10-K 1 hkn_10k-123110.htm ANNUAL REPORT hkn_10k-123110.htm


SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________ 
 
Commission file number 1-10262

HKN, INC.
(Exact name of registrant as specified in its charter)
 
Delaware
95-2841597
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
 180 State Street, Suite 200
76092
Southlake, Texas
(Zip Code)
(Address of principal executive offices)
 
 
Registrant’s telephone number, including area code (817) 424-2424
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class:
 
Name of each exchange on which registered:
Common Stock, Par Value $0.01 Per Share
NYSE AMEX

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.        ¨ Yes  þ No
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes o No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No.
 
Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o  No þ
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.          ¨
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer and large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):
Large accelerated filer ¨                                               Accelerated filer ¨                                              Non-accelerated filer ¨                          Smaller reporting company  þ
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).         ¨ Yes    þ No
 
 
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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, 2010 was approximately $29 million. For purposes of the determination of the above stated amount only, all directors, executive officers and 5% or more stockholders of the Registrant are presumed to be affiliates.

The number of shares of Common Stock, par value $0.01 per share, outstanding as of February 11, 2011 was 10,026,098.

DOCUMENTS INCORPORATED BY REFERENCE

Specified portions of the registrant’s definitive Proxy Statement for the 2011 Annual Meeting of Shareholders, to be filed pursuant to Regulation 14A with the Securities and Exchange Commission not later than 120 days after the end of this fiscal year covered by this report, are incorporated by reference in Part III of this report.
 
 
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TABLE OF CONTENTS
 
   
Page
PART I.
   
ITEM  1.
Business
4
ITEM  1A.
Risk Factors
11
ITEM  1B.
Unresolved Staff Comments
18
ITEM  2.
Properties
18
ITEM  3.
Legal Proceedings
18
ITEM  4.
(Removed and Reserved)
19
PART II.
   
ITEM  5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
20
ITEM  6.
Selected Financial Data
22
ITEM  7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
22 
ITEM  7A.
Quantitative and Qualitative Disclosures about Market Risk
40
ITEM  8.
Financial Statements and Supplementary Data
40
ITEM  9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
72 
ITEM  9A.
Controls and Procedures
73
PART III.
   
ITEM 10.
Directors, Executive Officers and Corporate Governance
74
ITEM 11.
Executive Compensation
74
ITEM 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
74
ITEM 13.
Certain Relationships and Related Transactions and Director Independence
74
ITEM 14.
Principal Accounting Fees and Services
74
PART IV.
   
ITEM 15.
Exhibits, Financial Statement Schedules
75
 
 
3

 

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

PART I

ITEM 1. BUSINESS

Overview

Our business strategy is focused on enhancing value for our stockholders through the development of a well-balanced portfolio of energy-based assets.  Currently, the majority of the value of our assets is derived from our ownership in Gulf Coast oil and gas properties, ownership in publicly-traded common shares of Global Energy Development PLC (“Global”), our privately-held investment in BriteWater International LLC (“BWI”) and our coalbed methane prospects in Indiana and Ohio.  We consider these assets to be strategic for us, and our objective in 2011 is to build the value of these properties by:

·  
Monitoring and reducing operating costs
·  
Reducing operational, environmental, financial and third-party dependency risks
·  
Pursuing possibilities for “expanding our footprint” in these areas
·  
Performing economic upgrades and improvements

We are continuing to seek new investment opportunities in undervalued energy-based assets or companies which could provide future value for our shareholders.

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

Oil and Gas Development and Production Operations

During the three years ended December 31, 2010, we performed or participated in the drilling of 6 oil and gas wells in North America, completing 5 of the wells drilled.  As of December 31, 2010, we operate or own a non-operating working interest in 68 oil wells, 39 gas wells and 12 injection wells in the United States. All of our proved oil and gas reserves are concentrated in the Gulf Coast region of Louisiana and Texas.
 
Prospect Acreage - In addition to the producing property interests discussed above, we own, through certain wholly-owned subsidiaries, interests in a variety of domestic prospect acreage in the Creole, East Lake Verret and Lapeyrouse fields of Cameron, Assumption and Terrebonne Parishes, respectively, in Louisiana.
 
 
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See Note 14 – “Other Information” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K for financial information about our oil and gas interests.

Oil and Gas Customers

During 2010 and 2009, one domestic customer, Shell, purchased approximately 67% and 61%, respectively, of our consolidated oil and gas sales.

Oil and Natural Gas Marketing

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months.  Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation.  The spot market for oil and gas is subject to volatility as supply and demand factors fluctuate.  We may periodically enter into financial hedging arrangements with a portion of our oil and gas production.  For the period ended December 31, 2010 and 2009, we purchased crude oil commodity floor contracts at a premium of $78 thousand and $30 thousand, respectively.  These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. Estimated fair values of our purchased commodity derivatives were as follows (in thousands):

                     
As of December 31,
 
Commodity
 
Type
 
Volume/Day
 
Duration
 
Price
   
2010
   
2009
 
Crude Oil
 
Floor
 
 5,000 bbls
 
Jan 10 - May 10
  $ 60.00       -       15  
Crude Oil
 
Floor
 
 5,000 bbls
 
Jan 11 - June 11
  $ 60.00       3       -  
                        $ 3     $ 15  

Oil and Gas Properties and Locations

Production and Revenues – See also Note 16 – “Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K for certain information about our proved oil and gas reserves.  A summary of our ownership in our most significant producing properties at December 31, 2010 is as follows:

   
Average
Working
Interest
 
Average
Revenue
Interest
Main Pass Block 35
    91 %     72 %
Lake Raccourci
    47 %     33 %
Creole
    15 %     11 %
Lapeyrouse
    12 %     7 %
 
 
5

 
 
The following table shows, for the periods indicated, operating information attributable to our oil and gas interests:
 
   
2010
   
2009
   
2008
 
Production:
                 
Natural Gas (Mcf)
    257,000       388,000       703,000  
Oil (Bbls)
    126,000       148,000       149,000  
Revenues:
                       
Natural Gas
  $ 1,284,000     $ 1,542,000     $ 6,913,000  
Oil
    9,900,000       8,643,000       15,293,000  
Total
  $ 11,184,000     $ 10,185,000     $ 22,206,000  
                         
Unit Prices:
                       
Natural Gas (per Mcf)
  $ 5.00     $ 3.97     $ 9.83  
Oil (per Bbl)
  $ 78.24     $ 58.48     $ 102.35  
Production costs per equivalent Mcfe
  $ 7.72     $ 6.73     $ 6.75  
Amortization per equivalent Mcfe
  $ 2.46     $ 2.30     $ 2.87  

Acreage and Wells -- At December 31, 2010, we owned interests in the following oil and gas wells and acreage.

    Gross Wells     Net Wells     Developed Acreage     Undeveloped Acreage  
State
 
Oil
   
Gas
   
Oil
   
Gas
   
Gross
   
Net
   
Gross
   
Net
 
Texas
    -       5       -       0.17       508       52       -       -  
Louisiana
    68       34       43.70       4.24       7,293       2,204       3,378       1,648  
Total
    68       39       43.70       4.41       7,801       2,256       3,378       1,648  

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

Drilling Activity - A well is considered “drilled” when it is completed. A productive well is completed when permanent equipment is installed for the production of oil or gas.  A dry hole is completed when it has been plugged as required and its abandonment is reported to the appropriate government agency. The following tables summarize certain information concerning our drilling activity:
 
    Number of Gross Wells Drilled  
   
Exploratory
   
Developmental
   
Total
 
   
Productive
   
Drilled
   
Productive
   
Drilled
   
Productive
   
Drilled
 
2008
  2     2     1     2     3     4  
2009
  0     0     2     2     2     2  
2010
  0     0     0     0     0     0  
Total
  2     2     3     4     5     6  
 
 
6

 
 
      Number of Net Wells Drilled  
   
Exploratory
   
Developmental
   
Total
 
   
Productive
   
Drilled
   
Productive
   
Drilled
   
Productive
   
Drilled
 
2008
  0.35     0.35     0.02     0.04     0.37     0.39  
2009
  0.00     0.00     0.30     0.30     0.30     0.30  
2010
  0.00     0.00     0.00     0.00     0.00     0.00  
Total
  0.35     0.35     0.32     0.34     0.67     0.69  

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

Our domestic reserve estimates at December 31, 2010 were prepared by CREST Engineering Services and the years ended December 31, 2009 and 2008 have been prepared by Collarini Associates and CREST Engineering Services, Inc., both of which are independent, registered members of a professional engineering society in the state of Texas. We internally tested these reports to ensure the inputs and assumptions used are reasonable and have reviewed the qualifications of both Collarini and CREST. Proved oil and gas reserves are defined as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

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

We sold all of our interests in our equity method investment, Spitfire Energy, Ltd. (“Spitfire”), during 2010.  After making an exhaustive effort, we were unable to obtain the reserve information necessary from Spitfire for the year ended December 31, 2009.  After contacting Spitfire for updated reserve estimates as of December 31, 2009, they indicated these estimates were not available and would not be available to the public. Spitfire’s reserve report data for the year ended December 31, 2009 was based on a calendar year end of March 31, 2009. In addition, their reserve report is not compiled in accordance with the SEC guidelines. Therefore, Spitfire has not been included in our estimated reserve quantities of proved oil and gas reserves for any periods presented.
 
 
7

 
 
   
(Unaudited)
 
   
Total(1)
 
   
Oil
(Barrels)
   
Gas
(Mcf)
 
   
(in thousands)
 
Proved reserves:
           
As of December 31, 2007
    2,369       5,020  
Extensions and discoveries
    371       601  
Revisions
    (1,132 )     (703 )
Production
    (149 )     (703 )
Purchases of reserves in place
    -       -  
Sales of reserves in place
    -       -  
As of December 31, 2008
    1,459       4,215  
Extensions and discoveries
    221       203  
Revisions
    82       (1,016 )
Production
    (148 )     (388 )
Purchases of reserves in place
    1       61  
Sales of reserves in place
    -       -  
As of December 31, 2009
    1,615       3,075  
Extensions and discoveries
    -       -  
Revisions
    193       (382 )
Production
    (127 )     (257 )
Purchases of reserves in place
    1       47  
Sales of reserves in place
    (2 )     (218 )
As of December 31, 2010
    1,680       2,265  
Proved developed reserves at:
               
December 31, 2008
    1,417       3,733  
December 31, 2009
    1,425       2,890  
December 31, 2010
    1,490       2,062  
Proved undeveloped reserves at:
               
December 31, 2008
    42       482  
December 31, 2009 (2)
    190       185  
December 31, 2010 (3)
    190       203  
 
(1)  
All reserves were held within the United States for the years ended December 31, 2010, 2009 and 2008.
 
 
8

 

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

(3)  
Our December 31, 2010 proved undeveloped reserves were comprised of 190 thousand barrels of crude oil and 203 thousand Mcf of natural gas, net. We had no significant changes to our proved undeveloped reserves from the prior year period.  During the year ended December 31, 2010, the Company continued to focus its capital program on development projects and facility improvements and did not incur any capital expenditures or make any significant progress to convert any of our proved undeveloped reserves to proved developed reserves. As of December 31, 2010, no undeveloped reserves that were identified more than 5 years ago remain in our proved reserve portfolio.

At December 31, 2010, we had two fields, Main Pass and Creole Field, that contained 82% or more of our total proved reserves. The following table shows the production for these fields for the year ended December 31:

   
2010
   
2009
 
Field:  
Oil (Bbls)
   
Gas (Mcf)
   
Oil (Bbls)
   
Gas (Mcf)
 
Main Pass
    92,695       -       104,965       -  
Creole Field
    23,128       50,403       23,720       66,342  

Coalbed Methane Prospects – Indiana and Ohio

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

  We continue to operate 12 pilot wells (10 production and 2 injection) in the dewatering phase and evaluate their progress. In this phase, pilot wells are produced to maximize fluid (water) production in order to lower reservoir pressure so that desorption of gas can occur in these test wells on the Indiana Posey Contract area. In the current gas pricing environment, resource plays, such as coalbed methane prospects, can become uneconomical since all well, facility and flowline costs in addition to operating costs during the dewatering/desorption process must be incurred before  revenues can be generated. In addition, we continue to monitor the operating costs and future value related to these prospects, and our discretionary capital expenditures related to our coalbed methane prospects may be curtailed at our discretion in the future. Such expenditure curtailments could result in us losing prospect acreage or reducing our interest in future coalbed methane projects.
 
 
9

 

International Energy Investment – Global Energy Development PLC

At December 31, 2010 and 2009, we held an investment in Global Energy Development PLC (“Global”) through our ownership of approximately 34% of Global’s ordinary shares. We account for our ownership of Global shares as a cost method investment. Global is a petroleum exploration and production company focused on Latin America. Global’s shares are traded on the AIM, a market operated by the London Stock Exchange.  See Note 3 – “Other Investments” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K for further information.

Canadian Energy Investment – Spitfire Energy, Ltd.

Prior to our divestiture of our entire investment in Spitfire during 2010, we held approximately 25% of Spitfire’s outstanding common shares. As a result of this ownership of Spitfire’s outstanding common shares, we were deemed to have the ability to exert significant influence over Spitfire’s operating and financial policies. Accordingly, we reflected our investment in Spitfire as an equity method investment.  Due to timing differences in our filing requirements and the lack of availability of financial information for the current quarterly period, we recorded our share of Spitfire’s financial activity on a three-month lag. Our investment in Spitfire was reported in our consolidated balance sheet at its adjusted carrying value as a non-current asset, and our earnings in Spitfire were reported net of tax as a single line on our consolidated statement of operations.

 During the first half of 2010, we sold our remaining interest in Spitfire, which consisted of approximately 9.9 million Spitfire common shares, for cash proceeds of $3.3 million. We realized a gain on the sale of approximately $1.9 million using the average cost method, which included $351 thousand of foreign currency gains which were reclassified into earnings from other comprehensive income, in our consolidated statement of operations. At December 31, 2009, our carrying value of this investment was $1.6 million.

Investment in BriteWater International, LLC

We hold an investment in a privately-held company, BriteWater International, LLC (“BWI”), which owns a patented oilfield emulsion breaking “OHSOL” technology.   This environmentally-clean process can be used to purify oilfield emulsions by breaking and separating the emulsions into oil, water and solids. This technology has been successfully tested using a mobile OHSOL unit in a demonstration in Prudhoe Bay, Alaska, which demonstrated the effectiveness of the OHSOL emulsion breaking technology to recover valuable hydrocarbons and reduce wastes. BWI is currently pursuing opportunities to commercialize the OHSOL technology by securing contracts for the operation of OHSOL plant equipment both internationally and domestically.  See Note 2 – “Investment in BriteWater International, LLC.” in the Notes to Consolidated Financial Statements contained in Part III, Item 8 of this Annual Report on Form 10-K for further information.

Employees

At December 31, 2010, we had 16 employees. We have experienced no work stoppages or strikes as a result of labor disputes and consider relations with our employees to be satisfactory. We maintain group medical, dental, vision, and long-term disability and long-term care insurance plans for our employees.

 
10

 
 
ITEM 1A.  RISK FACTORS

We wish to caution you that there are risks and uncertainties that could cause our actual results to be materially different from those indicated by forward-looking statements that we make from time to time in filings with the SEC, news releases, reports, proxy statements, registration statements and other written communications, as well as oral forward-looking statements made from time to time by our representatives. These risks and uncertainties include, but are not limited to, the risks described below. 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. We do not assume any obligation to update forward-looking statements.

Risks associated with our crude oil and natural gas operations:

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

Our profitability, cash flows and the carrying value of our oil and natural gas properties are highly dependent upon the market prices of oil and natural gas. 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.  Historically, the oil and natural gas markets have proven cyclical and volatile as a result of factors that are beyond our control.  Any declines in oil and natural gas prices or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves.  During 2010, commodity pricing for both crude oil and natural gas averaged above pricing from the respective prior year period. During 2010, based on NYMEX pricing, the price for a barrel (bbl) of oil ranged from a high of $92.21 to a low of $66.88 and the price for a Mmbtu of gas ranged from a high of $7.38 to a low of $3.17.

Our future success depends on our ability to find, develop and produce oil and gas reserves.  

As is generally the case, our producing properties in the Gulf of Mexico and the onshore Gulf Coast often have high initial production rates which are followed by steep declines. To maintain production levels, we must locate and develop or acquire new oil and gas reserves to replace those depleted by production. Without successful exploration or acquisition activities, our reserves, production and revenues will decline rapidly. We may be unable to find, develop or produce additional reserves at an acceptable cost. In addition, substantial capital is required to replace and grow reserves. If lower oil and gas prices or operating constraints or production difficulties result in our cash flow from operations being less than expected, we may be unable to expend the capital necessary to locate and develop or acquire new oil and gas reserves.

Actual quantities of recoverable oil and gas reserves and future cash flows from those reserves most likely will vary from our estimates.  

Estimating accumulations of oil and gas is complex. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
 
 
11

 
 
· the quality and quantity of available data;
 
· the interpretation of that data;
 
· the accuracy of various mandated economic assumptions; and
 
· the judgment of the persons preparing the estimate.
 
The proved reserve information set forth in this report is based on estimates we prepared in accordance with the definition of proved reserves prepared in accordance with Financial Accounting Standards Board’s Accounting Standards Codification 932, Extractive Activities- Oil and Gas (“ASC 932”).

Estimates prepared by others might differ materially from our estimates. Actual quantities of recoverable oil and gas reserves, future production, oil and gas prices, revenues, taxes, development expenditures and operating expenses most likely will vary from our estimates. Any significant variance could materially affect the quantities and net present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing oil and gas prices. Our reserves also may be susceptible to drainage by operators on adjacent properties.

You should not assume that the present value of future net cash flows is the current market value of our estimated proved oil and gas reserves. In accordance with reserve disclosure requirements, we calculate the estimated discounted future net cash flows from proved reserves using twelve month average prices and costs. Actual future prices and costs may be materially higher or lower than the prices and costs we used.

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

We require significant expenditures of capital in order to locate and develop producing properties and to drill exploratory and exploitation wells.  In conducting exploration, exploitation and development activities for 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 abandonment of 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.

We are dependent on other operators who influence our productivity.

We have limited influence over the nature and timing of exploration and development on oil and natural gas properties we do not operate, including limited control over the maintenance of both safety and environmental standards.  In 2010, approximately 33% of our production and 33% of our proved reserve volumes were from our non-operated properties. The operators of those properties may:

·  
refuse to initiate exploration or development projects,

·  
initiate exploration or development projects on a slower schedule than we prefer; or

·  
drill more wells or build more facilities on a project than we can adequately fund, which may limit our participation in those projects or limit our percentage of the revenues from those projects.

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.
 
 
12

 
 
Our working interest owners may face cash flow and liquidity concerns.

If oil and natural gas prices decline, many of our working interest owners could experience liquidity and cash flow problems.  These problems may lead to their attempting to delay the pace of drilling or project development in order to conserve cash.  Any such delay could be detrimental to our projects.  Some working interest owners may be unwilling or unable to pay their share of the project costs as they become due.  A working interest owner may declare bankruptcy and refuse or be unable to pay its share of the project costs, and we would be obligated to pay that working interest owner’s share of the project costs.

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

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

·  
the extent of local production and imports of oil and gas,
 
·  
the proximity and capacity of pipelines and other transportation facilities,
 
·  
fluctuating demand for oil and gas,
 
·  
the marketing of competitive fuels, and
 
·  
the effects of governmental regulation of oil and gas production and sales.
 
Natural gas associated with oil production is often not marketable due to demand or transportation limitations and is often flared at the producing well site.  Pipeline facilities do not exist in certain areas of exploration and, therefore, any actual sales of discovered oil and gas might be delayed for extended periods until such facilities are constructed.

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

We are subject to operating hazards normally associated with the exploration and production of oil and gas, including hurricanes, 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, wind damage  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.

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

Our operations in the Texas and Louisiana Gulf Coast area are subject to risks from hurricanes and other natural disasters. Damage caused by wind, hurricanes, earthquakes or other operating hazards could result in substantial losses to us. In the past, our oil and gas operations have been affected by tropical storms and hurricanes on occasion resulting in additional costs and reduced oil and gas volumes during those periods. 
 
 
13

 

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

The exploration and production business is highly competitive.  Many of our competitors have substantially larger financial resources, staffs and facilities.  Our competitors in the United States include numerous major oil and gas exploration and production companies.  Our investment in Global may be affected as a result of the competition faced in Latin America.

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

From time to time we are a defendant in various litigation matters. The nature of our 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 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 may be susceptible on a going forward basis, to increased scrutiny, greater complexity resulting in increased costs, or delays in receiving appropriate authorizations.

We may be affected by global climate change or by legal, regulatory, or market responses to such change.

The growing political and scientific sentiment is that increased concentrations of carbon dioxide and other greenhouse gases in the atmosphere are influencing global weather patterns. Changing weather patterns, along with the increased frequency or duration of extreme weather conditions, could impact the availability or increase the cost to produce our products. Additionally, the sale of our products can be impacted by weather conditions.

Concern over climate change, including global warming, has led to legislative and regulatory initiatives directed at limiting the greenhouse gas (“GHG”) emissions. For example, proposals that would impose mandatory requirements on GHG emissions continue to be considered by policy makers in the territories we operate. Laws enacted that directly or indirectly affect our oil and gas production could impact our business and financial results.
 
 
14

 

Risk factors associated with our financial condition:

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

We reported net losses of approximately $192 thousand and $3.3 million for the years ended December 31, 2010 and 2009, respectively. We have reported net losses in four of the last five fiscal years.  Our ability to generate net income is strongly affected by, among other factors, the market price of crude oil and natural gas.  Consequently, future losses may adversely affect our business, prospects, financial condition, results of operations and cash flows.

If estimated discounted future net cash flows were to decrease, we may be required to take write-downs.

We periodically review the carrying value of our oil and gas properties under applicable full-cost accounting rules. These rules require a write-down 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 write-downs of oil and gas properties could occur. Whether we will be required to take such a charge will depend on the average prices for oil and gas during the period and the effect of reserve additions or revisions, property sales and capital expenditures during such period.

Our financial condition may suffer if estimates of our 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 prepared in accordance with ASC 932 and the Securities and Exchange Commission’s Final Rule, Modernization of the Oil and Gas Reporting Requirements, and reflects only estimates of the accumulation of oil and gas and the economic recoverability of those volumes.  Our future production, revenues and expenditures with respect to such oil and gas reserves could be different from estimates, and any material differences may negatively affect our business, financial condition and results of operations.

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

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

·  
the quantities of oil and gas that are ultimately recovered,

·  
the production and operating costs incurred,

·  
the amount and timing of future development expenditures, and

·  
future oil and gas sales prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data.
 
 
15

 

The estimated discounted future net cash flows described in this Annual Report for the year ended December 31, 2010 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 prepared in compliance with ASC 932, and the Securities and Exchange Commission’s Final Rule and, as such, are based on average prices and costs as of the date of the estimate, while future prices and costs may be materially higher or lower.  The Standard requires that we report our oil and natural gas reserves using a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 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 the market value of our investment in Global decreases, the value of our common stock could be negatively impacted.

At December 31, 2010, we held an investment in Global through our ownership of approximately 34% of their outstanding ordinary shares.  This investment represents a substantial part of our balance sheet at December 31, 2010.  The market value of Global’s common shares increased during 2010, as compared to the prior year period, but there can be no assurance that their common stock will continue to improve in the future. A potential decrease in the value of their common stock could adversely affect our financial statements and the value of our common stock.

We may suffer losses on our investment in Global from exchange rate fluctuations.

We account for our investment in Global using the U.S. dollar as the functional currency.  The shares of common stock associated with our investment in Global are denominated in British sterling pounds.  We could suffer losses in our investment if the value of the British sterling pound were to drop relative to the value of the U.S. dollar.  Any substantial currency fluctuations could create a material adverse effect on the value of our investment in Global.

Two of our shareholders cumulatively own a significant amount of our common stock and may exercise significant control over us.

As of December 31, 2010, Lyford Investments Enterprises Ltd. (“Lyford”) and UniPure Energy Acquisition Ltd. (“UEA”) beneficially owned approximately 32% and 12%, respectively, of the combined voting power of our outstanding common stock. Lyford and UEA are in a position to significantly influence decisions with respect to:

  our direction and policies, including the election and removal of directors,
 
  mergers or other business combinations,
 
  the acquisition or disposition of our assets,
 
  future issuances of our common stock or other securities,
 
  our incurrence of debt, and
 
  the payment of dividends, if any, on our common stock, and amendments to our certificate of incorporation and bylaws.
 
 
16

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

Risks associated with market conditions:

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

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

· commodity prices of oil and natural gas,

· the volatility of the market in general,

· the results of our drilling,

· current expectations of our future financial performance.

For example, our common stock price has fluctuated from a high of $13.10 per share to a low of $1.40 per share over the three years ended December 31, 2010.  This volatility may affect the market value of our common stock in the future.  See Part II, Item 5: Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Future sales of our common stock, including our proposed rights offering, may affect the market price of our common stock.

     We have proposed a rights offering which our shareholders will vote on during March 2011. If approved, we will issue rights to acquire up to 7.5 million shares of common stock during 2011 at a price of $2.00 per share. If the rights offering is consummated, shareholders who do not exercise their rights in the rights offering will experience a dilution in their percentage ownership of our outstanding common stock upon completion of the rights offering.

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.

Sales of substantial amounts of our common stock in the public market, and the availability of shares for future sale, including the shares of our common stock to be issued in a rights offering could adversely affect the prevailing market price of our common stock and could cause the market price of our common stock to remain low for a substantial time.  We cannot foresee the impact of such potential sales on the market, but it is possible that if a significant percentage of such available shares were attempted to be sold within a short period of time, the market for our shares would be adversely affected. It is also unclear whether or not the market for our common stock could absorb a large number of attempted sales in a short period of time, regardless of the price at which they might be offered.  Even if a substantial number of sales do not occur within a short period of time, the mere existence of this “market overhang” could have a negative impact on the market for our common stock and our ability to raise additional capital.
 
 
17

 
 
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 1.0 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, 2010, we had outstanding 1,000 shares of Series G1 Preferred and 1,000 shares of Series G2 Preferred. These shares of preferred stock have rights senior to our common stock with respect to dividends and liquidation.

We may issue additional shares of common stock which may dilute the value of our common stock and adversely affect the market price of our common stock.

A large issuance of shares of common stock could decrease the ownership percentage of current outstanding stockholders and could result in a decrease in the market price of our common stock.  In addition, we may elect to issue additional shares of common stock for financing or other purposes, which could result in a decrease in the market price of our common stock.

Pursuant to the terms of our investment in BWI and the related Agreement, HKN and the other BWI unit-holders granted to one another put and call options with respect to 3,050 units of BWI in exchange for issuance of 725 thousand restricted shares of our common stock.  These options are exercisable only if certain conditions are satisfied prior to June 2012.  In September 2010, two BWI unit-holders exercised their Put Option to HKN, and we received an additional 2,288 units of BWI in exchange for the issuance of 544 thousand shares of our restricted common stock. One BWI unit-holder’s Put Option remains exercisable until June 30, 2012 and if exercised would result in an additional issuance of 16 thousand restricted shares of our common stock.
 
ITEM 1B. UNRESOLVED STAFF COMMENTS

None
 
ITEM 2. PROPERTIES

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

We have an office in Southlake, Texas. We have a lease for approximately 4,062 square feet in Southlake, Texas, which runs through April 30, 2011.  We sublease approximately 1,866 square feet of office space in Katy, Texas to a third-party.  This lease runs through February 28, 2011. The remaining obligation for our leases for 2011 is approximately $136 thousand as of December 31, 2010. In early  2011, we renewed our lease for the office in Southlake and cancelled the remainder of our Katy lease. See “Liquidity and Capital Resources – Obligations and Commitments – Consolidated Contractual Obligations” contained in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
ITEM 3. LEGAL PROCEEDINGS

IRS ExaminationDuring 2008, we received a proposed adjustment to our federal tax liability for the calendar year 2005.  The proposed adjustment relates to the calculation of the adjusted current earnings (“ACE”) component of the alternative minimum tax and asserts that we recognized a gain for ACE purposes on the sale of the Global PLC stock in 2005.  In its proposed adjustment, the IRS alleges that we owe approximately $3.6 million in tax for the year ended December 31, 2005. Penalties and interest calculated through December 31, 2010 in the amount of $2.4 million could also be assessed. We filed a formal protest with the IRS Appeals Office during 2008.  In April 2009, we filed our supplement to the written protest which included a third party valuation report supporting the basis of our recognized gain recorded for ACE purposes.
 
 
18

 
 
ASC 740, Income Taxes, prescribes a recognition threshold of more-likely-than-not to be sustained upon examination. This guidance also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosures and transition.  Utilizing the process outlined above, we have recorded an income tax contingency for this item, including interest and penalties, of $225 thousand in our consolidated financial statements based, in part, on a preliminary indication of a probability-weighted fair value assessment of the Global stock.  In February 2011, the IRS requested and we agreed to extend the statute of limitations to April 2012 and notified us that the IRS exam group has provided a written response to the HKN third party valuation report that supports our recognized gain recorded for ACE purposes. We intend to review and make a formal response to the IRS over the next few months. Although we intend to vigorously defend the proposed adjustment and strongly believe the third party valuation report supports our position and that we have meritorious defenses, if the IRS Appeals Office were to deny all of our protests and our assumptions and estimates associated with this income tax contingency are inaccurate, we could be liable for approximately $6 million in additional tax, penalties and interest.
 
ITEM 4. (REMOVED AND RESERVED)
 
 
19

 
 
PART II

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

Price Range of Common Stock

Beginning March 1991 until June 2007, our common stock was listed on the American Stock Exchange and traded under the symbol HEC. In June 2007, the trading symbol of our common stock was changed to the symbol HKN. The American Stock Exchange was acquired by NYSE Euronext during 2008 and renamed NYSE Amex. Our common stock is currently traded on this exchange under the symbol HKN.  At December 31, 2010, there were 456 holders of record of our common stock.

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

       
Prices
 
       
High
   
Low
 
2009 --  
First Quarter
  $ 3.19     $ 1.48  
   
Second Quarter
    2.75       1.40  
   
Third Quarter
    3.09       2.15  
   
Fourth Quarter
    3.90       2.91  
2010 --  
First Quarter
  $ 3.72     $ 2.90  
   
Second Quarter
    5.72       2.91  
   
Third Quarter
    3.65       2.80  
   
Fourth Quarter
    4.20       3.25  

Dividends

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

Equity Compensation Plans

We have no equity compensation plans. There are no shares currently authorized for issuance related to equity compensation.

Performance of the Common Stock

The following performance graph shall not be deemed incorporated by reference by any general statement incorporating by reference in the Annual Report on Form 10-K into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such Acts.
 
 
20

 
 
The graph below compares the cumulative total stockholder return on the Common Stock for the last five fiscal years with the cumulative total return on the S&P 500 Index and the Dow Jones Exploration and Production Index over the same period (assuming the investment of $100 in the Common Stock, the S&P 500 Index and the Dow Jones Secondary Oils Stock Index on December 31, 2005 and reinvestment of all dividends).

Comparison of Cumulative Total Return
Assumes Initial Investment of $100 on December 31, 2005
 
Information on Share Repurchases

The following table provides information about purchases by us pursuant to our previously announced share repurchase program during the three months ended December 31, 2010, of our Common Stock:
 
   
(a)
   
(b)
   
(c)
   
(d)
 
Period
 
Total
Number of
Shares
Purchased
   
Average
Price Paid
per Share
   
Total
Number of
Shares
Purchased
as part of
Publicly
Announced
Program
   
Maximum
Number of
Shares that
May Yet Be
Purchased
Under
the Plans
or Programs
 
October 1, 2010 through October 31, 2010
    -     $ -       36,647       492,939  
November 1, 2010 through November 30, 2010
    35,000     $ 4.48       71,647       457,939  
December 1, 2010 through December 31, 2010
    -     $ -       71,647       457,939  
Total
    35,000     $ 4.48       71,647       457,939  
 
 
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ITEM 6.  SELECTED FINANCIAL DATA

Not applicable
 
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 “Risk Factors” at the beginning of this report on Form 10-K for additional discussion of some of these risks and uncertainties.  Unless the context requires otherwise, when we refer to “we,” “us” and “our,” we are describing HKN, Inc. and its consolidated subsidiaries on a consolidated basis.

BUSINESS OVERVIEW

Our business strategy is focused on enhancing value for our stockholders through the development of a well-balanced portfolio of energy-based assets.  Currently, the majority of the value of our assets is derived from our ownership in Gulf Coast oil and gas properties, ownership in publicly-traded common shares of Global Energy Development PLC (“Global”), our privately-held investment in BriteWater International LLC (“BWI”) and our coalbed methane prospects in Indiana and Ohio.  We consider these assets to be strategic for us, and our objective in 2011 is to build the value of these properties by:

·      
Monitoring and reducing operating costs
·      
Reducing operational, environmental, financial and third-party dependency risks
·      
Pursuing possibilities for “expanding our footprint” in these areas
·      
Performing economic upgrades and improvements

We continue to seek new investment opportunities in undervalued energy-based assets or companies which could provide future value for our shareholders.

2010 Recap and 2011 Outlook

During 2010, commodity pricing for both crude oil and natural gas increased as compared to the prior year period, averaging approximately 34% and 26% higher, respectively, than 2009.  In 2011, our objective is to continue to maintain and/or improve our working capital and to increase our operating margin as compared to prior year.  We believe in the long-term fundamentals of our industry. Our oil and gas operations for the year ended 2010 were cash-flow positive, and we plan to maintain our discretionary cash balance during 2011.
 
Our investments in both Global and BWI represent a significant concentration of value of our assets. During 2010, we extended a financing loan to Global, and, during 2009 we extended a financing loan to BWI in order to promote the development activities of these companies while also earning a 10% and 8% annualized rate of return, respectively, on our funds during the term of these loans. Any intersegment interest income between us and BWI has been eliminated in consolidation at December 31, 2010 and 2009. At December 31, 2010, the outstanding principal balance of the loans receivable from Global and BWI were $5 million and $1.9 million, respectively. Both loans are secured by assets of the respective companies and provide for cash interest payments on a monthly and quarterly basis.
 
 
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                During 2010, we continued to enhance the value of our Main Pass 35 field, located offshore Louisiana in the Gulf of Mexico, by performing various process and structural upgrades and improvements to the facility and its equipment.   We believe our Main Pass 35 asset has unique characteristics such as low-decline oil production, behind-pipe development potential as well as third-party oil, gas and water processing and handling services for neighboring fields in the area.  Our Main Pass 35 field remains a strategic asset for us in 2011.

Each year we evaluate our assets to determine which may have reached their full potential, do not have an expectation of near-term value enhancement or represent a disproportionate concentration of value in one asset and should be targeted for monetization.  In 2011, we are targeting certain of our non-strategic Gulf Coast oil and gas properties for divestiture in order to mitigate possible future losses of these end-of-life properties.
   
We continue to have access to capital, and we have a cash balance of approximately $5 million at December 31, 2010. We anticipate our operating cash flow and other capital resources, if needed, will adequately fund our planned capital expenditures and other capital uses over the near-term.  Based on industry outlook for 2011, prices for oil and natural gas are expected to increase as compared to the prior year.

We have submitted a proposal to shareholders for a $15 million rights offering under which we would issue, if approved, rights to acquire additional 7.5 million of our common shares at a price of $2.00 per share. Proceeds from this rights offering would be used to acquire or invest in energy-based businesses, securities, working interests and other oil, natural gas and energy-related investments, properties, products and technologies, as well as for general corporate purposes.

Capital Deployment Update

During 2010, we continued to deploy assets into energy-based opportunities to build value and/or cash flow as follows:

§  
We deployed capital expenditures of approximately $1.1 million to enhance the value of our Main Pass 35 field through process, structural, environmental and operational improvements to the facility.

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

§  
We extended a financing loan to Global in order to promote the development activities of Global while also earning a 10% annualized rate of return on our funds during the term of the loan.

§  
We issued 544 thousand restricted shares and paid $531 thousand to acquire an additional 32.59% interest in BWI, bringing our ownership interest to 52.09% at December 31, 2010.

Gulf Coast Oil and Gas Properties

During 2010, our results of operations reflect increased oil and natural gas revenues as compared to 2009 as a result of increased commodity prices.  During the current year, the realized price of oil averaged $78.24 per barrel (“Bbl”), approximately 34% higher than 2009.  Natural gas prices realized in 2010 averaged $5.00 per metric cubic foot (“Mcf”), approximately 26% higher than prior year.  At year end, substantially all of our production is concentrated in ten oil and gas fields along the onshore and offshore Texas and Louisiana Gulf Coast.  During December 2010, our net domestic production rate averaged approximately 365 barrels of oil equivalent (“boe”) per day.
 
 
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Our revenues are primarily derived from sales from our Gulf Coast oil and gas properties. Approximately 67% of our production comes from our operated properties all located in the United States. These revenues are a function of the oil and gas volumes produced and the prevailing commodity price at the time of production, and certain quality and transportation discounts. The commodity prices for crude oil and natural gas as well as the timing of production volumes have a significant impact on our operating income. During 2010, our oil and gas revenues were comprised of approximately 89% oil sales and 11% natural gas production.

The following field data updates the status of our operations through December 31, 2010:

Main Pass, Plaquemines Parish – Louisiana

We continue to enhance the value of our Main Pass 35 field, which is located approximately six miles offshore Louisiana in the Gulf of Mexico, by performing various process and structural upgrades in addition to other improvements to the facility and its equipment.  We believe our Main Pass 35 asset is in a strategic location within the Gulf of Mexico and has unique characteristics such as low-decline oil production, behind-pipe development potential as well as third-party oil, gas and water processing and handling services for neighboring fields in the area. Our Main Pass 35 field remains a strategic asset for us in 2011.

We have an average 91% interest in Main Pass 35 and are the field operator. This field contains a ten-platform facility complex including separation, injection, compression, processing and transportation terminals for oil, water and gas. The field also contains 65 wellbores (59 oil and 6 injection wells), of which 33 are active, and an eight mile oil transport line with pump/metering facilities. We currently have license to 21 square miles of 3D seismic data covering the area held by productive leases. Gross production during 2010 averaged approximately 364 boe per day. Several wells have been identified as potential recompletion candidates during 2011 to increase oil production and reduce gas lift expense.

During 2010, work was finished on pipeline modifications mandated by the Corps of Engineers to a third-party gas sales line that serves our facility. We also began work to upgrade the flowlines and increase capacity at our facility which will allow us to bring additional third party or operated production volumes through the facility in the future.  We experienced lower than normal production at this property during 2010 as a result of several flowline and gas lift line repairs as well as compressor maintenance and repairs. In addition, the field experienced downtime due to the aforementioned Corps of Engineers gas pipeline modifications.

Creole Field, Terrebonne Parish - Louisiana

We hold an average 15% non-operated working interest in this offshore field. Gross daily production from the wells (ten completions) was approximately 885 boe per day during 2010. One major workover to replace tubing and one re-entry of an abandoned well were successfully completed in 2010, and several production enhancement projects which resulted in increased production rates were also completed during the year. The previously abandoned SL18423 #3 well was re-entered and placed on production in 2010 and has averaged 55 boe per day through the end of the year.

The production enhancement studies were implemented by the new operator which took over during 2010, and a program was designed and implemented to pressure test a number of wells in the field. The data gathered allows for the proper configuration of the gas lift system as well as diagnostic information to determine whether a stimulation program would be beneficial to each well. The data gathered in this program led to acid stimulation programs for four of the completions, one of which was performed during the third quarter of 2010 and resulted in an initial ten-fold increase in oil rates.   Work on the remaining wells should be completed during the first quarter of 2011 following the installation of additional tanks to handle the expected increase in production.
 
 
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Lapeyrouse Field, Terrebonne Parish – Louisiana

We hold an average non-operated working interest of approximately 12% in the production from nine wells in this field. Gross field production averaged approximately 183 boe per day for 2010.  Evaluation efforts by the operator are still ongoing with additional diagnostic work planned by the operator to address the field pressure decline and to utilize all available wellbores. We are considering this field for divestiture in 2011.
 
Lake Raccourci Field, Lafourche Parish – Louisiana
 
We hold an average 47% operated working interest in each of our Lake Raccourci wells. Gross production for this field averaged 168 boe per day for 2010. Production decreased significantly in 2009 primarily due to the fact that the SL 14284-1 well ceased production in February 2009.  Diagnostic work indicated that the well ceased production due to sand build up in the tubing.  Coiled tubing work was carried out, but failed to restore production. We are currently evaluating the economic potential of a recompletion to the Tex 16 zone behind pipe, as well as several other zones in our two other producing wells in the field in light of low natural gas product prices. The SL 14589#3 well was successfully recompleted in mid 2010 and began flowing 333 gross boe per day, but this well experienced fill problems late in the fourth quarter of 2010 and is currently awaiting diagnostic work.

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 2010 was approximately 36 boe per day.  During 2010, we successfully re-perforated our saltwater disposal well in order to maintain specified injection pressure tolerance and keep production rates steady.

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 376 boe per day during 2010.
 
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 29 boe per day for 2010.  Several prospects have been identified in the area, but due to current oil and gas pricing, we expect additional drilling and work over activity will be delayed by the operator.  We are considering this field for divestiture in 2011.
 
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 157 boe per day for 2010.

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

We own a 25% non-operated working interest in the Boquillas #1 well. The well has stopped producing and will be plugged and abandoned in early 2011.
 
 
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NW Speaks Field, Lavaca County – Texas

We own approximately 2% to 7% in various leases in the NW Speaks area. Current gross production for this field averaged approximately 52 boe per day during 2010 from two wells.  We are considering this field for divestiture in 2011.

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 21 boe per day during 2010 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.

Raymondville Field, Willacy County – Texas

In March 2010, we sold our interest in this field effective April 1, 2010. 

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 14 boe per day during 2010, but the well ceased to produce in mid-August. Recent well work was unsuccessful, and no other potential exists in the well. The well will be plugged and abandoned in early 2011.

Coalbed Methane Prospects – Indiana and Ohio

 We currently hold two coalbed methane exploration and development agreements in Indiana and Ohio. The agreements provide for a phased delineation, pilot and development program with corresponding staged expenditures. Third party consultants with a long track record in successful coalbed methane development provide expert advice for these projects.

On the Indiana Posey Prospect, we are currently in the second pilot well phase of Phase II (Exploratory Phase) of the project.  As part of the second pilot well phase, we drilled five pilot producers and completed a water disposal well with specialized fracture stimulation.  We continue to be in the dewatering phase in both pilot areas and are evaluating the progress of these test wells. During this phase, the pilot wells are produced to maximize fluid (water) production in order to lower reservoir pressure so that desorption of gas can occur in the pilot test wells on the Indiana Posey Contract area.  Following this evaluation period for 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 gas commodity pricing increases.  We continue to focus our efforts 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 particularly since all well, facility and flowline costs as well as operating costs during the dewatering/desorption process must be incurred before revenues can be generated. Our discretionary capital expenditures related to coalbed methane prospects may be curtailed at our discretion in the future. Such expenditure curtailments could result in loss of certain prospect acreage or reduction of our interest in future coalbed methane development projects.
 
 
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INVESTMENT IN BRITEWATER INTERNATIONAL, LLC.
 
We hold an investment in a privately-held company, BriteWater International, LLC (“BWI”), which owns a patented oilfield emulsion breaking “OHSOL” technology.   We are deemed to be the primary beneficiary, and we consolidate the assets and liabilities of BWI and their results of operations accordingly.

In September 2010, we increased our ownership in BWI from 19.5% to 42.38% upon the exercise of the Put Option by two BWI unit-holders. As a result of the exercise of the Put Option, we received an additional 2,288 units of BWI in exchange for the issuance of 544 thousand restricted shares of our common stock.

In December 2010, we increased our ownership interests to 52.09% through our participation in a rights offering by BWI under which unit-holders were given the right to purchase additional membership units at a price of $10 per unit.  We purchased an additional 53,061 units for $531 thousand under the rights offering.  See Note 2 – “Investment in BriteWater International, LLC.” in the Notes to Consolidated Financial Statements contained in Part III, Item 8 of this Annual Report on Form 10-K for further information.

INVESTMENT IN GLOBAL

At December 31, 2010 and 2009, we owned approximately 34% of Global’s ordinary shares. At December 31, 2010 and 2009, 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 the share amounts):

   
December 31,
2010
   
December 31,
2009
 
Shares of Global Stock Held by HKN
    11,893,463       11,893,463  
Closing Price of Global Stock
  £ 1.09     £ 0.66  
Foreign Currency Exchange Rate
    1.5524       1.6221  
Market Value of Investment in Global
  $ 20,136     $ 12,637  

The foreign currency translation adjustment of approximately $968 thousand and the unrealized gain on investment of $8.5 million for these changes in market value between the two periods were recorded to other comprehensive income in stockholders’ equity during the year ending December 31, 2010.

Global’s asset base and financial information continue to be strong; therefore we intend to hold our shares of Global until the London market improves. See Note 3 – “Other Investments” in the Notes to Consolidated Financial Statements contained in Part III, Item 8 of this Annual Report on Form 10-K for further information.

INVESTMENT IN SPITFIRE

At December 31, 2009 we held an investment in Spitfire through the ownership of approximately 25% of Spitfire’s currently outstanding common shares. Spitfire is an independent public company (TSX-V; SEL) engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids in Western Canada. At December 31, 2009, our carrying value of this investment was $1.6 million.

During 2010, we sold our remaining interest in Spitfire, which consisted of approximately 9.9 million shares of Spitfire common shares, for cash proceeds of $3.3 million. We realized a gain on sale of assets of $1.9 million using the average cost method, which included $351 thousand of foreign currency gains which were reclassified into earnings from other comprehensive income, in our consolidated statement of operations.
 
 
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Prior to our divestiture, and as a result of our approximate 25% ownership of Spitfire’s outstanding common shares, we were deemed to have the ability to exert significant influence over Spitfire’s operating and financial policies. Accordingly, we reflected our investment in Spitfire as an equity method investment.  Due to timing differences in our filing requirements and the lack of availability of financial information for the current quarterly period, we recorded our share of Spitfire’s financial activity on a three-month lag. Our investment in Spitfire was reported in our consolidated balance sheet at its adjusted carrying value as a non-current asset, and our earnings in Spitfire were reported net of tax as a single line on our consolidated statement of operations.  See Note 4 – “Equity Investment in Spitfire Energy” in the Notes to Consolidated Financial Statements contained in Part III, Item 8 of this Annual Report on Form 10-K for further information.
 
CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

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

Property and Equipment – We follow the full cost method of accounting for our investments in oil and natural gas properties. All costs incurred with the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. Under the full cost method of accounting, such costs may be incurred both prior to or after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion and equipment. Included in capitalized costs are general and administrative costs that are directly related to acquisition, exploration and development activities, and which are not related to production, general corporate overhead or similar activities. For the years 2010 and 2009, such capitalized general and administrative costs totaled $300 thousand and $295 thousand respectively. General and administrative costs related to production and general overhead are expensed as incurred.
 
Proceeds from the sale of oil and natural gas properties are credited to the full cost pool, except in transactions where the proceeds received from the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss would be recognized.
 
Future development, site restoration, and dismantlement and abandonment costs, net of salvage values, are estimated property by property based upon current economic conditions and are included in our amortization of our oil and natural gas property costs.
 
The provision for depletion and amortization of oil and natural gas properties is computed by the unit-of-production method. Under this computation, the total unamortized costs of oil and natural gas properties (including future development, site restoration, and dismantlement and abandonment costs, net of salvage value), excluding costs of unproved properties, are divided by the total estimated units of proved oil and natural gas reserves at the beginning of the period to determine the depletion rate. This rate is multiplied by the physical units of oil and natural gas produced during the period.  Changes in the quantities of our reserves can significantly impact our provision for depletion and amortization of oil and natural gas properties.
 
The cost of unevaluated oil and natural gas properties not being amortized is assessed quarterly to determine whether such properties have been impaired. In determining impairment, an evaluation is performed on current drilling results, lease expiration dates, current oil and natural gas industry conditions, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.  At December 31, 2010, we had approximately $5.3 million in unevaluated oil and gas properties which is related to our unevaluated coalbed methane properties in Indiana.
 
 
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Full-Cost Ceiling Test – At the end of each quarterly period, the unamortized cost of oil and natural gas properties, after deducting the asset retirement obligation, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using average monthly prices, discounted at 10%, and the lower of cost or fair value of unproved properties adjusted for related income tax effects.
 
The calculation of the ceiling test and the provision for depletion are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify a revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
 
Based on the average commodity pricing for the twelve months ended December 31, 2010 of $4.37 per Mmbtu for natural gas and $79.43 per barrel for crude oil, we did not have an impairment of our oil and natural gas properties under the full cost method of accounting. Due to the imprecision in estimating oil and natural gas revenues as well as the potential volatility in oil and natural gas prices and their effect on the carrying value of our proved oil and natural gas reserves, there can be no assurance that write-downs in the future will not be required as a result of factors that may negatively affect the present value of proved oil and natural gas reserves and the carrying value of oil and natural gas properties, including volatile oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve quantities and unsuccessful drilling activities. For a complete discussion of our proved oil and gas reserves, see Note 16 – “Oil and Gas Disclosures” in the Notes to Consolidated Financial statements contained in Part II, Item 8 of the Annual Report of Form 10-K.

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

We carry our financial instruments, including cash, our common stock investment in Global and our 10% Senior Secured Global Note Receivable, at their estimated fair values. Our investment in ordinary shares of Global has been designated as available for sale rather than a trading security. The associated unrealized gains and losses on our available for sale investments are recorded to other comprehensive income until realized and are reclassified into earnings using specific identification.  The fair value of our investment in the ordinary shares of Global is based on prices quoted in an active market.

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

Equity Method Investments – For investments in which we have the ability to exercise significant influence but do not control, we follow the equity method of accounting. Prior to its divestiture during 2010, we reflected our investment in Spitfire as an equity method investment.

Translation of Non-U.S. Currency Amounts - Assets and liabilities of our former equity investment in Spitfire Energy, whose functional currency is the Canadian dollar, were  translated into U.S. dollars at exchange rates in effect at each balance sheet date. Revenue and expense items were translated at average exchange rates prevailing during the periods. Our investment in Global is also subject to foreign currency exchange rate risk as our ownership of Global’s ordinary shares are denominated in British sterling pounds. Translation adjustments are included in other comprehensive income until the investment is sold.
 
 
29

 

Consolidation - Our investment in BWI is considered to be a variable interest, as defined in the FASB’s guidance related to consolidations. This guidance requires the primary beneficiary of a variable interest entity’s (“VIE”) activities to consolidate the VIE. A VIE is defined 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.  We have determined that our investment in BWI meets these requirements, and we are the primary beneficiary, as defined. Accordingly, we consolidate the assets and liabilities as well as the results of operations of BWI into our financial statements.  The results of operations of BWI for the six months ended December 31, 2009 and twelve months ended December 31, 2010 are consolidated in our results of operations.

As of December 31, 2010, 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 and have concluded that Global was not a VIE at December 31, 2010.
 
Proved Reserves - Our estimates of proved reserves are based on quantities of oil and gas reserves which current engineering data indicates are recoverable from known reservoirs under existing economic and operating conditions.  Estimates of proved reserves are key elements in determining our depletion and expense and our full cost ceiling limitation. Estimates of proved reserves are inherently imprecise because of uncertainties in projecting rates of production and timing of developmental expenditures, interpretations of geological, geophysical, engineering and production data and the quality and quantity of available data.  Changing economic conditions also may affect our estimates of proved reserves due to changes in developmental costs and changes in commodity prices that may impact reservoir economics.  We utilize independent reserve engineers to estimate our proved reserves annually.  See Note 16 - “Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements contained in Part II, Item 8 of this Annual Report on Form 10-K.

Income TaxesWe 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. Deferred tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled.  We measure and record income tax contingency accruals in accordance with guidance related to uncertain tax positions.

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.

During 2008, we received a proposed adjustment to our federal tax liability for the calendar year 2005.  We filed a formal protest with the IRS Appeals Office during 2008.  In April 2009, we filed our supplement to the written protest which included a third party valuation report supporting the basis of our recognized gain recorded for ACE purposes.  Utilizing the process outlined above, we have recorded an income tax contingency for this item, including interest and penalties, of $225 thousand.  Although we intend to vigorously defend the proposed adjustment and strongly believe the third party valuation report supports our position and that we have meritorious defenses, if the IRS Appeals Office were to deny all of our protests and our assumptions and estimates associated with this income tax contingency are inaccurate, we could be liable for approximately $6 million in additional tax, penalties and interest.
 
 
30

 

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

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

Recent Accounting Pronouncements – In January 2010, the FASB issued guidance related to “Improving Disclosures about Fair Value Measurements.” These new disclosures require entities to separately disclose amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers. In addition, in the reconciliation for fair value measurements for Level 3, entities should present separate information about purchases, sales, issuances, and settlements. This guidance was effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlement in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. Our adoption of the disclosures did not have a material impact on our notes to the consolidated financial statements. See Note 6 – “Fair Value Measurements” in the Notes to consolidated financial statements for additional information.

In February 2010, the FASB issued amendments to certain recognition and disclosure requirements related to subsequent events. This guidance states that if an entity is an SEC filer, it is required to evaluate subsequent events through the date that the financial statements are issued. In addition, an entity that is an SEC filer is not required to disclose the date through which subsequent events have been evaluated. We adopted this guidance as of February 2010 and have included the required disclosures in our consolidated financial statements. See Note 18 – “Subsequent Events” in the Notes to Consolidated Financial Statements for additional information.
 
 
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RESULTS OF OPERATIONS

For the purposes of discussion and analysis, we are presenting a summary of our consolidated results of operations followed by more detailed discussion and analysis of our operating results.  The primary components of our net income / (net loss) for each of the years in the two year period ended December 31, 2010, were as follows (in thousands, except per-share and production data):
 
   
Year Ended December 31,
 
   
2010
   
2009
   
% Change
 
Oil and gas operating profit (1)
  $ 3,340     $ 1,594       110 %
Gas sales revenues
  $ 1,284     $ 1,542       (17 %)
Gas production (mcf)
    256,812       388,153       (34 %)
Gas price per mcf
  $ 5.00     $ 3.97       26 %
Oil sales revenues
  $ 9,900     $ 8,643       15 %
Oil production (bbls)
    126,526       147,784       (14 %)
Oil price per bbl
  $ 78.24     $ 58.48       34 %
Other revenues, net
  $ 1,720     $ 2,153       (20 %)
General and administrative expenses, net
  $ 3,663     $ 3,197       15 %
Provision (benefit) for doubtful accounts
  $ (22 )   $ 183       (112 %)
Depreciation, depletion, amortization and accretion
  $ 3,419     $ 3,524       (3 %)
Other losses
  $ 79     $ 33       139 %
Equity in losses in Spitfire
  $ 20     $ 225       (91 %)
Gain on sale of investment
  $ (1,887 )   $ (30 )     (6190 %)
Income tax benefit
  $ (20 )   $ (40 )     50 %
Net loss
  $ (192 )   $ (3,345 )     94 %
Net loss attributed to noncontrolling interests
  $ 798     $ 295       171 %
Net income (loss) attributed to HKN
  $ 606     $ (3,050 )     120 %
Net income (loss) attributed to common stock
  $ 605     $ (3,469 )     117 %
Net income (loss) per common share
  $ 0.06     $ (0.37 )     117 %
 
(1)  
Oil and gas operating profit is calculated as oil and gas revenues less oil and gas operating expenses

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

Operating Results:

Oil and Gas Revenues and Oil and Gas Expenses for the Year Ended December 31, 2010 Compared to December 31, 2009

Primarily as a result of higher oil and gas commodity pricing in the markets during 2010, our oil and gas revenues increased from $10.2 million in the prior year period to $11.2 million for the current year period.

Our natural gas revenues decreased from approximately $1.5 million during 2009 to $1.3 million for 2010. The prices realized for natural gas sales increased 26%, averaging $5.00 per mcf during 2010 compared to $3.97 per mcf during 2009, while natural gas production decreased 34% in 2010 as compared to the prior year period due primarily to decreased production from the Boquillas well and the Raymondville field.   The Boquillas well stopped producing in 2010 and is scheduled to be plugged in 2011, and the Raymondville field was sold during the first quarter of 2010.  These decreases were partially offset by production gains from our Lake Raccourci field which were the result of the recompletion of the 14589 #3 well during the third quarter of 2010.
 
 
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Our oil revenues increased to approximately $9.9 million during 2010 from approximately $8.7 million during 2009. We realized a 34% increase in oil prices received, increasing from an average of $58.48 per barrel in 2009 to $78.24 per barrel in the current year.  Overall oil production decreased by 14% in 2010 as compared to the prior year due primarily to decreased oil production at our Main Pass and Raymondville fields. Main Pass decreases were the result of abnormally cold temperatures during the first quarter of 2010 as well as downtime experienced during pipeline modifications, and the Raymondville field was sold during the first quarter of 2010.  These decreases were partially offset by production gains from our Lake Raccourci field which was the result of the 14589 #3 recompletion during 2010.

Our oil and gas operating expense decreased 9%, decreasing from approximately $8.6 million during 2009 to $7.8 million during 2010 due primarily to the sale of our Raymondville field and severance tax refunds for prior periods received during 2010 as a result of well exemptions on certain wells at Main Pass.  These were partially offset by increased labor and oilfield service costs at Main Pass.

Interest and Other Income, net

Fees, interest and other income decreased from $2.2 million in 2009 to $1.7 million in 2010, primarily due to lower processing fees compared to the prior year period as a result of declines in third party production coming through the Main Pass facility which were partially offset by increased interest income and the transaction fee, which were both the result of the issuance of the loan to Global during 2010.

General and Administrative Expense

General and administrative expenses increased 15% from $3.2 million for 2009 to $3.7 million for 2010 primarily due to an additional six months of BWI operating costs being consolidated during the 2010 period.  Remaining general and administrative costs remained flat as compared to the prior year period.

Provision for Doubtful Accounts

We recognized a benefit for doubtful accounts of approximately $22 thousand during 2010 compared to a provision of $183 thousand in 2009 primarily due to the collection of a receivable amount that was previously reserved in 2009 related to one of our oil and gas processing and handling customers who had filed Chapter 11 bankruptcy.

Depreciation, Depletion, Amortization and Accretion Expense

Depreciation, depletion, amortization and accretion (DD&A) expense decreased 3% in 2010 when compared to prior year primarily due to lower production volumes. The decrease was partially offset by increased depletion rates in 2010. The average depletion rate per boe on our properties increased from $13.82 per boe in 2009 to $14.76 per boe in 2010.

Other Losses

During 2010 and 2009, we recognized losses of $72 thousand and $16 thousand, respectively,  on our commodity contracts, and in 2009 we recognized $16 thousand in changes in the fair value of our Spitfire warrants in other losses in our consolidated financials.

Income Tax Expense

We recognized an income tax benefit of $20 thousand during 2010 due to the reversal of our deferred tax liability related to the Texas Margin Tax and an income tax benefit of $40 thousand during 2009 due to an adjustment made during that period to our 2008 state income tax liability.
 
 
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Accrual of Dividends related to Preferred Stock

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

   
2010
   
2009
 
Series G1
  $ 8,000     $ 12,000  
Series G2
    8,000       8,000  
Series M
    -       260,000  
Total
  $ 16,000     $ 280,000  
 
Payments of Preferred Stock Dividends and Preferred Stock Redemptions

At December 31, 2010 and 2009 the following shares of our Preferred Stock issuances were outstanding:
 
   
2010
   
2009
 
Series G1
    1,000       1,000  
Series G2
    1,000       1,000  
Total
    2,000       2,000  
 
Payment of Preferred Stock Dividends -- During 2010 and 2009, we paid the accrued dividends related to preferred stock for the Series G1 and G2 Preferred with shares of our common stock and issued approximately 148 and 157 shares, respectively, of our common stock as payment for the accrued dividends related to the Series G1 and G2 Preferred. The difference between the fair value of the shares of our common stock and the carrying value of the dividend liability, net of withholding taxes paid on behalf of the preferred shareholders, is considered a debt extinguishment gain of $15 thousand and $18 thousand in 2010 and 2009, respectively, and is reflected as payment of preferred stock dividends as an increase to net income (loss) to arrive at net income (loss) attributed to common stock.

During the two years ended December 31, 2010, the accounting for the modification and payment of dividends of our preferred stocks were reflected as either increases or decreases to net income (loss) attributed to common stock.  In June 2009, upon issuance of our common shares, the conversion price of the Series M Preferred decreased from $13.22 to $11.85 per share. The incremental intrinsic value of the change in the Series M Preferred conversion price of $76 thousand is reflected as a payment of preferred stock dividends in our consolidated statement of operations for the year ended December 31, 2009.

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

Redemption of Series G1 Preferred During 2009, we redeemed six hundred shares of our Series G1 Preferred with a liquidation value of $100 per share and 18 shares of Common stock for $5 thousand in cash. In addition, we paid approximately $2 thousand in accrued dividends on these shares.  We had no redemptions of any preferred shares during the period ended December 31, 2010.
 
 
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The net effect of these preferred stock modifications and payments of preferred stock dividends for the two years ended December 31 is as follows:
 
   
2010
   
2009
 
Series G1
  $ 8,000     $ 7,000  
Series G2
    7,000       8,000  
Series M
    -       (154,000 )
Total
  $ 15,000     $ (139,000 )
 
LIQUIDITY AND CAPITAL STRUCTURE

Financial Condition
 
   
December 31,
   
December 31,
 
(Thousands of dollars)
 
2010
   
2009
 
Current ratio
 
2.68 to 1
   
2.74 to 1
 
Working capital (1)
  $ 7,575     $ 5,989  
Total debt
  $ -     $ -  
Total cash and marketable securities less debt
  $ 4,815     $ 7,030  
Total stockholders' equity
  $ 65,112     $ 57,831  
Total liabilities to equity
 
0.22 to 1
   
0.18 to 1
 
 
(1) Working capital is the difference between current assets and current liabilities.

The increase in our working capital as of December 31, 2010 as compared to December 31, 2009 is primarily due to the sale of our investment in Spitfire during 2010.  We have no debt outstanding as of December 31, 2010. We deployed approximately $3.1 million during the 2010 period for capital projects.  The majority of these capital expenditures were used for upgrades and improvements at our Main Pass 35 facility as well as the recompletion of two producing wells at our Creole field.
 
During 2010, oil and natural gas prices increased as compared to the prior year period. We continued to maintain positive cash flow from operations during 2010, and we have a cash balance of approximately $5 million at December 31, 2010. In 2011, we anticipate our operating cash flow and other capital resources, if needed, will adequately fund our planned capital expenditures and other capital uses over the near-term.  Based on the industry outlook for 2011, prices for oil and natural gas are expected to be higher as compared to 2010.

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

We have submitted a proposal to shareholders for a $15 million rights offering under which we would issue, if approved, rights to acquire an additional 7.5 million of our common shares at a price of $2.00 per share. Proceeds from this rights offering would be used to acquire or invest in energy-based businesses, securities, working interests and other oil, natural gas and energy-related investments, properties, products and technologies, as well as for general corporate purposes.
 
 
35

 

During February 2011, we agreed to extend the maturity date of our Global Note Receivable by one year, resulting in a new maturity date of September 14, 2012.  In association with this amendment, we also increased the interest rate from 10% up to 10.5%.  This note is fully secured by oil producing assets of Global, and interest is paid on a monthly basis.

At December 31, 2010, if our remaining convertible preferred stock were converted, and if the remaining option to issue common shares associated with our investment in BWI was exercised, we would be required to issue the following amounts of our common stock:

Instrument
 
 Conversion
Price (a)
 
Shares of
Common Stock
Issuable at
December 31,
2010
 
Series G1 Preferred
  $ 280.00       357  
Series G2 Preferred
  $ 67.20       1,488  
Remaining BWI Put/Call Option (b)
            16,477  
Common Stock Potentially Issued Upon Conversion
            18,322  
 
(a) Certain conversion prices are subject to adjustment under certain circumstances.
(b) See Note 2- Investment in BriteWater International, LLC. in the Notes to Consolidated Financial Statements for additional information.
 
Option to Issue Common Shares – Pursuant to the terms of our investment in BWI and the related Agreements, HKN and the other BWI unit-holders granted to one another put and call options with respect to 3,050 units of BWI in exchange for the issuance of 725 thousand restricted shares of our common stock.  These options are exercisable only if certain conditions are satisfied prior to June 2012.  In September 2010, two BWI unit-holders exercised their Put Option, and we received an additional 2,288 units of BWI in exchange for the issuance of 544 thousand shares of our restricted common stock. As a result of the rights offering completed by BWI in December 2010 and the resulting dilution of the ownership, the shares of any remaining shares to be issued under the put and call option were adjusted from 181 thousand restricted shares to 16 thousand restricted shares of our common stock. One BWI unit-holder’s Put Option remains exercisable until June 30, 2012 and if exercised would result in an additional issuance of 16 thousand restricted shares of our common stock.  Please see Note 2 –“Investment in BriteWater International, LLC” in the Notes to Consolidated Financial Statements for additional information in our investment.

Significant Ownership of our Stock

As of December 31, 2010, Lyford and UEA beneficially owned approximately 32% and 12%, respectively, of the combined voting power of our outstanding common stock. Mr. Alan Quasha, Chairman of the Board of Directors of HKN, is the son of Phyllis Quasha, who is deemed a beneficial owner of Lyford and UEA, but Mr. Quasha disclaims any beneficial ownership of these shares. Lyford and UEA are in a position to exercise significant influence over the election of our board of directors and other matters.  

Cash Flows

Net cash flow provided by operating activities during 2010 was $2.4 million, as compared to $10.3 million in 2009. The decrease in cash flow provided by operating activities as compared to the prior year period was primarily caused by a $9.5 million conversion of marketable securities into cash in 2009.  Excluding the conversion of marketable securities, our cash generated by operations increased approximately $1.6 million. Our cash on hand at December 31, 2010 totaled approximately $5 million.
 
 
36

 
 
Net cash provided by financing activities during 2010 totaled approximately $197 thousand, compared to cash used by financing activities of $6.6 million in 2009. This increase is primarily due to repurchases of our preferred and common stock in 2009. Net cash used in investing activities during 2010 totaled approximately $4.8 million, compared to $2.4 million in 2009. The increase is primarily comprised of capital expenditures associated with recompletion costs for two wells in our non-operated Creole field and upgrades and improvements made at our Main Pass 35 facility.
 
Obligations and Commitments

Oil, Natural Gas and Coalbed Methane Commitments - During 2010, we expended approximately $3.1 million for capital expenditures and workovers in the United States. The majority of these capital expenditures were associated with recompletion costs for the Creole field in Louisiana and upgrades and improvements made at our Main Pass 35 facility in offshore Louisiana.  In 2011, we expect to fund our capital expenditures with available cash on hand and through projected cash flow from operations.  Our capital expenditures for 2011 are discretionary and, as a result, will be curtailed if sufficient funds are not available. Such expenditure curtailments, however, could result in us losing certain prospect acreage or reducing our interest in future development projects.

BriteWater Contingencies - In 2009, BWI recorded a contingent liability of $800 thousand which may be payable upon the conclusion of certain events related to BWI’s equipment. There were no changes to the BWI liability recorded during the period ended December 31, 2010.

Environmental Contingencies - The Environmental Protection Agency (“EPA”) visited our Main Pass facility and issued a report during April 2008 which detailed minor housekeeping violations, several of which were corrected during the course of the inspection. We responded to this report during June 2008 with explanations of how each violation was fully remediated. During May 2010, we received a follow-up letter from the EPA requesting a meeting to discuss our June 2008 response. We held a meeting with the EPA during July 2010, and we anticipate that we will settle this EPA action for less than $50 thousand during early 2011.

IRS Examination - During 2008, we received a proposed adjustment to our federal tax liability for the calendar year 2005.  The proposed adjustment relates to the calculation of the adjusted current earnings (“ACE”) component of the alternative minimum tax and asserts that the Company recognized a gain for ACE purposes on the sale of the Global PLC stock in 2005.  In its proposed adjustment, the IRS alleges that we owe approximately $3.6 million in tax for the year ended December 31, 2005. Penalties and interest calculated through December 31, 2010 in the amount of $2.4 million could also be assessed. We filed a formal protest with the IRS Appeals Office during 2008.  In April 2009, we filed our supplement to the written protest which included a third party valuation report supporting the basis of our recognized gain recorded for ACE purposes.
 
ASC 740, Income Taxes, prescribes a recognition threshold of more-likely-than-not to be sustained upon examination. This guidance also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosures and transition.  Utilizing the process outlined above, we have recorded an income tax contingency for this item, including interest and penalties, of $225 thousand in our consolidated financial statements based, in part, on a preliminary indication of a probability-weighted fair value assessment of the Global stock.  In February 2011, the IRS requested and we agreed to extend the statute of limitations to April 2012 and notified us that the IRS exam group has provided a written response to the HKN third party valuation report that supports our recognized gain recorded for ACE purposes. We intend to review and make a formal response to the IRS over the next few months. Although we intend to vigorously defend the proposed adjustment and strongly believe the third party valuation report supports our position and that we have meritorious defenses, if the IRS Appeals Office were to deny all of our protests and our assumptions and estimates associated with this income tax contingency are inaccurate, we could be liable for approximately $6 million in additional tax, penalties and interest.
 
 
37

 

Deferred Tax Liability - In 2009, upon our investment in BWI, we recorded a deferred tax liability which was calculated by applying the domestic statutory tax rates to the difference between the purchase price and the estimated tax basis.  This difference resulted in a deferred tax liability of $960 thousand. Additionally, at the investment date, there were net operating losses (“NOL”) of approximately $2.8 million and a related deferred tax asset of $962 thousand. The company applied a valuation allowance of $575 thousand against the deferred tax asset, which resulted in a net deferred tax liability of $573 thousand. The valuation allowance was due to the uncertainty related to the timing of when the NOL will expire versus the amount of time that these assets will be fully depreciated. There were no changes to the deferred tax liability recorded during the period ended December 31, 2010.

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

We recognize the full amount of asset retirement obligations beginning in the period in which they are incurred if a reasonable estimate of a fair value can be made. At December 31, 2010, our asset retirement obligation liability totaled approximately $8.9 million.

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

Consolidated Contractual Obligations  The following table presents a summary of our consolidated contractual obligations and commercial commitments as of December 31, 2010 (in thousands):
 
   
Payments Due by Period
 
Contractual Obligations
 
2011
   
2012
   
2013
   
2014
   
Thereafter
   
Total
 
Office Leases (1)
  $ 136     $ 122     $ 41     $ -     $ -     $ 299  
Oil, Gas and Coalbed Methane Commitments (2)
  $ -     $ -     $ -     $ -     $ -       -  
Asset Retirement Obligation
  $ -     $ 211     $ 283     $ 11     $ 8,432       8,937  
Total Contractual Cash Obligations
  $ 136     $ 333     $ 324     $ 11     $ 8,432     $ 9,236  
 
(1) Amounts include updated lease obligations for our offices that were renewed in early 2011.

(2) Our 2011 capital expenditures are discretionary and, as a result, will be curtailed if sufficient funds are not available.

In addition to the above commitments, during 2011 and afterward, government authorities under our Louisiana state leases and other operators may also request us to participate in the cost of drilling additional exploratory and development wells. We may fund these future expenditures at our discretion. Further, the cost of drilling or participating in the drilling of any such exploratory and development wells cannot be quantified at this time since the cost will depend on factors out of our control, such as the timing of the request, the depth of the wells and the location of the property. As of December 31, 2010, we had no material purchase obligations.
 
 
38

 
 
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, 2010, we were not involved in any unconsolidated SPE transactions. We have no off-balance sheet arrangements.

Treasury Stock - At December 31, 2010 and 2009, we held no shares of treasury stock. During the year ended December 31, 2009, we repurchased and retired approximately 708 thousand shares of our common stock. This included a repurchase of 500 thousand shares of our common stock for $1.3 million from a shareholder in a privately negotiated transaction pursuant to our repurchase program. During the year ended December 31, 2010, we repurchased and retired approximately 72 thousand treasury shares at a cost of $272 thousand. As of December 31, 2010 approximately 458 thousand shares remained available for repurchase under our repurchase program.

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

Redemption of Series G1 Preferred -  During 2009, we redeemed six hundred shares of our Series G1 Preferred with a liquidation value of $100 per share and 18 shares of common stock for $5 thousand in cash. In addition, we paid approximately $2 thousand in accrued dividends on these shares.  We had no redemptions of any preferred shares during the period ended December 31, 2010.

Adequacy of Capital Sources and Liquidity

We believe that we have the ability to provide for our operational needs, our planned capital expenditures and possible investments through projected operating cash flow and cash on hand. Our operating cash flow is adversely affected by declines in oil and natural gas prices, which can be volatile.  However, we have worked to reduce our controllable costs and expect to maintain positive cash flow from operations.  Should projected operating cash flow decline, we may further reduce our capital expenditures and possible investments and/or consider the issuance of debt, equity and convertible debt instruments, if needed, for utilization for the capital expenditure program or possible energy-based investment opportunities.  We may also reduce our ownership interest in Global’s common shares through strategic sales under certain conditions.
 
We have no debt outstanding at December 31, 2010. We have submitted a proposal to shareholders for a $15 million rights offering under which we would issue, if approved, rights to acquire an additional 7.5 million of our common shares at a price of $2.00 per share. Proceeds from this rights offering would be used to acquire or invest in energy-based businesses, securities, working interests and other oil, natural gas and energy-related investments, properties, products and technologies, as well as for general corporate purposes. If we seek to raise other equity or debt financing to fund capital expenditures or other acquisition and development opportunities, those transactions may be affected by the market value of our common stock.  If the price of our common stock declines, our ability to utilize our stock either directly or indirectly through convertible instruments for raising capital could be negatively affected. Further, raising additional funds by issuing common stock or other types of equity securities could dilute our existing stockholders, which dilution could be substantial if the price of our common stock decreases. Any securities we issue may have rights, preferences and privileges that are senior to our existing equity securities. Borrowing money may also involve pledging some or all of our assets.
 
 
39

 
 
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.
 
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following financial statements appear on pages 41 through 72 in this Annual Report.
 
  Page
Report of Independent Registered Public Accounting Firm
41
   
Consolidated Balance Sheets -- December 31, 2010 and 2009
42
   
Consolidated Statements of Operations -- Years ended December 31, 2010 and 2009
43
   
Consolidated Statements of Stockholders’ Equity -- Years ended December 31, 2010 and 2009
44
   
Consolidated Statements of Cash Flows -- Years ended December 31, 2010 and 2009
45
   
Notes to Consolidated Financial Statements
46
 
 
 
 
40

 
 
Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders
HKN, Inc.

We have audited the accompanying consolidated balance sheets of HKN, Inc., and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the two years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting.  Our audit included 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of HKN, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2010 in conformity with U.S. generally accepted accounting principles.




HEIN & ASSOCIATES LLP
Dallas, TX
February 17, 2011
 
 
41

 
 
HKN, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except for share amounts)
 
Assets
 
December 31,
   
December 31,
 
   
2010
   
2009
 
Current Assets:
           
Cash and temporary investments
  $ 4,815     $ 7,030  
Accounts receivable, net
    1,704       1,969  
Notes receivable - affiliates
    5,000       -  
Prepaid expenses and other current assets
    553       433  
Total Current Assets
    12,072       9,432  
                 
Unevaluated oil and gas properties
    5,301       5,099  
Evaluated oil and gas properties, net
    32,231       29,355  
OHSOL equipment, net
    6,319       6,227  
Other equipment, net
    628       697  
Property and Equipment, net
    44,479       41,378  
                 
Intangible assets, net
    2,302       2,591  
Investment in Global
    20,136       12,637  
Investment in Spitfire, equity method
    -       1,608  
Other Assets
    130       414  
    $ 79,119     $ 68,060  
                 
Liabilities and Stockholders' Equity
               
                 
Current Liabilities:
               
Trade payables
  $ 1,265     $ 498  
Accrued liabilities and other
    1,373       1,353  
BWI contingency
    800       800  
Income tax contingency
    225       225  
Revenues and royalties payable
    834       567  
Total Current Liabilities
    4,497       3,443  
                 
Asset Retirement Obligation
    8,937       6,193  
Deferred Income Taxes
    573       593  
Total Liabilities
    14,007       10,229  
                 
Commitments and Contingencies (Note 17)
               
                 
Stockholders’ Equity:
               
Series G1 Preferred Stock, $1.00 par value; $100 thousand and $160 thousand liquidation value, respectively;
 
700,000 shares authorized; 1,000 shares outstanding
    1       1  
Series G2 Preferred Stock, $1.00 par value; $100 thousand liquidation value
         
100,000 shares authorized; 1,000 shares outstanding
    1       1  
Series M Preferred Stock, $1.00 par value;
               
50,000 shares authorized; no shares outstanding
    -       -  
Common stock, $0.01 par value; 24,000,000 shares authorized;
               
10,026,098 and 9,553,847 shares issued, respectively
    100       96  
Additional paid-in capital
    438,967       437,877  
Accumulated deficit
    (388,039 )     (388,644 )
Accumulated other comprehensive income
    10,491       3,213  
Total HKN, Inc. Stockholders’ Equity
    61,521       52,544  
Noncontrolling interest
    3,591       5,287  
Total Stockholders' Equity
    65,112       57,831  
    $ 79,119     $ 68,060  
 
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements.
 
 
42

 
 
HKN, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands except for share and per share amounts)
 
   
Year Ended December 31,
 
   
2010
   
2009
 
Revenues and other:
           
Oil and gas operations
  $ 11,184     $ 10,185  
Interest and other income
    1,720       2,153  
      12,904       12,338  
Costs and Expenses:
               
Oil and gas operating expenses
    7,844       8,591  
General and administrative expenses
    3,663       3,197  
(Benefit) provision for doubtful accounts
    (22 )     183  
Depreciation, depletion, amortization and accretion
    3,419       3,524  
Interest expense and other losses
    79       33  
      14,983       15,528  
Other income and (expenses):                
Equity in losses of Spitfire
    (20     (225
Gain on sale of investment
    1,887       30  
      1,867       (195
                 
Loss from operations before income taxes
  $ (212 )   $ (3,385 )
Income tax benefit
    (20 )     (40 )
Net loss
  $ (192 )   $ (3,345 )
Net loss attributable to noncontrolling interests
    798       295  
Net income (loss) attributable to HKN, Inc.
  $ 606     $ (3,050 )
Accrual of dividends related to preferred stock
    (16 )     (280 )
Payments of dividends and modification of preferred stock
    15       (139 )
          Net income (loss) attributed to common stock
  $ 605     $ (3,469 )
Basic and diluted net income (loss) per common share:
               
Net income (loss) per common share
  $ 0.06     $ (0.37 )
Weighted average common shares outstanding
    9,696,047       9,269,565  
 
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements.
 
 
43

 
 
HKN, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(in thousands)
 
     
Preferred Stock
     
Common
     
Addit-
ional
Paid-In
     
Trea-
sury
     
Non-
controll-
ing
     
Accum-
ulated
    Accum-
ulated
Other
Compre-
hensive
       
      G1       G2       M    
Stock
   
Capital
   
Stock
   
Interest
   
Deficit
   
Income
   
Total
 
Balance,  December 31, 2008
  $ 2     $ 1     $ 44     $ 93     $ 442,642     $ (19 )   $ -     $ (385,171 )   $ 2,312     $ 59,904  
                                                                                 
Issuance of restricted shares related to investment, net of issuance costs of $35 thousand
    -       -       -       10       1,307       -       -       -       -       1,317  
Cumulative effect of Series M Preferred conversion feature
    -       -       -       -       -       -       -       (4 )     -       (4 )
Adjustment of Series M conversion price
    -       -       -       -       76       -       -       (76 )     -       -  
Accrual of preferred stock dividends
    -       -       -       -       -       -       -       (280 )     -       (280 )
Issuance of preferred stock dividends
    -       -       -       -       1       -       -       (63 )     -       (62 )
Preferred stock redemption
    (1 )     -       (44 )     -       (4,356 )     -       -       -       -       (4,401 )
Treasury stock repurchase
    -       -       -       -       -       (1,890 )     -       -       -       (1,890 )
Treasury stock retirements
    -       -       -       (7 )     (1,902 )     1,909       -       -       -       -  
Equity in stock repurchases by Spitfire
    -       -       -       -       109       -       -       -       -       109  
Comprehensive loss:
                                                                               
Net loss
                                                            (3,050 )     -          
Unrealized holding gain on
available for sale investments
                                                                    24          
Unrealized foreign currency gain
                                                                    877          
Total comprehensive loss
                                                                            (2,149 )
Noncontrolling interest in investment
    -       -       -       -       -       -       5,287       -       -       5,287  
Balance, December 31, 2009
  $ 1     $ 1     $ -     $ 96     $ 437,877     $ -     $ 5,287     $ (388,644 )   $ 3,213     $ 57,831  
                                                                                 
Issuance of restricted shares related to investment
    -       -       -       5       1,372       -       -       -       -       1,377  
Issuance of membership units in BWI
    -       -       -       -       (10 )     -       479       -       -       469  
Exercise of BWI put option
    -       -       -       -       -       -       (1,377 )     -       -       (1,377 )
Accrual of preferred stock dividends
    -       -       -       -       -       -       -       (16 )     -       (16 )
Issuance of preferred stock dividends
    -       -       -       -       -       -       -       15       -       15  
Treasury stock repurchase
    -       -       -       -       -       (272 )     -       -       -       (272 )
Treasury stock retirements
    -       -       -       (1 )     (271 )     272       -       -       -       -  
Equity in stock repurchases by Spitfire
    -       -       -       -       (1 )     -       -       -       -       (1 )
Comprehensive loss:
                                                                               
Net income
                                                            606       -          
Unrealized holding gain on
available for sale investments
                                                                    8,467          
Unrealized foreign currency loss
                                                                    (1,189 )        
Total comprehensive income
                                                                            7,884  
Noncontrolling interest in investment
    -       -       -       -       -       -       (798 )     -       -       (798 )
Balance, December 31, 2010
  $ 1     $ 1     $ -     $ 100     $ 438,967