Summary of Significant Accounting Policies

Description of the Business

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

Basis of Presentation

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Certain amounts in prior years' financial statements have been reclassified to conform to the 2011 financial statement presentation.

Assumptions, Judgments, and Estimates

In the course of preparing the financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.

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, 2011 and 2010 is $16.1 million and $16.3 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 natural gas purchasers and from 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 natural gas receivables are collected within two months.

Bad Debt Recovery

The Company recognized $38.5 million in bad debt expense in the year ended December 31, 2008 related to the Flying J bankruptcy. On July 6, 2010, the Joint Plan of Reorganization of Flying J was confirmed under Chapter 11 of the United States Bankruptcy Code. Additionally, the United States Bankruptcy Court approved and confirmed the June 15, 2010 Stipulation and Agreed Order (the Stipulation) with Flying J regarding the resolution of the Company's claim in Flying J's pending bankruptcy. Pursuant to the Stipulation, Flying J agreed that the total amount owed to the Company by Flying J was $60.5 million and, as a result, the Company received $60.5 million in cash on July 23, 2010. In the quarter ended September 30, 2010, the Company recorded a settlement of the Company's Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5 million.

Discontinued Operations

In 2009, the Company sold its DJ assets, the results of operations of which are reported as discontinued operations in the 2009 Statements of Operations. See Note 2 to the Financial Statements.

Income Taxes and Uncertain Tax Positions

The Company recognizes deferred income tax liabilities and assets for the expected future income tax consequences of temporary differences between financial accounting bases and income tax bases of assets and liabilities. Deferred income taxes are measured by applying currently enacted income tax rates. The Company accounts for uncertainty in income taxes for income tax positions taken or expected to be taken in an income tax return. Only income tax positions that meet the more-likely-than-not recognition threshold will be recognized.

Derivative Instruments

The Company enters into derivative contracts, primarily swaps and collars, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the "normal purchases normal sales" exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. The Company is required to formally document, at the inception of a hedge, the hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment. Effective January 1, 2010, the Company elected to discontinue all hedge accounting prospectively. As a result, subsequent to December 31, 2009, the Company records all derivative instruments as either assets or liabilities at fair value and recognizes all gains and losses from changes in derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive loss (AOCL). See Notes 8 and 9 to the Financial Statements. Cash settlements of derivative instruments used to manage commodity price risk are classified as cash flows from operating activities in the Statements of Cash Flows along with the cash flows from the related oil and natural gas production activities. The Company nets derivative assets and liabilities of a given counterparty whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The Company uses these agreements to manage and reduce its potential counterparty credit risk. The Company does not enter into derivative instruments for speculative or trading purposes.

Oil and Natural Gas Properties, Buildings and Equipment

The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs 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 finds 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.

The provision for depletion of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.

Buildings and equipment are recorded at cost. Depreciation is calculated 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.

Capitalized Interest

Acquisition costs of proved undeveloped and unproved properties qualify for interest capitalization during a period if interest cost is incurred and activities necessary to bring the properties into a productive state are in progress. As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re-designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re-designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

Impairment of Proved and Unproved Properties

Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows. Due to the impact of lower natural gas prices, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets. See Notes 9 and 11 to the Financial Statements.

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.

Assets Held for Sale

Any properties held for sale as of the date of presentation of the balance sheets have been classified as assets held for sale and are separately presented on the balance sheets at the lower of net book value or fair value less the cost to sell. See Note 3 to the Financial Statements.

Asset Retirement Obligations

The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO 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 AROs result in adjustments to the related capitalized asset and corresponding liability.

Deferred Financing Costs

Costs incurred in connection with the execution or modification of the Company’s credit facility, and in connection with the Company's senior and subordinated notes, are capitalized and amortized over the life, or expected life, of the debt using the effective interest method.

Prepaid Expenses and Other

The components of prepaid expenses and other are as follows:



	Year Ended December 31,
(in thousands)	2011	2010
Prepaid expenses	5,275	9,590
Inventory	11,526	4,443
Total prepaid expenses and other	16,801	14,033

Accrued Liabilities

The components of accrued liabilities are as follows:



	Year Ended December 31,
(in thousands)	2011		2010
Property taxes	$	10,430	$	11,245
Accrued interest	9,205		10,074
Accrued payroll	9,953		10,225
Other accrued liabilities	5,478		4,690
Total accrued liabilities	$	35,066	$	36,234

Revenue Recognition

Revenues associated with sales of 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 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. Revenues are also derived from natural gas marketing sales, which represent excess capacity on the Rockies Express, Wyoming Interstate, and Ruby pipelines used by the Company to market natural gas for its working interest partners and other third parties.

Significant Customers

The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and electricity to utility companies. Credit is extended based on an evaluation of the customer's financial condition and historical payment record. The Company does not believe that the loss of any one customer would impact the marketability of its products, but it may impact the profitability of its oil, natural gas or electricity sold. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the Company's crude oil sales customer in Utah could impact the marketability of a portion of the Company's Utah crude oil volumes.

In 2011, sales to ExxonMobil Oil Corporation and Shell Trading (US) Company accounted for approximately 43% and 14%, respectively, of the Company's revenue. In 2010, sales to two purchasers were approximately 44% and 14%, respectively, of the Company's revenue. In 2009, sales to three purchasers were approximately 25%, 16% and 12%, respectively, of the Company's revenue.

Concentrations of Market Risk

The results of the Company's oil and natural gas operations are impacted by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future depends on numerous factors beyond the Company's control, including weather, imports, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil and natural gas products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

During 2011, 2010 and 2009, the Company did not incur any credit losses with respect to counterparties to contracts for the sale of oil and natural gas or under the Company's derivative instruments. As of December 31, 2011, over 87% of the Company's California oil production is under contract with Shell Trading (US) Company and ExxonMobil Oil Corporation. The Company's contract with Shell Trading (US) Company continues through June 30, 2013 and the Company's contract with ExxonMobil Oil Corporation renews automatically on a month-to-month basis, unless either party to the contract terminates upon 90 days' notice.

The Company places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution. For the three years ended December 31, 2011, the Company has not incurred losses related to these investments.

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, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. The Company allocates steam costs to its oil and natural gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to utility companies. A portion of the capital costs of the cogeneration facilities is allocated to DD&A—oil and natural gas production. Electricity production used in oil and natural gas operations is allocated to operating costs—oil and natural gas production, and totaled $2.3 million, $2.8 million and $2.8 million for the years ended December 31, 2011, 2010 and 2009 respectively.

Transportation Costs

Natural gas transportation costs are included in either operating costs—oil and natural gas production or operating costs—electricity generation, as applicable. Natural gas transportation costs included in operating costs—oil and natural gas production were $21.4 million, $16.2 million and $16.1 million for 2011, 2010 and 2009, respectively. Costs for transporting natural gas used in electricity generation were $5.0 million, $4.7 million and $2.8 million for 2011, 2010 and 2009, respectively; a portion of these costs are allocated to operating costs—oil and natural gas production, as described above, and the remainder are included in operating costs—electricity generation.

Stock-Based Compensation

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

(Loss) Earnings Per Share

The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Unvested restricted stock issued prior to January 1, 2010, under the Company's equity incentive plans, has the right to receive non-forfeitable dividends, participating on an equal basis with common stock, and thus these securities are classified as participating securities. Participating securities do not have a contractual obligation to share in the Company's losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Unvested restricted stock issued subsequent to January 1, 2010, under the Company's equity incentive plans does not participate in dividends. Stock options issued under the Company's equity incentive plans do not participate in dividends.

Basic (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-basic during each period. Under the treasury stock method, diluted (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-dilutive, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of non-participating unvested restricted stock awards and outstanding stock options. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted (loss) earnings per share.

The following table shows the computation of basic and diluted net earnings per share from continuing and discontinued operations:



	Year Ended December 31,
	2011			2010		2009
	(in thousands, except per share amounts)
Net (loss) earnings from continuing operations	$	(228,063	)	$	82,524	$	47,224
Less: earnings allocable to participating securities	—			1,199		1,134
Net earnings from continuing operations available for common shareholders	$	(228,063	)	$	81,325	$	46,090

Net earnings from discontinued operations	$	—		$	—	$	6,806
Less: earnings allocable to participating securities	—			—		174
Net earnings from discontinued operations available for common shareholders	$	—		$	—	$	6,632

Basic (loss) earnings per share from continuing operations	$	(4.21	)	$	1.54	$	1.03
Basic earnings per share from discontinued operations	—			—		0.15
Basic (loss) earnings per share	$	(4.21	)	$	1.54	$	1.18

Dilutive (loss) earnings per share from continuing operations	$	(4.21	)	$	1.52	$	1.02
Dilutive earnings per share from discontinued operations	—			—		0.15
Dilutive (loss) earnings per share	$	(4.21	)	$	1.52	$	1.17

Basic weighted average shares	54,133			52,969		44,625
Add: dilutive effects of stock options	—			460		221
Diluted weighted average shares	54,133			53,429		44,846

Options of 1.5 million, 0.7 million and 1.6 million shares were not included in the weighted average shares-dilutive calculation for the years ended December 31, 2011, 2010 and 2009, respectively, because their effect would have been anti-dilutive.

Equity Method Investments

The Company owns interests in two entities that gather and transport natural gas in the Company's Lake Canyon and Brundage Canyon fields. The Company owns less than a 50% interest in both of these entities and such 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 Sheets.

Comprehensive (Loss) Earnings

Comprehensive (loss) earnings is a term used to refer to net (loss) earnings plus other comprehensive earnings (loss). Other comprehensive (loss) earnings is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders' equity instead of net (loss) earnings. The components of other comprehensive (loss) earnings were as follows:



	Year Ended December 31,
(in thousands)	2011			2010		2009
Net (loss) earnings	$	(228,063	)	$	82,524	$	54,030
Unrealized gain (loss) on derivatives, net of income taxes of $0, $0, and ($79,240), respectively	—			—		(129,287		)
Reclassification of realized (gain) loss on derivatives included in net earnings, net of income taxes of $0, $0, ($27,447)	—			—		(44,782		)
Amortization of Accumulated other comprehensive loss related to de-designated hedges, net of income taxes of $23,467, $10,153, and $0, respectively	38,289			16,566		—
Comprehensive (loss) earnings	$	(189,774	)	$	99,090	$	(120,039	)

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, and production of oil and natural gas, and all of the Company's operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.

Impact of Recently Issued Accounting Standard Updates

In December 2011, the FASB issued ASU No. 2011-11 Disclosures about Offsetting Assets and Liabilities. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company's financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. The Company is currently evaluating the provisions of ASU 2011-11 and assessing the impact, if any, it may have on the Company's financial position or results of operations.

In June 2011, the FASB issued ASU No. 2011-05 Presentation of Comprehensive Income. The ASU amends previously issued authoritative guidance and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. These amendments remove the option under current U.S. GAAP to present the components of other comprehensive income as part of the statements of changes in stockholder's equity. In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-12 Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards. The ASU supersedes pending paragraphs in ASU 2011-05 related to presenting reclassifications out of accumulated other comprehensive income by component in the financial statements. The adoption of this authoritative guidance will not have an impact on the Company's financial position or results of operations, but will require the Company to present the Statements of Comprehensive Income separately from its Statements of Shareholders' Equity, as these statements are currently presented on a combined basis.

In May 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs. The ASU amends previously issued authoritative guidance and requires new disclosures, clarifies existing disclosures and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the ASU clarifies the FASB's intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. The Company is currently evaluating the provisions of ASU 2011-04 and assessing the impact, if any, it may have on the Company's financial position or results of operations.