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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. #1)

x                Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2009

Commission file number 1-9735

BERRY PETROLEUM COMPANY

(Exact name of registrant as specified in its charter)

1999 Broadway

Suite 3700

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

Registrant’s telephone number, including area code:

(303) 999- 4400

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

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  YES o  NO x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 o

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.  o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  YES o  NO x

As of June 30, 2009, the aggregate market value of the voting and non-voting common stock held by non-affiliates was $684,959,425. As of February 1, 2010, the registrant had 50,952,786 shares of Class A Common Stock outstanding. The registrant also had 1,797,784 shares of Class B Stock outstanding on February 1, 2010 all of which are held by an affiliate of the registrant.

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EXPLANATORY NOTE

Berry Petroleum Company (the “Registrant”) is filing this Amendment No. 1 (this “Amendment”) to its Annual Report on Form 10-K for the fiscal year ended December 31, 2009 (the “Form 10-K”).  The sole purpose of this Amendment No. 1 is to amend Item 8 of the Form 10-K to correct the presentation error in the Statement of Comprehensive Income (Loss) for the year ended December 31, 2009 and the related disclosures in Note 3 to the audited financial statements.  Comprehensive income (loss) in the Form 10-K reflected a net gain from the change in fair value of derivatives of $174.1 million, which should have been reflected as a net loss. The unrealized gains (losses) on derivatives, net of income tax, has been revised from a gain of $205.3 million to a loss of $129.3 million.  The reclassification of realized (gains) losses on derivatives included in net income, net of taxes, has been revised from a gain of $31.2 million to a gain of $44.8 million. Accordingly, this Amendment reflects comprehensive loss of approximately $120.0 million, rather than comprehensive income of $228.1 million reflected in the Form 10-K. These corrections were also included in the Company’s Form 10-Q for the period ended June 30, 2010 filed August 9, 2010.  Except to correct Item 8 of the Form 10-K as described above, no other items or disclosures in the Form 10-K have been amended, and all other information included in the Form 10-K remains unchanged.  This Amendment does not reflect events occurring after the filing of the Form 10-K or modify, amend or update any items or disclosures therein in any way other than as required to reflect the changes identified above.

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Item 8. Financial Statements and Supplementary Data

Financial statement schedules have been omitted since they are either not required, are not applicable, or the required information is shown in the financial statements and related notes.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Berry Petroleum Company:

In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Berry Petroleum Company at December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 2 to the financial statements, the Company changed the manner in which it accounts for recurring fair value measurements of financial instruments in 2008. As discussed in Note 9 to the financial statements, the Company changed the manner in which it accounts for earnings per share in 2009.

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

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

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

February 25, 2010, except for the effects of the matter discussed in Note 17, as to which the date is August 11, 2010

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BERRY PETROLEUM COMPANY

Balance Sheets

December 31, 2009 and 2008

(In Thousands, Except Share Information)

The accompanying notes are an integral part of these financial statements.

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BERRY PETROLEUM COMPANY

Statements of Income

Years ended December 31, 2009, 2008 and 2007

(In Thousands, Except Per Share Data)

Statements of Comprehensive Income (Loss)

Years Ended December 31, 2009, 2008 and 2007

(In Thousands)

The accompanying notes are an integral part of these financial statements.

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BERRY PETROLEUM COMPANY

Statements of Shareholders’ Equity

Years Ended December 31, 2009, 2008 and 2007

(In Thousands, Except Per Share Data)

 The accompanying notes are an integral part of these financial statements.

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BERRY PETROLEUM COMPANY

Statements of Cash Flows

Years Ended December 31, 2009, 2008 and 2007

(In Thousands)

 The accompanying notes are an integral part of these financial statements.

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BERRY PETROLEUM COMPANY

Notes to the Financial Statements

1.                                      Summary of Significant Accounting Policies

Description of the business

Berry Petroleum Company (the Company) is an independent energy company engaged in the production, development, acquisition, exploitation and exploration of crude oil and natural gas. The Company has invested in cogeneration facilities which provide steam required for the extraction of heavy oil and which generates electricity for sale.

Basis of presentation

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reclassifications and error corrections

Included in the fourth quarter of 2009 are adjustments to correct the prior accounting for the Company’s royalties in the amount of $3.3 million, which resulted in decreasing its sales of oil and gas and increasing its royalties payable.  The year- to-date impact of the adjustment was $1.9 million.  Management concluded the impact was immaterial to the current and prior periods.

In March 2008, the Company determined there was an error in computing royalties payable in prior years, accumulating to $10.5 million as of December 31, 2007. The Company concluded the error was not material to any individual prior interim or annual period (or to the projected earnings for 2008) and, therefore, the error was corrected during the first quarter of 2008, with the effect of increasing sales of oil and gas by $10.5 million and reducing royalties payable.

Cash and cash equivalents

The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. The Company’s cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at December 31, 2009 and 2008 is $15.7 million and $31.8 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

Accounts receivable

Trade accounts receivable consist mainly of receivables from oil and gas purchases and joint interest owners on properties the Company operates.  For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings.  Generally, oil and gas receivables are collected within two months.

Allowance for doubtful accounts

The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.  As of both December 31, 2009 and 2008, the Company has an allowance for doubtful accounts of $38.5 million.  The 2008 amount represents the Company’s November and December 2008 sales to BWOC.  The Company had a long-term contract to sell all of its heavy crude oil in California for approximately $8.10 below WTI with BWOC.  On December 22, 2008, Flying J, Inc. and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary BWOC each filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code.  Also in December 2008, BWOC informed the Company that it was unable to receive the Company’s production.  On March 17, 2009, the Company entered into a stipulation with BWOC, terminating the contract effective as of March 16, 2009.  The Company recorded $38.5 million of bad debt expense in 2008 for the bankruptcy of BWOC.  Of that $38.5 million due from BWOC, $11.8 million represents 20 days of December 2008 crude oil sales and an administrative claim under the bankruptcy proceedings and $26.7 million represents November and the balance of December 2008 crude oil sales which would have the same priority as other general unsecured claims.  BWOC will also be liable to the Company for damages under this contract.  While the Company also has guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, the information received from the bankruptcy proceedings to date has not provided the Company with adequate data from which to make a conclusion that any amounts will be collected.  The Company has entered into various agreements with other companies to sell its California oil production.

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Discontinued operations

In 2009, the Company sold its DJ Basin assets, the results of operations of which, are reported as discontinued operations in the Statement of Income.

Income taxes and uncertain tax positions

Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes.  Deferred income taxes are accounted for using the asset and liability method, which results in the recognition of deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. A valuation allowance is recognized if it is determined that deferred tax assets may not be fully utilized in future periods.  Income tax positions must meet a more-likely-than-not recognition threshold to be recognized, and any potential accrued interest and penalties related to the unrecognized tax benefits are recognized within income tax expense.  Uncertain tax positions are recognized in the Balance Sheet as a current or noncurrent liability, based upon the expected timing of the payment to a taxing authority.

Derivatives

The Company periodically enters into commodity derivative contracts to manage its exposure to oil and natural gas price volatility.  The Company also enters into derivative contracts to mitigate the risk of interest rate fluctuations.   The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge.  Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings.  Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, has no effect on the statement of income because changes in fair value of the derivative offsets changes in the fair value of the hedged item.   Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings.  Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings.  The estimated fair value of derivative instruments requires substantial judgment.  These values are based upon, among other things, whether or not the forecasted hedged transaction will occur, option pricing models, futures prices, volatility, time to maturity and credit risk.  The values the Company reports in its financial statements changes as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond its control.

Prior to January 1, 2010, the Company designated most of its commodity and interest rate derivative contracts as cash flow hedges, whose unrealized fair value gains and losses were recorded to Accumulated other comprehensive loss (AOCL).  Effective January 1, 2010, the Company has elected to de-designate all of its commodity and interest rate contracts that had previously been designated as cash flow hedges as of December 31, 2009 and have elected to discontinue hedge accounting prospectively.

As a result, subsequent to December 31, 2009, the Company will recognize all gains and losses from prospective changes in commodity and interest rate derivative fair values immediately in earnings rather than deferring any such amounts in AOCL.  At December 31, 2009, AOCL consisted of $97 million ($60 million after tax) of unrealized losses, representing the mark-to-market value of the Company’s cash flow hedges as of the balance sheet date, less any ineffectiveness recognized.  As a result of discontinuing hedge accounting on January 1, 2010, such mark-to-market values at December 31, 2009 are frozen in AOCL as of the de-designation date and will be reclassified into earnings in future periods as the original hedged transactions affect earnings.  The Company expects to reclassify into earnings from AOCL the frozen value related to de-designated commodity hedges during the next three years.

Oil and gas properties, buildings and equipment

The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive.

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Depletion of oil and gas producing properties is computed using the units-of-production method. Depreciation of lease and well equipment, including cogeneration facilities and other steam generation equipment and facilities, is computed using the units-of-production method or on a straight-line basis over estimated useful lives ranging from 10 to 20 years. Buildings and equipment are recorded at cost. Depreciation is provided on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. Estimated residual salvage value is considered when determining depreciation, depletion and amortization (DD&A) rates.  Changes in reserves are applied on a prospective basis.

Interest incurred on funds borrowed to finance exploration and certain acquisition and development activities is capitalized. To qualify for interest capitalization, the costs incurred must relate to the acquisition of unproved reserves, drilling of wells to prove up the reserves and the installation of the necessary pipelines and facilities to make the property ready for production. Such capitalized interest is included in oil and gas properties, buildings and equipment. Capitalized interest is added into the depreciable base of the assets and is expensed on a units-of-production basis over the life of the respective project.

In accordance with authoritative guidance, the Company groups assets at the field level and periodically reviews the carrying value of its property and equipment to test whether current events or circumstances indicate such carrying value may not be recoverable. If the tests indicate that the carrying value of the asset is greater than the estimated future undiscounted cash flows to be generated by such asset, then an impairment adjustment needs to be recognized. Such adjustment consists of the amount by which the carrying value of such asset exceeds its fair value. The Company generally measures fair value by considering sale prices for similar assets or by discounting estimated future cash flows from such asset using an appropriate discount rate. Considerable management judgment is necessary to estimate the fair value of assets, and accordingly, actual results could vary significantly from such estimates. When assets are sold, the applicable costs and accumulated depreciation and depletion are removed from the accounts and any gain or loss is included in income. Expenditures for maintenance and repairs are expensed as incurred.

Asset retirement obligations

Asset retirement obligations (ARO) relate to future costs associated with plugging and abandonment of oil and gas wells, removal of equipments and facilities from leased acreage and returning such land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount.  The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset.  Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.

Accrued liabilities

Accrued liabilities consist primarily of accrued property taxes, accrued interest and accrued payroll costs.  Accrued property taxes were $8.3 million and $13.5 million as of December 31, 2009 and 2008, respectively.  Accrued interest was $6.9 million and $8.4 million as of December 31, 2009 and 2008, respectively.  Accrued payroll costs were $8.2 million and $8.4 million as of December 31, 2009 and 2008, respectively.

Revenue recognition

Revenues associated with sales of crude oil, natural gas, electricity and natural gas marketing are recognized when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. The electricity and natural gas the Company produces and uses in its operations are not included in revenues. Revenues from crude oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of its net working interest (entitlement method).  Revenues are derived from gas marketing sales which represent excess capacity on the Rockies Express pipeline which the Company uses to market natural gas for its working interest partners.

Electricity cost allocation

The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations and securing operating control of the respective steam generation.  Cogeneration, also called combined heat and power (CHP), extracts energy from the exhaust of a turbine that would otherwise be wasted, to produce steam. Such cogeneration operations produce electricity and steam. The Company allocates steam costs to its oil and gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to the utilities. Electricity used in oil and gas operations is allocated at cost. A portion of the capital costs of the cogeneration facilities is allocated to DD&A-oil and gas production. 

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Electricity consumption included in oil and gas operating costs for the years ended December 31, 2009, 2008 and 2007 was $2.8 million, $5.8 million and $5.0 million, respectively.

Transportation costs

Transportation costs, consisting primarily of natural gas transportation costs, are included in either “Operating costs - oil and gas production” or “Operating costs - electricity generation,” as applicable. Natural gas transportation costs included in Operating costs - oil and gas production were $15.2 million, $9.5 million and $1.2 million for 2009, 2008 and 2007, respectively.  Natural gas transportation costs included in Operating costs - electricity generation were $2.8 million, $7.2 million and $6.7 million for 2009, 2008 and 2007, respectively. Additionally, the transportation costs in Uinta were $0.2 million, $0.2 million and $1.4 million in 2009, 2008 and 2007, respectively.

Stock-based compensation

The Company recognizes the grant date fair value of stock options and other stock based compensation issued in the statement of income.  Expense is recognized on a straight-line basis over the employee’s requisite service period (generally the vesting period of the award).

Earnings (loss) per share

Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period.  Under the treasury stock method, diluted earnings (loss) per share is computed by dividing net earnings (loss) adjusted for the effects of potential common shares.

Related party transactions

In December 2007, the Company accepted a tender issued by Bakersfield Fuel & Oil Company (BFO) to purchase all of its shares in BFO for $2.9 million. These proceeds are reflected in the “Proceeds from sale of assets” line on the Statements of Cash Flows and in the “Gain on sale of assets” line on the Statements of Income. Mr. Thomas Jamieson is a Director of Berry Petroleum Company and a director and the controlling stockholder of BFO. The tender was made to all shareholders of BFO other than Mr. Jamieson and his affiliates. The Corporate Governance and Nominating Committee, with input from the Audit Committee, approved this transaction.

Equity method investments

The Company owns interests in two entities which serve to gather and transport natural gas in the Company’s Lake Canyon and Brundage Canyon fields. The Company owns less than 50% interest in both entities and these interests are accounted for using the equity method.  The Company’s net investment in these entities is included under the caption “Other assets” on its Balance Sheet.

Impact of recently issued accounting standard updates

In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-06 “Improving Disclosures about Fair Value Measurements.”   The ASU amends previously issued authoritative guidance and requires new disclosures and clarifies existing disclosures and is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the rollforward 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.  As this requires only additional disclosures, the guidance will have no impact on the Company’s financial position or results of operations.

2.                                      Fair Value Measurement

In September 2006, authoritative guidance was issued that defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Company adopted this guidance as of January 1, 2008 for all financial and nonfinancial assets and liabilities recognized or disclosed at fair value on a recurring basis.  The Company has also adopted the authoritative guidance as it relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis as of January 1, 2009 pursuant to the authoritative guidance issued by the FASB in February 2008.  The adoption of the authoritative guidance did not have a material impact on the financial statements for the years ended December 31, 2009 or 2008.

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The authoritative guidance establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers include: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy.  Oil swaps, natural gas swaps and interest rate swaps are valued using internal models which are based on active market data and are classified within Level 2 of the valuation hierarchy. Derivatives that are valued based upon models with significant unobservable market inputs (primarily volatility), and that are normally traded less actively are classified within Level 3 of the valuation hierarchy. The Company determines the value of option contracts utilizing industry-standard option pricing models based on inputs that are either readily available in public markets, can be derived from information available in publicly quoted markets, or are quoted by financial institutions that trade these contracts. In situations where the Company obtains inputs via quotes from financial institutions, it verifies the reasonableness of these quotes via similar quotes from another financial institution as of each date for which financial statements are prepared. The Company also considers counterparty credit risk and its own credit risk in its determination of all estimated fair values. The Company has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds.  Level 3 derivatives include oil collars, natural gas collars and natural gas basis swaps.

The following tables set forth by level within the fair value hierarchy the Company’s assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2009 and 2008.

Assets and liabilities measured at fair value on a recurring basis

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Changes in Level 3 fair value measurements

The table below includes a rollforward of the Balance Sheet amounts (including the change in fair value) for financial instruments classified by us within Level 3 of the valuation hierarchy. When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources).

The $3.4 million of transfers out of Level 3 for the year ended December 31, 2009 represent crude oil collars that were converted to crude oil swaps during the first quarter of 2009.

For further discussion related to the Company’s derivatives see Note 3 to the financial statements.

Fair Market Value of Financial Instruments

The Company used various assumptions and methods in estimating the fair values of its financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short-term maturity of these instruments. The carrying amount of the Company’s credit facilities approximated fair value, because the interest rates on the credit facilities are variable. The fair values of the 8.25 % senior subordinated notes due 2016 and the 10.25 % senior notes due 2014 were estimated based on quoted market prices. The fair values of the Company’s derivative instruments and other investments are discussed above.

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Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

In December 2009, subsequent to the approval of the Company’s capital budget, the Company recorded a $4.2 million impairment charge related to the write down of a drilling rig to its fair value.  Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, operational costs, and a risk-adjusted discount rate.  The fair value measurement was based on Level 3 inputs.  The fair value of the drilling rig on December 31, 2009 was $3.3 million.

3.                                      Hedging

To minimize the effect of a downturn in oil and gas prices and protect the Company’s profitability and the economics of its development plans, the Company enters into crude oil and natural gas hedge contracts from time to time. The terms of contracts depend on various factors, including management’s view of future crude oil and natural gas prices, acquisition economics on purchased assets and future financial commitments. This price hedging program is designed to moderate the effects of a severe crude oil and natural gas price downturn while allowing us to participate in some commodity price increases. The Company benefits from lower natural gas pricing as it is a consumer of natural gas in its California operations.  In the Rocky Mountains and E. Texas the Company benefits from higher natural gas pricing. The Company has hedged, and may hedge in the future, both natural gas purchases and sales as determined appropriate by management.  Management regularly monitors the crude oil and natural gas markets and financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging and/or basis adjustments or other price protection is appropriate in accordance with policy established by its Board of Directors.  Currently, the hedges are in the form of swaps and collars.  However, the Company may use a variety of hedge instruments in the future to hedge WTI or the index gas price.  The Company also utilizes interest rate derivatives to protect against changes in interest rates on its floating rate debt.

At December 31, 2009, the net fair value derivative liability was $97.4 million as compared to a net fair value asset of $185.9 million at December 31, 2008 which reflects changes in commodity prices and interest rates. Based on NYMEX strip pricing as of December 31, 2009, the Company expects to make hedge payments under the existing derivatives of $21.7 million during the next twelve months.

At December 31, 2009, AOCL consisted of $(60.4) million, net of tax, of unrealized losses from crude oil and natural gas swaps and collars that qualified for hedge accounting treatment at December 31, 2009, less any ineffectiveness recognized.  As a result of discontinuing hedge accounting on January 1, 2010, such mark-to-market values at December 31, 2009 are frozen in AOCL as of the de-designation date and will be reclassified into earnings in the same period that the forecasted transactions impact earnings.

The related cash flow impact of all of the Company’s hedges is reflected in cash flows from operating activities.

The Company presents its derivative assets and liabilities on its Balance Sheets on a net basis.  The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with a counterparty to a derivative contract.  The Company uses these agreements to manage and reduce its potential counterparty credit risk.

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The following table disaggregates the Company’s net derivative assets and liabilities into gross components on a contract-by-contract basis before giving effect to master netting arrangements.  Finally, the Company identifies the line items on its Balance Sheets in which these fair value amounts are included.  The gross asset and liability values in the table below are segregated between those derivatives designated in qualifying hedge accounting relationships and those not designated in hedge accounting relationships.  The Company uses the end of period accounting designation to determine the classification for each derivative position.

The tables below summarize the Statement of Income impacts of the Company’s derivative instruments before tax for the twelve months ending December 31, 2009 (in millions):

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Amount of Gain or (Loss) Recognized in Income on Derivatives not designated as Hedging Instruments under authoritative guidance as of twelve months ending December 31, 2009:

During the first quarter of 2009, the Company converted oil collars for 6,000 Bbl/D for the full year 2010 into swaps for the same volumes with swap prices ranging from $61.00 to $64.80.

The Company generally utilizes NYMEX WTI based derivatives to hedge cash flows from its California oil sales.  The Company’s oil sales contracts with multiple refiners are primarily based on the field posting prices.  There is a high correlation between WTI and the field posting prices which allowed us to utilize hedge accounting.  As there is a ready market for the Company’s crude oil in California, the Company does not believe the loss of any particular contract impacts the probability that its hedged forecasted transactions will occur.  The Company generally hedges its natural gas at the basis location that corresponds to the forecasted sale.

While the Company designates the majority of its hedges as cash flow hedges, it has not elected hedge accounting on certain of its crude oil and natural gas hedges.  During the twelve months ended December 31, 2009, the Company recorded $6.5 million under the caption “Gain (loss) on derivatives” related to hedges for which it either did not elect hedge accounting or which no longer qualified for hedge accounting.  In conjunction with the sale of the DJ basin assets, during the first quarter of 2009, the Company concluded that the forecasted transaction in certain of its hedging relationships was not probable of occurring.  As such, the Company reclassified a gain of $14.3 million from AOCL to the Statement of Income under the caption “Gain (loss) on derivatives.”  “Gain (loss) on derivatives” includes a loss for cash settlements of $7.6 million and a gain for the change in fair value of $0.3 million on hedges for which the Company has not elected hedge accounting. Additionally, a portion of the change in fair value for hedges that was designated as cash flow hedges may impact the Company’s income as the sales price is not perfectly correlated with the Company’s hedges.  The Company recognized an unrealized net loss of $0.5 million on the Statement of Income under the caption “Gain (loss) on derivatives” for the twelve months ended December 31, 2009, respectively, as a result of ineffectiveness.  During the first quarter of 2009, the Company entered into natural gas derivatives on behalf of the purchaser of its DJ assets.  The Company did not elect hedge accounting for these hedges and recorded an unrealized net loss of $0.5 million on the Statement of Income under the caption “(Loss) income from discontinued operations, net of taxes.”

The Company’s hedge contracts have been executed primarily with counterparties that are party to its senior secured revolving credit facility.

Neither the Company nor its counterparties are required to post collateral in connection with its derivative positions and netting agreements are in place with each of the Company’s counterparties allowing the Company to offset its commodity derivative asset and liability positions.  The credit rating of each of these counterparties was AA-/Aa2, or better as of December 31, 2009.  The Company’s derivatives are held with a small number of counterparties and as of December 31, 2009, the Company’s largest three counterparties accounted for 76% of the value of its total derivative positions.

As of December 31, 2009, the Company had the following commodity hedges:

For further discussion related to the fair value of the Company’s derivatives see Note 2 to the financial statements.

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4.                                      Asset Retirement Obligations (AROs)

The following table summarizes the change in abandonment obligation for the years ended December 31 (in thousands):

The ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

5.                                      Acquisitions and Divestitures

During the twelve months ended December 31, 2009, the Company completed acquisitions totaling $13.5 million. In June 2009, the Company acquired property near McKittrick, California, the deep rights to one of the leases in its Darco property in E. Texas, and additional interests in its Piceance Garden Gulch assets.

On July 17, 2009, the Company completed the financing of its E. Texas gas gathering system for $18.4 million in cash.  The Company entered into concurrent long-term gas gathering agreements for the E. Texas production which contained an embedded lease.  The transaction was treated as a financing obligation.  Accordingly, the net book value of the property of $16.7 million will be depreciated over the remaining useful life of the asset and the cash received of $18.4 million was recorded as a financing obligation.  A portion of future payments will be recorded as gathering expense, a portion as interest expense and the balance as a reduction in the financing obligation.  There is no minimum payment required under these agreements.

On March 3, 2009, the Company entered into an agreement to sell its DJ basin assets and related hedges for $154 million before customary closing adjustments. The closing date of the sale of the assets was April 1, 2009.  The Company recorded a pre-tax impairment loss of $9.6 million related to the sale, which is aggregated within the $5.9 million “(Loss) income from discontinued operations, net of taxes” on its Statement of Income for the twelve months ended December 31, 2009.

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(Loss) income from discontinued operations, net of tax on the accompanying statements of income is comprised of the following (in thousands):