
	2003			2004		2005
Oil and natural gas revenues	$	27,309		$	29,308	$	37,209
Less:
Oil and natural gas operating costs		9,469			7,964		10,663
Depreciation and amortization		8,941			10,713		11,369
Provision for asset impairments		—			—		—
Full cost valuation allowance		—			—		—
Accretion expense		460			388		384
Income tax expense /(benefit)		(184	)		579		733

		18,686			19,644		23,149

Results of operations from oil and natural gas producing activities	$	8,623		$	9,664	$	14,060

Oil and Gas Reserve Data — (Unaudited) — The following information is presented with regard to GEM’s and Global’s proved oil and gas reserves. The reserve values and cash flow amounts reflected in the following reserve disclosures are based on prices as of year end. Global reflected proved reserves in Colombia related to its Alcaravan, Bolivar, Bocachico Association Contracts and the Rio Verde and Luna Llena Exploration and Production Concession Contract. Global has reflected no proved reserves related to its Peru or Panama operations.

In February and October 2001, Global was notified by Ecopetrol that Global could proceed with the development and production of the Buturama and Palo Blanco fields, respectively, on a sole-risk basis. As such, Global is entitled to receive Ecopetrol’s share of production after royalty, until Global has recovered 200% of its costs, after which time Ecopetrol could elect to begin to receive its 50% working interest share of production. In light of Ecopetrol’s election not to participate in these fields and in light of Global’s plans to undertake a gas injection project thereby reducing the royalty payment to 8%, Global has reflected its 92% share of future net cash flows from the Buturama field in its proved reserves as of December 31, 2005.

In 2004, Global was advised of Ecopetrol’s intent to declare the Cajaro #1 well commercial pursuant to the Alcaravan Contract terms. As of November 9, 2005, Global and Ecopetrol continue to negotiate the terms of Ecopetrol’s commerciality declaration, including the extent of the commercial area and the unitization of the Cajaro #1 commercial area and a portion of Global’s Los Hatos Exploration and Production Contract which is adjacent to the Alcaravan Contract area. As a result, Global’s net revenue interest in the production from the Mirador discovery on the Cajaro #1 well has been affected by Ecopetrol’s declaration of commerciality. Effective as of October 1, 2004, production from Cajaro #1 associated with the Alcaravan Contract area has been and will continue to be allocated until the finalization of the unitization proceedings as follows: Ecopetrol, on behalf of the Colombian government, receives a royalty interest of 8% of all production, and all production (after royalty payments) attributable to the Alcaravan Contract area is allocated 10.5% to Ecopetrol and 89.5% to Global. During 2005, Ecopetrol submitted a revised and reduced commerciality area associated with the Cajaro #1 well for the consideration of Global.

Based upon the extent of the area declared commercial in relation to the Cajaro #1 well by Ecopetrol, Global advised Ecopetrol, ANH and the Ministry of Energy that Global’s Los Hatos Exploration and Production Contract area, which is adjacent to Global’s Alcaravan Contract, is being drained of Mirador formation oil reserves located beneath the Los Hatos Contract. Because two contract areas are being drained by one well, Colombian law requires the division of reserves and revenues be settled through a unitization proceeding. This proceeding could affect the Cajaro #1 net revenues and costs assigned to both Ecopetrol and Global. Based on the commerciality maps and data currently under review by both Global and Ecopetrol, 21%

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of the crude produced by Cajaro is deemed to be from the Alcaravan Contract and Global has reflected a 50% interest in net production from the Cajaro #1 well associated with the Alcaravan Contract area in the cash flows and results of operations in its financial statements. Based upon the revised commerciality area currently under review by both Global and Ecopetrol and the allocation of production of the Cajaro #1 during 2005, Global has recorded a receivable of approximately $2 million from Ecopetrol attributable to 1) the production volumes delivered to Ecopetrol in excess of Ecopetrol’s share of post-commerciality revenue and 2) Ecopetrol’s share of post-commerciality development costs and operating expenses.

All Colombian proved reserves are net of the Colombian Ministry of Energy’s royalty and any Ecopetrol back-in after payout pursuant to each related Association and Concession Contract. Global’s Colombian reserves in the Bolivar, Alcaravan and Bocachico, Rio Verde and Luna Llena Contract Blocks have been prepared by Ryder Scott Company. For further discussion of Global’s Colombian operations, see Note 7 – Global’s Middle American Operations.

GEM’s reserve estimates at December 31, 2005 have been prepared by Netherland, Sewell & Associates, Inc.

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. 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.

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 base 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.

“Standardized measure” relates to the estimated discounted future net cash flows, as adjusted for Global’s and GEM’s asset retirement obligations, and major components of that calculation relating to proved reserves at the end of the year in the aggregate and by geographic area, based on year end prices, costs, and statutory tax rates and using a 10% annual discount rate. Prices at December 31, 2004 were based on NYMEX prices of $40.25/barrel and $6.18/mmbtu, as adjusted for quality differentials. Prices at December 31, 2005 were based on the West Texas Intermediate price of $57.75/barrel and the Henry Hub $10.08/mmbtu, as adjusted by field for quality, transportation and regional price differentials.

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	(Unaudited)
	United States				Colombia			Total Worldwide
	Oil (Barrels)		Gas (Mcf)		Oil (Barrels)		Gas (Mcf)	Oil (Barrels)		Gas (Mcf)
	(in thousands)
Proved reserves:
As of December 31, 2002	3,286		34,508		5,493		—	8,779		34,508
Extensions and discoveries	—		706		—		—	—		706
Revisions	(131	)	(3,404	)	(722	)	—	(853	)	(3,404	)
Production	(238	)	(2,133	)	(394	)	—	(632	)	(2,133	)
Sales of reserves in place	(1,569	)	(15,463	)	—		—	(1,569	)	(15,463	)

As of December 31, 2003	1,348		14,214		4,377	⁽¹⁾	—	5,725	⁽¹⁾	14,214
Extensions and discoveries	310		1,760		490		—	800		1,760
Revisions	(70	)	(859	)	(175	)	—	(245	)	(859	)
Production	(182	)	(1,788	)	(366	)	—	(548	)	(1,788	)
Sales of reserves in place	—		—		(126	)	—	(126	)	—

As of December 31, 2004	1,406		13,327		4,200	⁽¹⁾	—	5,606	⁽¹⁾	13,327
Extensions and discoveries	16		497		206		—	222		497
Revisions	(4	)	(3,995	)	857		—	853		(3,995	)
Improved recovery	—		—		13		—	13		—
Production	(135	)	(1,299	)	(443	)	—	(578	)	(1,299	)
Purchases of reserves in place	14		571		202		—	216		571
Sales of reserves in place	(50	)	(648	)	—		—	(50	)	(648	)

As of December 31, 2005	1,247		8,453		5,035	⁽¹⁾	—	6,282	⁽¹⁾	8,453

Proved developed reserves at:
December 31, 2003	768		9,488		1,178	⁽²⁾	—	1,946	⁽²⁾	9,488
December 31, 2004	553		2,391		1,282	⁽³⁾	—	1,835	⁽³⁾	2,391
December 31, 2005	975		7,643		1,960	⁽⁴⁾	—	2,935	⁽⁴⁾	7,643

⁽¹⁾	Includes approximately 629,000, 615,000 and 3,336,000 barrels of total proved reserves attributable to a 14.38%, 14.65% and 66.25% minority interest of a consolidated subsidiary at December 31, 2003, 2004 and 2005, respectively.

⁽²⁾	Includes approximately 169,000 barrels of total proved developed reserves attributable to a 14.38% minority interest of a consolidated subsidiary.

⁽³⁾	Includes approximately 188,000 barrels of total proved developed reserves attributable to a 14.65% minority interest of a consolidated subsidiary.

⁽⁴⁾	Includes approximately 1,299,000 barrels of total proved developed reserves attributable to a 66.25% minority interest of a consolidated subsidiary.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:


	(Unaudited)
	United States			Colombia			Total Worldwide
	(in thousands)
December 31, 2004:
Future cash inflows	$	150,816		$	152,183		$	302,999
Production costs		(43,489	)		(37,891	)		(81,380	)
Development costs		(23,046	)		(15,216	)		(38,262	)
Future income taxes		(936	)		(4,254	)		(5,190	)

Future net cash flows		83,345			94,822			178,167
10% discount factor		(24,835	)		(28,682	)		(53,517	)

Standardized measure of discounted future net cash flows ⁽²⁾	$	58,510		$	66,140	⁽¹⁾	$	124,650	⁽¹⁾

December 31, 2005:
Future cash inflows	$	164,998		$	234,439		$	399,437
Production costs		(47,899	)		(61,096	)		(108,995	)
Development costs		(17,357	)		(19,571	)		(36,928	)
Future income taxes		(1,162	)		(4,725	)		(5,887	)

Future net cash flows		98,580			149,047			247,627
10% discount factor		(25,012	)		(44,606	)		(69,618	)

Standardized measure of discounted future net cash flows ⁽³⁾	$	73,568		$	104,441	⁽²⁾	$	178,009	⁽²⁾

⁽¹⁾	Includes approximately $9,690,000 of discounted future net cash flows attributable to a 14.65% minority interest of a consolidated subsidiary.

⁽²⁾	Includes approximately $69,192,000 of discounted future net cash flows attributable to a 66.25% minority interest of a consolidated subsidiary.

⁽³⁾	Cash flows associated with asset retirement obligations are included in the Standardized Measure of Discounted Future Net Cash Flows.

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	(Unaudited)
	2003			2004			2005
	(in thousands)
Worldwide
Standardized measure — beginning of year	$	160,237	⁽¹⁾	$	107,076	⁽²⁾	$	124,650	⁽³⁾
Increase (decrease)
Sales, net of production costs		(17,840	)		(21,344	)		(26,546	)
Net change in prices, net of production costs		34,007			43,922			66,957
Development costs incurred		6,111			16,192			13,441
Change in future development costs		2,856			(13,478	)		(7,361	)
Change in future income taxes		205			3,355			(499	)
Revisions of quantity estimates		(22,513	)		(8,161	)		1,898
Accretion of discount		16,024			10,707			12,637
Changes in production rates, timing and other		(39,517	)		(27,718	)		(20,570	)
Extensions and discoveries, net of future costs		1,776			14,099			8,690
Sales of reserves-in-place		(34,270	)		—			(1,579	)
Purchases of reserves-in-place		—			—			6,291

Standardized measure — end of year	$	107,076	⁽²⁾	$	124,650	⁽³⁾	$	178,009	⁽⁴⁾

⁽¹⁾	Includes approximately $8,349,000 of discounted future net cash flows attributable to a 14.38% minority interest of a consolidated subsidiary.

⁽²⁾	Includes approximately $7,598,000 of discounted future net cash flows attributable to a 14.38% minority interest of a consolidated subsidiary.

⁽³⁾	Includes approximately $9,690,000 of discounted future net cash flows attributable to a 14.65% minority interest of a consolidated subsidiary.

⁽⁴⁾	Includes approximately $69,192,000 of discounted future net cash flows attributable to a 66.25% minority interest of a consolidated subsidiary.

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(19)

COMMITMENTS AND CONTINGENCIES

Operating Leases — Harken leases its corporate and certain other office space and certain field operating offices. Total office lease payments for Harken, GEM, Global and IBA during 2003, 2004 and 2005 totaled $698,000, $465,000 and $756,000, respectively, net of applicable sublease arrangements. Future minimum rental payments required under all leases that have initial or remaining noncancellable lease terms in excess of one year as of December 31, 2005, net of sublease reimbursements of $214,000, in 2006, are as follows:


Year	Amount
2006	$	709,000
2007		371,000
2008		277,000
2009		240,000
2010		242,000
Thereafter		262,000

Total minimum payments required	$	2,101,000

In September 1997, Harken Exploration Company, a wholly-owned subsidiary of Harken, was served with a lawsuit filed in U.S. District Court for the Northern District of Texas, Amarillo Division, styled D. E. Rice and Karen Rice, as Trustees for the Rice Family Living Trust (“Rice”) vs. Harken Exploration Company. In the lawsuit, Rice alleged damages resulting from Harken Exploration Company’s alleged spills on Rice’s property and claimed that the Oil Pollution Act (“OPA”) should have applied in this circumstance. Rice alleged that remediation of all of the alleged pollution on its land would cost approximately $40 million.

In October 1999, the trial court granted Harken’s Motion for Summary Judgment that the OPA did not apply and dismissed the Rice claim under it. Rice appealed the trial court’s summary judgment to the U.S. Fifth Circuit Court of Appeals. In April 2001, the Fifth Circuit Court of Appeals issued its opinion affirming the trial court’s summary judgment in Harken’s favor. Rice did not appeal the Fifth Circuit Court of Appeals decision. On August 15, 2002, Harken was served with a new suit filed by Rice in state court in Hutchinson County, Texas. In this new state case, Rice sought approximately $40 million in remediation costs and damages. Formal mediation of this matter took place in January 2004. Following mediation, the parties reached a settlement agreement, whereby Harken and Harken’s insurers agreed to pay to Rice the total sum of $1.9 million in return for a full and final release for all disputes and claims alleged by Rice against Harken. The insurer agreed to contribute $775,000 of this settlement amount. Based on the settlement agreement and the contribution from the insurers, Harken has accrued and expensed $1.125 million in December 2003. Harken’s insurers, pursuant to a separate Fifth Circuit Court of Appeals order, have covered Harken’s legal costs of defense in the litigation. In April 2004 the trial court, upon joint motion of the parties, dismissed the Rice lawsuit in its entirety.

420 Energy Investment, Inc. and ERI Investments, Inc. (collectively “420 Energy”) filed a lawsuit against XPLOR Energy, Inc., a wholly-owned subsidiary of Harken (“XPLOR”), on December 21, 1999 in the New Castle County Court of Chancery of the State of Delaware. In their complaint, 420 Energy alleged that they were entitled to appraisal and payment of the fair value of their common stock in XPLOR as of the date XPLOR merged with Harken. Harken has relied on an indemnity provision in the XPLOR merger agreement to tender the costs of defense in this matter to former stockholders of XPLOR. In April 2004, 420 dismissed this lawsuit in its entirety.

In May 2002, Henry C. Magee III (“Magee”) filed a complaint against XPLOR Energy SPV-I, Inc. and XPLOR Energy Operating Company, as the successor in Interest to Araxas SPV-I, Inc. and Araxas Exploration, Inc. in the United States District Court for the Eastern District of Louisiana. In his complaint,

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Magee alleges that XPLOR breached a contractual obligation relating to a royalty interest assignment from XPLOR’s predecessor in interest, Araxas Exploration, Inc. The court granted Magee’s motion for summary judgment as to a disputed interpretation of the assignment clause but reserved for trial XPLOR’s reformation claim. Subsequent to the summary judgment, Magee asserted additional claims relating to his purported royalty interest assignment.

On September 10, 2004, all parties to the Magee litigation agreed to settle all matters in dispute and related to the disputes at issue in that litigation. The settlement resulted in Harken contributing approximately $157,000 in cash for settlement and compromise of the Magee claims. On December 9, 2004 the parties filed a Joint Motion to dismiss the Magee lawsuit. On December 10, 2004, the court signed and entered its order and judgment dismissing with prejudice the Magee lawsuit.

In October 2003, Xplor was served with a complaint filed by Apache Corporation in the Harris County District Court. Apache sought payment of $219,000 plus interest and attorneys’ fees. Apache alleged that the amount demanded was due pursuant to the terms of a 1998 purchase and sale agreement between Apache and Xplor. In March 2004, Apache and Xplor entered into a compromise and settlement agreement resolving all disputes between the parties and resulting in the dismissal with prejudice to refiling of this case.

In September 2003, Harken de Colombia Ltd. (“HDC”), a Harken subsidiary, obtained a copy of a demand submitted on behalf of several former employees of Geophysical Acquisition & Processing Services Ltd. (“GAPS”), a subcontractor to HDC. In their demand, the former GAPS employees request that the Colombian labor courts in Bogotá, Colombia, declare Harken de Colombia jointly liable with GAPS for past wages allegedly due to the former GAPS employees. Harken disputes the allegations submitted by the former GAPS employees and will vigorously defend against those allegations. A similar claim brought by another group of former GAPS employees in La Dorada, Colombia, was successfully rejected by Harken and dismissed by the labor court in that city. In 2003, the court dismissed the claims of the GAPS employees.

In late 2004, HDC determined that a property owner had instituted an action in Colombia against Grant Geophysical, Inc. a subcontractor to HDC, alleging that his property had been damaged by an amount of approximately $1.9 million as a result of certain seismic activities conducted by Grant Geophysical, Inc. on the claimants property. As of March 16, 2005, HDC has not been joined in the litigation, served or officially notified of any claims against it. As a result, Harken considers the claim to be unasserted. HDC’s subcontract with Grant Geophysical contains an indemnity provision requiring Grant Geophysical, Inc. to indemnify HDC for any losses. While HDC will continue to monitor this matter, Harken believes that the ultimate outcome of this matter will not have a material adverse effect on Harken’s financial conditions and results of operations.

On May 31, 2005, the Colombian federal taxing authority, referred to by its Spanish acronym as “DIAN,” issued an Official Tax Assessment with regard to HDC’s tax return for 2001. The tax assessment includes a presumptive income tax (“PIT”) equal to approximately $605,000 and an inaccuracy fine of $968,000. The described tax assessment is based on DIAN’s position that HDC understated its asset base for tax purposes in its 2001 Colombian tax return. The basis for DIAN’s position is that HDC had “productive” assets in 2001, namely the Alcaravan and Bolivar Association Contracts that should have been included in HDC’s asset base calculation. In August 2005, HDC filed its response to the tax assessment through the institution of a formal administrative proceeding. DIAN must respond within one year. HDC intends to complete the administrative proceeding and object to DIAN’s conclusions on the following grounds: (a) Colombian statutes require that the asset base for PIT be calculated as of the end of the year preceding the tax year in question; and (b) as of the year ended December 31, 2000, the Alcaravan and Bolivar contracts were not productive assets for tax purposes. HDC faced a similar issue for its 2000 Colombian tax return. HDC refuted DIAN’s claim based on the arguments presented above, and ultimately the 2000 Colombian tax return issues were resolved in HDC’s favor. HDC has engaged the same outside lawyers and tax consultant to assist in this matter as were engaged in the 2000 tax return matter. Accordingly, Harken believes that any liability to Harken or its consolidated companies as a result of the tax assessment will not have a material adverse effect on Harken’s operations or financial condition.

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Harken provides for reserves related to contingencies when a loss is probable and the amount is reasonably estimable. Harken and its subsidiaries currently are involved in various other lawsuits and other contingencies, which in management’s opinion, will not result in a material adverse effect upon Harken’s financial condition or operations taken as a whole.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in its filings with the Securities and Exchange Commission (SEC) are recorded, processed, summarized and reported within the time period specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including its chief executive and chief financial officers, as appropriate, to allow timely decisions regarding required disclosure based on the definition of “disclosure controls and procedures” as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). In designing and evaluating the disclosure controls and procedures, management has recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply judgment in evaluating its controls and procedures. As of the end of the period covered by this report, and under the supervision and with the participation of management, including the Company’s Chief Executive Officer and Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of these disclosure controls and procedures. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this annual report.

Changes in Internal Control over Financial Reporting

As previously reported, during the quarter ended September 30, 2005, the Company identified a material weakness with respect to accounting for the redemption of certain of its Series G1, Series G2 and Series G4 Preferred stock.

The Company entered into and closed three separate transactions to redeem certain shares of its Series G1, Series G2 and Series G4 Preferred stock during the quarter ended September 30, 2005. In accounting for these transactions as of September 30, 2005, the Company inadvertently used the liquidation value (rather than the carrying value) in its calculation of dividends to preferred holders. This calculation was made for determining the increase or decrease to net income attributed to common stockholders.

The Company engaged two third party accounting consultants to assist it in determining the proper accounting treatment for these transactions. It was determined that these redemptions should be treated similarly to preferred stock dividends in accordance with EITF Topic D-42, “The Effect on the Calculation of Earnings per Share for the Redemption or Induced Conversion of Preferred Stock,” and EITF Topic D-53, “Computation of Earnings per Share for a Period That Includes a Redemption or an Induced Conversion of a Portion of a Class of Preferred Stock”.

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Based on the above, Company personnel prepared detailed calculations of the effect on net income attributed to common stock associated with the redemption of these preferred shares. In accordance with the Company’s policies and procedures, its Chief Financial Officer reviewed the calculations, and, additionally, the Company engaged one of the third party consultants to review the calculations as an additional level of review. While not part of its control procedures, the Company specifically engaged its auditors to review the accounting memoranda and calculations, in draft form, both at the local partner level and at the technical accounting partner level. The Company, however, failed to reference its calculations underlying these transactions to the related accounting advice received. Had the Company performed this additional procedure, it would have located the calculation error as part of its internal control structure and its journal entries would have been correct.

As the Company’s auditors were completing their quarterly review of the Company’s September 30, 2005 Form 10-Q, they discovered the calculation error. The error resulted in a material adjustment of the Company’s Form 10-Q draft which was corrected prior to filing its final Form 10-Q. In assessing the internal control implications of the error, the Company determined that the error met the criteria for a material weakness and disclosed it accordingly. In deciding to disclose this as a material weakness, the Company considered the fact that its existing internal control procedures failed to detect the error and its overall impact on its financial statements.

The Company’s existing internal controls over financial reporting include preparing a quarterly summary list of complex transactions, preparing accounting memos for each of these transactions describing the proper US GAAP application and forwarding the accounting memos and related calculations (if applicable) to its third party consultants. During the quarter ended December 31, 2005, the Company added an additional procedure where all journal entries and related calculations which underlie these complex transactions are referenced to the supporting accounting literature and accounting memoranda.

The item described above represents a change in the Company’s internal control over the financial reporting during the quarter ended December 31, 2005 that materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed, under the supervision of the Company’s chief executive and chief financial officers, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (GAAP). The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

The Company conducted an evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2005. This evaluation was based on the framework in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). All internal control systems, no matter how well designed, have inherent limitations. Therefore,

117

even those systems determined to be effective can provide only reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

Based on the Company’s evaluation under the framework in Internal Control – Integrated Framework, and on the change in internal control over financial reporting implemented in the quarter ended December 31, 2005 as described above, our chief executive officer and chief financial officer concluded that internal control over financial reporting was effective as of December 31, 2005. The Company’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by Hein & Associates LLP, an independent registered public accounting firm, as stated in their report which appears elsewhere in this report.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Harken Energy Corporation

We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that Harken Energy Corporation maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Harken Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

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

118

In our opinion, management’s assessment that Harken Energy Corporation maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Harken Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Harken Energy Corporation as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005 of Harken Energy Corporation and our report dated February 23, 2006 expressed an unqualified opinion thereon.

HEIN & ASSOCIATES LLP

Dallas, Texas

February 23, 2006

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PART III

ITEM 10.

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information regarding Harken’s directors and executive officers is set forth under “Proposal One: Election of Directors”, “Executive Officers of Harken” and “Section 16(a) Beneficial-Ownership Reporting Compliance” in Harken’s Proxy Statement, to be filed on or before April 30, 2006, which information is incorporated herein by reference.

Harken has adopted a code of ethics that applies to all members of Board of Directors and employees of Harken, including, the principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. Harken has posted a copy of the code on Harken’s internet website at the internet address: http://www.harkenenergy.com/corpgov.html. Copies of the code of ethics may be obtained free of charge from Harken’s website at the above internet address.

ITEM 11.

EXECUTIVE COMPENSATION

Information regarding Harken’s compensation of its named executive officers is set forth under “Compensation of Executive Officers” in Harken’s Proxy Statement, to be filed on or before April 30, 2006, which information is incorporated herein by reference. Information regarding Harken’s compensation of its directors is set forth under “Compensation of Directors” in the Proxy Statement, which information is incorporated herein by reference.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information regarding security ownership of certain beneficial owners and management is set forth under “Ownership of Common Stock” in Harken’s Proxy Statement, to be filed on or before April 30, 2006, which information is incorporated herein by reference.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information regarding certain relationships and related transactions is set forth under “Certain Relationships and Related Transactions” in Harken’s Proxy Statement, to be filed on or before April 30, 2006, which information is incorporated herein by reference.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item is incorporated by reference herein from Harken’s Proxy Statement, which will be filed with the SEC on or before April 30, 2006.

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PART IV

ITEM 15.

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

(a)	The following documents are filed as a part of this Annual Report:

(1)

Financial Statements included in Part II of this Annual Report:


		Page
Harken Energy Corporation and Subsidiaries

— Reports of Independent Registered Public Accounting Firms		63

— Consolidated Balance Sheets — December 31, 2004 and 2005		65

— Consolidated Statements of Operations for the three years ended December 31, 2005		66

— Consolidated Statements of Stockholders’ Equity for the three years ended December 31, 2005		67

— Consolidated Statements of Cash Flows for the three years ended December 31, 2005		68

— Notes to Consolidated Financial Statements		69

(2)

The information required by Schedule I is either provided in the related financial statements or in a note thereto, or is not applicable to Harken. The information required by all other Schedules is not applicable to Harken.

(3)

Exhibits



*3.1		Restated Certificate of Incorporation of Harken Energy Corporation.

3.2		Amended and Restated Bylaws of Harken Energy Corporation (filed as Exhibit 3.7 to Harken’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-10262, and incorporated by reference herein).

4.1		Form of certificate representing shares of Harken common stock, par value $.01 per share (filed as Exhibit 1 to Harken’s Registration Statement on Form 8-A, File No. 1-10262, filed with the SEC on June 1, 1989 and incorporated by reference herein).

4.2		Rights Agreement, dated as of April 6, 1998, by and between Harken Energy Corporation and ChaseMellon Shareholder Services L.L.C., as Rights Agent (filed as Exhibit 4 to Harken’s Current Report on Form 8-K dated April 7, 1998, file No. 1-10262, and incorporated by reference herein).

4.3		Amendment to Rights Agreement by and between Harken Energy Corporation and American Stock Transfer and Trust Company (successor to Mellon Investor Services LLC, (formerly known as ChaseMellon Shareholder Services L.L.C.), as Rights Agent, dated June 18, 2002 (filed as Exhibit 4.11 to Harken’s Quarterly Report on Form 10-Q for the period ended September 30, 2002, File No. 1-10262, and incorporated by reference herein).

4.4		Amendment to Rights Agreement by and between Harken Energy Corporation and American Stock Transfer and Trust Company (successor to Mellon Investor Services LLC, (formerly known as ChaseMellon Shareholder Services L.L.C.), as Rights Agent, dated August 27, 2002 (filed as Exhibit 4.12 to Harken’s Quarterly Report on Form 10-Q for the period ended September 30, 2002, File No. 1-10262, and incorporated by reference herein).

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4.5		Certificate of Designations of Series E Junior Participating Preferred Stock (filed as Exhibit A to Exhibit 4 to Harken’s Current Report on Form 8-K dated April 7, 1998, file No. 1-10262, and incorporated by reference herein).

4.6		Certificate of Increase of Series E Junior Participating Preferred Stock of Harken Energy Corporation (filed as Exhibit 4.6 to Harken’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-10262, and incorporated by reference herein).

4.7		Certificate of Designations of Series G1 Convertible Preferred Stock (filed as Exhibit 3.7 to Harken’s Current Report on Form 8-K dated February 13, 2003, File No. 1-10262, and incorporated by reference herein).

4.8		Certificate of Increase of Series G1 Convertible Preferred Stock of Harken Energy Corporation (filed as Exhibit 3.8 to Harken’s Current Report on Form 8-K dated February 13, 2003, File No. 1-10262, and incorporated by reference herein).

4.9		Certificate of Designations of Series G2 Convertible Preferred Stock (filed as Exhibit 4.10 to Harken’s Annual Report on Form 10-K, as amended, for the fiscal year ended December 31, 2001, File No. 1-10262, and incorporated by reference herein).

4.15		Certificate of Designations of Series M Cumulative Convertible Preferred Stock (filed as Exhibit 4.1 to Harken’s Current Report on Form 8-K dated October 8, 2004, File No. 1-10262, and incorporated by reference herein).

4.16		Conversion/Redemption Agreement, dated October 7, 2004 by and between Harken Energy Corporation and the holders of Harken’s Series L Cumulative Convertible Preferred Stock (filed as Exhibit 10.3 to Harken’s Current Report dated October 8, 2004, File No. 1-10262, and incorporated by reference herein).

10.1		Association Contract (Bolivar) by and between Harken de Colombia, Ltd. and Empresa Colombia de Petroleos (filed as Exhibit 10.4 to Harken’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1996, and incorporated herein by reference).

10.2		Association Contract (Alcaravan) dated as of December 13, 1992, but effective as of February 13, 1993, by and between Empresa Colombiana de Petroleos (filed as Exhibit 10.1 to Harken’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-10262, and incorporated herein by reference).

10.3		Association Contract (Bocachico) dated as of January 1994, but effective as of April 1994, by and between Harken de Colombia, Ltd. and Empresa Colombiana de Petroleos (filed as Exhibit 10.1 to Harken’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 1994, File No. 1-10262, and incorporated herein by reference).

10.4		Purchase and Sale Agreement dated January 31, 2002 between Republic Resources, Inc. and Harken Energy Corporation (filed as Exhibit 10.15 to Harken’s Annual Report on Form 10-K, as amended, for the fiscal year ended December 31, 2001, File No. 1-10262, and incorporated by reference herein).

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10.5		Stockholders’ Agreement by and between Harken Energy Corporation’s wholly-owned subsidiary, International Business Associates Holding Co., Ltd. and International Business Associates, Ltd., John Kean, Jr. and Stanley Brownell (filed as Exhibit 10.3 to Harken’s Current Report Form 8-K dated September 14, 2004, File No. 1-10262, and incorporated by reference herein).

10.6		Series A Redeemable Preferred Stock Subscription Agreement by and between a wholly owned subsidiary of Harken Energy Corporation, International Business Associates Holding Co., Ltd. and International Business Associates, Ltd. with annexes thereto (filed as Exhibit 10.1 to Harken’s Current Report Form 8-K dated September 14, 2004, File No. 1-10262, and incorporated by reference herein).

10.7		Rio Verde Exploration and Production Contract (English Translation) (filed as Exhibit 10.1 to Harken’s Current Report on Form 8-K dated September 16, 2004, File No. 1-10262, and incorporated by reference herein).

10.8		Los Hatos Exploration and Production Contract (English Translation) (filed as Exhibit 10.1 to Harken’s Quarterly Report on 10-Q for the fiscal quarter ended September 30, 2005, File No. 1-10262, and incorporated by reference herein).

*10.9		Exploration and Development Agreement by and between Gulf Energy Management Company and Ohio Triangle, L.P. an Ohio Limited partnership.

*10.10		Luna Llena Exploration and Production Contract (English Translation).

*10.11		Global Energy Development PLC. Unsecured Variable Coupon Convertible Notes due October 30, 3012.

*10.12		Caracoli Exploration and Production Contract (English Translation)

10.13		Redemption and Release Agreement by and between International Business Associates Holding Co. Inc., and International Business Associates, Ltd., International Business Associates (USA), Inc., John Kean Jr. and Stanley J. Brownell dated January 31, 2006 (filed as Exhibit 10.1 to Harken’s Current Report on form 8-K dated January 31, 2006, File No. 001-10262, and incorporated herein by reference).

10.14		Stock Purchase Agreement by and between Harken Energy Corporation and Alexandria Global Master fund, Ltd. dated August 29, 2005 (filed as Exhibit 10.1 to Harken’s Current Report on Form 8-K, dated August 31, 2005, File No. 001-10262, and incorporated herein by reference).

10.15		Exploration and Development Agreement - Indiana Posey (filed as Exhibit 10.1 to Harken’s Current Report on Form 8-K, dated March 22, 2005, File No. 001-10262, and incorporated herein by reference).

10.16		Exploration and Development Agreement - Ohio Cumberland (filed as Exhibit 10.1 to Harken’s Current Report on Form 8-K, dated March 29, 2005, File No. 001-10262, and incorporated herein by reference).

10.17		Block 95 - Peru Exploration and Production Agreement - English Translation (filed as Exhibit 10.1 to Harken’s Current Report on Form 8-K, dated April 12, 2005, File No. 001-10262, and incorporated herein by reference).

10.18		Crude Oil Sales Contract (filed as Exhibit 10.1 to Harken’s Current Report on Form 8-K, dated April 21, 2005, File No. 001-10262, and incorporated herein by reference).

10.19		Valle Lunar Technical Evaluation Agreement (filed as Exhibit 10.1 to Harken’s Current Report on Form 8-K, dated May 31, 2005, File No. 001-10262, and incorporated herein by reference).

*21		Subsidiaries of Harken

*23.1		Consent of Independent Registered Public Accounting Firm – Hein & Associates, LLP

*23.2		Consent of Independent Registered Public Accounting Firm - BDO Seidman, LLP

*23.3		Consent of Netherland, Sewell & Associates, Inc. (Independent Reserve Engineers)

*23.4		Consent of Ryder Scott Company (Independent Reserve Engineers)

*24		Power of Attorney

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*31.1		Certification by Chief Executive Officer of Harken Energy Corporation.

*31.2		Certification by Chief Financial Officer of Harken Energy Corporation.

*32.1		Certificate of the Chief Executive Officer of Harken Energy Corporation.

*32.2		Certificate of the Chief Financial Officer of Harken Energy Corporation.

*	Filed herewith

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SIGNATURES

Pursuant to the requirements of the Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 28, 2006.

HARKEN ENERGY CORPORATION

/s/ Anna M. Williams

By: Anna M. Williams, Vice President – Finance and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities on February 28, 2006.


Signature		Title

/s/ Anna M. Williams		Vice President – Finance and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
Anna M. Williams

/s/ Mikel D. Faulkner		Director, Chief Executive Officer and President (Principal Executive Officer)
Mikel D. Faulkner

/s/ Michael M. Ameen *		Director
Michael M. Ameen		Director

/s/ J. William Petty *		Director
J. William Petty		Director

/s/ Alan G. Quasha *		Director
Alan G. Quasha		Director

/s/ H. A. Smith *		Director
H. A. Smith		Director

/s/ Anna M. Williams

* By: Anna M. Williams, Attorney in-fact

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