HARKEN ENERGY CORP - 10-K Annual Report

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

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 an accelerated filer (as defined in Exchange Act Rule 12b-2). 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, 2004 was approximately $75 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 March 9, 2005 was 221,661,672.

Part III of this Annual Report on Form 10-K incorporates by reference portions of the Registrant’s definitive proxy statement, to be filed with the Securities and Exchange Commission not later than 120 days after the close of its fiscal year.

Certain information in this Annual Report, including certain information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7, is “forward-looking information” as defined by the Private Securities Litigation Reform Act of 1995. Examples include discussions as to Harken Energy Corporation’s expectations, beliefs, plans, goals, objectives and future financial or other performance or assumptions concerning matters discussed in this Annual Report. This information, by its nature, involves estimates, projections, forecasts and uncertainties that could cause actual results or outcomes to differ substantially from those expressed in the forward-looking statement.

The business of Harken Energy Corporation (together with its wholly-owned or controlled subsidiaries, “Harken” or the “Company”) is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond its ability to control. A number of these factors have been identified herein under “Risk Factors” set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this report, and that are otherwise described from time to time in Harken’s Securities and Exchange Commission (“SEC”) reports filed after this report. The factors include weather conditions; governmental regulations; cost of environmental compliance; inherent risk in the operation of drilling; production risks; fluctuations in energy-related commodities prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets; capital market conditions; changes in accounting standards; the risks of operating businesses in regulated industries that are in the process of becoming deregulated or increasingly regulated; and political and economic conditions in Eastern Europe, Middle America and South America (including inflation rates). Although Harken’s management strives to mitigate market risk through risk management activities, changes in commodity prices can have an adverse impact on earnings and asset values.

Any forward-looking statement speaks only as of the date on which it is made, and Harken undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made.

Unless the context requires otherwise, when we refer to “Harken”, “we”, “us” and “our”, we are describing Harken Energy Corporation and its consolidated entities on a consolidated basis.

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, and our telephone number is (817) 424-2424.

We are an independent oil and gas exploration, exploitation, development and production company operating both internationally and domestically. Our operations are divided into three operating segments. 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. Our international crude oil exploration and production operations are conducted through our 85% owned subsidiary, Global Energy Development plc (“Global”) with activities in Colombia, Panama and Peru. During 2004, we invested in International Business Associates, Ltd. (“IBA”) which comprises our third segment. IBA is in the initial stages of operations and focuses primarily on opportunities created by the recent deregulation of the energy markets in Eastern Europe by trading energy futures or other energy based contracts, principally in Hungary and the United States.

Our revenues are primarily derived from production from our oil and gas properties. GEM operates approximately 40% 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 we enter into hedging contracts to achieve more predictable cash flows and to reduce our exposure to declines in market prices.

As of December 31, 2004 GEM had approximately 22 BCFe of proved oil and gas reserves net to our interest with discounted future net cash flows, discounted at 10%, of approximately $59 million. At December 31, 2004, GEM represented 46% of our consolidated oil and gas proved reserve volumes, and in 2004, GEM represented approximately 63% of our consolidated oil and gas revenues. In 2004, GEM’s oil and gas revenues were comprised of approximately 40% oil sales and 60% 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, 2004 we had approximately 4.2 million barrels of international proved oil reserve volumes net to our interest with discounted future net cash flows, discounted at 10%, of approximately $66 million. Approximately 615,000 barrels of proved oil reserve volumes and $9.7 million of discounted future net cash flows are attributable to a 14.65% minority interest of a consolidated subsidiary. All of Global’s proved reserve volumes are located in Colombia. During 2004, Global produced 366,000 net barrels of oil in Colombia generating oil revenues of approximately $11 million. Global represented 54% of our total proved reserves at December 31, 2004 and approximately 37% of our consolidated oil and gas revenues in 2004. Global’s activities in Panama and Peru, thus far, have been limited to technical evaluations of potential exploration areas.

During 2003, we focused on reducing our significant debt obligations consisting primarily of our 5% Senior Convertible Notes (“5% European Notes”) and our 5% Convertible Notes (“Benz Convertible Notes”) issued to Benz Energy, Incorporated (“Benz”), which were scheduled to mature in May 2003 and November 2003, respectively. Under our 2003 capital restructuring plan, we actively worked to repurchase, redeem and/or restructure our outstanding debt obligations prior to their maturity date. Also, certain additional convertible debt obligations were either converted into or redeemed with shares of our common stock, under the terms of the specific note agreements, either prior to or upon the maturity date in 2003. Since January 1, 2003 and as of March 16, 2005, we have reduced our overall outstanding debt principal amounts by 85%, or approximately $48 million.

During 2004, we increased our capital expenditures over 150% compared to the prior year with drilling and exploration expenditures totaling approximately $18 million. Approximately $9 million of these capital of expenditures were associated with each of Global and GEM. During 2004, GEM participated in the drilling of 12 gross wells with an average completion rate of 75% and an average finding cost of approximately $2.06 per MCFe.

During 2004, Global drilled the Estero #4 well and recompleted several wells including the Tilodrian #1 and Macarenas #1 wells located in the new Rio Verde Exploration and Production Contract area. Also in 2004, Global signed two new Exploration and Production Contracts covering approximately 160,000 acres in Colombia, which included the Rio Verde Exploration and Production Contract.

In December 2004, Global was notified that Perupetro S.A., the national oil company of Peru, had approved our application for an exploration and production contract in Peru for Block 95. Subject to the completion of regulatory procedures, Global expects to sign its first exploration and production contract in Peru during early second quarter of 2005. We expect to drill our first well under the new contract in 2006. During the initial three phases of the Peru contract, only one well is required in addition to certain exploratory studies and work requirements. Should Global determine, at its discretion, to proceed with phases 4 to 6 of the contract, additional wells may be required.

In September 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. In addition, while our investment remains outstanding, Harken will hold the majority of the board positions in IBA. We anticipate IBA will trade gas futures contracts in Hungary and the United States. Through IBA, we expect to capitalize on the skills, knowledge and relationships that IBA’s principals have developed through a five year presence in Hungary, the Ukraine and Russia. We anticipate IBA will increase its trading activities during 2005.

During 2005 we are continuing to concentrate on the development and growth of our oil and gas assets and energy-based growth opportunities. In February 2005, our Board of Directors approved the 2005 capital expenditure program of approximately $34 million. Of the 2005 capital expenditure budget, approximately $16 million is related to GEM and approximately $18 million is related to Global’s budgeted capital expenditures. We expect to fund these capital expenditures through available cash on hand and through projected cash flow from operations in 2005. Possible weakening commodity prices, a decline in drilling success or substantial delays in bringing on production from wells drilled could cause us to reduce our 2005 drilling plans. The majority of our planned capital expenditures for 2005 are discretionary, and as a result, will be curtailed if sufficient funds are not available.

During the three years ended December 31, 2004, GEM has drilled or participated in the drilling of 26 oil and gas wells in North America, completing 21 of the wells drilled. GEM’s domestic drilling activity increased following the August 1999 acquisition of XPLOR Energy, Inc. (“XPLOR,” a wholly-owned subsidiary) and the December 1999 acquisition of prospects from Benz, whereby we acquired a variety of domestic prospect acreage within its Texas and Louisiana Gulf Coast area of emphasis. Over the past several years, we have capitalized on the higher product prices by selling 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 the three years ended December 31, 2004, generated cash proceeds of approximately $24 million, which were used in part to support GEM’s exploration and development activities and repay debt obligations.

GEM is continuing to seek joint venture and farmout opportunities to explore and develop its domestic prospect portfolio. Consistent with our 2005 focus, GEM is seeking acquisition opportunities to expand our domestic operations.

As of December 31, 2004, GEM operates or owns a non-operating working interest in 85 oil wells, 78 gas wells and 16 injection wells in the United States. Substantially all of GEM’s North American operations are currently located in the onshore and offshore Gulf Coast regions of South Texas and Louisiana and the Texas Panhandle region. There were no domestic customers during 2002, 2003 or 2004 which individually represented 10% or more of our consolidated revenues.

Gulf Coast Operations — Following the establishment of GEM, all of our domestic operations, are held and managed by GEM. At December 31, 2004, through various wholly-owned subsidiaries, GEM owns operating and non-operating working interests in 45 gas wells located in various counties in South Texas, concentrated in the Raymondville area of Willacy County and the Esperanza field in Wharton County. In Louisiana, GEM owns operated and non-operated interests in 60 oil wells and 8 gas wells concentrated primarily in the Main Pass area offshore Plaquemines Parish and the Lake Raccourci area of LaFourche Parish. In April 2002, we acquired the Republic Properties, which now consist of 12 oil and gas wells located primarily in Jackson County, Texas, the Bayou Sorrel field located in Iberville and Lafayette Parishes, Louisiana. After the sale of certain of our Panhandle operations during the fourth quarter of 2003, substantially all of GEM’s domestic proved reserves are located in the Gulf Coast region of Louisiana and Texas.

In 2004, GEM drilled or participated in the drilling of 12 Gulf Coast area exploratory and development wells and successfully completed 9 of those wells with one well held for sidetrack. During the fourth quarter of 2004, one exploitation well was drilled in the Lapeyrouse field. On a cumulative basis through December 31, 2004, GEM participated in the drilling of a total of 34 wells in the Raymondville area of South Texas, successfully completing 31 of the wells drilled. GEM holds an approximate 27% working interest in the Raymondville area wells.

West Texas Operations - Prior to the December 2003 sale of the 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. In December 2003, GEM and certain wholly-owned subsidiaries of GEM sold the majority of our oil and gas properties located in the Panhandle region of Texas for gross cash proceeds of approximately $7 million, subject to certain adjustments. At December 31, 2004, GEM continues to own interests in 23 oil and gas wells in the Panhandle area of Texas. GEM also owns interest in 2 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.

At December 31, 2004, Global held, through Harken de Colombia, Ltd., a wholly-owned subsidiary of Global, three Association Contracts, the Alcaravan, Bolivar and Bocachico contracts (collectively the “Association Contracts”) with Empresa Colombiana de Petroleos (“Ecopetrol”), the state-owned Colombian oil company. As described below, the Association Contracts provide for the potential participation in production by Ecopetrol. In 2004, the Colombian government updated its hydrocarbons administration by establishing a new agency, the National Hydrocarbons Agency (“ANH”) and by allowing a new form of royalty-based concession contract that eliminated the potential for production participation of the Colombian government. During 2004, Global also acquired exploration and production rights pursuant to two separate Exploration and Production Concession Contracts, the Rio Verde and Los Hatos Contracts issued by the recently established ANH. 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 Contract. 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. Ecopetrol, which purchased the majority of Global’s crude oil production in 2004, 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. The procedures and policies include our decision in 2001 to replace Global’s field operating employees with outsourced personnel. Global’s operating plans in Colombia are continuing, subject to the ongoing monitoring of security developments. For further discussion of Global’s security concerns in Colombia, see “Risk Factors” set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7.

Alcaravan Contract — The Alcaravan Association Contract (the “Alcaravan Contract”) gives Global the exclusive right to explore for, develop and produce oil and gas throughout approximately 24,000 gross acres in the Alcaravan area of Colombia, which is located in Colombia’s Llanos Basin approximately 140 miles east of Santafe de Bogota. 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, Global was advised of Ecopetrol’s intent to declare the Cajaro #1 well commercial pursuant to the Alcaravan Contract terms. As of March 16, 2005, 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 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. As of December 31, 2004, 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. Production from Cajaro #1 will be allocated as follows: Ecopetrol, on behalf of the Colombian government, will receive a royalty interest of 8% of all production, and all production (after royalty payments) attributable to the Alcaravan Association Contract area 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. 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 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, in October 2004, Global, based on the proposed unitization maps and data presented by Ecopetrol, began reflecting a 50% 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 as of December 31, 2004.

Alcaravan Contract Operations – Global has drilled eight wells on the Alcaravan acreage, six of which are currently producing. These six producing wells include the Estero #1, Estero #2, Estero #4 and Estero #5 wells, the Canacabare #1 well and the Cajaro #1 well. In January and February 2005, daily combined production from the Estero #1 and Estero #2 wells from the Palo Blanco field have averaged a total of approximately 429 gross barrels per day. In 2004, the Cajaro #1 well produced a total of 148,835 gross barrels of oil during the year. At December 31, 2004, Global reflects proved reserves of approximately 1.14 million net barrels related to its interest in the Palo Blanco field. During 2004, Global produced a total of approximately 365,000 gross barrels of oil from its Palo Blanco field, and since inception and through December 31, 2004, Global has produced a cumulative total of approximately 2,232,000 gross barrels of oil from its Palo Blanco field.

At December 31, 2004, Global also reflects proved reserves of approximately 78,000 net barrels related to its interest in the Anteojos prospect within the Alcaravan Contract area, which includes the Canacabare #1 well. The Canacabare #1 well, which was drilled during 1998 to a total depth of 8,410 feet, has not produced consistently due to the rainy season and resulting operating conditions in the Llanos Basin area in Colombia. Daily production from the Canacabare #1 well began in mid- 2003 and production totaled 48,000 gross barrels of oil during 2003 and through April 2004 at which time the well was shut-in due to a downhole pump failure. 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 2004, the Torcaz wells averaged approximately 79 gross barrels of production per day from the Torcaz field. At December 31, 2004, Global reflected proved reserves of approximately 157,000 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 2005.

In December 1999, Global submitted an application to Ecopetrol for their participation in the Rio Negro field. Global submitted an updated application to Ecopetrol in October 2002 and received sole risk approval in June 2003. Accordingly, Global reflects its 80% interest in gross production and cash flows in its financial statements and reserve information.

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 12% 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 12% based upon Global’s plans to undertake the Catalina Gas Injection project in 2005. 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. Global and Ecopetrol entered into an agreement in June 2002 whereby Global relinquished all but approximately 59,000 of the Bolivar Contract area acreage in exchange for the release from the sixth year Bolivar Contract work obligations. The release of such acreage did not affect Global’s proved reserves on the Bolivar Contract area. With the

execution of this amendment, Global has completed the Exploration Period related to 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. In November 1997, Global spudded its first well on the Bolivar Contract acreage, the Catalina #1, which was found to be productive, but is no longer producing. In March 1998, Global spudded 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, the Laurel #1, drilled in 1999, and the Olivo #2, drilled in early 2001, were unproductive.

At December 31, 2004, 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, scheduled for 2005, for a total cost of completion of approximately $1.7 million. Such costs are expected to be funded out of cash on hand and cash from operations. During 2004, the Olivo #1 produced a total of 38,000 gross barrels of oil and, since inception, Global has produced cumulative production of approximately 577,000 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. Global anticipates spending approximately $3.9 million of its 2005 budgeted capital expenditures on the development of the Buturama field. The majority of the budgeted costs are for the drilling of the Catalina #2 well in 2005. For further discussion of Global’s security concerns in Colombia, see “Risk Factors” set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7.

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. In 2003, Global drilled and completed the Cajaro #1 well. Global placed the Cajaro #1 well on production effective in June 2003. The 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 a new 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 require 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 is required to reprocess 300 kilometers of existing seismic data and acquire 50 kilometers of new 2D seismic data. The time period for Phase 1 is 20 months.

If Global elects to enter Phase 2 of the contract, Global must drill one exploration well and acquire a further 25 kilometers of 2D seismic. 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.

Los Hatos Concession—In November 2004 Global signed a new 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.

If Global elects to enter Phase 2 of the contract, Global must drill either one well or acquire 50 kilometers of 2D seismic. 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.

In April 2001, Global, through a wholly owned subsidiary, signed a Technical Evaluation Agreement (“Peru TEA”) with Perupetro, the national oil company of Peru. The Peru TEA covered an area of approximately 6.8 million gross acres in northeastern Peru. Under the terms of the Peru TEA, Global had the option to convert the Peru TEA to a seven-year exploration contract, with a twenty-two year production period. Terms of the Peru TEA allowed Global to conduct a study of the area that included the reprocessing of seismic data and evaluation of previous well data. In April 2003, Global received an extension from Perupetro of the Peru TEA to July 2003. In June of 2003 Global submitted a final report and completed all obligations required under the TEA. Prior to the expiration of the Peru TEA in July 2003, Global exercised its option under the Peru TEA and entered into negotiations with Perupetro for a License Contract. All work requirements under the Peru TEA were satisfied prior to its expiration. In December 2004, Global announced that Perupetro had approved for signature a new License Contract between Perupetro and Global for the Exploration and Exploitation of Hydrocarbons in the Block 95 Area located in the Marañon Basin of Northeastern Peru.

This approval represents a required statutory step towards the signing of Global’s first License Contract in Peru with Global anticipating that the Contract will be signed by Global and Perupetro and subsequently become effective by early second quarter of 2005.

Global anticipates that the signed Contract will assign Global exclusive exploration and production rights to approximately 1,255,000 acres and that Global will own a 100% working interest in the Contract subject only to an initial 5% royalty. The size of the royalty is to be determined by future production levels. The Contract duration is currently set at approximately 7 years for the initial exploration phases and 23 years for the exploitation phase.

In September 2001, Global, through a wholly owned subsidiary, signed a Technical Evaluation Agreement (“Panama TEA”) with the Ministry of Commerce and Industry for the Republic of Panama. The Panama TEA covered an area approximately 1.4 million gross acres divided into three blocks in and offshore Panama. Under the terms of this Panama TEA, Global performed certain work program procedures and studies and submitted them to the Panamanian government. The Panama TEA provided Global with an 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 options to negotiate an Exploration and Exploitation Contract. As of March 16, 2005, the negotiations with the Panamanian government are still in progress.

Global is committed to broadening its exploration efforts. In addition to operations in Colombia, Peru and Panama, Global’s operational experience may enable Global to expand its exploration efforts elsewhere in Latin America or internationally. Global’s business strategy is to focus on improvement of its cash flow by increasing its daily production volumes, as well as to develop energy projects and to aggregate international assets through strategic acquisitions and alliances.

Production and Revenues – See also “Note 20 – 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:

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

Acreage and Wells — At December 31, 2004, GEM and Global owned interests in the following oil and gas wells and acreage.

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:

As of December 31, 2004, we had 35 employees, including 11, 9 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.

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 practicable after we electronically file such material with, or furnish it to the SEC.

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 and London, England. We lease approximately 26,800 (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, 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 November 2005, and approximately 200 square feet of office space in London, England, which lease runs through April 2005. The average annual cost of our leases are approximately $669,000. See “Liquidity and Capital Resources – Capital Commitments – Consolidated Contractual Obligations” contained in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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, 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 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 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.

In 2004, the Colombian federal taxing authority (“DIAN”) issued a Special Request suggesting that Harken de Colombia, Ltd. (“HDC”) modify its tax return for the year 2001 to reflect additional tax liabilities of approximately $975,000 pursuant to the Colombian presumptive income tax regulations (“PIT”). The Colombian PIT is calculated with reference to the taxpayer’s asset base. In this case, DIAN’s Special Request relates to DIAN’s opinion that HDC understated its asset base for tax purposes in its 2001 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. HDC has responded to DIAN’s request by pointing out the following: (1) that 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 (2) that for an asset to be considered “productive” Colombian regulations require that Ecopetrol declare sole risk or commerciality as to the asset in question. In our case, those declarations did not occur until 2001. As a result, the Alcaravan and Bolivar contracts were not “productive” assets as of December 31, 2000. HDC faced a similar request for its year ended December 31, 2000 tax return. HDC successfully refuted DIAN’s claim based on the same arguments presented above. Therefore, Harken believes that any liability to Harken or its subsidiaries as a result of this Special Request will not have a material adverse effect on Harken’s financial condition. Harken has not provided a reserve because it cannot reasonably determine the probability of a loss.

There were no matters submitted to a vote of security holders during the fourth quarter of 2004.

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

Since March 18, 1991, our common stock has been listed on the American Stock Exchange and traded under the symbol HEC. At December 31, 2004, there were 2015 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 “Risk Factors” set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7.

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.

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, Series G4 Preferred Stock, Series J 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 12 – Redeemable Preferred Stock and Note 13 – Stockholders’ Equity.”

For information concerning our equity compensation plans, including both stockholder approved plans and non-stockholder approved plans, see “Security Ownership of Certain Beneficial Owners and Management” in Part III, Item 12.

The following table presents our repurchases of our common stock for each of the three months included in the fourth quarter ended December 31, 2004:

We repurchased the 2,000,000 common shares under our previously announced 2004 stock repurchase program which we concluded on December 31, 2004.

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.

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

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

We are an independent oil and gas exploration, exploitation, development, production and trading company operating both internationally and domestically. Our operations are divided into three operating segments. 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 located principally in the onshore and offshore Gulf Coast regions of South Texas and Louisiana. Our international crude oil operations are conducted through our 85% owned subsidiary, Global Energy Development plc (“Global”) with activities in Colombia, Panama and Peru. During 2004, we invested in International Business Associates, Ltd. (“IBA”) which comprises our third segment. IBA is in the initial stages of operations and focuses primarily on opportunities created by the recent deregulation of the energy markets in Eastern Europe by trading energy futures or other energy based contracts, principally in Hungary and the United States.

Our revenues are primarily derived from production from our oil and gas properties. GEM operates approximately 40% of its natural gas and crude oil properties 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 we enter into hedging contracts to achieve more predictable cash flows and to reduce our exposure to declines in market prices.

Revenues from Global are derived solely from our Colombian oil production. As of December 31, 2004 we had approximately 4.2 million barrels of international proved oil reserve volumes net to our interest with discounted future net cash flows, discounted at 10%, of approximately $66 million. Approximately 615,000 barrels of proved oil reserve volumes and $9.7 million of discounted future net cash flows are

attributable to a 14.65% minority interest of a consolidated subsidiary. All of Global’s proved reserve volumes are located in Colombia. During 2004, Global produced 366,000 barrels of oil in Colombia generating oil revenues of approximately $11 million. Global represented 54% of our total proved reserves at December 31, 2004 and approximately 37% of our consolidated oil and gas revenues in 2004. Global’s activities in Panama and Peru, thus far, have been limited to technical evaluations of potential exploration areas.

During 2004, we increased our capital expenditures over 150% compared to the prior year with drilling and exploration expenditures totaling approximately $18 million. Approximately $9 million of these capital expenditures were associated with each of Global and GEM. During 2004, GEM participated in the drilling of 12 gross wells with an average completion rate of 75% and an average finding cost of approximately $2.06 per MCFe.

During 2004, Global drilled the Estero #4 well and recompleted several wells including the Tilodrian #1 and Macaranes #1 wells included in the new Rio Verde Exploration and Production Contract. Also in 2004, Global signed two new Exploration and Production Contracts covering more than 160,000 acres in Colombia, which included the Rio Verde Exploration and Production Contract.

Also in September 2004, Global signed a new Exploration and Production Contract with the National Hydrocarbons Agency of the Republic of Colombia for the Rio Verde area located in the central Llanos region. The contract assigns Global exclusive exploration and production rights to 75,000 acres located approximately 40 kilometers north of Global’s Palo Blanco complex. During Phase 1 of the contract, Global was required to equip for production two existing wells, the Tilodiran #1 and Macaranes #1, that were drilled in 1986 and 1993 and tested productive. Both of these wells were equipped for production in late 2004 and early 2005.

In November 2004, Global signed an additional Exploration and Production Contract with the same agency in Colombia to explore 85,000 acres in the Los Hatos area which is adjacent to the Palo Blanco field. We own 100% of the contract, subject only to an initial 8% royalty payable to the Colombian Ministry of Energy. The royalty may be adjusted in the future based on future production. Under the terms contract, Global is required to drill one exploratory well during phase 1 within 16 months of contract signing. At Global’s option, Global may elect to add up to 4 additional phases, each requiring an additional exploratory well to be drilled within a 12 month period. During phase 2, twenty-five kilometers of 2D seismic may be acquired in lieu of an exploratory well.

In December 2004, Global was notified that Perupetro S.A., the national oil company of Peru, had approved our application for an exploration and production contract in Peru for Block 95. Subject to the completion of regulatory procedures, Global expects to sign its first exploration and production contract in Peru during the first quarter of 2005. We expect to drill our first well under the new contract in 2006. During the initial three phases of the Peru contract, only one well is required in addition to certain exploratory studies and work requirements. Should Global determine, at its discretion, to proceed with phases 4 to 6 of the contract, additional wells may be required.

In September 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. In addition, while our

investment remains outstanding, Harken will hold the majority of the board positions in IBA. We anticipate IBA will trade gas futures contracts in Hungary and the United States. Through IBA, we expect to capitalize on the skills, knowledge and relationships that IBA’s principals have developed through a five year presence in Hungary, the Ukraine and Russia. We anticipate IBA will increase its trading activities during 2005.

During 2005 we are concentrating on the development and growth of our oil and gas assets and energy-based growth opportunities. In February 2005, our Board of Directors approved the 2005 capital expenditure program of approximately $34 million. Of the 2005 capital expenditure budget, approximately $16 million is related to GEM and approximately $18 million is related to Global’s planned capital expenditures. We expect to fund these capital expenditures through available cash on hand and through projected cash flow from operations in 2005. Possible weakening commodity prices, a decline in drilling success or substantial delays in bringing on production from wells drilled could cause us to reduce our 2005 drilling plans. The majority of our planned capital expenditures for 2005 are discretionary, and as a result, will be curtailed if sufficient funds are not available.

The volatility of crude oil and natural gas prices has a significant impact on the profitability of our oil and gas operations. Overall, the oil and gas industry benefited from increased oil and gas commodity prices in 2004 helping to generate improved industry cash flows from operations. Worldwide crude oil inventories during 2004 were low compared to average inventories over the last ten years. These lower worldwide crude oil inventories helped contribute to higher crude oil prices as compared to average crude oil prices over the past several years. OPEC restrained marginal international oil supplies in 2004 thereby preventing the growth in oil inventories. Geopolitical disruptions to the international supply of oil occurred in Nigeria, Venezuela and Iraq. Both Venezuela and Iraq had not returned to their average 2003 production levels by the end of 2004. Worldwide demand for oil and gas increased in 2004 in response to improving worldwide economic conditions. Worldwide natural gas inventories in 2004 were slightly above the five year average, but improved demand for natural gas helped contribute to higher natural gas prices in 2004 as compared to average natural gas prices over the past several years. Industry-wide oil and gas drilling activity increased domestically and abroad in 2004 in response to improved industry cash flows from operations.

During 2003, we reduced our debt obligations through repurchases for cash at a discount, conversions into our common stock or through issuances of debt or equity securities with more favorable terms. During 2004, we continued in our efforts to improve our capital structure while focusing on developing our oil and gas assets and improving our cash flow from operations. During the two years ended December 31, 2004, we reduced our debt obligations by 85% to $8.6 million at year-end 2004. As of December 31, 2004, we had unrestricted cash of $28.6 million and working capital of almost $22 million. Our debt to equity ratio was 0.15 to 1 with approximately $56 million in shareholders’ equity at December 31, 2004.

Many of these capital structure changes involved the issuance of our common stock or conversion of certain existing convertible debt and preferred stock into shares of our common stock or into instruments convertible into shares of our common stock. As a result, our common shares outstanding increased from 25.4 million shares outstanding at the beginning of 2003 to approximately 219.6 million shares outstanding at December 31, 2004. At March 16, 2005, if our outstanding debt and equity instruments were exercised and/or converted, we would issue the following amount of our common stock:

In 2002, we received the proceeds of a 10% Term Loan (the “Investor Term Loan”) in the aggregate principal amount of $5,000,000 to Lyford Investments Enterprises Ltd. (“Lyford”) in exchange for a loan of $5,000,000 cash.

As additional consideration for the Investor Term Loan, as amended, we issued to Lyford warrants (the “Lyford Warrants”) to purchase up to 7,000,000 shares of Global held by us at a price of 50 UK pence per share. In August 2002, Global issued to its minority shareholders warrants to purchase up to 505,407 shares of Global stock at 60 UK pence per share (the “Minority Shareholder Warrants”). The Lyford Warrants expire in October 2005 and the Minority Shareholder Warrants expire in August 2005. Global’s shares are traded on the Alternative Investment Market of the London Stock Exchange (“AIM”). Under generally accepted accounting principles in the United States (“US GAAP”), we are required to record the Minority Shareholder Warrants and the Lyford Warrants (collectively referred to as “Global Warrants held by Outside Parties”) as derivatives in accordance with the Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). SFAS 133 requires us to record the estimated fair value of the warrants as a liability at issuance and to adjust the liability to estimated fair value each period with any changes in value reflected in earnings. The fair value of the Global Warrants held by Outside Parties was calculated by a third party firm, using the Black-Scholes pricing model, based primarily on the underlying market price of Global’s common stock.

During 2004, the trading price of Global’s shares increased dramatically causing a substantial increase in the fair value of the liability of the Global Warrants held by Outside Parties. During 2004, there was a 206% increase in Global’s common share price from approximately 50 UK pence at December 31, 2003 to 153 UK pence at December 31, 2004. In 2004, we recorded an unrealized loss of $14 million relating to the increase in value of the Global Warrants held by Outside Parties. In 2005, we could recognize additional losses if Global’s share price increases and possible gains if Global’s share price decreases. Our earnings could continue to fluctuate by material amounts until the warrants expire in 2005. We anticipate that the Global Warrants held by Outside Parties will be exercised prior to expiration which will dilute our ownership in Global but will not require a cash outlay from us to settle the $15 million Global Warrant Liability that is reflected on our Consolidated Balance Sheet as of December 31, 2004.

As part of Global’s August 2002 issuance of warrants to its shareholders, Global issued to us warrants to purchase 6,487,481 shares of Global’s stock at 60 UK pence per share. Since Global is a consolidated subsidiary, this warrant issuance is not reflected in our Consolidated Financial Statements. The estimated fair value of these warrants at December 31, 2004 was approximately $11.8 million, as calculated by a third party firm. These warrants expire in August 2005. We anticipate exercising these warrants prior to expiration which would require a cash outlay from us to Global of approximately 3.8 million UK pounds sterling (or approximately $7.4 million using the December 31, 2004 exchange rate).

In addition to the Global stock warrants described above, certain employees and directors of Global hold options to purchase 4,032,000 shares of Global’s common stock at December 31, 2004.

At December 31, 2004 we owned 85.35% of Global’s common stock. Our ownership in Global may be reduced if the warrants and options described above are exercised. As of December 31, 2004, the following Global warrants and options were outstanding:

If all Global warrants and stock options were exercised, our fully-diluted ownership of Global’s issued and outstanding ordinary common shares could decrease from 85.35% to 59.96%.

As of March 16, 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 the approval of other matters. See “Risk Factors” set forth in this section.

Our consolidated financial statements have been prepared in accordance with 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 reasonable. 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:

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 20 - “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 the 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, safety considerations that may ultimately impact the amount of the obligation.

Derivative Instruments— We are exposed to risk from fluctuations in crude oil and natural gas prices. To reduce the impact of this risk in earnings and to increase the predictability of our cash flow, from time to time we enter into certain derivative contracts, primarily collars and floors for a portion of our North American oil and gas operations. As required by SFAS 133, we are required to record all derivative contracts at fair value on our balance sheet. Changes in fair value are required to be recorded in income or income and 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 utilize independent third parties to assist us in determining the fair value of many of our transactions, including the Global Warrants held by Outside Parties. Fair value is generally determined by applying widely acceptable valuation models, (i.e the Black Scholes valuation model) using the trading price of the underlying instrument or by comparison to instruments with comparable maturities and terms.

On September 28, 2004, the Securities and Exchange Commission, (the”SEC”) released Staff Accounting Bulletin (“SAB”) 106 regarding the application of SFAS 143, “Accounting for Asset Retirement Obligations (“AROs”),” by oil and gas producing companies following the full cost accounting method. Pursuant to SAB 106, oil and gas producing companies that have adopted SFAS 143 should exclude the future cash outflows associated with settling AROs (ARO liabilities) from the computation of the present value of estimated future net revenues for the purposes of the full cost ceiling calculation. In addition, estimated dismantlement and abandonment costs, net of estimated salvage values, that have been capitalized (ARO assets) should be included in the amortization base for computing depreciation, depletion and amortization expense. SAB 106 is effective prospectively as of the beginning of the first fiscal quarter beginning after October 4, 2004. We adopted SAB 106 in the fourth quarter of 2004. SAB 106 had no impact on our consolidated financial statements.

On December 16, 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payment” 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, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. Statement 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” For us, SFAS 123 (R) is effective for the first reporting period after June 15, 2005 and is applicable only to new awards or awards that have been modified, repurchased or cancelled after the effective date. We are currently evaluating the impact this new standard will have on our company.

On December 16, 2004, the FASB issued Statement 153, “Exchanges of Nonmonetary Assets”, an amendment of APB Opinion No. 29, to clarify the accounting for nonmonetrary exchanges of similar productive assets. SFAS 153 provides a general exception from fair value measurement for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Statement will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We do not have any nonmonetary transactions for any period presented to which this Statement would apply.

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.

Net loss and per-share amounts for each of the years in the three year period ended December 31, 2004, were as follows:

The primary components or our (1) net loss for the year ended December 31, 2003 compared to the net loss for the year ended December 31, 2002 and (2) net loss for the year ended December 31, 2004 compared to the net loss for the year ended December 31, 2003, are outlined in the table below:

During 2003 and 2004 our operating profits were dramatically affected by rising commodity prices for natural gas and crude oil. Our average realized natural gas price per MCF increased from $3.33 in 2002 to $5.40 in 2003 and to $6.18 in 2004, an increase of 62% in 2003 and 14% in 2004. Crude oil prices experienced similar increases. GEM’s average realized price for crude oil sales per barrel increased from $24.78 in 2002 to $30.38 in 2003 and to $40.05 in 2004. Global’s average realized price for crude oil sales per barrel increased from $16.38 in 2002 to $21.72 in 2003 and to $29.98 in 2004.

These increases helped to mitigate our oil and gas production declines in 2003 and 2004. During 2003 our natural gas production declined 34% and crude oil production declined 13% from the previous year. This decline was primarily attributable to cutbacks in our capital expenditure programs during 2002 and 2003.

In 2004, our consolidated net natural gas production declined an additional 16% to 1.8 Bcf and crude oil net production declined 14% to 546,000 Bbls. The 2004 decrease in GEM’s oil and gas production was due to the December 2003 sale of certain Texas panhandle properties and 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 fourth quarter of 2004. Production volumes from the Lake Raccourci field and Main Pass 35 field and facility were substantially reduced due to the severe storms in September and October 2004. The majority of GEM’s oil and gas production is located along the Gulf of Mexico.

The decrease in Global’s crude oil production was primarily due to declines in producing wells and workovers in late 2004 of certain wells that reduced oil production during the workover process. Oil production from new wells drilled during 2004 helped to mitigate the overall decrease in volumes.

The 2003 decrease in general and administrative expenses compared to 2002 was primarily due to employee reductions during 2003 offset by related severance costs. We reduced our employee count by 38%, from 42 employees to 26 employees in 2003. The 2003 decrease in general and administrative expenses over the prior year period was partially mitigated by increased legal and professional costs in 2003 associated with our capital restructuring plan. During 2004, our general and administrative were approximately equal to the costs incurred in 2003. Decreases in general and administrative expenses in 2004 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 was offset by start-up costs associated with IBA and an increase in professional and audit fees associated with implementation of the Sarbanes-Oxley 404 internal control compliance requirements. We expect general and administrative expenses to increase in 2005 primarily due to the consolidation of a full-year of IBA’s operations.

After realizing a 22% decrease in depreciation, depletion and amortization (“DD&A”) expense during 2003, our 2004 DD&A expense increased approximately 20% to $10.7 million. 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, as our consolidated oil and gas production decreased approximately 17%, 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 52% to $2.25 per 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 $1.17 per MCFe in 2004.

During the fourth quarter of 2002, we recorded a non-cash full-cost valuation allowances totaling $0.5 million related to Global’s Peru and Panama unevaluated property costs incurred for specific areas which Global no longer intended to pursue under its Technical Evaluation Agreements in Peru and Panama. Global has no proved reserves associated with the Peru or Panama Technical Evaluation Agreements. We did not record any full-cost valuation allowances in 2003 or 2004.

Given the volatility of oil and gas prices, our 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, we may record additional impairments of oil and gas properties. In addition, additional 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. For further discussion, see “Note 4 – Oil and Gas Properties” in the Notes to Consolidated Financial Statements contained in Part II, item 8.

During the fourth quarter of 2002, we recorded an impairment of approximately $400,000 on certain Colombia oilfield equipment consisting of casing and tubing inventory. Based on the low industry demand for such equipment in light of heightened Colombia security concerns, the carrying value of such inventory was in excess of estimated future cash flows from the sale or use of such equipment. We did not record any asset impairments in 2003 or 2004.

During 2002 and 2003 we settled various liabilities, contingencies and lawsuits, some of which were settled for amounts less than we had previously recorded. In 2002 we recorded litigation and contingent liability settlement expenses of $2.2 million related to a mediated settlement of the Petrochemical litigation and a benefit of approximately $1.0 million for a litigation settlement that was settled for an amount less than we had recorded in previous years. During the fourth quarter of 2003, we recorded an expense of $1.1 million associated with settlement related to the Rice lawsuit. During 2004, we recorded no litigation and contingent liability expense amounts. As of December 31, 2004, we believe our reserves for litigation and contingent liabilities are adequate. For further discussion see “Note 21 – Commitments and Contingencies” in the Notes to Consolidated Financial Statements contained in Part II, item 8.

Interest expense and other includes the following for each of the years in the three-year period ended December 31, 2004:

Our annual interest expense and other has decreased significantly over the three-year period ended December 31, 2004 due primarily to the reduction of our overall debt as a result of our 2002 and 2003 capital

restructuring plan. The overall reduction in our debt balances has reduced interest expense by over 91% during this three-year period.

Interest expense and other decreased 25% during 2003 compared to 2002, primarily due to the overall reduction in our current and long-term debt. The decrease in interest expense and other was mitigated by our expensing of the remaining unamortized debt issuance costs of approximately $740,000 related to the issuance of warrants to purchase Global ordinary shares which were issued to Lyford in consideration for the Investor Term Loan which was paid in full in March 2003. In addition, we expensed $281,000 of unamortized debt issuance costs of a promissory note issued to Waverley Investments Limited, which was redeemed with cash in full in June 2003.

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.

During 2002 and 2003, we repurchased or exchanged certain of our 5% European Notes for cash and/or other debt securities. During 2002, we recorded a gain of $890,000 relating to the acquisition or exchange of $7,880,000 principal amount of 5% European Notes. Also, in August 2002, we repurchased $4,071,000 principal amount of Benz Convertible Notes for $1,231,000 in cash and recorded a gain of approximately $2.8 million related to that transaction. During 2003, we recorded a gain of approximately $5.5 million from cash purchases, exchanges and/or payments of outstanding 5% European Notes and Benz Convertible Notes.

During 2004 we repaid the principal amount of the Senior Secured Notes, at a discount of approximately 18%, recording a gain on extinguishment of $325,000. In December 2004, we redeemed the December 2004 principal installment of the 4.25% Convertible Notes in accordance with the terms of the notes, for a number of shares of our common stock equal to 110% of the sum of the outstanding principal amount of the notes to be redeemed plus accrued and unpaid interest. On the December 2004 settlement date, we recorded a loss on extinguishment of approximately $170,000 for the payment of the December 2004 installment of the 4.25% Convertible Notes for the difference between the carrying value of the 4.25% Convertible Notes and the fair market value of the 1.9 million shares of our common stock issued.

During 2003 we realized an income tax benefit of $184,000 due primarily to a refund related to the amended 2001 Colombian income tax declaration for Global’s wholly-owned subsidiary, Harken de Colombia, Ltd. We received no such refund in either 2002 or 2004.

In December 2002, we exchanged 2,000,000 of our shares of common stock of Global for 1,232,742 of the redeemable ordinary common shares of New Opportunities Investment Trust PLC (“NOIT”), an investment trust organized under the laws of the United Kingdom (a public limited company admitted for trading on the Alternative Investment Market of the London Stock Exchange). We accounted for the 1,232,742 ordinary shares of NOIT as an investment in available for sale securities in accordance with Statement of

Financial Accounting Standards No. 115 “Accounting for Certain Investment in Debt and Equity Transactions”. Available for sale marketable securities are recorded at fair value with gains or losses deferred in other comprehensive income until it is sold, except for any loss that is considered a permanent impairment of the investment. A permanent impairment of an “available for sale” marketable security is required to be reflected in earnings immediately.

Subsequent to our investment in NOIT, the market price of NOIT’s common stock experienced a continuing steep decline and a continued lack of trading activity. We considered our investment in NOIT to be permanently impaired. In 2002 and again in early 2003 we recorded the impairment of our NOIT investment as an expense of $499,000 and $488,000, respectively in the Consolidated Statement of Operations for 2002 and 2003. In late 2003 the stock price of NOIT began to increase and its trading activity began to stabilize and improve, and by the end of 2003 we had recovered $606,000 of the previously recognized losses, which we recorded as a deferred gain in Other Comprehensive Income as of December 31, 2003. In February 2004, we sold all of our shares of NOIT for $1.6 million, recognizing a gain 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 our previously recognized losses in 2002 and 2003.

In July and August 2002, we issued a 10% term loan to Lyford in exchange for $5 million in cash and warrants to purchase from us a total of 7 million shares of Global’s common stock, representing approximately 29% of our holdings of Global shares. The warrants expire October 2005 and are exercisable at 50 UK pence per share (the approximate quoted market price of Global’s common stock at the date of issuance of the warrants). In August 2002, Global issued warrants to its minority shareholders to purchase 505,407 shares of Global’s common stock at 60 UK pence per share. As more fully described in Note 8 – “Global Warrants and Stock Options” in the Notes to Consolidated Financial Statements, contained in Part II, Item 8, we are required to recognize the fair value of the Global Warrants held by Outside Parties as a liability with any changes in fair value reflected in earnings.

We engage a third party firm to determine the fair value of the warrants, which is based in part, on the underlying share price of Global’s common stock. At issuance in 2002, the fair value of the warrants was estimated to be approximately $644,000, and throughout 2002 and 2003, Global’s common stock experienced insignificant fluctuations in value. As of December 31, 2003, the fair value of the warrants was determined to be approximately $651,000 and a loss of $7,000 associated with the increase in the Global warrant liability was recorded in earnings in 2003.

Following Global’s May 2004 announcement of year-end 2003 results and the successful drilling of the Estero #4 well, Global’s share price increased significantly. Throughout 2004, Global’s common share price has fluctuated but has increased in value from approximately 50 UK pence at December 31, 2003 to 153 UK pence at December 31, 2004. As of December 31, 2004, the fair value of the Global warrant liability was estimated to be approximately $15 million, and we recognized a loss in 2004 of $14 million for the increase in the fair value of the Global Warrants held by Outside Parties. As noted earlier, our earnings could continue to fluctuate by material amounts until the warrants expire in 2005. We anticipate that the Global Warrants held by Outside Parties will be exercised prior to their expiration in 2005, which will dilute our ownership in Global.

All of our preferred stock issuances require us to accrue dividends. Dividends related to all of our preferred stock issuances 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) attributable to common shareholders.

Accruals of dividends related to preferred stock for each of the three years are as follows:

In April 2004 upon the issuance of the Series G4 Preferred, 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 Condensed Statement of Operations for the year ended December 31, 2004, as an increase to Net Income Attributed to Common Stock.

In October 2004, we entered into a Conversion/Redemption Agreement (the “Agreement”) with the holders of the 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”).

We have 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 as a decrease to Net Income Attributed to Common Stock.

In October 2004, we offered all Series G1 Preferred and Series G2 Preferred holders an inducement to convert their Series G1 Preferred and G2 Preferred shares into shares of our common stock. For a limited time, holders of Series G1 Preferred and G2 Preferred were able to convert their 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. Under the original conversion terms, the Series G1 Preferred are convertible into shares of our common stock at a conversion rate of $12.50 per share, and the Series G2 Preferred are convertible into shares of our common stock at a conversion rate of $3.00 per share.

We 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 Exchange of Preferred Stock in the Consolidated Statement of Operations for the year ended December 31, 2004 as an approximate $287,000 decrease to Net Income Attributed to Common Stock.

During 2003 and 2004, 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 and 2004 we issued approximately 947,000 and 742,000 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 and $4.2 million in 2003 and 2004, respectively, and is reflected as Payment of Preferred Stock Dividends as an addition to net income/(loss) to arrive at net income/(loss) attributable to common shareholders. See “Note 13 - Stockholders’ Equity” in the Notes to the Consolidated Financial Statements contained in Part II, Item 8 for further discussion.

During 2004 the proceeds allocated to the Series L Preferred represented a discount to the market value of the underlying shares of our common stock. 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 attributable to the Series L Preferred. This represented a beneficial conversion feature and was recorded in 2004 as a Payment of Preferred Stock Dividends as a decrease to net income/(loss) to arrive at net income/(loss) attributable to common shareholders.

Also during 2004, as a result of the issuance of certain equity securities and pursuant to the terms of the agreements, we adjusted the conversion and exercise prices of the Series J Preferred and Series L Preferred and common stock warrants. We recorded Payments of Preferred Stock Dividends totaling $214,000 related to these adjustments as a decrease to net income/(loss) to arrive at net income/(loss) attributable to common shareholders.

The payment of preferred stock dividends for each issuance and transaction for each of the three years is as follows:

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 our GEM operating results for each of the years in the three-year period ended December 31, 2004:

Oil and Gas Revenues and Oil and Gas Expenses for the Year Ended December 31, 2003 Compared to December 31, 2002.

GEM’s gross oil and gas revenues during 2003 related to the operations in the onshore and offshore areas of the Texas and Louisiana Gulf Coast and the Western and Panhandle regions of Texas. In March 2003, we sold interests in oil and gas producing properties located in Louisiana for approximately $600,000. In December 2003, we sold the majority of our oil and gas properties located in the Panhandle region of Texas for a gross sales price of approximately $7 million, subject to certain adjustments. During 2003, oil and gas revenues increased 8% to approximately $18.8 million compared to approximately $17.4 million for the prior year due to an increase in average commodity prices received during 2003, offset by declines in production.

Gas revenues increased 7% to approximately $11.5 million during 2003 compared to approximately $10.8 million for the prior year due to an increase in average gas prices received during 2003, as we received an overall average price of $5.40 per Mcf of gas during 2003 compared to $3.33 per Mcf received during 2002. Mitigating the increase in gas revenues was the decline in gas production of 34% to 2,132,515 Mcf in 2003 as compared to 3,225,104 Mcf in 2002.

Oil revenues increased 9% to approximately $7.2 million during 2003 compared to approximately $6.6 million during 2002 due to an increase in oil prices received during 2003 which averaged $30.38 per barrel compared to $24.78 per barrel in 2002. This increase in oil revenues was mitigated by a 11% decrease in oil volumes as compared to 2002.

Oil and gas production volumes were 26% lower in 2003 as compared to 2002 due primarily to high decline rates on certain Lapeyrouse and Lake Raccourci wells which reached the end of their productive lives in specific producing zones, along with normal production decline on other producing properties. Capital expenditures to develop the domestic oil and gas assets in 2003 were minimized in order to focus capital resources on reducing outstanding debt principal balances.

Oil and gas operating expense decreased 3% to approximately $7.1 million during 2003 compared to approximately $7.3 million during the prior year primarily due to a decrease in oil and gas sales volumes in 2003. This decrease was mitigated by increased salt water disposal costs associated with the Lake Raccourci field in Lafourche Parish, Louisiana, along with increased compressor and chemical treating costs per well.

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

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 fourth quarter 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 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 $6.14 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. We currently hold a natural gas floor contract with a $5.00 strike price per MMBTU for 70,000 MMBTUs per month for the twelve-month period ending December 31, 2005.

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. We currently hold a crude oil floor contract with a $30.00 strike price per barrel for 6,000 barrels per month for the twelve-month period ending December 31, 2005.

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.

GEM’s oil and gas production volumes are expected to increase in 2005. Our 2005 budgeted capital expenditures for the development of GEM’s oil and gas assets is approximately $16 million, a 78% increase in GEM’s capital expenditures as compared to 2004. See “Liquidity and Capital Resources” below for further discussion.

Global’s revenues relate to our oil operations in Colombia, from production from our Bolivar, Bocachico and Alcaravan Association Contract Areas. The following table sets forth Global’s operating results for each of the years in the three-year period ended December 31, 2004:

During the three year period ended December 31, 2004, Global has experienced increasing oil revenues and operating profits and declining oil production volumes. In 2003, Global’s revenues increased approximately 12% and increased an additional 28% in 2004. Operating profits increased 10% in 2003 and an additional 37% in 2004. 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 83% over the three year period ending December 31, 2004 to an average $30.02 per barrel in 2004. All Colombian crude oil production is sold at spot rates less quality adjustments.

Oil Revenues and Oil Expenses for the Year Ended December 31, 2003 Compared to December 31, 2002.

Global’s oil volumes declined in 2003 by 15% compared to 2002 primarily to normal production decline on the producing wells, mechanical lifting inefficiencies at the Canacabare #1 well and shutting-in of the Catalina #1 well, offset by new production from the Cajaro #1 well. In 2002, the Torcaz #2 well in Bocachico Association Contract Area was placed on production and in 2003, Global completed the drilling of the Cajaro #1 well on the Alcaravan Contract Area with production commencing in June 2003.

In March 2003, Global initiated production from the Canacabare #1 located in Global’s Alcaravan Association Contract block in the Llanos Basin of Eastern Colombia. During 2003, daily production began from the Canacabare #1 well and produced a total of 39,000 gross barrels of oil during 2003.

Global’s operating expenses increased 18% from approximately $2.0 million for 2002 to approximately $2.4 million for 2003, primarily due to the installation of subsurface production equipment on the Canacabare #1 well, along with generator repair costs for the Bocachico Contract area and the additional operating costs of the Cajaro #1 well which began production in June 2003.

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

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.

Global’s oil production volumes are expected to increase in 2005. Our 2005 budgeted capital expenditures for the development of Global’ oil assets are approximately $18 million, a 100% increase in Global’s capital expenditures as compared to 2004. See “Liquidity and Capital Resources” below for further discussion.

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, 2004, IBA had no liabilities and their principal asset was $11.6 million in cash. IBA’s cash balance represents approximately 40% of our consolidated cash balance.

During late 2004, IBA placed minimal gas futures trades resulting in trading losses of $260,000. In 2004, IBA incurred $656,000 in general and administrative expenses primarily attributed to salaries, travel and professional fees associated with its startup and initialization of trading operations. We anticipate IBA will increase its trading operations during 2005.

Under our capital restructuring plan during 2003, we focused our resources and efforts on repurchasing and/or restructuring our outstanding debt obligations. At the beginning of 2003, our outstanding debt was in excess of $56 million and we had negative working capital of approximately $33.5 million. Working capital is the difference between current assets and current liabilities.

During 2003, we significantly reduced our overhead costs through cost containment and staff reductions and reduced our oil and gas capital expenditures in order to reduce our outstanding debt obligations. During 2003, we successfully reduced our outstanding debt obligations to approximately $7.4 million outstanding at December 31, 2003, an 87% reduction compared to the prior year.

Many of the capital structure changes during 2003 and 2004 involved the issuance of our common stock or conversion of our debt and preferred stock into our common stock or instruments convertible into our common stock. As a result, our common shares outstanding increased from 25.4 million shares at January 1, 2003 to 219.6 million shares at December 31, 2004.

During 2004, we concentrated on the development and growth of our oil and gas assets and energy-based growth opportunities by increasing budgeted oil and gas capital expenditures in 2004 to approximately $18 million. Also we continued our efforts to strengthen our capital structure through extinguishing certain debt at an 18% discount, issuing convertible debt and equity securities for approximately $24 million in cash, converting higher yield preferred stock instruments into shares of our common stock, and repurchasing 2 million shares of our common stock in the market.

In 2005, our Board of Directors approved the 2005 capital expenditure budget totaling approximately $34 million for GEM and Global, representing an 89% increase from our 2004 capital expenditure budget. We anticipate funding the 2005 capital expenditures programs from cash on hand and internally generated cash flow from operations. 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 subsidiaries.

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. At December 31, 2004, we ended the year with positive working capital of approximately $21.8 million, with outstanding total debt of $8.6 million, and cash on hand of approximately $28.6 million. IBA’s cash balance represents approximately 40% of our consolidated cash balance at December 31, 2004.

Net cash from financing activities during 2004 totaled approximately $20.3 million and consisted of approximately $3.2 million in net cash proceeds from the issuance of our common stock and warrants, approximately $16.1 million in net cash proceeds from issuances of preferred stock and warrants and approximately $4.9 million in net cash proceeds from the issuance of 5% Senior Convertible Notes, offset by approximately $2.5 million in repayments of Senior Secured Notes and certain 4.25% Convertible Notes and approximately $1.1 million in repurchases of our common stock. Net cash used in investing activities during 2004 totaled approximately $16.2 million and was primarily comprised of approximately $17.8 million in capital expenditures offset by approximately $1.6 million received for the sale of our investment in NOIT.

Global’s capital expenditures for 2004 totaled approximately $8.9 million. GEM’s capital expenditures for 2004 totaled approximately $8.8 million.

GEM Capital Commitments – GEM’s 2005 capital expenditure budget includes efforts to increase its oil and gas reserves through acquisition, exploitation and development drilling activities. We anticipate GEM capital expenditures will total approximately $16 million during 2005. GEM’s 2005 capital expenditure budget focuses on the onshore and offshore Gulf Coast regions of Texas and Louisiana. Based in part upon the success of its drilling efforts in 2004, the majority of this budgeted capital amount will be used to participate in the drilling of fifteen to twenty exploratory and development wells along the Texas and Louisiana Gulf Coast. GEM currently holds an average working interest in the Lake Raccourci producing wells of approximately 40% and holds an average working interest of approximately 12% in the Lapeyrouse producing wells. However, GEM’s planned North American capital expenditures for 2005 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 2005 will total approximately $18 million to develop its crude oil assets in Middle America. The majority of Global’s 2005 capital expenditure plans are targeted for its Colombian operations in the Palo Blanco Field, Bolivar Field and the Rio Verde Field under its existing Association and Exploration and Production Contracts in Colombia. Approximately $1 million is budgeted for other seismic and exploration costs in Peru, Panama and Colombia. Approximately $4.9 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 National Hydrocarbons Agency of the Republic of Colombia. These contracts required Global to perform certain activities in Colombia in accordance with a prescribed timetable. As of March 16, 2005, 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.

We expect to fund the budgeted 2005 capital expenditures with available cash on hand and through projected cash flow from operations in 2005. Possible weakening commodity prices, a decline in drilling success or substantial delays on bringing on production form wells drilled could cause us to reduce projected 2005 expenditures. The majority of our planned capital expenditures for 2005 are discretionary and may be curtailed or reduced if sufficient funds are not available.

4.25% Convertible Notes — In December 2003, we issued $5 million principal amount of 4.25% Convertible Notes due 2006 to certain investors. The 4.25% Convertible Notes may be redeemed for cash, at our option, in whole or in part, at any time, upon not less than 10 days notice to the holders. Our 4.25% Convertible Notes are convertible into shares of our common stock at a conversion price of $1.25 per share, subject to certain adjustments.

The 4.25% Convertible Notes are also convertible at our option into shares of our common stock if, for any period of 30 consecutive days commencing upon registration of the underlying conversion shares, the average of the closing prices of our common stock for each trading day during such 30-day period equals or exceeds 125% of the 4.25% Convertible Notes Conversion Price (or $1.56 per share of our common stock).

The 4.25% Convertible Notes may be redeemed at our option, for cash equal to the outstanding principal and accrued interest to the date of redemption, upon not less than 10 days notice to the noteholders. In addition, we may redeem the relevant installment of principal and accrued and unpaid interest of the outstanding 4.25% Convertible Notes for shares of our common stock, in each case upon not less than 10 days notice to the noteholders. If we elect to redeem the 4.25% Convertible Notes for shares of our common stock, each note will be redeemed for a number of shares of our common stock equal to 110% of the principal value of the notes to be redeemed, plus accrued and unpaid interest thereon to the date of redemption, divided by the average market price of the stock over the 10 calendar days immediately preceding the date of the notice of redemption.

Pursuant to the terms of the 4.25% Convertible Notes, we are required to maintain unencumbered assets such that the ratio of (1) the fair market value of the unencumbered assets to (2) the outstanding principal amount of the 4.25% Convertible Notes, is equal to or greater than 1.5 to 1.0. At December 31, 2003 and 2004, we were in compliance with the asset coverage ratio under the 4.25% Convertible Notes.

At December 31, 2003 and 2004, respectively, based on the scheduled principal installments, approximately $1.7 million of the 4.25% Convertible Notes is classified as current debt in the Consolidated Balance Sheet.

5% Senior Convertible Notes — In August 2004, we issued to qualified investors $5,245,000 aggregate principal amount of our 5% Senior Convertible Notes due June 30, 2009 (the “5% Notes”) in exchange for $5,245,000 in cash. The 5% Notes are convertible into shares of our common stock at a conversion price of $0.52 per share, subject to adjustments in certain circumstances. The 5% Notes bear interest at the rate of 5% per annum. Interest is payable semi-annually in arrears on December 31 and June 30, commencing December 31, 2004. Upon registration with the SEC of the shares of Harken’s common stock into which the 5% Notes are convertible, the holders of the 5% notes may exercise their rights to convert the 5% Notes. The Notes may be converted in whole or in part, at our option, after the effective date of the registration statement, if at any time following such effective date the average market price of our common stock over any 20 consecutive business day period equals or exceeds 125% of the conversion price ($0.65 per share). The outstanding principal balance of the Notes becomes due and payable in full on June 30, 2009 in cash or, at our option, in shares of our common stock equal to 110% of the principal amount of the 5% Notes divided by the 20-day average market price of our common shares immediately preceding the date of notice of redemption.

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. Global’s international oil exploration and production operations, including well drilling and seismic activities, require specific governmental environmental licenses and permits, the acquisition of which in the past have been subject to extensive delays. Global may continue to experience similar delays in the future. Failure to obtain these licenses and permits in a timely manner may prevent or delay our operational plans.

Effective January 1, 2003, we changed our method of accounting for asset retirement obligations in accordance with FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). Prior to the effective date of SFAS 143, we reflected asset retirement obligations for acquired assets net of related estimated salvage values to be realized at the time of retirement. Under the new accounting method, 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, 2004, our asset retirement obligation liability was approximately $6 million. See Notes to Consolidated Financial Statements, “Note 5 – Asset Retirement Obligation” contained in Part II, Item 8, for further discussions.

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 contractual obligations and commercial commitments as of December 31, 2004.

In addition to the above commitments, during 2005 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. We may fund these future domestic expenditures at our discretion. Further, the cost of drilling or participating in the drilling of any such exploratory and development wells cannot be quantified at this time since the cost will depend on factors out of our control, such as the timing of the request, the depth of the wells and the location of the property. Our discretionary capital expenditures for 2005 will be curtailed if we do not have sufficient funds available. If we do not have sufficient funds or otherwise chooses 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, 2004, 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, 2004, we were not involved in any unconsolidated SPE transactions.

We believe that we have the ability to provide for our 2005 operational needs and our 2005 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.

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.

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, 2004, we have sustained losses in each of our 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 reported losses in each of the last six fiscal years, including a net loss of approximately $12.7 million for the year ended December 31, 2004. We have reported cumulative net losses of approximately $217 million over the last six 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. During the fourth quarter of 2000, we recorded a writedown of our oil and gas properties of approximately $156 million primarily due to a significant reduction in our proved undeveloped reserves in Colombia following the drilling of a non-productive well. 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. During 2004, we recorded a loss of approximately $14 million related to the increase of the fair value of the liability of the Global Warrants held by Outside Parties. Consequently, future losses may adversely affect our business, prospects, financial condition, results of operations and cash flows.

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:

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, 2004, 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 its 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 its 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 March 16, 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:

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

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:

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 last three years ending December 31, 2004. 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 and Related Stockholder Matters.

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 or redemptions of our 4.25% Convertible Notes or 5% Notes, or conversions of our Series G1 Preferred, Series G2 Preferred, Series G4 Preferred, Series J Preferred and Series M Preferred or exercise of warrants issued to holders of our Series J, 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, 2004, we had outstanding 13,925 shares of Series G1 Preferred, 2,500 shares of Series G2 Preferred and 77,517 shares of Series G4 Preferred, 50,000 shares of Series J Preferred, 10,000 shares of Series L 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, 2004, each share of Series G1 Preferred, Series G2 Preferred, Series G4 Preferred, Series J Preferred and Series M Preferred, may be converted into shares of common stock at conversion prices of $12.50, $3.00, $2.00, $0.85, and $0.60 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.

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.

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 2003, the price for a bbl of oil ranged from a high of $35.60 to a low of $28.07 and the price for a Mcf of gas ranged from a high of $9.13 to a low of $4.43. 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.

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:

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.

Through our investment in IBA, we are 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.

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.

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 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.

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 and in Colombia, Peru and Panama include 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, we have experienced and may continue to experience delays in obtaining permits and authorization in Colombia necessary for our operations. We are 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 operations in foreign countries 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 our foreign operations.

Our foreign operations involve substantial costs and are subject to certain risks because 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 our international operations to economic and operating risks not experienced in our domestic operations. We follow the full cost method of accounting for exploration and development of oil and gas reserves in which all of our acquisition, exploration and development costs are capitalized. Costs related to the acquisition, holding and initial exploration of oil and gas associated with our contracts in countries with no proved reserves are initially capitalized, including internal costs directly identified with acquisition, exploration and development activities. If we abandon all exploration efforts in a country where no proved reserves are assigned, all acquisition and exploration costs associated with the country are expensed. From time to time, we make assessments as to whether our investment within a country is impaired and whether exploration activities within a country will be abandoned based on our analysis of drilling results, seismic data and other information we believe to be relevant. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict.

If we fail to comply with the terms of certain contracts related to our foreign operations, we could lose our rights under each of those contracts.

The terms of each of the Colombian Association and Exploration and Production Contracts, the Peruvian License Agreement and the anticipated Panamanian Concession Contract require that we perform certain activities, such as seismic interpretations and the drilling of required wells, in accordance with those contracts and agreements. Our failure to timely perform those activities as required could result in the loss of our rights under a particular contract, which would likely result in a significant loss to us. As of March 16, 2005, we were in compliance with the requirements of each of the existing Association and Concession Contracts.

We require significant additional financing for our foreign operations, which financing may not be available.

We anticipate that full development of our 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 we are unable to timely obtain adequate funds to finance these investments, our 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.

We anticipate that amounts required to fund our foreign activities, conducted primarily through our ownership of Global, will be funded from 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 our foreign operations.

Our foreign operations are subject to political, economic and other uncertainties.

Our subsidiary, Global, currently conducts significant operations in Colombia, Peru and Panama and may also conduct operations in other foreign countries in the future. At December 31, 2004, approximately 54% of our consolidated proved reserve volumes and 37% 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:

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’s 40-year armed conflict between the government and leftist guerrilla groups has escalated in recent years. 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, our operations continue mostly unaffected, although from time to time, guerilla activity in Colombia has delayed our projects there. This guerilla activity has increased over the last few years, causing delays in the development of our fields in Colombia. Guerilla activity, such as road blockades, has also from time to time slowed our deployment of workers in the field and affected our operations. In addition, guerillas could attempt to disrupt the flow of our production through pipelines. In addition to these security issues, we 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.

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

Colombia is among several nations whose progress in stemming the production and transit of illegal drugs is subject to annual certification by the President of the United States. Although Colombia was so certified in 2004, 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:

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 our relationship with the Colombian national oil company and the Colombian government’s ability to control guerrilla activities and could exacerbate the factors relating to our foreign operations discussed above. Any sanctions imposed on Colombia by the United States government could threaten our ability to obtain necessary financing to develop the Colombian properties or cause Colombia to retaliate against us, 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 accounts for its 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 2004 was 0.00036, as compared to an average of 0.00036 for December 2003 and 0.000355 for December 2002.

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 these factors.

Commodity Price Risk – We are a producer of hydrocarbon commodities, including crude oil, condensate and natural gas. We use oil and gas derivative financial instruments, limited to collars and floors with maturities of 24 months or less, to mitigate our exposure of 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 year end 2004.

In September 2004, we 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 contract period from January 1, 2005 through December 31, 2005. We designated the above derivative as a hedge of the exposure to variability of cash flows related to forecasted sales of specified production from certain of our domestic property operations. Such crude oil floor contract is reflected in Prepaid Expenses and Other Assets on our Consolidated Balance Sheet at December 31, 2004 with a fair value of approximately $40,000.

In October 2004, we 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. We designated this derivative as a hedge under SFAS 133. At December 31, 2004, this hedge no longer qualified for hedge accounting treatment under SFAS 133. This natural gas floor contract is reflected in Prepaid Expenses and Other Assets in the Consolidated Balance Sheet at December 31, 2004 with a market value of approximately $63,000.

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. At December 31, 2004 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.

The following financial statements appear on pages 60 through 114 in this Annual Report.

We have audited the accompanying consolidated statements of operations, stockholders’ equity and cash flows of Harken Energy Corporation for year ended December 31, 2002. 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 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 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 Harken Energy Corporation’s operations and its cash flows for the year ended December 31, 2002 in conformity with U.S. generally accepted accounting principles.

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

We conducted our audit in accordance with 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 financial position of Harken Energy Corporation at December 31, 2003, and the consolidated results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 5 to the consolidated financial statements, effective January 1, 2003, Harken Energy Corporation changed its method of accounting for asset retirement obligations.

We have audited the accompanying consolidated balance sheet of Harken Energy Corporation as of December 31, 2004, and the related consolidated statements of operations, stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Harken Energy Corporation at December 31, 2004, and the consolidated results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements.

Harken is engaged in oil and gas exploration, development and production operations both domestically and internationally through its various subsidiaries. The majority of Harken’s domestic operations presently include oil and gas exploration, development and production operations in the onshore and offshore Gulf Coast regions of South Texas and Louisiana. Harken’s international operations during the year ended December 31, 2004 included three exclusive Colombian Association Contracts with Ecopetrol, two Exploration and Production Contracts with the newly formed National Hydrocarbons Agency of the Republic of Colombia and Technical Evaluation Agreements covering acreage in Peru and Panama. In September 2004, Harken invested in a start-up energy company which was formed to engage in trading gas futures contracts, principally in Hungary as well as in the United States.

Principles of Consolidation and Presentation — The Consolidated Financial Statements include the accounts of Harken Energy Corporation (a Delaware corporation) and all of its wholly-owned and majority-owned subsidiaries and variable interest entity (“Harken”) after elimination of significant intercompany balances and transactions.

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. Actual results could differ from those estimates. Certain prior year amounts have been reclassified to conform with the 2004 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 $2,888,000, $1,769,000 and $219,000 during 2002, 2003 and 2004, respectively. All significant non-cash investing and financing activities are discussed in Notes 2, 11 and 13 – Mergers, Acquisitions and Dispositions, Convertible Notes Payable and Stockholders’ Equity.

Concentrations of Credit Risk — Although Harken’s cash and temporary investments, commodity derivative instruments 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 high-grade, short-term securities, 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. Harken sells its oil and gas production to companies involved in the transportation and refining of oil and natural gas. Harken performs continuing credit evaluations of its customers’ financial condition and

although Harken generally does not require collateral, letters of credit may be required from its 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, 2004 is adequate. However, actual write-offs might exceed the recorded allowance.

Property and Equipment — Harken follows the full cost accounting method to account for the costs incurred in the acquisition, exploration, exploitation, development and production of oil and gas reserves. Other property is depreciated on the straight-line method over their estimated useful lives ranging from four to twenty years. Production facilities are depreciated on a units-of-production method.

In accordance with the full cost accounting method for oil and gas properties, Harken reflected valuation allowances during the year ended December 31, 2002 related to the amount of net capitalized costs of evaluated oil and gas properties in excess of the present value of Harken’s oil and gas reserves. See Note 5 – Oil and Gas Properties for further discussion.

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, 2003, other assets included deferred issuance costs of $252,000, net of $23,000 of accumulated amortization, $545,000 of oilfield material and equipment inventory and $449,000 of prepaid drilling costs. At December 31, 2004, other assets included debt issuance costs of $398,000, net of $89,000 of accumulated amortization, $473,000 of oilfield material and equipment inventory and $1,010,000 of prepaid drilling costs and other. Debt issuance costs are amortized over the term of the associated debt instrument.

Middle American Operations — Harken’s Middle American operations are all conducted through its ownership in Global Energy Development PLC (“Global”) (a public limited company registered in England and Wales under the Companies Act (1985) of the United Kingdom) and include oil and gas exploration and development efforts in Colombia, Peru and Panama pursuant to certain Association Contracts, Exploration and Production Contracts, and Technical Evaluation Agreements. See further discussion in Note 7 – Middle American Operations. Global accounts for its Middle America activities using the United States dollar as the functional currency as significant exploration expenditures have typically been denominated in U.S. dollars. See further discussion at Notes 5 and 20 — Oil and Gas Properties and Oil and Gas Disclosures.

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 2002, Harken recorded interest expense of $3,856,000, net of $114,000 of interest which was capitalized to Harken’s oil and gas properties. During 2003, Harken recorded interest expense of $3,312,000, net of $103,000 of interest which was capitalized to Harken’s oil and gas properties. During 2004, Harken recorded interest expense of $402,000, net of $82,000 of interest which was capitalized to Harken’s 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 $238,000, $241,000 and $238,000 for such amounts during 2002, 2003 and 2004, respectively.

Provision for Asset Impairments — Assets that are used in Harken’s operations, and are not held for resale, are carried at cost, less any 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.

During 2002, Global reflected an impairment of $400,000 based on continued declines in the market on certain Colombia oilfield equipment consisting primarily of casing and tubing materials held by Global. Based on the low industry demand for such equipment in light of heightened Colombia security concerns, the carrying value of such inventory was in excess of estimated future cash flows from sale or use of such equipment as estimated using third party quotations.

Revenue Recognition – Harken uses 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 Harken is entitled based on its 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 Harken’s operations.

Commodity Derivative Financial Instruments — Harken 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. Harken accounts for its derivatives in accordance with Statement of Financial Accounting Standard 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, Harken 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. Harken 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 option derivative contracts, Harken excludes the time value component from the assessment of hedge effectiveness. For derivative instruments not designated as hedging instruments, Harken records the change in fair value of the derivative instrument to earnings in Interest Income in the Consolidated Statement of Operations. For further discussion, see Note 17 – Derivative Instruments.

Stock Options – Harken applies APB Opinion 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for all stock option plans. No stock-based compensation cost has been recognized in the consolidated statements of operations for stock options granted to employees because the option exercise price was equal to or exceeded the market price of the underlying common stock on the date of grant. See Note 14 for further discussion of Harken’s and Global’s stock-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 stock option plans had been determined in accordance with the fair value based method prescribed in SFAS 123. 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. 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. For further discussion of Harken’s and Global’s stock options, see Note 14 – Stock Option Plan.

Sales of Oil and Gas Properties – Harken accounts 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.

Accounting for Payment of Series G1 Preferred, Series G2 Preferred and Series G4 Preferred Stock Dividend Liability in Common Shares – Harken accounts for the payment of the Series G1, Series G2 and Series G4 Preferred stock dividends with shares of Harken common stock as a debt extinguishment in accordance with Accounting Principles Board Opinion No. 26, “Extinguishment of Debt” (APB 26). Accordingly, the difference between the carrying value of the Series G1 and Series G2 preferred stock dividend liability at December 31, 2002, approximately $7.4 million, and the fair market value of the shares of Harken common stock issued by Harken in payment of the liability in January 2003, approximately $227,000, is recognized as a Payment of Preferred Stock Dividends in the Consolidated Statement of Operations for the year ended December 31, 2003 as a $6.8 million increase, net of income taxes paid on behalf of the preferred shareholders, to Net Income Attributed to Common Shareholders. For further discussion of Harken’s accounting treatment for payment of Series G1, G2 and G4 Preferred stock dividends, see Note 13 – Stockholders’ Equity.

In 2004, Harken paid the Series G1, Series G2 and Series G4 preferred stock dividend liabilities accrued at December 31, 2003, June 30, 2004 and December 31, 2004 with a total of approximately 742,000

shares of Harken common stock. Accordingly, the difference between the carrying values of the preferred stock dividend liability at December 31, 2003, June 30, 2004 and December 31, 2004 of approximately $4.9 million, and the fair market value of the shares of Harken common stock issued by Harken in payment of the liabilities in 2004, approximately $619,000, is recognized as a Payment of Preferred Stock Dividends in the Consolidated Statement of Operations for the year ended December 31, 2004 as a $4.2 million increase, net of income taxes paid on behalf of the preferred shareholders, to Net Income Attributed to Common Shareholders.

Potential Change in Ownership in Global — At December 31, 2004, Harken owned 85.35% of Global’s common stock. As more fully described in Note 8 – Global Warrants and Stock Options, Harken’s ownership in Global may be reduced under certain circumstances. The following Global warrants and options are outstanding:

(a) As required under SFAS 133, Harken is required to record the warrants issued to Lyford Investment Enterprises Ltd. (“Lyford”) and the minority shareholders (collectively referred to as “Global Warrants held by Outside Parties”) as a liability at fair value with any changes in fair value reflected in earnings each period. At December 31, 2003 and 2004, these warrants were recorded as a liability of $651,000 and $15 million in the Consolidated Balance Sheets. These warrants will expire in August and October 2005.

(b) 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 shares at 60 UK pence per share. Since Global is a consolidated subsidiary, the warrant issuance is not reflected in the consolidated financial statements. The estimated fair market value of these warrants at December 31, 2003 and 2004 was approximately $16,000 and $11.8 million, as calculated by a third-party firm. These warrants will expire in August 2005.

If all Global warrants and stock options, as listed above, were exercised, Harken’s ownership in Global’s ordinary common shares could decrease from 85.35% to 59.96%. As mentioned above, Harken has accounted for Global Warrants held by Outside Parties as a derivative in accordance with SFAS 133, and accordingly has reflected the fair value of the warrants as a liability in the Consolidated Balance Sheet at December 31, 2003 and 2004. Such liability is reflected at the fair value of the derivative, based on the underlying market price of Global common stock, and the corresponding gain or loss related to the change in derivative fair value is reflected in earnings. Harken will continue to measure the changes in the fair value of these warrants and record such changes in value through the income statement in the period in which such changes occur.

Consolidation of Variable Interest Entity – In September 2004, Harken invested $12.5 million in a start-up energy company, International Business Associates, Ltd. (“IBA”) which was formed to focus primarily on opportunities created by the recent deregulation of the energy markets in Eastern Europe. IBA will engage in trading gas futures contracts, principally in Hungary as well as in the United States. IBA’s trading operations

are expected to increase in early 2005. 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 holds 3 of 5 seats on IBA’s Board of Directors.

In accordance with Financial Accounting Standards Board Interpretations 46 (Revised December 2003) “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN 46R), Harken’s investment in IBA is a variable interest. FIN 46R requires the consolidation of a variable interest entity, as defined, if a company will absorb a majority of the variable interest entity’s expected losses, receive a majority of the variable interest entity’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 for the period from September 10, the closing date of the transaction, through December 31, 2004.

Recent Accounting Pronouncements - In September 2004, the SEC released Staff Accounting Bulletin No. 106 (SAB 106) which expresses the SEC’s views regarding the application of FASB Statement No. 143, Accounting for Asset Retirement Obligations, (SFAS 143) by oil and gas producing companies following the full cost accounting method. SAB 106 addresses the calculation of ceiling tests for full-cost oil and gas companies, depreciation, depletion and amortization as affected by the adoption of SFAS 143, as well as the required related disclosures. SAB 106 had no impact on Harken’s financial position or results of operations.

On December 16, 2004, the FASB issued Statement 153, “Exchanges of Nonmonetary Assets”, an amendment of APB Opinion No. 29, to clarify the accounting for nonmonetrary exchanges of similar productive assets. SFAS 153 provides a general exception from fair value measurement for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Statement will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not have any nonmonetary transactions for any period presented that this Statement would apply.

Acquisition of Republic Properties — In January 2002, a wholly-owned subsidiary of Harken signed an agreement to acquire certain property interests (the “Republic Properties”) from Republic Resources, Inc.

(“Republic”). This acquisition was closed in April 2002 following approval by Republic stockholders and debenture holders. The Republic Properties consist of interests in oil and gas wells plus interests in additional prospect acreage located in southern Louisiana and the Texas Gulf Coast region. The Republic Properties were acquired by Harken in exchange for 2,645,500 shares of Harken common stock, which was valued at $2,645,500 on the closing date, plus 79,365 shares of Harken common stock issued as a transaction fee in this acquisition. In addition, the Purchase and Sale Agreement provided for contingent additional consideration of cash or additional shares of Harken common stock, or any combination of the two as Harken may decide, to be paid within 45 days after December 31, 2003, based on a defined calculation to measure the appreciation, if any, of the reserve value of the Republic Properties. No such consideration was required based on the reserve value of certain Republic Properties at December 31, 2003. Since Harken acquired only the oil and gas properties from Republic, the entire purchase price was allocated to the domestic full cost pool.

Sale of Certain Panhandle Oil and Gas Properties – In the fourth quarter of 2003, Harken 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. Harken 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. Harken’s Gulf Coast assets are primarily natural gas. In December 2003, Harken used approximately $4 million of the Panhandle asset sales proceeds to repay all outstanding principal and interest under and terminate Harken’s 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.

Pro Forma Information — The following unaudited pro forma combined condensed statement of operations for the year ended December 31, 2002 gives effect to the acquisition of the Republic Properties and the sale of the Panhandle oil and gas properties, as if it had been consummated at January 1, 2002. 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 each transaction. The above transactions were 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 Adjustments - Pro Forma Condensed Statement of Operations - Year Ended December 31, 2002

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

Included within cash and temporary investments at December 31, 2003 and 2004 are certain investments in money market accounts. The cost of such investments totaled $11,615,000 and $9,715,000 as of December 31, 2003 and 2004, respectively, with cost equal to fair value.

On December 16, 2002, Harken exchanged 2,000,000 of its shares of common stock of Global for 1,232,742 of the redeemable ordinary common shares of New Opportunities Investment Trust PLC (“NOIT”), an investment trust organized under the laws of the United Kingdom (a public limited company admitted for trading on the Alternative Investment Market of the London Stock Exchange). This transaction reduced Harken’s ownership in Global from 92.77% to 85.62%. Harken accounted for the 1,232,742 ordinary shares of NOIT as an investment in available for sale securities in accordance with Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investment in Debt and Equity Transactions,” and reflected the fair value of the investment as an asset included as Investment in Securities at December 31, 2003. As of December 31, 2002, the fair value of the investment, based on the market price of the NOIT common stock, had declined by $499,000. Due to the fact the NOIT common stock price had declined significantly since the date of exchange and trading volume of the stock was minimal, Harken believed this decline was other than temporary. At December 31, 2002, the fair market value of the investment in NOIT was approximately $1.1 million, and the holding loss of $499,000 was recorded in Loss on Investment in Harken’s Consolidated Statement of Operations for the year ended December 31, 2002.

During the three months ended March 31, 2003, the fair value of the investment had declined an additional $488,000. Based on the continuing steep decline of the market price of the NOIT common stock, and its continued lack of trading activity, Harken believed this decline to be other than temporary, and the associated holding loss of $488,000 was included in Loss on Investment during the related period. During the later half of 2003, the market price of NOIT common stock and its trading activity began to stabilize and improve. At December 31, 2003, the fair market value of the investment in NOIT increased to approximately $1.2 million, based on the underlying market price of NOIT common stock. The unrealized holding gain of $606,000 was included as a separate component of Accumulated Other Comprehensive Income in stockholders equity in Harken’s Consolidated Balance Sheet at December 31, 2003. In February 2004, Harken sold all of its 1,232,742 ordinary shares of NOIT on the Alternative Investment Market of the London Stock Exchange for cash proceeds of approximately $1.6 million recognizing 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.

In September 2004, Harken invested $12.5 million in a start-up energy company, IBA, which was formed to focus primarily on opportunities created by the recent deregulation of the energy markets in Eastern Europe. It is anticipated that IBA will engage in trading gas futures contracts, principally in Hungary as well as in the United States. IBA had minimal trading operations in 2004. 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. 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. Harken currently holds three of the five IBA Board of Directors positions. Harken’s preferred stock investment represents almost 100% of IBA’s initial working capital as of December 31, 2004.

In accordance with FIN 46R, Harken’s investment in IBA is a variable interest. FIN 46R requires the consolidation of a variable interest entity, as defined, if a company will absorb a majority of the variable interest entity’s expected losses, receive a majority of the variable interest entity’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 for the period from September 10, the closing date of the transaction, through December 31, 2004. IBA’s net loss included in the Consolidated Results of Operations for the period ended December 31, 2004 was approximately $1 million.

Harken follows 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. Harken capitalized $370,000, $272,000 and $821,000 of internal costs directly related to these activities in 2002, 2003 and 2004, respectively. Such costs include certain office and personnel costs of Harken’s international and domestic exploration field offices and do not include any corporate overhead. Harken also capitalizes costs of dismantlement, restoration and abandonment as required under FASB issued Statement No. 143, “Accounting for Asset Retirement Obligations.” See Note 6 – Asset Retirement Obligation and Note 20—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 U.S. domestic oil and gas properties was $1.44, $1.47 and $2.25 per equivalent Mcf produced during 2002, 2003 and 2004, respectively. Amortization of certain Colombian oil properties was $8.23, $7.56 and $7.02 per equivalent barrel of oil produced during 2002, 2003 and 2004, respectively. The evaluated costs of oil and gas properties, net of accumulated depreciation and amortization, at December 31, 2003 and 2004 include approximately $12.5 million and $18.5 million, respectively, related to Colombia. See Note 7 – 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 of Harken to obtain funds to finance such exploration and development. Harken anticipates 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.

During the fourth quarter of 2002, Harken recorded non-cash full-cost valuation allowances totaling $521,000 related to a portion of Global’s Peru and Panama unevaluated property costs. Global has no proved reserves associated with the Peru or Panama Technical Evaluation Agreements.

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 additional impairments of oil and gas properties could occur. In addition, it is reasonably possible that additional 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.

Effective January 1, 2003, Harken changed its method of accounting for asset retirement obligations in accordance with SFAS 143. Prior to the effective date of SFAS 143, Harken reflected asset retirement obligations for acquired assets net of related estimated salvage values to be realized at the time of retirement. Under SFAS 143, Harken recognizes 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. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The net of tax cumulative effect of the change in accounting method on prior years resulted in a charge to income of $813,000 ((.01) per share) in the first quarter of 2003.

A summary of Harken’s assets with required asset retirement obligations as of December 31, 2004 is as follows:

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

The pro forma effects of the application of SFAS 143, as if the statement had been adopted for all periods presented, is presented below (thousands of dollars except per share information):

The following table describes all changes to Harken’s asset retirement obligation liability during the years ended December 31, 2003 and 2004.

Harken’s Middle American operations are conducted through its ownership in Global. Global’s ordinary shares are listed for trading on the Alternative Investment Market of the London Stock Exchange. At December 31, 2004, Harken owns approximately 85% of Global’s common shares, which may be subject to reduction under certain circumstances, as further described in Note 8 – Global Warrants and Stock Options.

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 two Exploration and Production Contracts with the newly formed National Hydrocarbons Agency of the Republic of Colombia. 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, 2004, 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, 2004, Global was in compliance with the requirements of each of the Alcaravan, Bocachico and Bolivar Association Contracts.

In September 2004, Global signed an Exploration and Production Contract with the National Hydrocarbons Agency of the Republic of Colombia for the Rio Verde area, located in the central Llanos region. The 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. Terms of the contract require Global during Phase 1 to equip for production two existing wells located on the Rio Verde acreage, the Tilodiran #1 and the Macarenas #1. Both of these wells were equipped for production in late 2004 and early 2005. Also during Phase 1 of the contract, Global is required to reprocess 300 kilometers of existing seismic and acquire 50 kilometers of new 2D seismic. The estimated cost to reprocess and acquire the seismic is approximately $600,000.

If Global elects to enter Phase 2 of the Rio Verde contract, Global must drill one exploration well and acquire a further 25 kilometers of 2D seismic. 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.

In November 2004, Global signed a new exploration and production contract with the National Hydrocarbons Agency of the Republic of Colombia for the Los Hatos area, 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. If Global elects to enter phase 2 of the contract, Global must drill either one well or acquire 50 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 March 16, 2005, Global was in compliance with the requirements of each of the Rio Verde and Los Hatos Exploration and Production 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. 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 March 16, 2005, 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, 2004, 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 in the cash flows in its financial statements and reserve information.

At December 31, 2004, Global has proved reserves attributable to the Alcaravan, Bolivar and Bocachico Association Contracts and the Rio Verde 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 Tilodiran and Macarenas fields.

Peru Operations – In April 2001, Global, through a wholly owned subsidiary, signed a Technical Evaluation Agreement (“Peru TEA”) with Perupetro, the national oil company of Peru. The Peru TEA covered an area of approximately 6.8 million gross acres in northeastern Peru. Under the terms of the Peru TEA, Global had the option to convert the Peru TEA to a seven year exploration contract, with a twenty-two year

production period. Terms of the Peru TEA allowed Global to conduct a study of the area that included the reprocessing of seismic data and evaluation of previous well data. In April 2003, Global received an extension from Perupetro of the Peru TEA to July 2003. In June of 2003 Global submitted a final report and completed all obligations required under the TEA. Prior to the expiration of the Peru TEA in July 2003, Global exercised its option under the Peru TEA and entered into negotiations with Perupetro for a License Contract. All work requirements under the Peru TEA were satisfied prior to its expiration. As of December 2004, the negotiations with Perupetro for a License Contract were completed. Global announced on December 2004 that Perupetro, the national oil company of Peru, had approved for signature a new License Contract between Perupetro and Global for the Exploration and Exploitation of Hydrocarbons in the Block 95 Area located in the Marañon Basin of Northeastern Peru.

Panama Operations – In September 2001, Global, through a wholly owned subsidiary, signed a Technical Evaluation Agreement (“Panama TEA”) with the Ministry of Commerce and Industry for the Republic of Panama. The Panama TEA covered an area approximately 1.4 million gross acres divided into three blocks in and offshore Panama. Under the terms of this Panama TEA, Global performed certain work program procedures and studies and submitted them to the Panamanian government. The Panama TEA provided Global with an 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 options to negotiate an Exploration and Exploitation Contract. As of March 16, 2005, the negotiations with the Panamanian government are still in progress.

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 $5,000,000 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 pursuant to the terms of, and the completion of, the 2003 rights offering to Harken’s shareholders.

As additional consideration for the Investor Term Loan, as amended, Harken issued to Lyford warrants (the “Lyford Warrants”) to purchase up to 7,000,000 shares held by Harken of Global at a price of 50 UK pence per share. The warrants will expire on October 13, 2005, 90 days after the originally scheduled maturity date of the Investor Term Loan. These warrants constitute approximately 29% of Harken’s holdings of Global shares at December 31, 2004.

Global Warrants held by Global’s 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 up to 505,407 shares of Global stock at 60 pence per share. During 2004, certain of Global’s minority interest owners exercised their warrants to purchase 5,406 shares of Global stock at 60 UK pence per share. At December 31, 2004, there were 500,061 Global warrants held by Global’s minority interest owners outstanding. The warrants expire in August 2005.

Harken is required to account for the Global Warrants held by Outside Parties as derivatives in accordance with SFAS 133. SFAS 133 requires Harken to record the estimated fair value of the warrants as a

liability at issuance and to adjust the liability to estimated fair value each period with any changes in value reflected in earnings.

During 2004, there was a 206% increase in Global’s common share price from approximately 50 UK pence at December 31, 2003 to 153 UK pence at December 31, 2004. As a result of the changes in Global’s common share price, Harken recorded a loss of approximately $14 million for the year ended December 31, 2004 for the change in the fair value of the Global Warrants held by Outside Parties. The fair value of the warrants was calculated by a third party firm based primarily on the underlying market price of the Global common stock.

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. These warrants expire in August 2005. Since Global is a consolidated subsidiary, this warrant issuance is not reflected in the consolidated financial statements. The estimated fair market value of these warrants at December 31, 2004 was approximately $11.8 million, as calculated by a third-party firm.

Global Stock Options - In addition to the warrants described above, certain employees and directors of Global hold options to purchase 3,243,000 of Global’s ordinary common shares at 50 UK pence per share.

In December 2004, Global issued to certain of its directors, officers and employees options to purchase 780,000 of Global’s ordinary common shares at 151 UK pence per share.

Stock options to purchase 132,000 of Globals’ ordinary common shares at 50 UK pence per share were exercised during 2004. As a result of the Global warrants and stock options exercised during 2004, Harken’s ownership in Global decreased from 85.62% to 85.35% as of December 31, 2004.

If all outstanding Global warrants and stock options were exercised, Harken’s ownership in Global could decrease from 85.35% to 59.96%.

In May 2003, Harken issued to certain holders of Harken’s 5% Senior Convertible Notes due 2003 (the “5% European Notes”) certain 10% Notes Payable (“Notes Payable”) in the total principal amount of $1,390,500, along with the payment of approximately $1,080,000 in cash in exchange for $3,090,000 principal amount of the 5% European Notes. The Notes Payable were to mature on April 30, 2004 and were unsecured. Interest incurred on the Notes Payable was payable semi-annually in October 2003 and April 2004. The principal amount of the Notes Payable was payable in two installments. The first installment in the principal amount of $772,500 together with accrued interest was paid in October 2003. A second and final installment of principal in the amount of $618,000 together with accrued interest was payable no later than April 30, 2004. During December 2003, Harken exercised its right, under the terms of the notes, to prepay the remaining outstanding principal and interest of the Notes Payable. Harken’s indebtness under the Notes Payable was repaid in full on December 31, 2003.

In May 2003, Harken issued $2,020,000 principal amount of Increasing Rate Senior Secured Notes Due 2008 (“Senior Secured Notes”) in exchange for $2,020,000 principal amount of 5% European Notes. The Senior Secured Notes were to mature on May 26, 2008 and ranked senior to the 7% Senior Convertible Notes due 2007 (the “7% European Notes”). Interest incurred on the Senior Secured Notes was payable quarterly beginning January 2004 until maturity.

The principal balance of the Senior Secured Notes could have been redeemed at Harken’s option for cash equal to the outstanding principal balance. Prior to maturity, the principal balance in its entirety, plus accrued and unpaid interest, of the Senior Secured Notes could have been prepaid, upon not less than 30 days notice to the noteholders, at a discount with a combination of cash and freely tradable shares of Harken common stock, as defined in the Senior Secured Note agreement. In December 2003, Harken exercised its rights, under the terms of the notes, to prepay the principal balance in its entirety, plus accrued and unpaid interest, at the stated discount with cash. Harken provided the required notice to the noteholders in December 2003. Subsequently, in accordance with the terms of the notes, in January 2004, Harken repaid in full, the principal amount of the Senior Secured Notes, at a discount equal to 18%, plus accrued and unpaid interest, with cash. In 2004, Harken recorded a gain on extinguishment of $325,000 in the Consolidated Results of Operations. Harken’s indebtness under the Senior Secured Notes was repaid in full in January 2004.

As of December 31, 2004, maturities of Harken’s long-term and short-term debt in 2005 through 2009 are $1,667,000, $1,666,000, $0, $0 and $5,245,000, respectively.

7% European Notes — At December 31, 2003, Harken had outstanding a total of approximately $340,000 principal amount of its 7% European Notes, which were to mature on March 31, 2007. In February 2004, in accordance with the terms of the 7% European Notes, Harken converted the remaining outstanding principal amounts of $340,000, plus accrued and unpaid interest of its 7% European Notes into approximately 696,000 shares of Harken common stock. No gain or loss was recorded for the mandatory conversions of the 7% European Notes as this transaction did not qualify as debt extinguishment.

4.25% Convertible Notes — In December 2003, Harken issued to qualified investors a total of $5 million principal amount of its 4.25% Convertible Notes due 2006 (the “4.25% Convertible Notes”), which

mature in December 2006, in exchange for $5 million cash. The 4.25% Convertible Notes are unsecured and rank equal to all other present and future unsecured indebtedness of Harken. Both principal and accrued interest on the 4.25% Convertible Notes are 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).

On the December 2004 settlement date, 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.

At December 31, 2003 and 2004, respectively, based on the scheduled principal installments, approximately $1.7 million of the 4.25% Convertible Notes are classified as current debt in the Consolidated Balance Sheet.

Pursuant to the terms of the 4.25% Convertible Notes, Harken is required to maintain unencumbered assets such that the ratio of (a) the fair market value of the unencumbered assets to (b) the outstanding principal amount of the 4.25% Convertible Notes, is equal to or greater than 1.5 to 1.0. At December 31, 2003 and 2004, Harken was in compliance with the asset coverage ratio under the 4.25% Convertible Notes.

5% Senior Convertible Notes — In August 2004, Harken issued to qualified investors $5,245,000 aggregate principal amount of its 5% Senior Convertible Notes due June 30, 2009 (the “5% Notes”) in exchange for $5,245,000 in cash. The 5% Notes are 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 bear interest at the rate of 5% per annum. Interest is payable semi-annually in arrears on December 31 and June 30, commencing December 31, 2004. Upon registration with the SEC of the shares of Harken’s common stock into which the 5% Notes are convertible, the holders of the 5% notes may exercise their rights to convert the 5% Notes. The Notes may be converted in whole or in part, at Harken’s option, after the effective date of the registration statement, if at any time following such effective date 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 outstanding principal balance of the Notes becomes due and payable in full on June 30, 2009 in cash or, at Harken’s option, in shares of Harken common stock equal to 110% of the principal amount of the 5% Notes divided by the 20-day average market price of Harken’s common shares immediately preceding the date of notice of redemption.

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. Such 5% European Notes were originally convertible into shares of Harken common stock at a conversion price of $65.00 per share, subject to adjustment in certain circumstances. In January 2003, such conversion price was adjusted to $45.22 per share. Since their issuance in 1998 and prior to their maturity in 2003, Harken repurchased or exchanged an aggregate of approximately $77.7 million principal amount of the 5% European Notes. Upon the date of their maturity in May 2003, the outstanding principal balance of the 5% European Notes, prior to their conversion into shares of Harken common stock, was approximately $7.3 million.

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. The number of the redemption shares was equal to 115% of the principal amount of the notes to be redeemed plus accrued and unpaid interest, divided by approximately $0.35 (the average market price of the common stock over the 30 calendar days immediately preceding the date of the notice of the redemption).

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.

Waverley Note — In March 2003, Harken issued $3,410,000 principal amount of 7% European Notes and the Waverley Note to Waverley in exchange for 17,050 shares of Harken’s Series G-1 Preferred owned by an affiliate of Waverley, and $3,410,000 in cash. In June 2003, Harken redeemed the entire $1,705,000 principal amount of the Waverley Note for cash, the difference between the carrying value of the Waverley Note and the principal amount was fully accreted to Interest Expense in 2003.

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 March 2000, the maturity date of certain of the Benz Convertible Notes was extended to November 26, 2003. The Benz Convertible Notes were originally convertible into shares of Harken common stock at a conversion price of $65.00 per share, subject to adjustment in certain circumstances. In 2003, the conversion price for the Benz Convertible Notes was adjusted to $29.41 per share, effective January 31, 2003. In July 2002, pursuant to the terms of the Benz Convertible Notes, Harken elected to redeem Benz Convertible Notes with a principal amount of approximately $1.1 million for 2 million shares of Harken common stock. In August 2002, Harken repurchased approximately $4.1 million principal amount of Benz Convertible Notes from a holder for $1.2 million in cash and recognized a gain on extinguishment of approximately $2.8 million on this transaction during 2002. Prior to their maturity date in November 2003, Harken had repurchased or redeemed to date approximately $6.3 million principal amount of the Benz Convertible Notes for cash and/or common stock.

In October 2003, Harken issued a notice of redemption for the Benz Convertible Notes for shares of Harken’s common stock. The date of redemption was November 26, 2003. In accordance with the terms of the Benz Convertible Notes, Harken redeemed each Benz Convertible Note outstanding on November 26, 2003, approximately $5.7 million principal amount of Benz Convertible Notes outstanding, plus accrued and unpaid interest, for approximately 8.6 million shares of Harken common stock. The Benz Convertible Notes were redeemed, in accordance with the terms of the notes, for a number of shares of common stock equal to 115% 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 $0.78 (the average market price of the common stock over the 30 calendar days immediately preceding the date of the notice of the redemption).

On the November 2003 settlement date, 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, 2004, the approximate carrying amount and estimated fair value of Harken’s non-traded fixed-rate debt is as follows:

The fair value of Harken’s non-traded fixed-rate debt is based on the discounted cash flows of principal and interest using an estimated available incremental borrowing rate.

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

The Series J 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 $0.85 per share, subject to adjustments in certain circumstances. The Series J Preferred is 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 has equaled or exceeded 150% of the conversion price ($1.28 per share).

Dividends - The holders of the Series J Preferred are entitled to receive dividends at an annual rate equal to 5% per share. All dividends on the Series J Preferred stock are payable quarterly in arrears, beginning on September 30, 2004 in cash or, at Harken’s option, in shares of Harken common stock. The dividend payments in September and December 2004 were paid in cash. The Series J Preferred dividend and liquidation

rights rank 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 expire in April 2005 and have an exercise price of $0.92. Harken may call the warrants if the closing price of Harken’s common stock over five consecutive days closes at or above 150% of the exercise price ($1.38 per share).

Unit Purchase Warrants - The unit purchase warrants issued in connection with the Series J Preferred have an exercise price of $100 per unit. Each unit consists 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 expire in April 2005.

Additional Dividend Feature – If an additional dividend event occurs while the Series J Preferred is outstanding, the holders will have the right to an annual additional dividend calculated at a rate of 6.0% per annum of the issue price of any outstanding Series J Preferred, payable in cash, until such additional dividend event has been remedied. Additional dividend events include the failure of Harken common stock to be listed for trading on any principal market, Harken’s failure to declare or pay in full any dividend payable on the shares of Series J Preferred on the applicable dividend payment date, as well as other additional dividend events that are defined in the terms of the Series J Preferred.

Optional Redemption Event - If an optional redemption event occurs while the Series J Preferred is outstanding, each holder will have the right to require Harken to repurchase all or any portion of such holder’s Series J Preferred at the greater of (x) 115% of the stated value of the Series J Preferred, or (y) the market value of Harken common stock as if the Series J Preferred were converted at the then prevailing conversion price at the time of redemption. An optional redemption event includes the failure to declare and pay dividends on the Series J Preferred, voluntary liquidation, a fundamental change in the ownership of Harken, failure of Harken to generally pay its debts as they become due, as well as other events defined in the terms of the Series J Preferred.

Accounting for the Series J Preferred Stock and Warrants – In accordance with EITF Topic D-98 “Classification and Measurement of Redeemable Securities” (EITF D-98), the Series J Preferred contains certain provisions whereby redemption is deemed to be out of Harken’s control. Therefore the fair value of the Series J Preferred, of approximately $4.7 million is classified as temporary equity in the Consolidated Balance Sheet at December 31, 2004.

In accordance with EITF 00-19 “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock” (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, is also classified as permanent equity in the Consolidated Balance Sheet at December 31, 2004.

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.

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 EITF Issue 00-27, Issue 7, 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 is recorded as a Payment of Preferred Stock Dividends of approximately $135,000 which is included as a decrease to Net Income 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 J Preferred was adjusted from $0.98 to $0.95. In August and October 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 conjunction with SFAS 123 “Accounting for Stock Based Compensation” (SFAS 123), the incremental increase in the fair value of the warrant of approximately $26,000, is recorded as a Payment of Preferred Stock Dividends which is included as a decrease to Net Income Attributed to Common Stock in the Consolidated Statement of Operations for the year ended December 31, 2004. If Harken issues any additional shares of its common stock or any common stock equivalent at a price per share less than the exercise price of the common stock warrants issued with the Series J Preferred, the exercise price of the common stock warrants is subject to additional adjustment.

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 have a liquidation value of $100 per share, are non-voting and were convertible at the holders’ option into Harken common stock at a conversion price of $0.71 per share, subject to adjustments in certain circumstances. 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. The June 2004 and December 2004 dividend payments were paid in cash at Harken’s option.

The dividend and liquidation rights of the Series L Preferred shall rank junior to all claims of creditors, including holders of outstanding debt securities, but senior to holders of Harken common stock and pari passu to any other series of Harken preferred stock, unless otherwise provided.

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.

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 is 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 is classified as permanent equity in the Consolidated Balance Sheet at December 31, 2004.

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 a decrease to Net Income 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 Issue 00-27, Issue 7, approximately $51,000 is recorded as a Payment of Preferred Stock Dividends which is presented as a decrease to Net Income 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 recorded as a Payment of Preferred Stock Dividends which is presented as a decrease to Net Income Attributed to Common Stock in the Consolidated Statement of Operations for the year ended December 31, 2004.

Series L Conversion / Redemption Agreement and Issuance of Series M Cumulative Convertible Preferred Stock

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 Cumulative Convertible Preferred Stock, 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. 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 March 16, 2005, the Series L Preferred is no longer outstanding.

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, subject to adjustments in certain circumstances. 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 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”, Harken has 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 as a decrease to Net Income 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. 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, 2004.

Common Stock — Harken has authorized 325 million shares of $.01 par common stock. At December 31, 2003 and 2004, Harken had 185,405,471 shares and 219,615,485 shares, respectively issued and outstanding. Dividends may not be paid to holders of Harken’s common stock prior to all dividend obligations related to Harken’s Series G1, Series G2, Series G4, Series J and Series M Preferred stock being satisfied.

Treasury Stock — At December 31, 2003 and 2004, Harken had 605,700 and 2,605,700 shares, respectively, of treasury stock. During 2003, Harken did not purchase any shares of its common stock. During 2004, Harken purchased 2 million shares of its common stock at a cost of approximately $1.1 million.

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, subject to adjustment in certain circumstances.

The Series G1 Preferred holders shall be entitled to receive dividends at an annual rate equal to $8 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, payable 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 G2, Series G3, Series G4, Series J and Series M Preferred,

which shall rank equal to the Series G1 Preferred. As of December 31, 2002, Harken had accrued approximately $6.3 million of dividends in arrears related to the Series G1 Preferred stock, approximately $15.62 per share of such preferred stock outstanding. During 2002, Harken’s Board of Directors declared that a dividend be paid on all accrued and unpaid dividends as of December 31, 2002 payable to holders of Harken Series G1 Preferred and Series G2 Preferred, such dividend was paid with shares of Harken common stock. As of the record date for such dividends, December 26, 2002, there were 402,688 shares of Series G1 Preferred outstanding. In January 2003, a total of approximately 587,000 shares of Harken common stock were paid to holders of Series G1 Preferred.

As of December 31, 2003, Harken had accrued approximately $2.6 million of dividends in arrears related to the Series G1 Preferred stock, approximately $8.00 per share of such preferred stock outstanding. During 2003, Harken’s Board of Directors declared that a dividend be paid on all accrued and unpaid dividends as of December 31, 2003 payable to holders of Harken Series G1 Preferred and Series G2 Preferred, such dividend to be paid with shares of Harken common stock. As of the record date for such dividends, December 30, 2003, there were 325,312 shares of Series G1 Preferred outstanding. During January and February 2004, a total of approximately 208,000 shares of Harken common stock were paid to holders of Series G1 Preferred.

During 2004, Harken’s Board of Directors declared that a dividend be paid on all accrued and unpaid dividends as of June 30, 2004 and December 31, 2004 payable to holders of Harken’s Series G1, Series G2 and Series G4 Preferred. 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 June and December 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 June and December 2004, a total of approximately 99,000 shares of Harken common stock were paid to holders of the Series G1 Preferred.

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

Inducement to Voluntarily Convert Series G1 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. Under the original conversion terms, the Series G1 Preferred are convertible into shares of Harken common stock at a conversion rate of $12.50 per share, and the Series G2 Preferred are convertible into shares of Harken’s common stock at a conversion rate of $3.00 per share.

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 tendered out of the total 295,372 Series G1 Preferred outstanding, and holders of 21,650 shares of Series G2 Preferred of the total 24,150 Series G2 Preferred outstanding tendered under the inducement offer. In November 2004, Harken agreed to issue 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 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 Exchange of Preferred Stock in the Consolidated Statement of Operations for the year ended December 31, 2004 as a $287,490 decrease to Net Income Attributed to 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, 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, subject to adjustment in certain circumstances. 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 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, payable 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, the Series G3, the Series G4, the Series J, and the Series M Preferred. At December 31, 2002, Harken had accrued approximately $1,080,000 of dividends in arrears related to the Series G2 Preferred stock, approximately $11.59 per share of such preferred stock outstanding. During 2002, Harken’s Board of Directors declared that a dividend be paid for all accrued and unpaid dividends payable as of December 31, 2002 to holders of Harken Series G1 Preferred and Series G2 Preferred, such dividend was paid with shares of Harken common stock. As of the record date for such dividends, December 26, 2002, there were 93,150 shares of Series G2 Preferred outstanding. In January 2003, a total of 360,010 shares of Harken common stock were paid to holders of Series G2 Preferred.

At December 31, 2003, Harken had accrued approximately $493,000 of dividends in arrears related to the Series G2 Preferred stock, approximately $8.00 per share of such preferred stock outstanding. During 2003, Harken’s Board of Directors declared that a dividend be paid for all accrued and unpaid dividends payable as of December 31, 2003 to holders of Harken Series G1 Preferred and Series G2 Preferred, such dividend to be paid with shares of Harken common stock. As of the record date for such dividends, December 30, 2003, there were 61,650 shares of Series G2 Preferred outstanding. During January and February 2004, a total of approximately 164,000 shares of Harken common stock were issued to holders of Series G2 Preferred.

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 G1 Preferred, Series G2 Preferred and Series G4 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 June

and December 2004, a total of approximately 40,000 shares of Harken common stock were paid to holders of the Series G2 Preferred.

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

See prior discussion of the October 2004 inducement to convert Series G1 and Series G2 Preferred into shares of Harken common stock. At December 31, 2004, there were 2,500 shares of Series G2 Preferred outstanding.

Series G3 Convertible Preferred Stock — In May 2003, 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 G3 Convertible Preferred Stock (the “Series G3 Preferred”), which 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 $0.50 per share, subject to adjustments in certain circumstances. The Series G3 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 during such period shall have equaled or exceeded $0.625 per share. In May 2003, Harken issued 92,700 shares of the Series G3 Preferred in exchange for approximately 31,350 shares of Harken’s outstanding Series G1 Preferred, including commissions, with a liquidation value of $100 per share, and $6 million in cash.

During 2003, holders of 16,000 shares of Harken’s Series G3 Preferred stock elected to exercise their conversion option, and such holders were issued a total of approximately 3.2 million shares of Harken common stock. Also in 2003, Harken exchanged 2,700 shares of Series G3 Preferred stock in receipt of 1,350 shares of Series G1 Preferred stock in payment of financial transaction services to a non-related party for the placement of the Series G3 Preferred series.

During 2004, holders of the remaining 76,700 shares of Harken’s Series G3 Preferred stock elected to exercise their conversion option, and these remaining holders were issued a total of approximately 15.5 million shares of Harken common stock. At December 31, 2004, the Series G3 Preferred is no longer outstanding.

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 has a liquidation value of $100 per share, is non-voting and is 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 is 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 has equaled or exceeded $2.20 per share, initially. This target price will be reduced by 10 percent of the immediately preceding target price in December of each year, commencing December 31, 2004.

The holders of the Series G4 Preferred are 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 are 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, commencing December 31, 2004. At Harken’s option, the dividends can 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.

Harken may also redeem the Series G4 Preferred in whole or in part for cash at any time at $100 per share plus any accrued and unpaid dividends. In addition, on or after January 1, 2006, Harken may further elect, in any six month period, to redeem up to 50% of the outstanding Series G4 Preferred with shares of Harken common stock valued at an average market price, and using a redemption value of the Series G4 Preferred that includes a 5% premium based on Harken’s market capitalization at the time of redemption.

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 G1, Series G2 and Series G4 Preferred, such dividend to be paid with shares of common stock. As of the record date for such dividends, in May 2004, there were 295,372 and 27,150 shares of Series G1 and Series G2, respectively and in November 2004 there were 13,925, 2,500 and 77,517 shares of Series G1, Series G2 and Series G4, respectively, outstanding. As of December 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 paid to holders of the Series G4 Preferred.

Accounting for the Series G4 Preferred Stock 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 Condensed Statement of Operations for the year ended December 31, 2004, as an increase to Net Income Attributed to Common Stock. The valuation of the Series G4 Preferred stock is supported by an appraisal, performed by RP&C International Inc. (“RP&C”), and is 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.

Accounting for Payment of Series G1, Series G2 and Series G4 Preferred Stock 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 26. Accordingly, the difference between the carrying value of the preferred stock dividend liability at December 31, 2002, approximately $7.4 million, and the fair market value of the shares of Harken common stock issued by Harken in payment of the liability in January 2003, approximately $227,000, is recognized as a Payment of Preferred Stock Dividends in the Consolidated Statement of Operations for the year ended December 31, 2003 as a $6.8 million increase, net of withholding taxes paid on behalf of the preferred shareholders, to Net Income Attributed to Common Shareholders.

In January and February 2004, Harken paid the Series G1 and Series G2 Preferred stock dividend liability accrued at December 31, 2003 with 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 as a $2.6 million increase to Net Income Attributed to Common Shareholders.

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 with 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 payment 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 as a $1.6 million increase to Net Income Attributed to Common Stock.

The number of common and preferred shares outstanding and shares held in treasury during 2003 and 2004 are as follows:

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 in NOIT in 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 investment in NOIT, the accumulated holding gain of $606,000 in Other Comprehensive Income was realized into earnings.

Rights Offering — In February 2003, Harken distributed to holders of its common stock, Series G1 preferred, and Series G2 preferred, at no charge, nontransferable subscription rights to purchase shares of its common stock. These shares of common stock included preferred stock purchase rights attached to such common stock under the Stockholder Rights Plan (see further discussion below). Such holders received one subscription right for each share of common stock they owned (or in the case of the Series G1 preferred and Series G2 preferred, one subscription right for each share of common stock issuable upon conversion) at the close of business on January 30, 2003. Harken distributed 32,154,867 subscription rights exercisable for up to 72,885,437 shares of common stock.

Each subscription right entitled the holders to purchase 2.2667 shares of common stock at a subscription price of $0.311 per right (or $0.1372 per share). The subscription rights expired on March 13, 2003. In connection with the rights offering, subscription rights were properly exercised for 13,169,779 shares of common stock for an aggregate purchase price of approximately $1,807,000 during 2003.

Standby Purchase Agreement — On September 6, 2002, Harken entered into a standby purchase agreement with Lyford that defined Harken’s rights and obligations, and the rights and obligations of Lyford, (the “Standby Commitment”). This agreement was amended on November 22, 2002. The standby purchase agreement obligated Harken to sell, and required Lyford to subscribe for and purchase from Harken, a number of shares of common stock equal to the Shortfall divided by the subscription price per share. The “Shortfall” was the amount by which $10,000,000 offering amount exceeded the aggregate subscription price paid by the stockholders who subscribed for and purchased shares in the offering.

During 2002, as compensation to Lyford for its Standby Commitment, Harken paid Lyford a Standby Commitment Fee of $600,000 by issuing 1,714,286 shares of common stock to Lyford (the “Standby Commitment Fee Shares”), with each such share being attributed a value of $0.35. Harken also paid Lyford $50,000, in cash, in 2002 for its legal fees in connection with the rights offering.

Pursuant to the standby purchase agreement, on March 20, 2003, Lyford purchased 59,716,227 shares of common stock from Harken for an aggregate purchase price of approximately $8,193,000. Lyford paid approximately $3,185,000 in cash to Harken. After giving effect to the consummation of Harken’s rights offering and the standby purchase agreement, Lyford became the holder of approximately 62% of Harken’s outstanding common stock, which resulted in a change of control of Harken. As of December 31, 2004, Lyford’s ownership has been subsequently reduced to approximately 30% in the aggregate due to the conversions of certain convertible notes payable and certain preferred shares into shares of Harken common stock.

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, 2004, approximately $3.3 million of the 4.25% Convertible Notes remain 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 11—Convertible Notes Payable for further discussion. Such 4.25% Convertible Notes are convertible into shares of Harken common stock at a conversion price of $1.25 per share, subject to adjustment in certain circumstances.

In August 2004, Harken issued to qualified purchasers a total of $5.245 million aggregate principal amount of its 5% Convertible Notes which are convertible into shares of Harken common stock at a conversion price of $0.52, subject to adjustments in certain circumstances. See Note 11 - 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, including the rights offering and the redemption of Harken’s 5% European Notes.

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, 2004. 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.

Harken has elected to follow Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25) and related Interpretations in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under SFAS 123 requires use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, because the exercise price of Harken’s and Global’s employee stock options equals or exceeds the market price of the underlying stock on the date of grant, no compensation expense is recognized.

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 4 years of continued employment. At December 31, 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. See Note 8 – Global Warrants and Stock Options for discussion on Global stock options. 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 3 years of continued employment.

Pro forma information regarding net income (loss) and income (loss) per share is required by SFAS 123 and has been determined for 2002, 2003 and 2004 as if Harken and Global had accounted for their employee stock options under the fair value method of that Statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the year ended December 31, 2004: risk-free interest rate of 3.5%; dividend yield of 0%; volatility factors of the expected market price of Global common stock of 28.93%; 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 year ended December 31, 2004 reflects the effects of Global’s employee stock-based compensation plans under the fair value method of SFAS 123. Harken’s pro forma information for 2002, 2003 and 2004, as disclosed in Note 1, has been determined as if Harken and Global had accounted for their employee stock-based compensation plans under the fair value method of SFAS 123.

The weighted average fair value of Harken’s options issued in 2002 and 2003 was $0.43 and $0.19 per share, respectively. The weighted average fair value of Global’s options issued in 2002 and 2004 was $0.34 and $0.55 share, respectively.

A summary of Harken’s and Global’s stock option activity, and related information for the years ended December 31, 2002, 2003 and 2004 follows (not in thousands):

Exercise prices for Harken’s options outstanding as of December 31, 2002 ranged from $0.51 to $63.75. Exercise prices for Harken’s options outstanding as of December 31, 2003 ranged from $8.125 to $63.75. The exercise price for Global’s options outstanding as of December 31, 2002 and 2003 was 50 UK pence. Exercise prices for Global’s options outstanding as of December 31, 2004 ranged from 50 UK pence ($0.71) to 151 UK pence ($2.91). All stock options granted, exercised and outstanding as of the year ended December 31, 2004 are related to Global.

The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2002, 2003, 2004 to the amount of income tax expense (benefit) that would result from applying domestic federal statutory tax rates to pretax income:

At December 31, 2004, Harken had available for U.S. federal income tax reporting purposes, a net operating loss (NOL) carryforward for regular tax purposes of approximately $109,000,000 which expires in varying amounts during the tax years 2005 through 2023, an alternative minimum tax NOL carryforward of approximately $92,000,000 which expires in varying amounts during the tax years 2005 through 2023, and a statutory depletion carryforward of approximately $3,647,000 which can be carried forward indefinitely to offset future taxable income of Harken subject to certain limitations imposed by the Internal Revenue Code. 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 NOLs. At December 31, 2004, Harken had

available for Colombian income tax reporting purposes a NOL carryforward of approximately $130,000,000 (US Dollars) that expires in varying amounts during the Colombian tax years 2005 through 2008.

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, primarily related to the NOLs and Colombian oil properties, were approximately $85.6 million at December 31, 2004. 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.

Total deferred tax liabilities, relating primarily to U.S. oil and gas properties as of December 31, 2003, were approximately $2.1 million. At December 31, 2003, total deferred tax assets, primarily related to the NOLs and Colombian oil and gas properties, were approximately $76 million. The total net deferred tax asset was offset by a valuation allowance of approximately $74 million at December 31, 2003, resulting in no impact to results of operations.

In May 2002, Harken entered into a severance agreement and agreed to forgive the repayment of a short-term loan in the principal amount of $64,000 to a member of management related to his resignation as an officer of Harken due to health reasons. Harken reflected the forgiveness as a charge to earnings during 2002.

In January 2004, pursuant to agreements executed in December 2003, Harken forgave the repayment of the remaining outstanding short-term loans in the principal amounts of $80,000 and $25,000 respectively, to a member of management and to a former member of management related to the surrender of their Harken stock options and 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 addition, RP&C has served as a financial advisor in connection with Harken’s restructuring of its international assets, obligations and operations through its Global subsidiary. Also, RP&C currently serves as Global’s nominated advisor for the AIM Exchange in London. 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 2003, Harken repurchased 5,395 shares of Series G1 Preferred stock held by RP&C in consideration for certain financial and transaction consulting services. During 2003, RP&C, as holders of 13,720 shares of Harken’s Series G1 Preferred Stock and 9,000 shares of Harken’s Series G2 Preferred Stock, elected to exercise their conversion option, and such holders were issued 426,424, shares of Harken common stock. During 2003 and 2004, Harken paid to RP&C approximately $1,028,000 and $927,000, respectively, for transaction costs associated with transaction consulting services. In connection with these services provided, RP&C may continue to earn such fees in the future.

Harken 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. Harken’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. Harken’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.

In 2003, Harken purchased a crude oil floor contract with a strike price of $23.00 per barrel for a notional amount of 6,500 barrels per month over a period of the contract through December 31, 2003. Harken did not designate the above derivative as a cash flow hedge under SFAS 133, therefore the derivative cost of approximately $34,000 was recognized as a decrease to Other Income in the Consolidated Statement of Operations for the year ended December 31, 2003.

During 2003 and 2004, Harken 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. Harken had not designated the above derivative as a hedge under SFAS 133, therefore the derivative was marked to market each period. The change in the fair value of the derivative of approximately $129,000 and $303,000 in 2003 and 2004, respectively, is reflected as a decrease and an increase, respectively, to Other Income in the Consolidated Statement of Operations. Such natural gas collar contract was settled at fair value in June 2004.

In December 2003, Harken 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, Harken 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, Harken 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. Harken 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 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, Harken 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. Harken 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 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, Harken 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. Harken designated this derivative as a hedge under SFAS 133. This crude oil floor contract is reflected in Prepaid Expenses and Other Assets in the Consolidated Balance Sheet at December 31, 2004 with a market value of approximately $40,000. During the year ended December 31,

2004, approximately $12,000 is included as a decrease to Other Income in the Consolidated Statement of Operations to reflect the decrease in value of this crude oil floor contract associated with time value.

In October 2004, Harken 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. Harken designated this derivative as a hedge under SFAS 133. At December 31, 2004, this hedge no longer qualified for hedge accounting treatment under SFAS 133. This natural gas floor contract is reflected in Prepaid Expenses and Other Assets in the Consolidated Balance Sheet at December 31, 2004 with a market value of approximately $63,000. During the year ended December 31, 2004, approximately $15,000 is included as a decrease to Other Income in the Consolidated Statement of Operations to reflect the change in fair value of this natural gas floor contract.

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 Harken’s domestic property operations. Gains and losses from commodity derivative instruments are reclassified into earnings when the associated hedged production occurs. Harken holds no derivative instruments which are designated as either fair value hedges or foreign currency hedges. Settlements of 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. Harken monitors its crude oil and natural gas production prices compared to New York Mercantile Exchange prices to assure its commodity derivatives are effective hedges in mitigating its commodity price risk.

Quarterly Data — (Unaudited) — The following tables summarize selected quarterly financial data for 2003 and 2004 expressed in thousands, except per share amounts:

Significant Customers — In 2002, 2003 and 2004, Ecopetrol, which purchases the majority of Global’s Colombia oil production, represented, 30%, 29% and 30%, respectively, 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 Harken due to the availability of other potential purchasers for its oil and gas production.

Operating Segment Information — Harken divides its operations into three operating segments which are managed and evaluated as separate operations. Gulf Energy Management, Inc. (“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 whereby production cash flows are discovered or acquired, and operates primarily through traditional ownership of mineral interests in the various states in which it operates. GEM 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 segment production cash flows have been discovered through extensive drilling operations conducted under Association and Exploration and Production Contracts with the state-owned oil and gas companies/ministries in the respective countries. Global’s production is primarily sold to Ecopetrol. During the three-year period ended December 31, 2004, none of Global’s segment revenues related to Peru or Panama. Harken’s investment in IBA represents its third operating segment. IBA engages in trading gas futures contracts, principally in Hungary as well as in the United States. IBA’s operations began in the late fourth quarter of 2004 and was comprised principally of start-up costs.

Harken’s accounting policies for each of its operating segments are the same as those described in Note 1 – Summary of Significant Accounting Policies. There are no intersegment sales or transfers. 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 20 – Oil and Gas Disclosures for geographic information regarding Harken’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, 2004:

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, 2002, 2003 and 2004.

Not included in the calculation for diluted earnings per share were 1,444,485 and 6,000 employee stock options outstanding during the years ended December 31, 2002 and 2003, respectively. 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 2002 and 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.

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

Global costs during 2002 include $353,000 and $233,000 of costs related to Peru and Panama, respectively. 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.

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

Oil and Gas Reserve Data — (Unaudited) — The following information is presented with regard to Harken’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 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, Global has reflected its 80% share of future net cash flows from the Buturama field in its proved reserves as of December 31, 2004.

In 2004, Global was advised of Ecopetrol’s intent to declare the Cajaro #1 well commercial pursuant to the Alcaravan Contract terms. As of March 16, 2005, 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 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. As of December 31, 2004, 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. Production from Cajaro will be allocated as follows: Ecopetrol, on behalf of the Colombian government, will receive a royalty interest of 8% 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. 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 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, in October 2004, Global, based on the proposed unitization maps and data presented by Ecopetrol, began reflecting a 50% interest in net production from the Cajaro #1 well from the Association Contract area in the cash flows in its financial statements and reserve information as of December 31, 2004.

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

GEM’s reserves reflect reductions for certain producing properties which were sold for cash during 2002 and 2003. GEM”s reserves at December 31, 2004 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 Harken’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.

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

Operating Leases — Harken leases its corporate and certain other office space and certain field operating offices. Total office lease payments during 2002, 2003 and 2004 were $736,000, $698,000 and $465,000, 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, 2004, net of sublease reimbursements of $234,000, $214,000 and $0 in 2005, 2006 and 2007, respectively, are as follows:

In 2004, Global was advised of Ecopetrol’s intent to declare the Cajaro #1 well commercial pursuant to the Alcaravan Contract terms. As of March 16, 2005, 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 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. As of December 31, 2004, 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. Production from Cajaro associated with the Alcaravan Contract area will be allocated as follows: Ecopetrol, on behalf of the Colombian government, will receive a royalty interest of 8% of all production, and all production (after royalty payments) attributable to the Alcaravan Contract area 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. 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, began in October 2004 reflecting a 50% interest in net production from the Cajaro #1 well associated with the Alcaravan Contract area in the cash flows in its financial statements and reserve information as of December 31, 2004. Until the unitization of the affected areas within the Alcaravan and the Los Hatos Contract areas is resolved, the ultimate impact on the distribution of production from the Cajaro #1 well cannot be definitively ascertained. Harken believes that the ultimate outcome of the unitization process will not have a material adverse effect on our financial conditions or operations. Harken has provided a net reserve of approximately $90,000 in accrued liabilities owed to Ecopetrol as of December 31, 2004 based on Harken’s estimate as to the reasonable and probable outcome of the unitization on the Cajaro #1 well. As noted above, the ultimate impact on the unitization of the affected areas within the Alcaravan and the Los Hatos Contract is uncertain and, therefore, additional losses may be incurred in the future. However, the amount of additional losses cannot be reasonably estimated at this time.

Operational Contingencies — The exploration, development and production of oil and gas are subject to various, federal and state laws and regulations designed to protect the environment. Compliance with these regulations is part of Harken’s day-to-day operating procedures. Infrequently, accidental discharge of such materials as oil, natural gas or drilling fluids can occur and such accidents can require material expenditures to correct. Harken maintains levels of insurance it believes to be customary in the industry to limit its financial

exposure. Management is unaware of any material capital expenditures required for environmental control during the next fiscal year.

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 $40,000,000. 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 $40,000,000 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 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., 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 Harken de Colombia Ltd. 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.

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

As reported in Harken’s Quarterly Report on Form 10-Q/A for the quarter ended June 30, 2004, the Audit Committee of the Company’s Board of Directors accepted BDO Seidman, LLP’s (“BDO”) resignation and terminated BDO’s engagement as the Company’s independent registered public accountants as of June 28, 2004. Thereafter, on June 29, 2004, BDO advised Harken’s management and Audit Committee that a material weakness in internal control over financial reporting existed relating to the Company’s inability to determine the appropriate accounting for non-routine securities transactions on a timely basis. During the second half of 2004, Harken entered into additional non-routine securities transactions. Harken’s management accounted for these transactions on a timely basis as BDO apparently would have required.

BDO’s report on the Company’s consolidated financial statements for the year ended December 31, 2003 did not contain an adverse opinion or disclaimer of opinion, nor was such report qualified or modified as to uncertainty, audit scope, or accounting principles.

Pursuant to Securities and Exchange Commission Release No. 50754 dated November 30, 2004, management’s annual report on internal control over financial reporting and the related attestation report of Harken’s independent registered public accounting firm will be included by amendment to this report on Form 10-K to be filed on or before April 30, 2005.

The Company’s principal executive officer and principal financial officer have evaluated the effectiveness of the Company’s disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended, as of December 31, 2004. Based upon their evaluation, the principal executive officer and principal financial officer concluded that, as of December 31, 2004, the company’s disclosure controls and procedures are effective. During the quarter ended December 31, 2004, there have been no changes in internal control over financial reporting for the period covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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, 2005, 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.

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, 2005, 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.

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, 2005, which information is incorporated herein by reference.

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, 2005, which information is incorporated herein by reference.

The information required by this item is incorporated by reference to Harken’s Proxy Statement for its 2005 Annual Meeting of Shareholders, which will be filed with the SEC on or before April 30, 2005.

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 March 16, 2005.

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 March 16, 2005.


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

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


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


		Page
PART I.

ITEM 1.	Business	4

ITEM 2.	Properties	16

ITEM 3.	Legal Proceedings	16

ITEM 4.	Submission of Matters to a Vote of Security Holders	16

PART II.

ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17

ITEM 6.	Selected Financial Data	19

ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	55

ITEM 8.	Financial Statements and Supplementary Data	56

ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	117

ITEM 9A.	Controls and Procedures	118

ITEM 9B.	Other Information	118

PART III.

ITEM 10.	Directors and Executive Officers of the Registrant	119

ITEM 11.	Executive Compensation	119

ITEM 12.	Security Ownership of Certain Beneficial Owners and Management	119

ITEM 13.	Certain Relationships and Related Transactions	119

ITEM 14.	Principal Accounting Fees and Services	119

PART IV.

ITEM 15.	Exhibits and Financial Statement Schedules	120


	Year Ended December 31,
	2000		2001		2002		2003		2004
Production:
Natural Gas (Mcf)		4,012,000		3,844,000		3,225,000		2,133,000		1,788,000
Oil (Bbls)		529,000		273,000		267,000		238,000		182,000
Revenues:
Natural Gas	$	16,178,000	$	16,643,000	$	10,753,000	$	11,524,000	$	11,044,000
Oil		15,422,000		6,708,000		6,617,000		7,229,000		7,290,000

Total	$	31,600,000	$	23,351,000	$	17,370,000	$	18,753,000	$	18,334,000

Unit Prices:
Natural Gas (per Mcf)	$	4.03	$	4.33	$	3.33	$	5.40	$	6.18
Oil (per Bbl)	$	29.15	$	24.57	$	24.78	$	30.38	$	40.05
Production costs per equivalent Mcfe	$	1.68	$	1.69	$	1.51	$	1.99	$	1.88
Amortization per equivalent Mcfe	$	1.07	$	1.52	$	1.44	$	1.47	$	2.25

Global

	Year Ended December 31,
	2000		2001		2002		2003		2004
Production:
Oil (Bbls)		460,000		500,000		465,000		394,000		366,000
Revenues:
Oil	$	10,649,000	$	8,291,000	$	7,619,000	$	8,556,000	$	10,974,000
Unit Prices:
Oil (per Bbl)	$	23.15	$	16.58	$	16.38	$	21.72	$	29.98
Production and transportation costs per equivalent barrel	$	4.96	$	5.87	$	4.38	$	6.09	$	6.95
Amortization per equivalent barrel	$	9.45	$	8.66	$	8.23	$	7.56	$	7.02


	Gross Wells		Net Wells		Developed Acreage		Undeveloped Acreage
State	Oil	Gas	Oil	Gas	Gross	Net	Gross	Net
Texas	22	45	22.00	9.89	7,453	3,349	5,926	1,567
Louisiana	63	31	55.12	5.12	6,712	2,405	9,210	3,543
Other	—	2	—	0.03	—	—	—	—

Total	85	78	77.12	15.04	14,165	5,754	15,136	5,110


	Average Working Interest		Average Revenue Interest
Lake Raccourci – Domestic	40	%	28	%
Lapeyrouse - Domestic	12	%	9	%
Raymondville - Domestic	27	%	19	%
Main Pass Block 35 – Domestic	90	%	72	%
Bayou Sorrel – Domestic	15	%	11	%
Jackson County, Texas - Domestic	9	%	7	%
Alcaravan Contract – Colombia	100	%	86	%
Bolivar Contract – Colombia	100	%	80	%
Bocachico Contract - Colombia	100	%	80	%
Rio Verde Contract – Colombia	100	%	89.5	%
Los Hatos Contract – Colombia	100	%	92	%
Block 95 Contract – Peru	100	%	95	%


	Number of Gross Wells Drilled
	Exploratory		Developmental		Total
	Productive	Drilled	Productive	Drilled	Productive	Drilled
2002	7	8	—	—	7	8
2003	0	1	5	5	5	6
2004	2	4	7	8	9	12

Total	9	13	12	13	21	26


	Number of Net Wells Drilled
	Exploratory		Developmental		Total
	Productive	Drilled	Productive	Drilled	Productive	Drilled
2002	1.35	1.36	—	—	1.35	1.36
2003	—	0.03	1.18	1.18	1.18	1.21
2004	0.10	0.10	1.05	3.23	1.15	3.33

Total	1.45	1.49	2.23	4.41	3.68	5.90


Global

	Number of Gross Wells Drilled
	Exploratory		Developmental		Total
	Productive	Drilled	Productive	Drilled	Productive	Drilled
2002	—	—	—	—	—	—
2003	1	1	—	—	1	1
2004	—	—	2	2	2	2

Total	1	1	2	2	3	3


	Number of Net Wells Drilled
	Exploratory		Developmental		Total
	Productive	Drilled	Productive	Drilled	Productive	Drilled
2002	—	—	—	—	—	—
2003	1.00	1.00	—	—	1.00	1.00
2004	—	—	2.00	2.00	2.00	2.00

Total	1.00	1.00	2.00	2.00	3.00	3.00


		Prices
		High		Low
2003 —	First Quarter	$	0.37	$	0.16
	Second Quarter		0.47		0.28
	Third Quarter		0.76		0.30
	Fourth Quarter		1.28		0.58
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


	Number of Shares Repurchased	Average Price Paid per Share
October 2004	0		N/A
November 2004	982,400	$	0.5125
December 2004	1,017,600	$	0.5241

TOTAL	2,000,000	$	0.5189


	December 31,
	2000			2001			2002			2003			2004
Operating Data:
Revenues and other	$	44,220,000		$	32,466,000		$	25,355,000		$	27,290,000		$	29,995,000
Net loss before cumulative effect of change in accounting principle	$	(152,933,000	)	$	(41,023,000	)	$	(9,807,000	)	$	(184,000	)	$	(12,670,000	)
Net loss	$	(152,933,000	)	$	(41,023,000	)	$	(9,807,000	)	$	(997,000	)	$	(12,670,000	)
Net income (loss) attributed to common stock	$	(153,309,000	)	$	(44,201,000	)	$	(13,917,000	)	$	2,132,000		$	(13,185,000	)
Basic income / (loss) per common share:
Net income / (loss) before cumulative effect of change in accounting principle	$	(9.09	)	$	(2.45	)	$	(0.64	)	$	0.03		$	(0.07	)
Net income / (loss)	$	(9.09	)	$	(2.45	)	$	(0.64	)	$	0.02		$	(0.07	)
Diluted loss per common share:
Net loss before cumulative effect of change in accounting principle	$	(9.09	)	$	(2.45	)	$	(0.64	)	$	(0.02	)	$	(0.07	)
Net loss	$	(9.09	)	$	(2.45	)	$	(0.64	)	$	(0.03	)	$	(0.07	)
Balance Sheet Data:
Current assets	$	29,144,000		$	14,245,000		$	11,021,000		$	16,849,000		$	36,005,000
Current liabilities		13,877,000			10,867,000			44,544,000			8,962,000			14,161,000

Working capital	$	15,267,000		$	3,378,000		$	(33,523,000	)	$	7,887,000		$	21,844,000

Total assets	$	145,347,000		$	95,806,000		$	85,580,000		$	81,012,000		$	107,481,000
Long-term obligations:
Convertible notes payable	$	69,940,000		$	51,388,000		$	11,106,000		$	3,673,000		$	6,911,000
Bank credit facilities		9,937,000			7,937,000			3,810,000			—			—
Investor term loan		—			—			5,000,000			—			—
Senior secured notes		—			—			—			2,020,000			—
Accrued preferred stock dividends		376,000			3,942,000			7,369,000			3,239,000			—
Asset retirement obligation		4,018,000			4,328,000			4,664,000			6,305,000			5,954,000
Global warrant liability		—			—			644,000			651,000			14,858,000
Other long-term obligations		523,000			1,130,000			—			—			—

Total	$	84,794,000		$	68,725,000		$	32,593,000		$	15,888,000		$	27,723,000

Stockholders’ equity	$	46,676,000		$	16,214,000		$	5,131,000		$	52,761,000		$	56,326,000
Series G1 preferred stock outstanding⁽²⁾		158,000			446,000			403,000			325,000			14,000
Series G2 preferred stock outstanding⁽²⁾		—			95,000			93,000			62,000			2,000
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
Weighted average common shares outstanding		16,863,610			18,063,584			21,742,163			112,694,654			201,702,235
Proved reserves at end of year⁽¹⁾⁽³⁾:
Bbls of oil		6,794,000			7,626,000			8,779,000			5,725,000			5,606,000
Mcf of gas		54,836,000			39,393,000			34,508,000			14,214,000			13,327,000
Future net cash flows	$	421,634,000		$	104,166,000		$	236,756,000		$	136,212,000		$	178,167,000
Present value (discounted at 10% per year)	$	264,697,000		$	63,297,000		$	160,237,000		$	107,076,000		$	124,650,000


	Conversion / Exercise Price ^(a)		Common Stock
4.25 % Convertible Notes	$	1.25	2,666,666
5% Convertible Notes	$	0.52	10,086,538
Series J Preferred	$	0.85	5,882,353
Series M Preferred	$	0.60	8,333,333
Series G1 Preferred	$	12.50	111,400
Series G2 Preferred	$	3.00	83,333
Series G4 Preferred	$	2.00	3,875,850
Common Stock Warrants	$	1.06	1,750,000
Series J Common Stock Warrants and Rights	$	0.93	3,019,988
Series L Common Stock Warrants	$	0.67	3,712,049
Series M Warrants	$	0.57	4,385,965

Common Stock Potentially Issued Upon Conversion / Exercise			43,907,475


Lyford Warrants (50 UK pence)	7,000,000	^(a)
Minority-Shareholder Warrants (60 UK pence)	500,061	^(a)
Global Warrants held by Harken (60 UK pence)	6,487,481	^(b)
Global employee stock options (50 UK pence)	3,252,000
Global employee stock options (151 UK pence)	780,000


(Thousands of dollars, except per-share amounts)	2002			2003			2004
Net loss	$	(9,807	)	$	(997	)	$	(12,670	)
Net income /(loss) attributed to common stock	$	(13,917	)	$	2,132		$	(13,185	)
Net income / (loss) per share -
Basic	$	(0.64	)	$	0.02		$	(0.07	)
Diluted	$	(0.64	)	$	(0.03	)	$	(0.07	)


	Favorable (Unfavorable) Variance
(Thousands of dollars)	2003 compared to 2002			2004 compared to 2003
GEM operating profit ⁽¹⁾	$	1,604		$	1,224
Global operating profit ⁽²⁾		578			2,280
IBA operating profit ⁽³⁾		—			(260	)
General and administrative expenses, net		1,088			(12	)
Depreciation and amortization		2,569			(1,772	)
Full cost valuation allowance		521			—
Provision for asset impairments		400			—
Litigation and contingent liability settlements, net		163			1,125
Accretion Expense		(125	)		72
Interest expense and other, net		1,139			2,980
Gains from exchanges and extinguishments of debt		1,997			(5,370	)
Income tax expense/benefit		421			(763	)
Increase in Global warrant liability		(7	)		(14,200	)
Gain/loss on investment		11			1,478
Cumulative effect of change in accounting principle		(813	)		813
Other		(736	)		732

		8,810			(11,673	)


	Payments Due by Period
	2005	2006	2007	2008-2009	Thereafter	Total
Contractual Obligations
Office Leases⁽¹⁾	645,000	543,000	111,000	37,000	—	1,336,000
Global Commitments⁽²⁾	4,900,000	—	—	—	—	4,900,000
GEM Commitments⁽³⁾	—	—	—	—	—	—
4.25% Convertible Notes⁽⁴⁾	1,667,000	1,666,000	—	—	—	3,333,000
5% Convertible Notes⁽⁵⁾	—	—	—	5,245,000	—	5,245,000
Asset Retirement Obligation	17,000	112,000	119,000	161,000	5,545,000	5,954,000

Total Contractual Cash Obligations	7,229,000	2,321,000	230,000	5,443,000	5,545,000	20,768,000


(Thousands of dollars, except per-unit amounts)	2002		2003		2004
Oil and Gas Revenues	$	17,370	$	18,753	$	18,334

Operating profit	$	10,078	$	11,682	$	12,906

Net oil sold (thousands of bbls)		267		238		182
Net gas sold (thousands of mcf)		3,225		2,133		1,788
Average price of oil sold (per bbls)	$	24.78	$	30.38	$	40.05
Average price of gas sold (per mcf)	$	3.33	$	5.40	$	6.18
Average production & transportation costs (per mcfe)	$	1.51	$	1.99	$	1.88


	As of December 31,
(Thousands of dollars)	2003		2004
Current ratio		1.88 to 1		2.54 to 1
Working capital	$	7,887	$	21,844
Total debt	$	7,360	$	8,578
Total cash less debt	$	4,813	$	20,054
Stockholders’ equity	$	52,761	$	56,326
Total debt to equity		0.14 to 1		0.15 to 1


		Page
Reports of Independent Registered Public Accounting Firms		57

Consolidated Balance Sheets — December 31, 2003 and 2004		60

Consolidated Statements of Operations — Years ended December 31, 2002, 2003 and 2004		61

Consolidated Statements of Stockholders’ Equity — Years ended December 31, 2002, 2003 and 2004		62

Consolidated Statements of Cash Flows — Years ended December 31, 2002, 2003 and 2004		63

Notes to Consolidated Financial Statements		64


	G1 Preferred Stock			G2 Preferred Stock			G3 Preferred Stock			G4 Preferred Stock		M Preferred Stock		Common Stock		Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Accumulated Other Comprehensive Income			Total
Balance, December 31, 2001	$	446,000		$	95,000		$	—		$	—	$	—	$	187,000	$	385,710,000		$	(1,433,000	)	$	(369,087,000	)	$	296,000		$	16,214,000
Issuance of common stock		—			—			—			—		—		27,000		2,623,000			—			—			—			2,650,000
Redemption of convertible note		—			—			—			—		—		20,000		1,091,000			—			—			—			1,111,000
Repurchase of preferred stock - related party		(6,000	)		—			—			—		—		—		45,000			—			—			—			39,000
Repurchase of preferred stock		(13,000	)		—			—			—		—		—		(53,000	)		—			—			—			(66,000	)
Conversions of preferred stock		(24,000	)		(2,000	)		—			—		—		3,000		463,000			—			—			—			440,000
Repurchase of treasury stock		—			—			—			—		—		—		—			(19,000	)		—			—			(19,000	)
Rights offering costs		—			—			—			—		—		17,000		555,000			—			—			—			572,000
Preferred stock dividends		—			—			—			—		—		—		—			—			(4,110,000	)		—			(4,110,000	)
Issuance of stock of subisidiary		—			—			—			—		—		—		(1,731,000	)		—			—			—			(1,731,000	)
Comprehensive income:
Net change in derivative fair value		—			—			—			—		—		—		—			—			—			(72,000	)
Reclassification of derivative fair value into earnings		—			—			—			—		—		—		—			—			—			(90,000	)
Net loss		—			—			—			—		—		—		—			—			(9,807,000	)		—
Total comprehensive loss																													(9,969,000	)

Balance, December 31, 2002	$	403,000		$	93,000		$	—		$	—	$	—	$	254,000	$	388,703,000		$	(1,452,000	)	$	(383,004,000	)	$	134,000		$	5,131,000
Issuance of common stock, net of offering costs		—			—			—			—		—		729,000		8,226,000			—			—			—			8,955,000
Conversion/redemption of convertible notes		(17,000	)		—			—			—		—		817,000		28,727,000			—			—			—			29,527,000
Issuance of preferred stock		(32,000	)		—			93,000			—		—		—		5,883,000			—			—			—			5,944,000
Repurchase of preferred stock - related party		(5,000	)		—			—			—		—		—		(43,000	)		—			—			—			(48,000	)
Conversions of preferred stock		(24,000	)		(31,000	)		(16,000	)		—		—		45,000		321,000			—			—			—			295,000
Payment of preferred stock dividends		—			—			—			—		—		9,000		210,000			—			6,805,000			—			7,024,000
Accrual of preferred stock dividends		—			—			—			—		—		—		—			—			(3,676,000	)		—			(3,676,000	)
Comprehensive income:
Unrealized holding gain on available for sale investment		—			—			—			—		—		—		—			—			—			606,000
Net loss		—			—			—			—		—		—		—			—			(997,000	)		—
Total comprehensive loss		—			—			—			—		—		—		—			—			—			—			(391,000	)

Balance, December 31, 2003	$	325,000		$	62,000		$	77,000			—		—	$	1,854,000	$	432,027,000		$	(1,452,000	)	$	(380,872,000	)	$	740,000		$	52,761,000
Issuance of common stock, net of offering costs		—			—			—			—		—		36,000		3,189,000			—			—			—			3,225,000
Issuance of common stock to repay debt		—			—			—			—		—		19,000		1,072,000			—			—			—			1,091,000
Conversion/redemption of convertible notes		—			—			—			—		—		7,000		311,000			—			—			—			318,000
Issuance of preferred stock and common stock warrants		—			—			—			—		50,000		—		7,355,000			—			(1,885,000	)		—			5,520,000
Conversions of preferred stock to common stock		(310,000	)		(37,000	)		(77,000	)		—		—		273,000		4,210,000			—			(289,000	)		—			3,770,000
Conversions of preferred stock to preferred stock		(1,000	)		(23,000	)		—			78,000		—		—		1,851,000			—			338,000			—			2,243,000
Payment of preferred stock dividends		—			—			—			—		—		7,000		611,000			—			4,206,000			—			4,824,000
Accrual of preferred stock dividends		—			—			—			—		—		—		—			—			(2,884,000	)		—			(2,884,000	)
Issuance of stock of subisidiary		—			—			—			—		—		—		(153,000	)		—			—			—			(153,000	)
Repurchase of treasury stock		—			—			—			—		—		—		—			(1,098,000	)		—			—			(1,098,000	)
Comprehensive income:
Reclassification of holding gain on available for sale investment into earnings		—			—			—			—		—		—		—			—			—			(606,000	)
Reclassification of derivative fair value into earnings		—			—			—			—		—		—		—			—			—			(15,000	)
Net loss		—			—			—			—		—		—		—			—			(12,670,000	)		—
Total comprehensive loss		—			—			—			—		—		—		—			—			—			—			(13,291,000	)

Balance, December 31, 2004	$	14,000		$	2,000		$	—		$	78,000	$	50,000	$	2,196,000	$	450,473,000		$	(2,550,000	)	$	(394,056,000	)	$	119,000		$	56,326,000


Warrants to purchase Global shares held by Harken (50 UK pence)	7,000,000	(a)
Warrants to purchase Global shares (Minority-owned) (60 UK pence)	500,061	(a)
Warrants to purchase Global shares (Harken-owned) (60 UK pence)	6,487,481	(b)
Global employee stock options (50 UK pence)	3,243,000
Global employee stock options (151 UK pence)	780,000


	Harken Actual			Pro Forma Adjustments			Pro Forma
Oil and gas revenue	$	24,989		$	308	⁽¹⁾	$	21,720
					(3,577	)⁽²⁾
Other revenues		366			—			366

Total Revenues		25,355			(3,269	)		22,086

Oil and gas operating expenses		9,331			83	⁽¹⁾		6,920
					(2,494	)⁽²⁾
General and administrative expenses, net		10,298			—			10,298
Depreciation and amortization		11,510			169	⁽¹⁾		12,138
					459	⁽³⁾
Litigation and contingent liability settlements, net		1,288			—			1,288
Full cost valuation allowance		521			—			521
Provision for asset impairments		400			—			400
Accretion expense		335			—			335
Interest expense and other, net		4,533			—			4,533

Total Expenses		38,216			(1,783	)		36,433

Gains from repurchases/exchanges of convertible notes		3,528			—			3,528
(Loss)/ gain on investment		(499	)		—			(499	)

Income tax expense		237			—			237

Loss before minority interest		(10,069	)		(1,486	)		(11,555	)
Minority interest in loss of subsidiary		262			—			262

Net loss	$	(9,807	)	$	(1,486	)	$	(11,293	)
Preferred stock dividends		(4,110	)		—			(4,110	)

Net loss attributed to common stock	$	(13,917	)	$	(1,486	)	$	(15,403	)

Basic and diluted loss per common share	$	(0.64	)					(0.69	)

Weighted average common shares outstanding		21,742,163						22,414,047


Asset Category	Asset Retirement Liability		Estimated Life
North American oil and gas producing properties	$	2,809,000	2-55 years
North American facilities and other property		2,428,000	12-29 years
Colombian oil producing properties		717,000	4-23 years
Colombian facilities and other property		—	—

	$	5,954,000


	2003	2004
Asset retirement obligation at beginning of year	$4,664,000	$	6,305,000
Liability recognized upon adoption of SFAS 143	2,138,000		—
Additions during the year	124,000		192,000
Deletions during the year	(1,081,000)		(507,000	)
Changes in estimates			(424,000	)
Accretion expense	460,000		388,000

Asset retirement obligation at end of year	$6,305,000	$	5,954,000


	December 31, 2003			December 31, 2004
7% European Notes	$	340,000		$	—
4.25% Convertible Notes		5,000,000			3,333,000
5% Senior Convertible Notes		—			5,245,000

		5,340,000			8,578,000
Less: Current portion		(1,667,000	)		(1,667,000	)

	$	3,673,000		$	6,911,000


	Carrying Amount		Fair Value
4.25% Convertible Notes	$	3,333,000	$	3,201,000
5% Notes		5,245,000		4,719,000

	$	8,578,000	$	7,920,000


	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, 2002	403,000		93,000		—		—	—	—		—	25,448,000	(606,000	)
Issuances of common stock	—		—		—		—	—	—		—	72,886,000	—
Issuance of preferred stock	(32,000	)	—		93,000		—	—	—		—	—	—
Repurchases of preferred stock	(5,000	)	—		—		—	—	—		—	—	—
Issuance of preferred dividends	—		—		—		—	—	—		—	947,000	—
Conversion/Redemption of Convertible Notes	(17,000	)	—		—		—	—	—		—	81,577,000	—
Conversions of G1 Preferred	(24,000	)	—		—		—	—	—		—	198,000	—
Conversions of G2 Preferred	—		(31,000	)	—		—	—	—		—	1,102,000	—
Conversions of G3 Preferred	—		—		(16,000	)	—	—	—		—	3,247,000	—

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	)


	Year Ended December 31,
	2002			2003			2004
	(in thousands)
Current Taxes:
Federal - AMT	$	(63	)	$	53		$	18
State		—			—			—
Foreign - Colombia		300			(237	)		561
Deferred		—			—			—

Total	$	237		$	(184	)	$	579


	Quarter Ended												Total Year
	March 31			June 30			September 30			December 31			Total Year
2003
Revenues and other	$	7,061		$	6,593		$	7,399		$	6,237		$	27,290
Gross profit		5,351			4,130			4,209			4,150			17,840
Litigation and contingent liability settlements, net		—			—			—			(1,125	)		(1,125	)
Net income / (loss) before cumulative effect of change in accounting principle		2,661			(400	)		16			(2,461	)		(184	)
Net income / (loss)		1,848			(400	)		16			(2,461	)		(997	)
Net income / (loss) attributed to common stock		7,906	^(A)		(1,410	)		(806	)		(3,558	)		2,132
Basic income / (loss) per common share	$	0.22	^(A)	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	0.02
Diluted income / (loss) per common share	$	0.05	^(A)	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.03	)

2004
Revenues and other	$	6,677		$	8,158		$	8,288		$	6,872		$	29,995
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
Net income / (loss)		1,511			(12,025	)		2,271			(4,427	)		(12,670	)
Net income / (loss) attributed to common stock		3,409			(11,491	)		795			(5,898	)		(13,185	)
Basic income / (loss) per common share	$	0.02		$	(0.06	)	$	0.00		$	(0.03	)	$	(0.07	)
Diluted income / (loss) per common share	$	0.02		$	(0.06	)	$	0.00		$	(0.03	)	$	(0.07	)


	GEM			GLOBAL			IBA			Total
For the year ended December 31, 2002:
Operating revenues	$	17,370		$	7,619			—		$	24,989
Oil and gas operating expenses		7,292			2,039			—			9,331
Interest and other income		(44	)		410			—			366
Depreciation and amortization		7,498			4,012			—			11,510
Full cost valuation allowance		—			521			—			521
Provision for asset impairments		—			400			—			400
Litigation and contingent liability settlements, net		1,288			—			—			1,288
Interest expense and other, net		4,238			295			—			4,533
Income tax (benefit) expense		(63	)		300			—			237
Segment loss		(6,298	)		(3,509	)		—			(9,807	)
Capital expenditures		3,688			2,324			—			6,012
Total assets at end of year		59,783			25,797			—			85,580
For the year ended December 31, 2003:
Operating revenues	$	18,753		$	8,556			—		$	27,309
Oil and gas operating expenses		7,071			2,398			—			9,469
Interest and other income		(122	)		103			—			(19	)
Depreciation and amortization		5,804			3,137			—			8,941
Litigation and contingent liability settlements, net		1,125			—			—			1,125
Interest expense and other, net		3,312			82			—			3,394
Income tax (benefit) expense		53			(237	)		—			(184	)
Segment income (loss)		(1,616	)		619			—			(997	)
Capital expenditures		4,427			4,149			—			8,576
Total assets at end of year		54,616			26,396			—			81,012
For the year ended December 31, 2004:
Operating revenues	$	18,334		$	10,974		$	—		$	29,308
Oil and gas operating expenses		5,428			2,536			—			7,964
Interest and other income		825			68			(206	)		687
Depreciation and amortization		7,304			3,400			9			10,713
Increase in fair value of Global warrant liability		14,207			—			—			14,207
Interest expense and other, net		412			2			—			414
Income tax (benefit) expense		(8	)		561			26			579
Segment income (loss)		(12,173	)		400			(897	)		(12,670	)
Capital expenditures		8,770			8,891			106			17,767
Total assets at end of year		62,670			33,108			11,703			107,481


	(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, 2001	2,614		39,393		5,012		—	7,626		39,393
Purchases of reserves in place	125		902		—		—	125		902
Extensions and discoveries	2		551		—		—	2		551
Revisions	837		(173	)	946		—	1,783		(173	)
Production	(267	)	(3,225	)	(465	)	—	(732	)	(3,225	)
Sales of reserves in place	(25	)	(2,940	)	—		—	(25	)	(2,940	)

As of December 31, 2002	3,286		34,508		5,493	⁽¹⁾	—	8,779	⁽¹⁾	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		13,327

Proved developed reserves at:
December 31, 2002	1,945		18,630		1,091	⁽²⁾	—	3,036	⁽²⁾	18,630
December 31, 2003	768		9,488		1,178	⁽³⁾	—	1,946	⁽³⁾	9,488
December 31, 2004	553		2,391		1,282	⁽⁴⁾	—	1,835	⁽⁴⁾	2,391


	(Unaudited)
	United States			Colombia			Total Worldwide
	(in thousands)
December 31, 2003:
Future cash inflows	$	135,410		$	110,575		$	245,985
Production costs		(41,241	)		(19,695	)		(60,936	)
Development costs		(19,338	)		(17,148	)		(36,486	)

Future net inflows before income tax		74,831			73,732			148,563
Future income taxes		(8,768	)		(3,583	)		(12,351	)

Future net cash flows		66,063			70,149			136,212
10% discount factor		(11,822	)		(17,314	)		(29,136	)

Standardized measure of discounted future net cash flows	$	54,241		$	52,835	⁽¹⁾	$	107,076	⁽¹⁾

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 net inflows before income tax		84,281			99,076			183,357
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	$	58,510		$	66,140	⁽²⁾	$	124,650	⁽²⁾


Year	Amount
2005	$	590,000
2006		543,000
2007		111,000
Thereafter		37,000

Total minimum payments required	$	1,281,000


		Page
Harken Energy Corporation and Subsidiaries
— Reports of Independent Registered Public Accounting Firms		57
— Selected Financial Data for the five years ended December 31, 2004		19
— Consolidated Balance Sheets — December 31, 2003 and 2004		60
— Consolidated Statements of Operations for the three years ended December 31, 2004		61
— Consolidated Statements of Stockholders’ Equity for the three years ended December 31, 2004		62
— Consolidated Statements of Cash Flows for the three years ended December 31, 2004		63
— Notes to Consolidated Financial Statements		64


3.1		Certificate of Incorporation of Harken Energy Corporation (filed as Exhibit 3.1 to Harken’s Current Report on Form 8-K dated February 13, 2003, File No. 1-10262, and incorporated by reference herein).

3.2		Certificate of Amendment to Certificate of Incorporation of Harken Energy Corporation (filed as Exhibit 3.2 to Harken’s Current Report on Form 8-K dated February 13, 2003, File No. 1-10262, and incorporated by reference herein).

3.3		Certificate of Amendment to Certificate of Incorporation of Harken Energy Corporation (filed as Exhibit 3.3 to Harken’s Current Report on Form 8-K dated February 13, 2003, File No. 1-10262, and incorporated by reference herein).

3.4		Certificate of Amendment to Certificate of Incorporation of Harken Energy Corporation (filed as Exhibit 3.4 to Harken’s Current Report on Form 8-K dated February 13, 2003, File No. 1-10262, and incorporated by reference herein).

3.5		Certificate of Amendment to Certificate of Incorporation of Harken Energy Corporation (filed as Exhibit 3.5 to Harken’s Current Report on Form 8-K dated February 13, 2003, File No. 1-10262, and incorporated by reference herein).


3.6		Certificate of Amendment to Certificate of Incorporation of Harken Energy Corporation (filed as Exhibit 3.6 to Harken’s Current Report on Form 8-K dated February 13, 2003, File No. 1-10262, and incorporated by reference herein).

*3.7		Certificate of Amendment to Certificate of Incorporation of Harken Energy Corporation dated August 4, 2004.

*3.8		Certificate of Amendment to Certificate of Incorporation of Harken Energy Corporation dated February 22, 2005.

3.9		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).

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).