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.

 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, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007 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, 2007, 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 of the consolidated financial statements, during the year ended December 31, 2007, Berry Petroleum Company changed the manner in which it accounts for uncertain tax positions.

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

Los Angeles, California

February 26, 2008

   

Download a Microsoft Excel version of the Income Statement, Balance Sheet and Cash Flow Statement 

 BERRY PETROLEUM COMPANY

 Balance Sheets

 December 31, 2007 and 2006

 (In Thousands, Except Share Information)

ASSETS		2007				2006
Current assets:
Cash and cash equivalents		$	316			$	416
Short-term investments			58				665
Accounts receivable			117,038				67,905
Deferred income taxes			28,547				-
Fair value of derivatives			2,109				7,349
Assets held for sale			1,394				8,870
Prepaid expenses and other			11,557				13,604
Total current assets			161,019				98,809
Oil and gas properties (successful efforts basis), buildings and equipment, net			1,275,091				1,080,631
Fair value of derivatives			-				2,356
Other assets			15,996				17,201
		$	1,452,106			$	1,198,997
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable		$	90,354			$	69,914
Property acquisition payable			-				54,400
Revenue and royalties payable			47,181				45,845
Accrued liabilities			21,653				20,415
Line of credit			14,300				16,000
Income taxes payable			2,591				-
Deferred income taxes			-				745
Other current liabilities			-				-
Fair value of derivatives			95,290				8,084
Total current liabilities			271,369				215,403
Long-term liabilities:
Deferred income taxes			128,824				103,515
Long-term debt			445,000				390,000
Abandonment obligation			36,426				26,135
Unearned revenue			398				1,437
Other long-term liabilities			1,657				-
Fair value of derivatives			108,458				34,807
			720,763				555,894
Commitments and contingencies (Note 11)
Shareholders' equity:
Preferred stock, $.01 par value, 2,000,000 shares authorized; no shares outstanding			-				-
Capital stock, $.01 par value:
Class A Common Stock, 100,000,000 shares authorized; 42,583,002 shares issued and outstanding (42,098,551 in 2006)			425				421
Class B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and outstanding (liquidation preference of $899) (1,797,784 in 2006)			18				18
Capital in excess of par value			66,590				50,166
Accumulated other comprehensive loss			(120,704	)			(19,977	)
Retained earnings			513,645				397,072
Total shareholders' equity			459,974				427,700
		$	1,452,106			$	1,198,997

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

 

 BERRY PETROLEUM COMPANY

 Statements of Income

 Years ended December 31, 2007, 2006 and 2005

 (In Thousands, Except Per Share Data)

			2007				2006				2005
REVENUES
Sales of oil and gas			$	467,400			$	430,497			$	349,691
Sales of electricity				55,619				52,932				55,230
Gain on sale of assets				54,173				97				130
Interest and other income, net				6,265				2,812				1,674
				583,457				486,338				406,725
EXPENSES
Operating costs - oil and gas production				141,218				117,624				99,066
Operating costs - electricity generation				45,980				48,281				55,086
Production taxes				17,215				14,674				11,506
Depreciation, depletion & amortization - oil and gas production				93,691				67,668				38,150
Depreciation, depletion & amortization - electricity generation				3,568				3,343				3,260
General and administrative				40,210				36,841				21,396
Interest				17,287				10,247				6,048
Commodity derivatives				-				(736)				-
Dry hole, abandonment, impairment and exploration				13,657				12,009				9,354
				372,826				309,951				243,866
Income before income taxes				210,631				176,387				162,859
Provision for income taxes				80,703				68,444				50,503
Net income			$	129,928			$	107,943			$	112, 356
Basic net income per share			$	2.95			$	2.46			$	2.55
Diluted net income per share			$	2.89			$	2.41			$	2.50
Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share)				44,075				43,948				44,082
Effect of dilutive securities:
Stock options				604				723				780
Other				227				103				118
Weighted average number of shares of capital stock used to calculate diluted net income per share				44,906				44,774				44,980
Statements of Comprehensive Income
Years Ended December 31, 2007, 2006 and 2005
(In Thousands)
Net income			$		129,928		$		107,943		$		112,356
Unrealized gains (losses) on derivatives, net of income taxes of ($66,627), $7,647, and ($16,677), respectively					(99,941	)			11,471				(25,015		)
Reclassification of realized gains (losses) on derivatives included in net income, net of income taxes of ($524), ($4,712) and $1,081, respectively					(786	)			(7,068	)			1,622
Comprehensive income			$		29,201		$		112,346		$		88,963

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

 BERRY PETROLEUM COMPANY

 Statements of Shareholders’ Equity

 Years Ended December 31, 2007, 2006 and 2005

 (In Thousands, Except Per Share Data)

 

			Class A			Class B			Capital in Excess of Par Value			Retained Earnings			Accumulated Other Comprehensive  Income (Loss)			Shareholders' Equity
Balances at January 1, 2005		$	210		$	9		$	60,676		$	203,178		$	(987	)	$	263,086
Shares repurchased and retired (217,800 shares)			(2	)		-			(6,314	)		-			-			(6,316	)
Stock-based compensation (294,358 shares)			3			-			(1,120	)		-			-			(1,117	)
Tax impact of stock option exercises			-			-			2,480			-			-			2,480
Deferred director fees - stock compensation			-			-			342			-			-			342
Cash dividends declared - $.30 per share			-			-			-			(13,228	)		-			(13,228	)
Unrealized loss on derivatives			-			-			-			-			(23,393	)		(23,393	)
Net income			-			-			-			112,356			-			112,356
Balances at December 31, 2005			211			9			56,064			302,306			(24,380	)		334,210
Two-for one stock split			211			9			(220	)		-			-			-
Shares repurchased and retired (600,200 shares)			(6	)		-			(18,713	)		-			-			(18,719	)
Stock-based compensation (498,939 shares)			5			-			9,256			-			-			9,261
Tax impact of stock option exercises			-			-			3,444			-			-			3,444
Deferred director fees - stock compensation			-			-			335			-			-			335
Cash dividends declared - $.30 per share, including RSU dividend equivalents			-			-			-			(13,177	)		-			(13,177	)
Unrealized gain on derivatives			-			-			-			-			4,403			4,403
Net income			-			-			-			107,943			-			107,943
Balances at December 31, 2006			421			18			50,166			397,072			(19,977	)		427,700
Stock-based compensation (484,451 shares)			4			-			12,930			-			-			12,934
Tax impact of stock option exercises			-			-			3,049			-			-			3,049
Deferred director fees - stock compensation			-			-			445			-			-			445
Cash dividends declared - $.30 per share, including RSU dividend equivalents			-			-			-			(13,292	)		-			(13,292	)
Cumulative effect of accounting change from adoption of FIN 48			-			-			-			(63	)		-			(63	)
Unrealized loss on derivatives			-			-			-			-			(100,727	)		(100,727	)
Net income			-			-			-			129,928			-			129,928
Balances at December 31, 2007		$	425		$	18		$	66,590		$	513,645		$	(120,704	)	$	459,974

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

 BERRY PETROLEUM COMPANY

 Statements of Cash Flows

 Years Ended December 31, 2007, 2006 and 2005

 (In Thousands)

Cash flows from operating activities:		2007				2006				2005
Net income		$	129,928			$	107,943			$	112,356
Depreciation, depletion and amortization			97,259				71,011				41,410
Dry hole and impairment			12,951				8,253				5,705
Commodity derivatives			574				(109	)			-
Stock-based compensation expense			8,200				6,436				1,703
Deferred income taxes			62,465				51,666				20,847
Gain on sale of asset			(54,173	)			(97	)			(130	)
Other, net			3,561				544				408
Cash paid for abandonment			(1,188	)			606				(1,381	)
Increase in current assets other than cash, cash equivalents and short-term investments			(47,876	)			(16,338	)			(26,717	)
Increase in current liabilities other than line of credit			36,578				13,314				33,579
Net cash provided by operating activities			248,279				243,229				187,780
Cash flows from investing activities:
Exploration and development of oil and gas properties			(281,702	)			(265,110	)			(118,718	)
Property acquisitions			(56,247	)			(257,840	)			(112,249	)
Additions to vehicles, drilling rigs and other fixed assets			(3,565	)			(21,306	)			(11,762	)
Capitalized interest			(18,104	)			(9,339	)			-
Proceeds from sale of assets			72,405				4,812				130
Net cash used in investing activities			(287,213	)			(548,783	)			(242,599	)
Cash flows from financing activities:
Proceeds from issuances on line of credit			395,150				327,250				18,000
Payments on line of credit			(396,850	)			(322,750	)			(6,500	)
Proceeds from issuance of long-term debt			229,300				569,700				144,000
Payments on long-term debt			(174,300	)			(254,700	)			(97,000	)
Dividends paid			(13,292	)			(13,177	)			(13,228	)
Book overdraft			(9,400	)			15,246				1,921
Repurchase of shares			-				(18,713	)			(6,314	)
Proceeds from stock option exercises			5,178				3,156				-
Excess tax benefit			3,049				3,444				-
Debt issuance costs			(1	)			(5,476	)			(760	)
Net cash provided by financing activities			38,834				303,980				40,119
Net decrease in cash and cash equivalents			(100	)			(1,574	)			(14,700	)
Cash and cash equivalents at beginning of year			416				1,990				16,690
Cash and cash equivalents at end of year		$	316			$	416			$	1,990
Supplemental disclosures of cash flow information:
Interest paid		$	33,945			$	15,019			$	5,275
Income taxes paid		$	6,715			$	18,148			$	26,544
Supplemental non-cash activity:
Increase (decrease) in fair value of derivatives:
Current (net of income taxes of ($36,562), $4,188, and ($3,631), respectively)		$	(54,844	)		$	6,282			$	(5,446	)
Non-current (net of income taxes of ($30,589), ($1,252), and ($11,965), respectively)			(45,883	)			(1,879	)			(17,947	)
Net increase (decrease) to accumulated other comprehensive income		$	(100,727	)		$	4,403			$	(23,393	)
Non-cash financing activity: Property acquired for debt		$	-			$	54,000			$	-

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

 BERRY PETROLEUM COMPANY

 Notes to the Financial Statements

 

1. General

We are an independent energy company engaged in the production, development, acquisition, exploitation and exploration of crude oil and natural gas. We have invested in cogeneration facilities which provide steam required for the extraction of heavy oil and which generates electricity for sale.

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.

2. Summary of Significant Accounting Policies

Cash and cash equivalents - We consider all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. Our cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at December 31, 2007 and 2006 is $7.8 million and $17.2 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

Short-term investments - Short-term investments consist principally of United States treasury notes and corporate notes with remaining maturities of more than three months at the date of acquisition and are carried at fair value. We utilize specific identification in computing realized gains and losses on investments sold.

Accounts receivable - Trade accounts receivable are recorded at the invoiced amount. We do not have any off-balance-sheet credit exposure related to our customers. We assess credit risk and allowance for doubtful accounts on a customer specific basis. As of December 31, 2007 and 2006, we do not have an allowance for doubtful accounts.

Income taxes - We compute income taxes in accordance with SFAS No. 109, Accounting for Income Taxes as interpreted by FIN 48, Accounting for Uncertainty in Income Taxes. SFAS No. 109 requires an asset and liability approach 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 our 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. FIN 48 also requires that amounts recognized in the Balance Sheet related to uncertain tax positions be classified as a current or noncurrent liability, based upon the expected timing of the payment to a taxing authority.

Derivatives - To minimize the effect of a downturn in oil and gas prices and protect our profitability and the economics of our development plans, from time to time we enter into crude oil and natural gas hedge contracts. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the Balance Sheet. Settlements are recognized on the Statements of Income under the caption “Sales of oil and gas”. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative, and the resulting designation is generally established at the inception of a derivative. For derivative contracts that do not qualify for hedge accounting under SFAS No. 133, the contracts are recorded at fair value on the Balance Sheet with the corresponding unrealized gain or loss on the Statements of Income under the caption “Commodity derivatives.” For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. The hedging relationship between the hedging instruments and hedged items, such as oil and gas, must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis. We measure hedge effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, or in the case of options based on the change in intrinsic value. A regression analysis is used to determine whether the relationship is considered to be highly effective retrospectively and prospectively. Actual effectiveness of the hedge will be calculated against the underlying cumulatively using the dollar offset method at the end of each quarter. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss, such as time value for option contracts, will be recognized immediately in the Statements of Income. Gains and losses on hedging instruments and adjustments of the carrying amounts of hedged items are included in revenues for hedges related to our crude oil and natural gas sales and in operating expenses for hedges related to our natural gas consumption. The resulting cash flows are reported as cash flows from operating activities. See Note 15 - Hedging.

Assets held for sale - We consider an asset to be held for sale when management approves and commits to a formal plan to actively market an asset for sale. Upon designation as held for sale, the carrying value of the asset is recorded at the lower of the carrying value or its estimated fair value, less costs to sell. Once an asset is determined to be “held for sale”, we no longer record DD&A on the property. We anticipate that we will dispose of certain properties or assets over time. The assets most likely for disposition will be those that do not fit or complement our strategic growth plan, that are not contributing satisfactory economic returns given the profile of the assets, or that we believe the development potential will not be meaningful to our company as a whole. Proceeds from these sales will contribute to the funding of our capital program. Net oil and gas properties and equipment classified as held for sale is $1.4 million and $8.9 million as of December 31, 2007 and 2006, respectively, in accordance with SFAS No. 144. 

Leases - We entered into two separate three year lease agreements on two company owned drilling rigs. Each agreement has a three year purchase option in favor of the lessee. The agreements were signed in 2005 and 2006 and are accounted for as direct financing leases as defined by SFAS No. 13, Accounting for Leases, and included in other long term assets on the Balance Sheet. We routinely enter into noncancelable lease agreements for premises and equipment used in the normal course of business. In addition to minimum rental payments, certain of these leases require additional payments to reimburse the lessors for operating expenses such as real estate taxes, maintenance, utilities and insurance. Rental expense is recorded on a straight-line basis.

Oil and gas properties, buildings and equipment - We account for our 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 will be 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 we are 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.

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.

In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we group assets at the field level and periodically review the carrying value of our 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. We generally measure 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 (ARO) - We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and gas production operations. The computation of our ARO is prepared in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations. Under this standard, we record the fair value of the future abandonment as capitalized abandonment costs in Oil and Gas Properties with an offsetting abandonment liability. We obtain estimates from third parties and use the present value of estimated cash flows related to the ARO to determine the fair value. The capitalized abandonment costs are amortized with other property costs using the units-of-production method. We increase the liability monthly by recording accretion expense using our credit adjusted interest rate. Accretion expense is included in DD&A in our financial statements.  

Revenue recognition - Revenues associated with sales of crude oil, natural gas, and electricity are recognized when title passes to the customer, net of royalties, discounts and allowances, as applicable. The electricity and natural gas we produce and use in our operations are not included in revenues. Revenues from crude oil and natural gas production from properties in which we have an interest with other producers are recognized on the basis of our net working interest (entitlement method).

Conventional steam costs - The costs of producing conventional steam are included in “Operating costs - oil and gas production.”

Cogeneration operations - Our investment in cogeneration facilities has been for the express purpose of lowering steam costs in our heavy oil operations and securing operating control of the respective steam generation. Such cogeneration operations produce electricity and steam. We allocate steam costs to our 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. Electricity consumption included in oil and gas operating costs for the years ended December 31, 2007, 2006 and 2005 was $5.0 million, $5.3 million and $5.7 million, respectively.

Shipping and handling costs - Shipping and handling 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 these categories were $6.7 million, $6.8 million and $5.8 million for 2007, 2006 and 2005, respectively. Additionally, the transportation costs in the Uinta basin were $1.4 million and $1.1 million in 2007 and 2006, respectively.

Production taxes - Consist primarily of severance, production and ad valorem taxes.

Stock-based compensation - We adopted SFAS No. 123(R) beginning January 1, 2006. We previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation effective January 1, 2004. The implementation of FAS123(R) did not have a material impact on us. The modified prospective method was selected as described in SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, we recognize stock option compensation expense as if we had applied the fair value method to account for unvested stock options from the original effective date. We recognize stock option compensation expense from the date of grant to the vesting date.

In accounting for the income tax benefits associated with employee exercises of share-based payments, we have elected to adopt the alternative simplified method as permitted by FASB Staff Position (“FSP”) No. FAS 123(R)-3, Accounting for the Tax Effects of Share-Based Payment Awards. FSP No. FAS 123(R)-3 permits the adoption of either the transition guidance described in SFAS No. 123(R) or the alternative simplified method specified in FSP No. FAS 123(R)-3 to account for the income tax effects of share-based payment awards. In determining when additional tax benefits associated with share-based payment exercises are recognized, we follow the ordering of deductions under the tax law, which allows deductions for share-based payment exercises to be utilized before previously existing net operating loss carryforwards. In computing dilutive shares under the treasury stock method, we do not reduce the tax benefit within the calculation for the amount of deferred tax assets.

Net income per share - Basic net income per share is computed by dividing income available to shareholders (the numerator) by the weighted average number of shares of capital stock outstanding (the denominator). Our Class B Stock is included in the denominator of basic and diluted net income. The computation of diluted net income per share is similar to the computation of basic net income per share except that the denominator is increased to include the dilutive effect of the additional common shares that would have been outstanding if all convertible securities had been converted to common shares during the period. Nonqualified stock options totaling 855,000, 499,000, and 23,000 were excluded from the calculation of diluted net income per common share for 2007, 2006 and 2005, respectively, because they were antidilutive. The assumed proceeds in the treasury stock calculation include proceeds received for the grant price and the tax windfall/shortfall amounts recognized in the financial statements.

Environmental expenditures - We review, on a quarterly basis, our estimates of costs of the cleanup of various sites, including sites in which governmental agencies have designated us as a potentially responsible party. When it is probable that obligations have been incurred and where a minimum cost or a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. Any liabilities arising hereunder are not discounted.

Subsidiaries - We have two subsidiaries which serve to gather and transport natural gas in our Lake Canyon and Brundage Canyon fields. These subsidiaries are accounted for using the equity method and our net investment in these entities is included under the caption “Other assets” on our Balance Sheet.

Accounting for business combinations - We have accounted for all of our business combinations using the purchase method, which is the only method permitted under SFAS 141, Accounting for Business Combinations. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, stock or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. We have not recognized any goodwill from any business combinations.

Capitalized interest - 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 our assets and is expensed on a units of production basis over the life of the respective project.

Recent accounting developments - In May 2005, SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 was issued. SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 became effective for our fiscal year beginning January 1, 2006. The adoption of SFAS No. 154 had no effect to our financial position and result of operations.

In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109, Accounting for Income Taxes. This interpretation requires that realization of an uncertain income tax position must be “more likely than not” (i.e. greater than 50% likelihood of receiving a benefit) before it can be recognized in the financial statements. Further, this interpretation prescribes the benefit to be recorded in the financial statements as the amount most likely to be realized assuming a review by tax authorities having all relevant information and applying current conventions. This interpretation also clarifies the financial statement classification of tax-related penalties and interest and sets forth new disclosures regarding unrecognized tax benefits. We adopted this interpretation in the first quarter of 2007. See Note 9. 

In September 2006, SFAS No. 157, Fair Value Measurements was issued by the FASB. This statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 will become effective for our fiscal year beginning January 1, 2008, and we are currently assessing the effect this statement may have on our financial statements. However, we do not believe that the implementation of SFAS 157 will have a material impact on our financial statements.

In September 2006, Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements was issued by the Securities and Exchange Commission. Registrants must quantify the impact on current period financial statements of correcting all misstatements, including both those occurring in the current period and the effect of reversing those that have accumulated from prior periods. This SAB was adopted at December 31, 2006. The adoption of SAB No. 108 had no effect on our financial position or our results of operations. 

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the Balance Sheet. This statement is effective beginning January 1, 2008 and we do not expect the Statement to have a material effect on our financial statements. 

In April 2007, the FASB issued a FASB Staff Position to amend FASB Interpretation 39, Offsetting of Amounts Related to Certain Contracts. FIN 39-1 states that a reporting entity that is party to a master netting arrangement can offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with paragraph 10 of Interpretation 39. FIN 39-1 will become effective for our fiscal year beginning January 1, 2008, and will have no effect on our financial statements, as we do not post collateral under our hedging agreements.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS 160 was issued to establish accounting and reporting standards for the noncontrolling interest in a subsidiary (formerly called minority interests) and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. We do not expect the adoption of SFAS 160 to have a material effect on our financial statements and related disclosures. The effective date of this Statement is the same as that of the related Statement 141(R).

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which improves the information that a reporting entity provides in its financial reports about a business combination and its effects. This Statement establishes principles and requirements for how the acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. We may experience a financial statement impact depending on the nature and extent of any new business combinations entered into after the effective date of SFAS No. 141(R).

3. Fair Value of Financial Instruments

Cash equivalents consist principally of commercial paper investments. Cash and equivalents of $.3 million and $.4 million at December 31, 2007 and 2006, respectively, are stated at cost, which approximates market.

Our short-term investments available for sale at December 31, 2007 and 2006 consist of United States treasury notes that mature in less than one year and are carried at fair value. For the three years ended December 31, 2007, realized and unrealized gains and losses of our short-term investments were insignificant to the financial statements. The fair value of our long-term senior subordinated notes is approximately $204.5 million and the carrying value of the remainder of our long-term debt approximates fair value.

4. Concentration of Credit Risks

We sell oil, gas and natural gas liquids to pipelines, refineries and oil companies and electricity to utility companies. Credit is extended based on an evaluation of the customer’s financial condition and historical payment record. 

On November 21, 2005, we entered into a new crude oil sales contract with an independent refiner for substantially all of our California production for deliveries beginning February 1, 2006.

On February 27, 2007, we entered into a multi-staged crude oil sales contract with a refiner for our Uinta basin crude oil. Under the agreement, the refiner began purchasing 3,200 gross Bbl/D beginning July 1, 2007. Upon completion of its refinery expansion in Salt Lake City, which is expected in the first half of 2008, the refiner will increase their total purchased volumes to 5,000 Bbl/D through June 30, 2013. Pricing under the contract, including transportation, is at a fixed percentage of WTI, which was near the posted price at the contract’s starting date.

For the three years ended December 31, 2007, we have experienced no credit losses on the sale of oil, natural gas, natural gas liquids or on hedging contracts. We place our temporary cash investments with high quality financial institutions and limit the amount of credit exposure to any one financial institution. For the three years ended December 31, 2007, we have not incurred losses related to these investments. While a significant portion of our hedges are with one counterparty, we utilize multiple counterparties and monitor each counterparty’s credit rating.

The following summarizes the accounts receivable balances at December 31, 2007 and 2006 and sales activity with significant customers for each of the years ended December 31, 2007, 2006 and 2005 (in thousands). We do not believe that the loss of any one customer would impact the marketability, but may impact the profitability of our crude oil, gas, natural gas liquids or electricity sold. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the crude oil sales customer could impact the marketability of a portion of our Utah crude oil volumes.

		Accounts Receivable						Sales before hedging and royalties
		As of December 31,						For the Year Ended December 31,
Customer		2007			2006			2007			2006			2005
Oil & Gas Sales:
A		$	5,347		$	-		$	39,791		$	-		$	-
B			-			2,732			20,239			75,597			81,342
C			5,793			2,980			28,170			10,458			-
D			44,450			28,768			404,038			305,587			-
E			-			-			18,000			21,317			-
		$	55,590		$	34,480		$	510,238		$	412,959		$	81,342
Electricity Sales:
F		$	1,979		$	4,279		$	26,033		$	24,335		$	24,391
G			2,573			5,658			29,470			28,597			30,893
		$	4,552		$	9,937		$	55,503		$	52,932		$	55,284

Sales amounts will not agree to the Statements of Income due primarily to the effects of hedging and price sensitive royalties paid on a portion of our crude oil sales, which are netted in “Sales of oil and gas” on the Statements of Income.

5. Oil and Gas Properties, Buildings and Equipment

Oil and gas properties, buildings and equipment consist of the following at December 31 (in thousands):

Oil and gas:		2007				2006
Proved properties:
Producing properties, including intangible drilling costs		$	869,176			$	649,928
Lease and well equipment (1)			448,100				358,392
			1,317,276				1,008,320
Unproved properties
Properties, including intangible drilling costs			285,823				309,959
Lease and well equipment			-				25
			285,823				309,984
			1,603,099				1,318,304
Less accumulated depreciation, depletion and amortization			350,604				258,466
			1,252,495				1,059,838
Commercial and other:
Land			810				774
Drilling rigs and equipment			12,443				10,478
Buildings and improvements			5,407				5,596
Machinery and equipment			18,525				16,025
			37,185				32,873
Less accumulated depreciation			14,589				12,080
			22,596				20,793
		$	1,275,091			$	1,080,631
(1) Includes cogeneration facility costs.

In February 2006, we closed on an agreement with a private seller to acquire a 50% working interest in natural gas assets in the Piceance basin of western Colorado for approximately $159 million. The acquisition was funded under our existing credit facility. We purchased 100% of Piceance Operating Company LLC (which owned a 50% working interest in the acquired assets). The total purchase price was allocated as follows: $30 million to proved reserves and $129 million to unproved properties. Allocation was made based on fair value. The historical operating activities of these oil and gas assets are insignificant compared to our historical operations, and therefore we have not included proforma disclosures. Piceance Operating Company LLC was dissolved subsequent to the acquisition.

In June 2006, we entered into an agreement with a party to jointly develop the North Parachute Ranch property in the Grand Valley field of the Piceance basin of western Colorado. We estimate we will pay up to $153 million to fund the drilling of 90 natural gas wells on the joint venture partner’s acreage. The maximum amount of cost charged to us will not exceed $1.7 million per well. If any wells are drilled for less than $1.7 million, the excess will be returned to us. In exchange for our payments of up to $153 million, we will earn a 5% working interest (4% net revenue interest) on each of the 90 wellbores and a net working interest of 95% (79% net revenue interest) in 4,300 gross acres located elsewhere on the property. The costs of drilling and development on the 4,300 gross acres will be shared by the partners in relation to the working interests. The $153 million payment was allocated to unproved properties based on the fair value of the 5% and 95% working interests.

In July 2006, we paid $51 million, the first installment of the total $153 million, and thereby earned the assignment of the 4,300 gross acres. In November 2006, we paid the second installment of approximately $48 million. We paid the third and final installment of approximately $54 million in May 2007. Prior to February 2011, we are required to drill 120 wells, bearing 95% of the cost, on our 4,300 gross acres and if not met, then we are required to pay $.2 million for each well less than 120 drilled. Additionally, if we have not drilled at least one well by mid-2011 in each 160 acre tract within the 4,300 gross acres, then that specific undrilled 160 acre tract shall be reassigned to the joint venture partner. As of the date of the agreement there were no operating activities from these gas assets.

In January 2005, we acquired certain interests in the Niobrara field of the DJ basin in northeastern Colorado for approximately $105 million to increase natural gas reserves and production. Assets purchased include $93 million of gas properties, $6 million of pipeline, and $5 million of compression equipment. Liabilities assumed included $1 million of asset retirement obligations.

The pro forma results presented below for the year ended December 31, 2005 have been prepared to report the effect on our results of operations under the purchase method of accounting as if it had been consummated on January 1, 2005. The pro forma results do not purport to represent the results of operations that actually would have occurred on such date or to project our results of operations for any future date or period. The following shows the results (in thousands, except per share data):

			2005
Proforma Revenue			$ 408,088
Proforma Income from operations			190,970
Proforma Net income			112,660
Proforma Basic earnings per share			5.11
Proforma Diluted earnings per share			5.01

Suspended Well Costs

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period of greater than one year since the completion of drilling (in thousands, except number of projects):

		2007				2006				2005
Capitalized exploratory well costs that have been capitalized for a period of one year or less		$	6,826			$	89			$	6,037
Capitalized exploratory well costs that have been capitalized for a period greater than one year			-				-				-
Balance at December 31		$	6,826			$	89			$	6,037
Number of projects that have exploratory well costs that have been capitalized for a period of greater than one year			-				-				-

The following table reflects the net changes in capitalized exploratory well costs (in thousands):

		2007				2006				2005
Beginning balance at January 1		$	89			$	6,037			$	3,452
Additions to capitalized exploratory well costs pending the determination of proved reserves			6,826				6,682				8,840
Reclassifications to wells, facilities and equipment based on the determination of proved reserves			-				(4,377	)			(3,369	)
Capitalized exploratory well costs charged to expense			(89	)			(8,253	)			(2,886	)
Ending balance at December 31		$	6,826			$	89			$	6,037

Dry hole, abandonment and impairment and asset sales

In 2007 we had dry hole, abandonment, impairment and exploration charges of $13.7 million that consisted primarily of a $4.6 million writedown a portion of our Tri-State acreage in connection with the current and pending sale of these properties, a $3.3 million impairment of our Coyote Flats prospect to reflect its fair value in conjunction with the preparation of our year end reserve estimates, a $2.9 million writedown of our Bakken properties which were sold in September 2007, geological and geophysical costs of $.7 million and other dry hole charges of $2.2 million.

In 2006, there was $8.3 million of dry hole, abandonment and impairment charges that consisted primarily of two Coyote Flats, Utah wells for $5.2 million, our 25% share in an exploration well located in the Lake Canyon project area of the Uinta basin drilled for approximately $1.6 million net to our interest and four wells in Bakken and four wells in the DJ basin for $1.5 million. For the year ended 2005, costs of $5.7 million were incurred on the following: one exploratory well on the Coyote Flats prospect, one well on the Midway-Sunset property, two exploratory wells at northern Brundage Canyon in the Uinta basin, and an impairment charge of $2.5 million on the remaining carrying value of our Illinois and eastern Kansas prospective CBM acreage were charged to expense.

In May 2007, we sold our non-core West Montalvo assets in Ventura County, California. The sale proceeds were approximately $61 million and we recognized a $52 million pretax gain on the sale, including post closing adjustments. We completed the sale of a portion of our Tri-State acreage during the fourth quarter of 2007 and have classified $1.4 million as held for sale at December 31, 2007 which reflects additional acreage that we plan to sell in the first quarter of 2008 in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets 

6.  Long-term and Short-term Debt Obligations

Short-term debt

In November 2005, we completed a new unsecured uncommitted money market line of credit (Line of Credit). Borrowings under the Line of Credit may be up to $30 million for a maximum of 30 days. The Line of Credit may be terminated at any time upon written notice by either us or the lender. At December 31, 2007 the outstanding balance under this Line of Credit was $14.3 million. Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1%. The weighted average interest rate on outstanding borrowings on the Line of Credit at December 31, 2007 and 2006 was 5.7% and 7.3%, respectively.

Long-term debt

In October 2006, we issued in a public offering $200 million of 8.25% senior subordinated notes due 2016. The deferred costs of approximately $5 million associated with the issuance of this debt are being amortized over the ten year life of the bonds. The net proceeds from the offering were used to 1) repay approximately $145 million of borrowings under the bank credit facility, which were $170 million as of the issuance date after the application of this payment, and 2) approximately $50 million was used to finance the November 2006 installment under the joint venture agreement to develop properties in the Piceance basin.

In April 2006, we completed a new unsecured five-year bank credit agreement (the Agreement) with a banking syndicate and extended the term by one year to July 2011. The Agreement is a revolving credit facility for up to $750 million and replaces the previous $500 million facility. The current borrowing base was established at $500 million, as compared to the previous $350 million. In 2007, we increased our borrowing base from $500 to $550 million. This transaction was accounted for in accordance with Emerging Issues Task Force, (EITF) 98-14, Debtor’s Accounting for Changes in Line-of-Credit or Revolving-Debt Arrangements.

The total outstanding debt under the credit facility’s borrowing base and line of credit was $259 million at December 31, 2007, leaving $291 million in borrowing capacity available. Interest on amounts borrowed under this debt is charged at LIBOR plus a margin of 1.00% to 1.75% or the prime rate, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. We are required under the Agreement to pay a commitment fee of .25% to .375% on the unused portion of the credit facility annually.

The maximum amount available is subject to an annual redetermination of the borrowing base in accordance with the lender's customary procedures and practices. Both we and the banks have bilateral rights to one additional redetermination each year.

The Agreement contains restrictive covenants which, among other things, require us to maintain a certain debt to EBITDA ratio and a minimum current ratio, as defined. The bond indebtedness of $200 million is subordinated to our credit facility indebtedness. Our bond indebtedness covenant limits debt to the greater of $750 million or 40% of Adjusted Consolidated Net Tangible Assets (as defined), which is estimated to be over $1 billion as of December 31, 2007. Additionally, as long as the interest coverage ratio (as defined) is met, we may incur additional debt. We were in compliance with all such covenants as of December 31, 2007. The weighted average interest rate on total long-term outstanding borrowings at December 31, 2007 and 2006 was 6.9% and 6.2%, respectively.

Additionally, in June 2006 and July 2006 we entered into five year interest rate swaps for a fixed rate of approximately 5.5% on $100 million of our outstanding borrowings under our credit facility for five years. These interest rate swaps have been designated as cash flow hedges.

7. Shareholders’ Equity

In March 2006, our Board of Directors approved a two-for-one stock split to shareholders of record on May 17, 2006, subject to obtaining shareholder approval of an increase in our authorized shares. On May 17, 2006 our shareholders approved the authorized share increase and in June 2006 each shareholder received one additional share for each share in the shareholder's possession on May 17, 2006. This did not change the proportionate interest a shareholder maintained in Berry Petroleum Company on May 17, 2006. All historical shares, equity awards and per share amounts have been restated for the two-for-one stock split.

Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock," are each entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $.50 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder.

In June 2005, we announced that our Board of Directors authorized a share repurchase program for up to an aggregate of $50 million of our outstanding Class A Common Stock. From June 2005 through December 31, 2007, we repurchased 818,000 shares in the open market for approximately $25 million. Our repurchase plan expired and no shares were repurchased in 2007.

Dividends

Our regular annual dividend is currently $.30 per share, payable quarterly in March, June, September and December. We paid a special dividend of $.02 per share on September 29, 2006 and increased our regular quarterly dividend by 15%, from $.065 to $.075 per share beginning with the September 2006 dividend.

Dividend payments are limited by covenants in our 1) credit facility to the greater of $20 million or 75% of net income, and 2) bond indenture of up to $20 million annually irrespective of our coverage ratio or net income if we have exhausted our restricted payments basket, and up to $10 million in the event we are in a non-payment default.

Shareholder Rights Plan

In November 1999, we adopted a Shareholder Rights Agreement and declared a dividend distribution of one Right for each outstanding share of Capital Stock on December 8, 1999. Each Right, when exercisable, entitles the holder to purchase one one-hundredth of a share of a Series B Junior Participating Preferred Stock, or in certain cases other securities, for $19.00. The exercise price and number of shares issuable are subject to adjustment to prevent dilution. The Rights would become exercisable, unless earlier redeemed by us 10 days following a public announcement that a person or group has acquired, or obtained the right to acquire, 20% or more of the outstanding shares of Common Stock, or 10 business days following the commencement of a tender or exchange offer for such outstanding shares which would result in such person or group acquiring 20% or more of the outstanding shares of Common Stock, either event occurring without the prior consent of us.

The Rights will expire on December 8, 2009 or may be redeemed by us at $.005 per Right prior to that date, unless they have theretofore become exercisable. The Rights do not have voting or dividend rights, and until they become exercisable, have no diluting effect on our earnings. A total of 500,000 shares of our Preferred Stock has been designated Series B Junior Participating Preferred Stock and reserved for issuance upon exercise of the Rights.

8. Asset Retirement Obligations

Inherent in the fair value calculation of 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. In 2007, we reassessed our estimate as costs have increased due to demand for these services, resulting in an increase in the ARO balance at year end.

Under SFAS 143, the following table summarizes the change in abandonment obligation for the years ended December 31 (in thousands):

		2007				2006
Beginning balance at January 1		$	26,135			$	10,675
Liabilities incurred			4,191				5,711
Liabilities settled			(2,121	)			(862	)
Revisions in estimated liabilities			5,779				9,176
Accretion expense			2,442				1,435
Ending balance at December 31		$	36,426			$	26,135

9. Income Taxes

The provision for income taxes consists of the following (in thousands):

		2007				2006				2005
Current:
Federal		$	12,939			$	12,231			$	22,666
State			5,299				4,547				6,990
			18,238				16,778				29,656
Deferred:
Federal			53,321				44,205				20,640
State			9,144				7,461				207
			62,465				51,666				20,847
Total		$	80,703			$	68,444			$	50,503

The following table summarizes the components of the total deferred tax assets and liabilities before financial statement offsets. The components of the net deferred tax liability consist of the following at December 31 (in thousands):

		2007				2006
Deferred tax asset:
Federal benefit of state taxes		$	8,391			$	4,248
Credit carryforwards			33,588				33,338
Stock option costs			6,716				3,989
Derivatives			80,469				13,275
Other, net			3,010				3,450
			132,174				58,300
Deferred tax liability:
Depreciation and depletion			(232,451	)			(162,560	)
Net deferred tax liability		$	(100,277	)		$	(104,260	)

At December 31, 2007, our net deferred tax assets and liabilities were recorded as a current asset of $28.5 million and a long-term liability of $128.8 million. At December 31, 2006, our net deferred tax assets and liabilities were recorded as a current liability of $.7 million and a long-term liability of $103.5 million.

Reconciliation of the statutory federal income tax rate to the effective income tax rate follows:

			2007			2006			2005
Tax computed at statutory federal rate			35	%		35	%		35	%
State income taxes, net of federal benefit			5			5			3
Tax credits			-			-			(7	)
Other			(2	)		(1	)		-
Effective tax rate			38	%		39	%		31	%

We have approximately $24 million of federal and $18 million of state (California) EOR tax credit carryforwards available to reduce future income taxes. The EOR credits will begin to expire, if unused, in 2024 and 2015 for federal and California purposes, respectively.

In June 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109, Accounting for Income Taxes. The Interpretation addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN No. 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

We adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no material adjustment to retained earnings. As of December 31, 2007, we had a gross liability for uncertain tax benefits of $12 million of which $9.1 million, if recognized, would affect the effective tax rate. We recognize potential accrued interest and penalties related to unrecognized tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. As of December 31, 2007, we had accrued approximately $1.1 million of interest related to our uncertain tax positions. The current portion of income taxes payable decreased from a prepaid amount of $3.6 million at year end 2006 to a $2.6 million liability at December 31, 2007. Approximately $1.6 million related to the reclassification of tax uncertain tax positions for which a cash tax payment is not expected to be made in the next twelve months to other noncurrent liabilities in accordance with FIN No. 48.

Due to the uncertainty about the periods in which examinations will be completed and limited information related to current audits, we are not able to make reasonably reliable estimates of the periods in which cash settlements will occur with taxing authorities for the noncurrent liabilities.

For the year ended December 31, 2007 we recognized a net benefit of approximately $.6 million to the Statements of Income due to the closure of certain federal and state tax years, offset by additional FIN 48 accruals net of interest expense of approximately $.2 million.

The following table illustrates changes in our gross unrecognized tax benefits (in millions):

		2007
Unrecognized tax benefits at January 1, 2007		$	14.6
Increases for positions taken in current year			.5
Decreases for positions taken in a prior year			(.3	)
Decreases for settlements with taxing authorities			-
Decreases for lapses in the applicable statute of limitations			(2.8	)
Unrecognized tax benefits at December 31, 2007		$	12.0

As of December 31, 2007, we remain subject to examination in the following major tax jurisdictions for the tax years indicated below:

Jurisdiction:	Tax Years Subject to Exam:
Federal	2004 – 2006
California	2003 – 2006
Colorado	2003 – 2006
Utah	2004 – 2006

10. Leases Receivable

We entered into two separate three year lease agreements on two company owned drilling rigs. Each agreement has a three year purchase option in favor of the lessee. The agreements were signed in 2005 and 2006, respectively. The total net investment in these rigs is approximately $8.8 million at December 31, 2007. Both agreements are accounted for as direct financing leases as defined by SFAS No. 13, Accounting for Leases. Net investment in both leases are included in the Balance Sheet as other assets and as of December 31, 2007 are as follows (in thousands):

Net minimum lease payments receivable		$	10,236
Unearned income			(1,437	)
Net investment in direct financing lease		$	8,799

As of December 31, 2007, estimated future minimum lease payments, including the purchase option, to be received are as follows (in thousands):

2008		$	4,545
2009			5,752
Total		$	10,297

11. Commitments and Contingencies

We have no accrued environmental liabilities for our sites, including sites in which governmental agencies have designated us as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not result in substantial costs incurred. We are involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of our business. In the opinion of management, the resolution of these matters will not have a material effect on our financial position, or on the results of our operations or liquidity.

During the California energy crisis in 2000 and 2001, we had electricity sales contracts with various utilities and a portion of the electricity prices paid to us under such contracts from December, 2000 to March 27, 2001 has been under a degree of legal challenge since that time.  It is possible that we may have a liability pending the final outcome of the CPUC proceeding on the matter.   We believe that any resolution of such dispute should be immaterial to us.

Our contractual obligations not included in our Balance Sheet as of December 31, 2007 are as follows (in thousands):

			Total		2008		2009		2010		2011		2012		Thereafter
Operating lease obligations			12,407		1,690		1,374		1,357		1,357		1,357		5,272
Drilling and rig obligations			74,749		23,559		18,817		7,353		25,020		-		-
Firm natural gas transportation contracts			173,243		15,206		19,545		19,544		19,545		19,054		80,349
Total		$	260,399	$	40,455	$	39,736	$	28,254	$	45,922	$	20,411	$	85,621

Operating leases - We lease corporate and field offices in California, Colorado and Texas. Rent expense with respect to our lease commitments for the years ended December 31, 2007, 2006 and 2005 was $1.5 million, $1 million and $.6 million, respectively. In 2006, we purchased an airplane for business travel which was subsequently sold and contracted under a ten year operating lease beginning December 2006.

Drilling obligations - Starting in 2006, we began to participate in the drilling of over 16 gross wells on our Lake Canyon prospect over the four year contract. Our minimum obligation under our exploration and development agreement is $9.6 million, and as of December 31, 2007 the remaining obligation is $5.4 million. Also included above, under our June 2006 joint venture agreement in the Piceance basin, we are required to have 120 wells drilled by February 2011 to avoid penalties of $.2 million per well or a maximum of $24 million. As of December 31, 2007 we have drilled 12 of these wells.

Drilling rig obligations - We are obligated in operating lease agreements for the use of multiple drilling rigs.

Firm natural gas transportation - We have one firm transportation contract which provides us additional flexibility in securing our natural gas supply for California operations. This allows us to potentially benefit from lower natural gas prices in the Rocky Mountains compared to natural gas prices in California. We have seven long-term transportation contracts on four different pipelines to provide us with physical access to move gas from our producing areas to various markets.

Other obligations. On February 27, 2007, we entered into a multi-staged crude oil sales contract with a refiner for our Uinta basin light crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D on July 1, 2007. Upon completion of its refinery expansion in Salt Lake City, which is expected in the first half of 2008, the refiner will increase their total purchased volumes to 5,000 Bbl/D through June 30, 2013. Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI, which was near the posted price at the contract’s starting date.

12. Equity Compensation Plans

In December 1994, our Board of Directors adopted the Berry Petroleum Company 1994 Stock Option Plan which was restated and amended in December 1997 and December 2001 (the 1994 Plan or Plan) and approved by the shareholders in May 1998 and May 2002, respectively. The 1994 Plan provided for the granting of stock options to purchase up to an aggregate of 3,000,000 shares of Common Stock. All options, with the exception of the formula grants to non-employee Directors, were granted at the discretion of the Compensation Committee and the Board of Directors. The term of each option did not exceed ten years from the date the options were granted. The 1994 Plan expired in December 2004, and the shareholders approved a new equity incentive plan in May 2005.

The 2005 Equity Incentive Plan (the 2005 Plan), approved by the shareholders in May 2005, provides for granting of equity compensation up to an aggregate of 2,900,000 shares of Common Stock. All equity grants are at market value on the date of grant and at the discretion of the Compensation Committee or the Board of Directors. The term of each grant did not exceed ten years from the grant date, and vesting has generally been at 25% per year for 4 years or 100% after 3 years. The 2005 Plan also allows for grants to non-employee Directors. The grants made to the non-employee Directors vest immediately. We generally use a broker for issuing new shares upon option exercise.

We adopted SFAS No. 123(R) to account for our stock option plan beginning January 1, 2006. This standard requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. We previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation effective January 1, 2004. The modified prospective method was selected as described in SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, we recognized stock option compensation expense as if it had applied the fair value method to account for unvested stock options from its original effective date. Total compensation cost recognized in the Statements of Income was $8.4 million, $6.1 million and $2.9 million in 2007, 2006 and 2005, respectively. The tax benefit related to this compensation cost was $3.3 million, $2.4 million and $1.2 million in 2007, 2006 and 2005, respectively.

Stock Options

During 2007, each of the non-employee Directors received 3,956 options at the market value on the date of grant. The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model that uses the assumptions noted in the following table. Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercises and employee terminations within the valuation model; separate groups of recipients that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding; the range given below results from certain groups of recipients exhibiting different exercise behavior. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.

	2007		2006		2005
Expected volatility	32% - 33%		32% - 33%		28% - 32%
Weighted-average volatility	33%		32%		32%
Expected dividends	1%		.8% - 1.0%		.92% - 1.3%
Expected term (in years)	4.9 - 5.6		5.3 - 5.5		4 - 5
Risk-free rate	3.4% - 4.7%		4.5% - 4.8%		3.8% - 4.4%

The following table summarizes information related to stock options outstanding and exercisable as of December 31, 2007:

							Weighted						Weighted
					Weighted		Average				Weighted		Average
Range of					Average		Remaining				Average		Remaining
Exercise			Options		Exercise		Contractual		Options		Exercise		Contractual
Prices			Outstanding		Price		Life		Exercisable		Price		Life
$6.00 - $15.50			728,900		$ 10.29		5.3		678,900		$ 9.98		5.21
$15.51 - $25.00			571,450		21.60		6.9		402,950		21.61		6.91
$25.01 - $34.50			999,801		31.81		8.5		431,326		31.46		8.40
$34.51 - $44.00			227,115		43.36		9.9		45,604		42.38		9.55
Total			2,527,266		$ 24.33		7.3		1,558,780		$ 19.88		6.66

 Weighted average option exercise price information for the years ended December 31 is as follows:

		2007				2006				2005
Outstanding at January 1		$	20.97			$	16.76			$	12.70
Granted during the year			43.40				32.82				29.56
Exercised during the year			12.52				10.83				8.40
Cancelled/expired during the year			22.88				19.11				18.68
Outstanding at December 31			24.33				20.97				16.76
Exercisable at December 31			19.88				16.24				12.31

The following is a summary of stock option activity for the years ended December 31 is as follows:

		2007				2006				2005
Balance outstanding, January 1			2,859,836				3,110,826				3,131,250
Granted			220,115				604,050				598,926
Exercised			(444,216	)			(526,990	)			(605,200	)
Canceled/expired			(108,469	)			(328,050	)			(14,150	)
Balance outstanding, December 31			2,527,266				2,859,836				3,110,826
Balance exercisable at December 31			1,558,780				1,493,067				1,423,076
Available for future grant			988,798				1,279,344				2,159,174
Weighted average remaining contractual life (years)			7.3				8				8
Weighted average fair value per option granted during the year based on the Black-Scholes pricing model		$	13.88			$	11.27			$	9.58

As of December 31, 2007, there was $8.1 million of total unrecognized compensation cost related to stock options granted under the Plan. This cost is expected to be recognized over a weighted-average period of 1.6 years. The tax benefit realized from stock options exercised during the year ended December 31, 2007, 2006 and 2005 is $3.5 million, $4.3 million and zero, respectively.

		Stock Options
		Year ended
		December 31, 2007				December 31, 2006				December 31, 2005
Weighted average fair value per option granted during the year based on the Black-Scholes pricing model		$	13.88			$	11.27			$	9.58
Total intrinsic value of options exercised (in millions)			11.9				11.8				12.6
Total intrinsic value of options outstanding (in millions)			50.8				29.8				36.8
Total intrinsic value of options exercisable (in millions)			38.3				22.3				26.2

12. Equity Compensation Plans (Cont’d)

Restricted Stock Units

Under the 2005 Equity Plan, we began a long-term incentive program whereby restricted stock units (RSUs) are available for grant to certain employees and non-employee Directors. Granted RSUs generally vest at either 25% per year over 4 years or 100% after 3 years. Unearned compensation under the restricted stock award plan is amortized over the vesting period. During 2007, each of the non-employee Directors received 1,319 RSUs. The RSUs granted to the non-employee Directors are 100% vested at date of grant but are subject to a deferral election before the corresponding shares are issued of a minimum of four years or until they leave the Board of Directors or upon change of control. We pay cash compensation on the RSUs in an equivalent amount of actual dividends paid on a per share basis of our outstanding common stock.

The following is a summary of RSU activity for the year ended December 31, 2007:

			RSUs			Weighted Average Intrinsic Value at Grant Date			Weighted Average Contractual Life Remaining
Balance outstanding, January 1			459,155		$	31.59			3.3 years
Granted			159,779			42.36
Converted			(64,633	)		31.80
Canceled/expired			(47,378	)		32.93
Balance outstanding, December 31			506,923		$	34.84			2.7 years

 

					RSUs Year ended
			December 31, 2007		December 31, 2006	December 31, 2005
Weighted-average grant date fair value of RSUs issued			$ 42.36		$ 31.86	$ 30.65
Total value of RSUs vested (in millions)			2.1		1.0	-
Total value of RSUs outstanding (in millions)			17.6		14.2	4.1

The total compensation cost related to nonvested awards not yet recognized on December 31, 2007 is $12.7 million and the weighted average period over which this cost is expected to be recognized is 1.6 years.

 

13. 401(k) Plan

We sponsor a defined contribution thrift plan under section 401(k) of the Internal Revenue Code to assist all employees in providing for retirement or other future financial needs. In December 2005, the 401(k) Plan was amended whereby effective January 1, 2006, our matching contribution is $1.00 for each $1.00 contributed by the employee up to 8% of an employee's eligible compensation. Prior to January 1, 2006, the employer match ranged from $1.00 to $1.50 for each $1.00 contributed by the employee up to 6% of an employee’s eligible compensation. The employer match amount was based on the achievement of certain monthly profit levels. Our contributions to the 401(k) Plan were $1.4 million, $1.2 million and $1.1 million for 2007, 2006 and 2005, respectively. Employees are eligible to participate in the 401(k) Plan on their date of hire and approximately 96% of our employees participated in the 401(k) Plan in 2007.

14. Director Deferred Compensation Plan

We established a non-employee director deferred stock and compensation plan to permit eligible directors, in recognition of their contributions to us, to receive fees as compensation and to defer recognition of their compensation in whole or in part to a Stock Unit Account or an Interest Account. When the eligible director ceases to be a director, the distribution from the Stock Unit Account shall be made in shares using an established market value date. The distribution from the Interest Account shall be made in cash. The aggregate number of shares which may be issued to eligible directors under the plan shall not exceed 500,000, subject to adjustment for corporate transactions that change the amount of outstanding stock. The plan may be amended at any time, but not more than once every six months, by the Compensation Committee or the Board of Directors. Shares earned and deferred in accordance with the plan as of December 31, 2007, 2006 and 2005 were 12,866, 13,387 and 13,770, respectively.

Amounts allocated to the Stock Unit Account have the right to receive an amount equal to the dividends per share we declare as applicable. The dividend payment date and this “dividend equivalent” shall be treated as reinvested in an additional number of units and credited to their account using an established market value date. Amounts allocated to the Interest Account are credited with interest at an established interest rate.

15. Hedging

From time to time we enter into crude oil and natural gas hedge contracts, the terms of which depend on various factors, including management’s view of future crude oil and natural gas prices and our future financial commitments. This hedging program is designed to moderate the effects of a severe crude oil price downturn and protect certain operating margins in our California operations. Currently, the hedges are in the form of swaps and collars, however we may use a variety of hedge instruments in the future. Management regularly monitors the crude oil and natural gas markets and our financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging or other price protection is appropriate. All of these hedges have historically been deemed to be cash flow hedges with the marked-to-market valuations provided by external sources, based on prices that are actually quoted.

The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. While a significant portion of our hedges are with one counterparty, we utilize multiple counterparties and monitor each counterparty’s credit rating. We are not required to issue collateral on these hedging transactions.

We entered into derivative contracts (natural gas swaps and collar contracts) in March 2006 that did not qualify for hedge accounting under SFAS 133 because the price index for the location in the derivative instrument did not correlate closely with the item being hedged. These contracts were recorded in 2006 at their fair value on the Balance Sheet and we recognized an unrealized net loss of approximately $4.8 million on the Statements of Income under the caption “Commodity derivatives.” We entered into natural gas basis swaps on the same volumes and maturity dates as the previous hedges in May 2006 which allowed for these derivatives to be designated as cash flow hedges going forward. We recognized an unrealized net gain of $5.6 million in 2006. The net gain of $.8 million was recorded in other accumulated comprehensive income at the date the hedges were designated and will be amortized to revenue as the related sales occur.

Additionally, in June 2006 and July 2006 we entered into five year interest rate swaps for a fixed rate of approximately 5.5% on $100 million of our outstanding borrowings under our credit facility for five years. These interest rate swaps have been designated as cash flow hedges.

The related cash flow impact of all of our derivative activities are reflected as cash flows from operating activities. At December 31, 2007, our net fair value of derivatives liability was $201.6 million as compared to $33.2 million at December 31, 2006. Based on NYMEX strip pricing as of December 31, 2007, we expect to make hedge payments under the existing derivatives of $94.3 million during the next twelve months. At December 31, 2007 and 2006, Accumulated Other Comprehensive Loss consisted of $120.7 million and $20 million, respectively, net of tax, of unrealized losses from our crude oil and natural gas swaps and collars that qualified for hedge accounting treatment at December 31, 2007. Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2007 and subsequent marked-to-market changes in the underlying hedging contracts are expected to be reclassified to earnings over the life of these contracts.

16. Master Limited Partnership

On October 22, 2007, we announced plans to form a master limited partnership (MLP) with an initial public offering of common units representing limited partner interests in the MLP. Our previously announced plans to proceed with a master limited partnership for certain of our assets is currently on hold due to the unfavorable capital market conditions.

17. Related Party Transaction

In December 2007, we accepted a tender issued by Bakersfield Fuel & Oil Company (BFO) to purchase all of our 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 in 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.

18. Quarterly Financial Data (unaudited)

The following is a tabulation of unaudited quarterly operating results for 2007 and 2006 (in thousands, except per share data).

						Income								Basic Net				Diluted Net
		Operating				Before				Net				Income				Income
2007		Revenues				Taxes				Income				Per Share				Per Share
First Quarter		$	116,369			$	31,149			$	18,855			$	.43			$	.42
Second Quarter			127,293				85,778				51,957				1.18				1.16
Third Quarter			130,974				42,273				26,855				.61				.60
Fourth Quarter			148,383				51,431				32,261				.73				.71
		$	523,019			$	210,631			$	129,928			$	2.95			$	2.89
2006
First Quarter		$	117,101			$	38,084			$	23,251			$	.53			$	.52
Second Quarter			122,356				57,197				34,203				.78				.76
Third Quarter			128,760				50,477				31,374				.71				.70
Fourth Quarter			115,212				30,629				19,115				.44				.43
		$	483,429			$	176,387			$	107,943			$	2.46			$	2.41

Supplemental Information About Oil & Gas Producing Activities (Unaudited)

The following sets forth costs incurred for oil and gas property acquisition, development and exploration activities, whether capitalized or expensed (in thousands):

Property acquisitions (1)		2007				2006				2005
Proved properties		$	-			$	33,390			$	97,348
Unproved properties			56,247				224,450				24,566
Development (2)			278,398				277,613				112,255
Exploration (3)			23,325				22,435				11,310
		$	357,970			$	557,888			$	245,479

The following sets forth results of operations from oil and gas producing and exploration activities (in thousands):

		2007				2006				2005
Sales to unaffiliated parties		$	467,400			$	430,497			$	349,691
Production costs			(158,433	)			(132,298	)			(110,572	)
Depreciation, depletion and amortization			(93,691	)			(67,668	)			(38,150	)
Dry hole, abandonment, impairment and exploration			(13,657	)			(12,009	)			(9,354	)
			201,619				218,522				191,615
Income tax expense			(77,250	)			(85,970	)			(57,872	)
Results of operations from producing and exploration activities		$	124,369			$	132,552			$	133,743

The following estimates of proved oil and gas reserves, both developed and undeveloped, represent our owned interests located solely within the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.

The following disclosures of oil and gas reserves are based on estimates prepared by independent engineering consultants as of December 31, 2007, 2006 and 2005. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves. The information provided does not represent management's estimate of our expected future cash flows or value of proved oil and gas reserves.

Changes in estimated reserve quantities

The net interest in estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas at December 31, 2007, 2006 and 2005, and changes in such quantities during each of the years then ended were as follows (in thousands):

			2007									2006									2005
			Oil			Gas						Oil			Gas						Oil			Gas
			Mbbl			MMcf			MBOE			Mbbl			MMcf			MBOE			Mbbl			MMcf			MBOE
Proved developed and Undeveloped reserves:
Beginning of year			112,538			226,363			150,262			103,733			135,311			126,285			105,549			25,724			109,836
Revision of previous estimates			(3,826	)		3,358			(3,262	)		(512	)		(222	)		(553	)		(681	)		4,084			-
Improved recovery			4,500			-			4,500			11,900			-			11,900			753			-			753
Extensions and discoveries			17,300			101,400			34,200			4,100			78,000			17,100			6,228			24,605			10,329
Property sales			(6,700	)		-			(6,700	)		-			-			-			(1,035	)		-			(1,035	)
Production			(7,210	)		(15,657	)		(9,819	)		(7,183	)		(12,526	)		(9,270	)		(7,081	)		(7,919)			(8,401	)
Purchase of reserves in place			-			-			-			500			25,800			4,800			-			88,817			14,803
End of year			116,602			315,464			169,179			112,538			226,363			150,262			103,733			135,311			126,285
Proved developed reserves:
Beginning of year			84,782			104,934			102,270			78,308			70,519			90,061			78,207			20,048			81,549
End of year			78,339			147,346			102,897			84,782			104,934			102,270			78,308			70,519			90,061

The standardized measure has been prepared assuming year end sales prices adjusted for fixed and determinable contractual price changes, current costs and statutory tax rates (adjusted for tax credits and other items), and a ten percent annual discount rate. No deduction has been made for depletion, depreciation or any indirect costs such as general corporate overhead or interest expense. Cash outflows for future production and development costs include those cash flows associated with the ultimate settlement of the asset retirement obligation.

Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves (in thousands):

		2007				2006				2005
Future cash inflows		$	11,211,151			$	6,195,547			$	6,088,170
Future production costs			(3,275,397	)			(2,497,785	)			(2,297,638	)
Future development costs			(812,070	)			(511,886	)			(333,722	)
Future income tax expense			(2,286,296	)			(892,669	)			(1,115,516	)
Future net cash flows			4,837,388				2,293,207				2,341,294
10% annual discount for estimated timing of cash flows			(2,417,882	)			(1,110,939	)			(1,089,914	)
Standardized measure of discounted future net cash flows		$	2,419,506			$	1,182,268			$	1,251,380
Average sales prices at December 31:
Oil ($/Bbl)		$	79.19			$	46.15			$	48.38
Gas ($/Mcf)		$	6.27			$	4.45			$	7.91
BOE Price		$	66.27			$	41.23			$	48.21

Changes in standardized measure of discounted future net cash flows from proved oil and gas reserves (in thousands):

		2007				2006				2005
Standardized measure - beginning of year		$	1,182,268			$	1,251,380			$	686,748
Sales of oil and gas produced, net of production costs			(326,174	)			(300,619	)			(240,039	)
Revisions to estimates of proved reserves:
Net changes in sales prices and production costs			1,451,140				(350,877	)			702,867
Revisions of previous quantity estimates			(78,758	)			(7,359	)			5
Improved recovery			108,655				158,213				12,267
Extensions and discoveries			825,775				227,348				168,291
Change in estimated future development costs			(385,656	)			(333,663	)			(157,068	)
Purchases of reserves in place			-				33,390				103,150
Sales of reserves in place			(98,680	)			-				(9,613	)
Development costs incurred during the period			281,702				277,075				111,613
Accretion of discount			162,257				125,138				87,650
Income taxes			(687,103	)			109,918				(392,886	)
Other			(15,920	)			(7,676	)			178,395
Net increase (decrease)			1,237,238				(69,112	)			564,632
Standardized measure - end of year		$	2,419,506			$	1,182,268			$	1,251,380

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