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 Condensed Financial Statements and the related notes that appear elsewhere in this report as well as our Annual Report on Form 10-K for the year ended December 31, 2008. 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. These risks, uncertainties, and other factors include, among others, the risks described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008 filed with the Securities and Exchange Commission, as well as other risks described in this Quarterly Report. Unless the context requires otherwise, when we refer to "we," "us" and "our," we are describing HKN, Inc. and its consolidated subsidiaries on a consolidated basis.

BUSINESS OVERVIEW

Our strategy is focused on enhancing value for our stockholders through the development of a well-balanced portfolio of energy-based assets. Our Gulf Coast oil and gas assets and our coalbed methane prospects provide an inventory of both high and low-risk projects and long-term opportunities.

Unfavorable changes in economic conditions, including decreased oil and gas commodity pricing, resulted in an adverse effect on our oil and gas revenue in the first quarter 2009. During the three months ended March 31, 2009, oil commodity pricing was approximately 62% lower than the prior year period, and natural gas commodity pricing was approximately 52% lower than the prior year period. If oil and gas commodity pricing and economic conditions decline again in the future, our revenue will continue to be adversely affected. While commodity pricing continues to remain low, we are focused on cutting our operational and general costs in order to remain cash-flow positive until pricing rebounds.

Focus on Efficient Operations

Oil and natural gas prices reached historically high levels in 2008. These high prices have been a key factor in the oil and gas industry experiencing cost increases that have exceeded general inflation trends. We are no different from others in the industry in that we have been impacted by these cost increases. However, we have continued to remain disciplined with regards to our operating costs and capital expenditures. As a result of the market turmoil and price decreases, oil and gas companies with high debt levels and lack of liquidity have been and will continue to be negatively impacted. During the first quarter 2009, oil and natural gas prices have declined sharply as compared to the prior year period. However, we have worked to reduce our controllable costs in order to maintain positive cash flow from operations even during this low commodity pricing environment.

We are in a financially-stable position due to our past strategies. We have no debt outstanding, and we have a cash and marketable securities balance of approximately $14.7 million at March 31, 2009. We also anticipate our operating cash flow and other capital resources, if needed, will adequately fund our planned capital expenditures and other capital uses over the near-term. Due to cost-cutting measures, we have budgeted our 2009 operations to remain cash-flow positive, even at current market pricing.

Gulf Coast Oil and Gas Properties

During the first quarter 2009, our results of operations reflect decreased oil and natural gas revenues due to the decrease in commodity prices as compared to the prior year period. Substantially all of our production is concentrated in twelve oil and gas fields along the onshore and offshore Texas and Louisiana Gulf Coast.

Our revenues are primarily derived from sales from our oil and gas properties. Approximately 50% of our production comes from our operated properties all located in the United States. These revenues are a function of the oil and gas volumes produced and the prevailing commodity price at the time of production, and certain quality and transportation discounts. The commodity prices for crude oil and natural gas as well as the timing of production volumes have a significant impact on our operating income. For the three months ended March 31, 2009, our oil and gas revenues were comprised of approximately 69% oil sales and 31% natural gas production. As of March 31, 2009, our net domestic production rate was approximately 737 barrels of oil equivalent ("boe") per day.

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

Main Pass, Plaquemines Parish - Louisiana

We have a 90% interest in Main Pass and are the field operator. This field contains a seven-platform facility complex including separation, injection, compression, processing and transportation terminals for oil, water and gas. The field also contains 67 wellbores (60 oil and 7 injection wells), of which 33 are active, and an eight mile oil transport line with pump/metering facilities. Our Main Pass 35 facility is located approximately six miles offshore in state waters off the Gulf Coast of Louisiana. During 2008, a third-party engineering firm completed evaluation and documentation of additional recompletion targets, a geological and geophysical study and wellbore utilization plan. We currently have license to 21 square miles of 3D seismic data covering the area held by productive leases. Gross production during the first quarter 2009 averaged approximately 421 boe per day. A comprehensive plan for the field is being evaluated in order to improve field economics. We are seeking to reduce operating costs and seek more favorable terms for our handling of third party production. The identified recompletion well work is currently on hold pending more favorable oil prices.

Lapeyrouse Field, Terrebonne Parish - Louisiana

We hold an average non-operated working interest of approximately 18% in the production from nine wells in this field. Gross field production averaged approximately 257 boe per day for the first quarter 2009. Evaluation efforts are still ongoing with additional diagnostic work planned by the operator to address the field pressure decline and to utilize all available wellbores.

Lake Raccourci Field, Lafourche Parish - Louisiana

We hold an average 40% operated working interest in each of our Lake Raccourci wells. Gross production for this field averaged 191 boe per day for the first quarter 2009. Production was down significantly this quarterly period, due to the fact that the SL 14284-1 well ceased production in February. Diagnostic work has indicated that the well ceased production due to sand build up in the tubing. Coiled tubing work is planned for early second quarter of 2009 to restore production rates.

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

We maintain a 25% operated working interest in one producing well in this field. Average gross production for the first quarter 2009 was approximately 47 boe per day. Production remains steady from this well field.

Creole Field, Terrebonne Parish - Louisiana

We hold an average 15% non-operated working interest in this offshore field. With adjoining acreage and facilities which will ensure the availability of gas lift gas and improved salt water disposal. Upgrades to surface facilities and flowlines and the drilling of a salt water disposal well were completed in 2008. Gross daily production from the wells (six completions) was approximately 647 boe per day during the first quarter 2009. Three completions in the two newest wells drilled in late 2008 were put on production in late March 2009 after significant weather delays.

East Lake Verret, Assumption Parish - Louisiana

We have an average 5% non-operated working interest in this field. Gross daily production from the two development wells on this project was approximately 811 boe per day during the first quarter 2009.

Point-au-Fer Field, Terrebonne Parish - Louisiana

We own a 12.5% non-operated working interest in this approximate 56 square mile area. Gross production for this field was approximately 46 boe per day for the first quarter 2009. Several prospects have been identified in the area, but due to the low oil and gas pricing, we expect additional drilling and workover activity will be delayed.

Branville Bay Field, St. Bernard Parish - Louisiana

We own a 12.5% non-operated working interest in two state leases in the Branville Bay area of Chandeleur Sound Block 71. Gross production for this field was approximately 254 boe per day for the first quarter 2009. Production at pre-storm rates was finally restored in January after the 2008 hurricane season.

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

We own a 25% non-operated working interest in the Boquillas #1 well. Gross production from this well was approximately 184 boe per day for the first quarter 2009.

NW Speaks Field, Lavaca County - Texas

We own approximately 2% to 10% in various leases in the NW Speaks area. Current gross production for this field averaged approximately 125 boe per day during the first quarter 2009 from two wells.

Allen Ranch Field, Colorado County - Texas

We own an 11.25% non-operated working interest in this area. Gross production for this field was approximately 64 boe per day during the first quarter 2009 primarily from the initial well, the Hancock Gas Unit #1 which is the only well currently producing from the field. Another development location has been identified, but future development of the field is currently on hold pending higher natural gas pricing.

We own a 27% non-operated working interest in this area. Current gross production for this field averaged approximately 689 boe per day during the first quarter 2009. No recompletion activity occurred in the first quarter 2009, but facility upgrades are currently underway on one well in the field.

Lucky Field, Matagorda County - Texas

We own a 7.5% non-operated working interest in this area. Current gross production for this field averaged approximately 65 boe per day during the first quarter 2009.

Coalbed Methane Prospects - Indiana and Ohio

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

On the Indiana Posey Prospect, we are currently in the second pilot well phase of Phase II (Exploratory Phase) of the project. The extent of water influx from the first pilot wells is under evaluation to enhance desorption efforts. Alternative design stimulations are also under evaluation as pumpdown continues as the initial fracture treatments are evaluated.

As part of the second pilot well phase, we drilled five pilot producers and completed a water disposal well with specialized fracture stimulation. The proprietary fracture stimulation is currently being evaluated for continued application. Upon completion of the fracturing program, pumpdown for desorption of the second Posey pilot will begin. Following an evaluation period of these two pilot areas, we will evaluate a Phase III - Development election and funding of a development well program as contemplated by the agreements.

On the Ohio Cumberland Prospect, the Phase II project has been temporarily suspended until such time as oil and gas commodity pricing increases. We are focusing our efforts in 2009 on the Indiana Posey Contract.

With the decline in oil and gas commodity prices, resource plays, such as coalbed methane prospects, can become uneconomical in low price environments. Our discretionary capital expenditures, including costs related to our coalbed methane prospects, may be curtailed at our discretion in the future. Such expenditure curtailments could result in us losing certain prospect acreage or reducing our interest in future development projects.

INVESTMENT IN GLOBAL

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

                                           March 31, 2009       December 31, 2008

   Shares of Global Stock held by HKN           11,893,463              11,893,463

   Closing price of Global Stock          £           0.43     £              0.68

   Foreign Currency Exchange Rate                   1.4297                  1.4619

   Market Value of Investment in Global   $          7,312     $            11,824

The foreign currency translation adjustment of $279 thousand and the unrealized loss on investment of $4.2 million for these changes in market value between the two periods are recorded to other comprehensive income in stockholders' equity at March 31, 2009.

INVESTMENT IN SPITFIRE

At March 31, 2009, we owned 11.1 million common shares of Spitfire and 1.3 million warrants to acquire common shares of Spitfire. Our common share holdings represent approximately 27% of the outstanding Spitfire common shares. As a result of our 27% ownership of Spitfire's outstanding common shares, we are deemed to have the ability to exert significant influence over Spitfire's operating and financial policies. Accordingly, we reflect our investment in Spitfire as an equity method investment.

INVESTMENT IN CANERGY FUND

HKN is currently the sole participant in both the Canergy Fund and Canergy Management. For the three months ended March 31, 2009, there was no trading activity related to the Canergy Growth Fund recorded on our consolidated condensed statement of operations, but we intend to monitor the market and reinvest cash as conditions improve and opportunities arise.

CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

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

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

The calculation of the ceiling test and the provision for depletion are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify a revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Based on March 31, 2009 pricing of $3.78 per Mmbtu of natural gas and $49.66 per barrel of oil, we did not have an impairment of our oil and natural gas properties under the full cost method of accounting. Due to the imprecision in estimating oil and natural gas revenues as well as the potential volatility in oil and natural gas prices and their effect on the carrying value of our proved oil and natural gas reserves, there can be no assurance that write-downs in the future will not be required as a result of factors that may negatively affect the present value of proved oil and natural gas reserves and the carrying value of oil and natural gas properties, including volatile oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve quantities and unsuccessful drilling activities.

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

We carry our financial instruments including cash, marketable securities, derivatives and our investment in ordinary shares of Global at their estimated fair values. The fair values of our securities are based on prices quoted in the active market. The fair value of our warrants on common stock of Spitfire is estimated using the Black Scholes model.

Our investment in Global is classified as an available-for-sale non-current asset in our accompanying balance sheets. The associated unrealized gains and losses on our available-for-sale investments (non-trading) are recorded to other comprehensive income until realized and are reclassified into earnings using specific identification.

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

Translation of Non-U.S. Currency Amounts - Assets and liabilities of non-U.S. investees whose functional currency is not the U.S. dollar are translated into U.S. dollars at exchange rates in effect at each balance sheet date. Revenue and expense items are translated at average exchange rates prevailing during the periods. Translation adjustments are included in other comprehensive income until the investment is sold.

Fair Value of Derivatives - Our Spitfire warrants are not exchange-traded derivatives. Management estimates the fair value of the Spitfire warrants using the Black Scholes Valuation model. The estimated fair value of the Spitfire warrants was $4 thousand at March 31, 2009 and was recorded in other assets on our consolidated condensed balance sheet. The Spitfire warrants are classified as Level 3 under Statement of Financial Accounting No. 157, "Fair Value Measurements" ("SFAS 157"). We do not consider the fair value of these Spitfire warrants to be material to our financial statements as of March 31, 2009. Also, we do not consider the unrealized loss of $12 thousand associated with the change in the value of these Spitfire warrants during the three months ended March 31, 2009 to be material to our financial statements.

We have not designated any of our derivative instruments as hedges under Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities." All gains and losses related to these positions are recognized in earnings.

Consolidation of variable interest entities - In January 2003, the Financial Accounting Standards Board ("FASB") issued FASB Interpretation No. ("FIN") 46, "Consolidation of Variable Interest Entities" ("FIN 46") and FIN46(R), which requires the primary beneficiary of a variable interest entity's ("VIE") activities to consolidate the VIE. FIN 46 defines a VIE as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the VIE's activities.

Our investments in the Canergy Growth Fund and Canergy Management are variable interests, as defined in FIN 46R. We have determined that the investments in the Canergy Growth Fund and in Canergy Management meet the requirements of FIN 46R, and we are the primary beneficiary, as defined. Therefore, we have consolidated the assets, liabilities and results of operations of the Canergy Growth Fund and Canergy Management for the three months ended March 31, 2009 and for the period from May 14, 2008, the formation date, through December 31, 2008.

As of March 31, 2009, we owned less than a majority of the common shares of Global and did not possess the legal power to direct the operating policies and procedures of Global through our direct ownership, combined with the ownership by Lyford in Global shares. In addition, we have concluded that Global was not a VIE at March 31, 2009 as contemplated by FIN 46(R).

Income Taxes - We account for income taxes under the liability method. Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. We measure and record income tax contingency accruals in accordance with Financial Accounting Standards Board Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" ("FIN 48").

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

In December 2007, FASB issued SFAS No. 141(R), "Business Combinations" ("SFAS 141R"), and SFAS No. 160, "Accounting and Reporting of Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB No. 51" ("SFAS 160"). SFAS 141R and SFAS 160 will significantly change the accounting for and reporting of business combination transactions and noncontrolling (minority) interests in consolidated financial statements. SFAS 141R retains the fundamental requirements in Statement 141 "Business Combinations" while providing additional definitions, such as the definition of the acquirer in a purchase and improvements in the application of how the acquisition method is applied. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests, and classified as a component of equity. These Statements became simultaneously effective January 1, 2009. Our adoption of these standards has currently had no effect on our consolidated condensed financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities ("SFAS 161"). This statement requires companies to provide enhanced disclosures about (a) how and why they use derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and
(c) how derivative instruments and related hedged items affect a company's financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Our adoption of SFAS 161 on January 1, 2009 did not have a material impact on our consolidated condensed financial statements. See note 6 - Derivative Instruments for additional information.

In May 2008, the FASB issued SFAS No. 162 "The Hierarchy of Generally Accepted Accounting Principles" ("SFAS 162"). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. SFAS 162 is effective sixty days following the SEC's approval of PCAOB amendments to AU Section 411, "The Meaning of 'Present fairly in conformity with generally accepted accounting principles". We are currently evaluating the potential impact, if any, of the adoption of SFAS 162 on our consolidated condensed financial statements.