Berry Petroleum Company | Annual Report 2008

ITEM 8 — Financial Statements and Supplementary Data

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Report of PricewaterhouseCoopers LLP, an Independent Registered Public Accounting Firm
Balance Sheets at December 31, 2008 and 2007
Statements of Income for the Years Ended December 31, 2008, 2007 and 2006
Statements of Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006
Statements of Shareholders' Equity for the Years Ended December 31, 2008, 2007 and 2006
Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006
Notes to the Financial Statements
Supplemental Information About Oil & Gas Producing Activities (Unaudited)

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, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008 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, 2008, 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 4 to the financial statements, the Company changed the manner in which it accounts for recurring fair value measurements of financial instruments in 2008.

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

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

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
February 25, 2009

BERRY PETROLEUM COMPANY

Balance Sheets

December 31, 2008 and 2007

(In Thousands, Except Share Information)

ASSETS	2008		2007
Current assets:
Cash and cash equivalents	$	240	$	316
Short-term investments		66		58
Accounts receivable, net of allowance for doubtful accounts of $38,511 and $0, respectively		65,873		117,038
Deferred income taxes		-		28,547
Fair value of derivatives		111,886		2,109
Assets held for sale		-		1,394
Prepaid expenses and other		11,015		11,557
Total current assets		189,080		161,019
Oil and gas properties (successful efforts basis), buildings and equipment, net		2,254,425		1,275,091
Fair value of derivatives		79,696		-
Other assets		19,182		15,996
	$	2,542,383	$	1,452,106
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	119,221	$	90,354
Revenue and royalties payable		34,416		47,181
Accrued liabilities		34,566		21,653
Line of credit		25,300		14,300
Income taxes payable		187		2,591
Deferred income taxes		45,490		-
Fair value of derivatives		1,445		95,290
Total current liabilities		260,625		271,369
Long-term liabilities:
Deferred income taxes		270,323		128,824
Long-term debt		1,131,800		445,000
Asset retirement obligation		41,967		36,426
Unearned revenue		-		398
Other long-term liabilities		5,921		1,657
Fair value of derivatives		4,203		108,458
		1,454,214		720,763
Commitments and contingencies (Note 14)
Shareholders' equity:
Preferred stock, $0.01 par value, 2,000,000 shares authorized; no shares outstanding		-		-
Capital stock, $0.01 par value:
Class A Common Stock, 100,000,000 shares authorized; 42,782,365 shares issued and outstanding (42,583,002 in 2007)		427		425
Class B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and outstanding (liquidation preference of $899) (1,797,784 in 2007)		18		18
Capital in excess of par value		79,653		66,590
Accumulated other comprehensive income (loss)		113,697		(120,704	)
Retained earnings		633,749		513,645
Total shareholders' equity		827,544		459,974
	$	2,542,383	$	1,452,106

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

BERRY PETROLEUM COMPANY

Statements of Income

Years ended December 31, 2008, 2007 and 2006

(In Thousands, Except Per Share Data)

		2008					2007					2006
REVENUES
Sales of oil and gas		$	697,977				$	467,400				$	430,497
Sales of electricity			63,525					55,619					52,932
Gas marketing			35,750					-					-
Gain (loss) on sale of assets			(1,297		)			54,173					97
Interest and other income, net			5,576					6,265					2,812
			801,531					583,457					486,338
EXPENSES
Operating costs - oil and gas production			200,098					141,218					117,624
Operating costs - electricity generation			54,891					45,980					48,281
Production taxes			29,898					17,215					14,674
Depreciation, depletion & amortization - oil and gas production			138,237					93,691					67,668
Depreciation, depletion & amortization – electricity generation			2,812					3,568					3,343
Gas marketing			32,072					-					-
General and administrative			55,353					40,210					36,841
Interest			26,209					17,287					10,247
Commodity derivatives			358					-					(736)
Dry hole, abandonment, impairment and exploration			12,316					13,657					12,009
Bad debt expense			38,665					-					-
			590,909					372,826					309,951
Income before income taxes			210,622					210,631					176,387
Provision for income taxes			77,093					80,703					68,444

Net income		$	133,529				$	129,928				$	107,943

Basic net income per share		$	3.00				$	2.95				$	2.46

Diluted net income per share		$	2.94				$	2.89				$	2.41

Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share)			44,485					44,075					43,948
Effect of dilutive securities:
Stock options			781					604					723
Other			129					227					103
Weighted average number of shares of capital stock used to calculate diluted net income per share			45,395					44,906					44,774

Statements
Years Ended December 31, 2008, 2007 and 2006
(In Thousands)
Net income	$			133,529		$			129,928		$			107,943
Unrealized gains (losses) on derivatives, net of income taxes of $96,546, ($66,627), and $7,647, respectively				157,522					(99,941	)				11,471
Reclassification of realized gains (losses) on derivatives included in net income, net of income taxes of $47,119, ($524) and ($4,712), respectively				76,879					(786	)				(7,068	)
Comprehensive income	$			367,930		$			29,201		$			112,346

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

BERRY PETROLEUM COMPANY

Statements of Shareholders' Equity

Years Ended December 31, 2008, 2007 and 2006

(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, 2006	$	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 - $0.30 per share, including RSU dividend equivalents		-			-		-			(13,177	)		-			(13,177	)
Change in fair value of 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 - $0.30 per share, including RSU dividend equivalents		-			-		-			(13,292	)		-			(13,292	)
Cumulative effect of accounting change from adoption of FIN 48		-			-		-			(63	)		-			(63	)
Change in fair value of 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

Stock-based compensation (199,363 shares)		2			-		11,684			-			-			11,686
Tax impact of stock option exercises		-			-		938			-			-			938
Deferred director fees - stock compensation		-			-		441			-			-			441
Cash dividends declared - $0.30 per share, including RSU dividend equivalents		-			-		-			(13,425	)		-			(13,425	)
Change in fair value of derivatives		-			-		-						234,401			234,401
Net income		-			-		-			133,529			-			133,529
Balances at December 31, 2008	$	427		$	18	$	79,653		$	633,749		$	113,697		$	827,544

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

BERRY PETROLEUM COMPANY

Statements of Cash Flows

Years Ended December 31, 2008, 2007 and 2006

(In Thousands)

Cash flows from operating activities:	2008			2007			2006
Net income	$	133,529		$	129,928		$	107,943
Depreciation, depletion and amortization		141,049			97,259			71,011
Dry hole and impairment		9,932			12,951			8,253
Commodity derivatives		(108	)		574			(109	)
Stock-based compensation expense		9,313			8,200			6,436
Deferred income taxes		67,982			62,465			51,666
(Gain) loss on sale of asset		1,297			(54,173	)		(97	)
Other, net		(756	)		3,561			544
Cash paid for abandonment		(4,607	)		(1,188	)		606
Allowance for bad debt		38,511			-			-
Change in book overdraft		23,984			(9,400	)		15,246
(Increase) decrease in current assets other than cash, cash equivalents and short- term investments		10,281			(47,876	)		(16,338	)
Increase (decrease) in current liabilities other than line of credit		(20,838	)		36,578			13,314
Net cash provided by operating activities		409,569			238,879			258,475
Cash flows from investing activities:
Exploration and development of oil and gas properties		(392,769	)		(281,702	)		(265,110	)
Property acquisitions		(667,996	)		(56,247	)		(257,840	)
Additions to vehicles, drilling rigs and other fixed assets		(4,832	)		(3,565	)		(21,306	)
Capitalized interest		(23,209	)		(18,104	)		(9,339	)
Proceeds from sale of assets		2,037			72,405			4,812
Net cash used in investing activities		(1,086,769	)		(287,213	)		(548,783	)
Cash flows from financing activities:
Proceeds from issuances on line of credit		404,000			395,150			327,250
Payments on line of credit		(393,000	)		(396,850	)		(322,750	)
Proceeds from issuance of long-term debt		1,708,700			229,300			569,700
Payments on long-term debt		(1,021,900	)		(174,300	)		(254,700	)
Dividends paid		(13,425	)		(13,292	)		(13,177	)
Repurchase of shares		-			-			(18,713	)
Proceeds from stock option exercises		2,813			5,178			3,156
Excess tax benefit		938			3,049			3,444
Debt issuance costs		(11,002	)		(1	)		(5,476	)
Net cash provided by financing activities		677,124			48,234			288,734
Net decrease in cash and cash equivalents		(76	)		(100	)		(1,574	)
Cash and cash equivalents at beginning of year		316			416			1,990
Cash and cash equivalents at end of year	$	240		$	316		$	416
Supplemental disclosures of cash flow information:
Interest paid	$	38,917		$	33,945		$	15,019
Income taxes paid	$	13,290		$	6,715		$	18,148
Supplemental non-cash activity:
Increase (decrease) in fair value of derivatives:
Current (net of income taxes of $75,772, ($36,562), and $4,188, respectively)	$	123,628		$	(54,844	)	$	6,282
Non-current (net of income taxes of $67,893, ($30,589), and ($1,252), respectively)		110,773			(45,883	)		(1,879	)
Net increase (decrease) to accumulated other comprehensive income (loss)	$	234,401		$	(100,727	)	$	4,403
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. Reclassifications and Error Corrections

Certain reclassifications have been made to prior period financial statements to conform them to the current year presentation. Specifically, the change in book overdraft line in the Statements of Cash Flows is classified as an operating activity to reflect the use of these funds in operations, rather than their prior year classification as a financing activity.

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

3. 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, 2008 and 2007 is $31.8 million and $7.8 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, 2008 and 2007, we have an allowance for doubtful accounts of $38.5 million and $0, respectively. The 2008 amount represents the Company's November and December 2008 sales to Big West of California (BWOC). In December 2008, Flying J, Inc., and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary BWOC filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Also in December 2008, BWOC informed the Company that it was unable to receive the Company's production. We have entered into various short-term agreements with other companies to sell our California oil production. Pricing and volumes under these agreements vary with prices ranging from just above the posted price for San Joaquin heavy oil to the posted price less a discount. In January 2009, our California crude oil daily production was, on average, near levels achieved prior to BWOC's Chapter 11 filing. BWOC is evaluating several options, including a sale of the Bakersfield, California refinery. We recorded $38.5 million of bad debt expense in 2008 for the bankruptcy of BWOC. Of the $38.5 million due from BWOC, $12.4 million represents December crude oil sales by the Company and represents an administrative claim under the bankruptcy proceedings and $26.1 million represents November crude oil sales which would have the same priority as other general unsecured claims. BWOC will also be liable to us for damages under this contract for any amounts received by us under our short-term contracts which are less than what we would have otherwise received from BWOC had they been able to accept our production. We have guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, in the event that our claim is not fully collectible from BWOC. While we believe that we may recover some or all of the amounts due from BWOC, the data received from the bankruptcy proceedings to date has not provided us with adequate data from which to make a conclusion that any amounts will be collected nor as to whether BWOC will assume or reject our contract.

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 on 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 contract. 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 (loss) 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 18 - 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 zero and $1.4 million as of December 31, 2008 and 2007, 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. Both of these lease agreements were terminated as of December 31, 2008.

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 use our historical cost to abandon wells and facilities to provide evidence of our future cost to adandon these assets. 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.

Accrued liabilities - Accrued liabilities consist primarily of Accrued property taxes, Accrued interest and Accrued payroll costs. Accrued property taxes were $13.5 million and $8.5 million as of December 31, 2008 and 2007, respectively. Accrued interest was $8.4 million and $3.3 million as of December 31, 2008 and 2007, respectively. Accrued payroll costs were $8.4 million and $7.1 million as of December 31, 2008 and 2007, respectively.

Revenue recognition - Revenues associated with sales of crude oil, natural gas, electricity and natural gas marketing 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). Revenues are derived from gas marketing sales which represent excess capacity on the Rockies Express pipeline which we use to market natural gas for our working interest partners.

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, 2008, 2007 and 2006 was $5.8 million, $5.0 million and $5.3 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 Operating costs - oil and gas production were $9.5 million, $1.2 million and $0 for 2008, 2007 and 2006, respectively. Natural gas transportation costs included in Operating costs - electricity generation were $7.2 million, $6.7 million and $6.8 million for 2008, 2007 and 2006, respectively. Additionally, the transportation costs in Uinta were $0.2 million, $1.4 million and $1.4 million in 2008, 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 340,000, 855,000, and 499,000 were excluded from the calculation of diluted net income per common share for 2008, 2007 and 2006, 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 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 12.

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. We adopted this Statement in 2008 and increased our disclosures accordingly. SFAS No. 157-2 addresses the same topic for nonfinancial assets and liabilities and will become effective for our fiscal year beginning January 1, 2009. We do not believe that the implementation of SFAS 157-2 will have a material impact 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 became effective for our fiscal year beginning January 1, 2008 and did not have any effect on our financial statements, as we do not post collateral under our hedging agreements.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which expands 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 non controlling 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 the principle 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).

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities. Expanded disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement will require us to provide the additional disclosures described above in the first quarter of 2009.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America (the GAAP hierarchy). This Statement became effective on November 13, 2008.

In September 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Positions (FSP) No. 133-1 and FIN 45-4 to amend FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument. This FSP also amends FASB Interpretation No.45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to require an additional disclosure about the current status of the payment/performance risk of a guarantee. Further, this FSP clarifies the FASB's intent about the effective date of FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities. This FSP was adopted in 2008 and did not have a material effect on our financial statements and related disclosures.

In February 2009, the SEC issued its final rule on Modernization of Oil and Gas Reporting (the Final Rule), which revises the disclosures required by oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the Final Rule changes the requirements for determining quantities of oil and gas reserves. The Final Rule also changes certain accounting requirements under the full cost method of accounting for oil and gas activities. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves, with a view to helping investors evaluate their investments in oil and gas companies. The amendments are designed to modernize the requirements for the determination of oil and gas reserves, aligning them with current practices and updating them for changes in technology. The Final Rule applies to registration statements filed on or after January 1, 2010, and annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. This rule will require us to provide the additional disclosures described above in our 10-K for our fiscal year ending December 31, 2009. We are still evaluating the impact the Final Rule will have on our financial statements but we may increase the amount of proved, undeveloped reserves reported from technology advances and we may disclose probable and possible reserves.

General - The price sensitive royalty that burdens our Formax property in the South Midway Sunset field has changed. We previously paid a royalty equal to 75% of the amount of the heavy oil posted above a price of $16.11. This price escalates at 2% annually. Effective January 1, 2008, the royalty rate is reduced from 75% to 53% as long as we maintain a minimum steam injection level, which we expect to meet, that reduces over time. Current net production from this property is approximately 2,300 Bbl/D.

4. Fair Value Measurements

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. We adopted this Statement as of January 1, 2008.

Determination of fair value

We have established and documented a process for determining fair values. Fair value is based upon quoted market prices, where available. We have various controls in place to ensure that valuations are appropriate. These controls include: identification of the inputs to the fair value methodology through review of counterparty statements and other supporting documentation, determination of the validity of the source of the inputs, corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. Furthermore, while we believe these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

Valuation hierarchy
SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.

Level 1 - inputs to the valuation methodology that are quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 - inputs to the valuation methodology that include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 - inputs to the valuation methodology that are unobservable and significant to the fair value measurement.

A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

Our oil swaps, natural gas swaps and interest rate swaps are valued using the counterparties' mark-to-market statements which are validated by our internally developed models and are classified within Level 2 of the valuation hierarchy. The observable inputs include underlying commodity and interest rate levels and quoted prices of these instruments on actively traded markets. Derivatives that are valued based upon models with significant unobservable market inputs (primarily volatility), and that are normally traded less actively are classified within Level 3 of the valuation hierarchy. Level 3 derivatives include oil collars, natural gas collars and natural gas basis swaps.

Assets and liabilities measured at fair value on a recurring basis

December 31, 2008 (in millions)	Total carrying value on the Balance Sheet	Level 2	Level 3

Commodity derivative asset	198.4	25.9	172.5
Interest rate swaps liability	(12.5)	(12.5)	-
Total assets at fair value	185.9	13.4	172.5

Changes in Level 3 fair value measurements

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

(in millions)	Three months ended December 31, 2008	Twelve months ended December 31, 2008

Fair value liability, beginning of period	$ (208.9)	$(194.3)
Total realized and unrealized gains and (losses) included in sales of oil and gas	227.1	196.0
Purchases, sales and settlements, net	154.3	170.8
Transfers in and/or out of Level 3	-	-
Fair value asset, December 31, 2008	172.5	172.5

Total unrealized gains and (losses) included in income related to financial assets and liabilities still on the condensed balance sheet at December 31, 2008	$ -	$-

In February of 2007, the FASB issued SFAS 159, which is effective for fiscal years beginning after November 15, 2007. SFAS 159 provides an option to elect fair value as an alternative measurement for selected financial assets and financial liabilities not previously carried at fair value. We adopted this statement at January 1, 2008, but did not elect fair value as an alternative for any financial assets or liabilities.

Cash equivalents consist principally of bank deposits. Cash and equivalents of $0.2 million and $0.3 million at December 31, 2008 and 2007, respectively, are stated at cost.

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. We use available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, "Disclosures about Fair Value of Financial Instruments" and does not impact our financial position, results of operations or cash flows. Our short-term investments available for sale at December 31, 2008 and 2007 consist of United States treasury notes that mature in less than one year. For the three years ended December 31, 2008, realized and unrealized gains and losses of our short-term investments were insignificant to the financial statements. The cost of our long-term senior subordinated notes is $200 million and the fair value is approximately $116 million. The cost and the fair value of our senior secured credit facilities is approximately $957 million.

5. 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 crude oil sales contract with BWOC for substantially all of our California production for deliveries beginning February 1, 2006. In December 2008, Flying J, Inc., and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary BWOC filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Also in December 2008, BWOC informed the Company that it was unable to receive the Company's production. We have entered into various short-term agreements with other companies to sell our California oil production. Pricing and volumes under these agreements vary with prices ranging from just above the posted price for San Joaquin heavy oil to the posted price less a discount. In January 2009, our California crude oil daily production was, on average, near levels achieved prior to BWOC's Chapter 11 filing. BWOC is evaluating several options, including a sale of the Bakersfield, California refinery. We recorded $38.5 million of bad debt expense in 2008 for the bankruptcy of BWOC. Of the $38.5 million due from BWOC, $12.4 million represents December 2008 crude oil sales by the Company and represents an administrative claim under the bankruptcy proceedings and $26.1 million represents November 2008 crude oil sales which would have the same priority as other general unsecured claims. BWOC will also be liable to us for damages under this contract for any amounts received by us under our short-term contracts which are less than what we would have otherwise received from BWOC had they been able to accept our production. We have guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, in the event that our claim is not fully collectible from BWOC. While we believe that we may recover some or all of the amounts due from BWOC, the data received from the bankruptcy proceedings to date has not provided us with adequate data from which to make a conclusion that any amounts will be collected nor as to whether BWOC will assume or reject our contract.

On February 27, 2007, we entered into a multi-staged crude oil sales contract with a refiner for our Uinta light crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D on July 1, 2007. After partial completion of its refinery expansion in Salt Lake City in March 2008, the refiner increased its total purchase capacity to 5,000 Bbl/D. This contract is in effect through June 30, 2013. This contract is our only sales contract for our Uinta oil.

During 2008, the Company experienced two credit losses related to its oil and natural gas sales. Included in bad debt expense is $0.2 million related to the bankruptcy of SemGroup and $38.5 million related to BWOC as described above. During the two years 2006 and 2007, we did not have any credit losses on the sale of oil, natural gas, natural gas liquids or 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, 2008, we have not incurred losses related to these investments.

As of December 31, 2008, $177 million, of the approximate net value of the Company's hedging positions of approximately $186 million, can be attributed to one of three counterparties. While a significant portion of our hedges are with a small number of counterparties, we monitor each counterparty's credit rating and CDS rate and as of December 31, 2008 each of our hedge counterparties maintained a rating of AA-(S&P)/Aa2(Moody's) or better. Neither we nor our counterparties are required to post collateral under our hedging contracts.

The following summarizes the accounts receivable balances at December 31, 2008 and 2007 and sales activity with significant customers for each of the years ended December 31, 2008, 2007 and 2006 (in thousands). We do not believe that the loss of any one customer would impact the marketability, but it 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	2008		2007		2008		2007		2006
Oil & Gas Sales:
A	$	4,082	$	5,347	$	107,414	$	39,791	$	-
B		-		-		3,795		20,239		75,597
C		4		5,793		17,734		28,170		10,458
D		38,787		44,450		582,885		404,038		305,587
E		5,785		-		32,431		-		-
	$	48,658	$	55,590	$	744,259	$	492,238	$	391,642
Electricity Sales:
F	$	1,799	$	1,979	$	30,975	$	26,033	$	24,335
G		2,227		2,573		34,553		29,470		28,597
	$	4,026	$	4,552	$	65,528	$	55,503	$	52,932

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. Accounts receivable amounts will not agree to the Balance Sheet due primarily to the Allowance for doubtful accounts, which is netted in Accounts receivable on the Balance Sheet.

As of December 31, 2008 we have an allowance for doubtful accounts of $38.5 million which represents the Company's November and December 2008 sales to Big West of California (BWOC). While the Company believes that it may recover some or all of the amounts due from BWOC, the data received from the bankruptcy proceedings to date has not provided the Company with any data from which to make a conclusion that any amounts will be collected. We did not have an allowance for doubtful accounts for the year ended December 31, 2007.

6. 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:	2008		2007
Proved properties:
Producing properties, including intangible drilling costs	$	1,820,609	$	869,176
Lease and well equipment (1)		663,610		448,100
		2,484,219		1,317,276
Unproved properties
Properties, including intangible drilling costs		255,412		285,823
		2,739,631		1,603,099
Less accumulated depreciation, depletion and amortization		509,277		350,604
		2,230,354		1,252,495
Commercial and other:
Land		810		810
Drilling rigs and equipment		13,166		12,443
Buildings and improvements		6,274		5,407
Machinery and equipment		22,767		18,525
		43,017		37,185
Less accumulated depreciation		18,946		14,589
		24,071		22,596
	$	2,254,425	$	1,275,091
(1) Includes cogeneration facility costs.

On July 15, 2008, the Company acquired certain interests in natural gas producing properties on 4,500 net acres in Limestone and Harrison Counties in East Texas for $668 million cash (E. Texas Acquisition) including an initial purchase price of $622 million, and post closing adjustments of $46 million.

In February 2006, we closed on an agreement with a private seller to acquire a 50% working interest in natural gas assets in Piceance 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. The 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 Piceance 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 $0.2 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.

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):

	2008		2007		2006
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	-	$	6,826	$	89
Capitalized exploratory well costs that have been capitalized for a period greater than one year		-		-		-
Balance at December 31	$	-	$	6,826	$	89

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):

	2008			2007			2006
Beginning balance at January 1	$	6,826		$	89		$	6,037
Additions to capitalized exploratory well costs pending the determination of proved reserves		-			6,826			6,682
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(6,826	)		-			(4,377	)
Capitalized exploratory well costs charged to expense		-			(89	)		(8,253	)
Ending balance at December 31	$	-		$	6,826		$	89

Dry hole, abandonment and impairmentand asset sales

In 2008 we had dry hole, abandonment and impairment charges of $12.3 million consisting primarily of $7.3 million for technical difficulties that were encountered on five wells in Piceance before reaching total depth. These holes were abandoned in favor of drilling to the same bottom hole location by drilling new wells. We incurred exploration costs of $2.4 million in 2008 compared to $0.7 million and $3.8 million in 2007 and 2006, respectively. These costs consist primarily of geological and geophysical costs in DJ. Due to the release of our rigs we performed an impairment test which resulted in $2.6 million of impairment costs resulting from the impairment of one rig. Additionally, we performed an impairment test of our oil and gas assets at December 31, 2008 in accordance with SFAS 144 and determined that no impairment was necessary.

In 2007 we had dry hole, abandonment, impairment and exploration charges of $13.7 million that consisted primarily of a $4.6 million writedown on 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 $0.7 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 Uinta drilled for approximately $1.6 million net to our interest and four wells in Bakken and four wells in DJ for $1.5 million.

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 sold in the first quarter of 2008 in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

7. Debt Obligations

Short-term lines of credit

In 2005, we completed an 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 and are subject to the borrowing base under the Company's senior credit facility. The Line of Credit may be terminated at any time upon written notice by either us or the lender. In conjunction with the amendment to our senior secured credit facility, on July 15, 2008, the Line of Credit was secured by our assets. At December 31, 2008 and 2007, the outstanding balance under this Line of Credit was $25.3 million and $14.3 million, respectively. 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, 2008 and 2007 was 1.4% and 5.7%, respectively. Covenants under this agreement match the covenants under our senior secured revolving credit facility.

In July, 2008, we completed a $100 million senior unsecured credit facility that was to mature on December 31, 2008. We terminated this credit facility without penalty in October 2008.

Senior Secured Revolving Credit Facility

On July 15, 2008, we entered into a five year amended and restated credit agreement (the Agreement) with Wells Fargo Bank, N.A. as administrative agent and other lenders. This agreement was amended on October 17, 2008, as noted below. The July 15, 2008 Agreement amended and restated the Company's previous credit agreement dated as of April 28, 2006. The Agreement is a revolving credit facility for up to $1.5 billion with a borrowing base of $1.0 billion. The outstanding Line of Credit reduces our borrowing capacity available under the Agreement. The borrowing base under the April 28, 2006 agreement was $650 million. Interest on amounts borrowed under this debt was charged at LIBOR plus a margin of 1.125% to 1.875% or the prime rate, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. An annual commitment fee of .25% to .375% was charged on the unused portion of the credit facility.

On October 17, 2008, we further amended our $1.5 billion credit facility with the Company's syndicate of banks which increased our borrowing base from $1.0 billion to $1.25 billion with commitments of $1.08 billion and a new maturity date of July 15, 2012. Commitments were increased during the fourth quarter of 2008 with the addition of $130 million in commitments bringing the total commitments under the facility to $1.21 billion from 19 banks. The amendment includes an accordion feature which allows the Company to increase borrowing commitments to $1.25 billion without further bank approval, and modifies the annual commitment fee and interest rate margins. Interest on amounts borrowed under the facility is charged at LIBOR or the prime rate plus a margin. The LIBOR and prime rate margins range between 1.375% and 2.125% based on the ratio of credit outstanding to the borrowing base. Additionally, an annual commitment fee of .30% to .50% is charged on the unused portion of the credit facility. The deferred costs of approximately $10.8 million associated with the issuance of this credit facility and $0.6 million associated with the issuance of the previous credit facility are being amortized over the four year life of the Agreement. The total deferred costs under this facility and the previous facility were $10.6 million as of December 31, 2008. A charge of $0.1 million was recorded on the income statement as a loss on debt extinguishment during the third quarter of 2008 related to parties who reduced their commitment or chose not to participate in the Agreement.

The total outstanding debt at December 31, 2008 under the Agreement and the Line of Credit was $932 million and $25 million, respectively, and $8 million in letters of credit have been issued under the facility, leaving $245 million in borrowing capacity available under the Agreement. The maximum amount available is subject to semi-annual redeterminations of the borrowing base, based on the value of our proved oil and gas reserves, in April and October of each year in accordance with the lender's customary procedures and practices. Both we and the banks have the bilateral right to one additional redetermination each year.

See Note 21 related to changes in the terms of our Senior secured credit facility in February 2009.

Senior Subordinated 8.25% NotesDue 2016

In 2006, we issued in a public offering $200 million of 8.25% senior subordinated notes due 2016 (the Notes). Interest on the Notes is paid semiannually in May and November of each year. The deferred costs of approximately $5 million associated with the issuance of this debt are being amortized over the ten year life of the Notes and the remaining balance as of December 31, 2008 was $4 million. 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 to finance the November 2006 installment under the joint venture agreement to develop properties in Piceance. Our bond notes and related interest of 8.25% mature in November 2016, but are not redeemable until November 1, 2011 and are not redeemable without any premium until November 1, 2014.

Financial Covenants

The senior secured revolving credit facility contains restrictive covenants which, among other things, require us to maintain a debt to EBITDA ratio of not greater than 3.5 to 1.0 and a minimum current ratio, as defined, of 1.0. The non-cash financial statement impact of hedging is excluded from the calculation of both ratios and all of the availability under the senior credit facility is added to current assets when computing the current ratio. The $200 million Notes are subordinated to our credit facility and line of credit indebtedness. Under the Notes, as long as the interest coverage ratio (as defined) is greater than 2.5 times, we may incur additional debt. Our covenant ratios for the two years ended December 31, 2008, were as follows:

	2008		2007
Current Ratio (Not less than 1.0)		1.2		2.5
EBITDA To Total Funded Debt Ratio (Not greater than 3.5)		2.7		1.6
Interest Coverage Ratio (Not less than 2.5)		8.4		9.3

We were in compliance with all such covenants as of December 31, 2008 and 2007.

Interest Rates and Interest Rate Hedges

Additionally, in 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 beginning on September 29, 2006. In 2008, the term on $50 million of these swaps was extended by one year. These interest rate swaps have been designated as cash flow hedges. In 2008, $50 million of these interest rate swaps were extended one year, resulting in a fixed rate of approximately 4.8%.

In 2008 we entered into three year interest rate swaps totaling $275 million for a fixed rate averaging approximately 2.2% on an additional $275 million of our outstanding borrowings under our credit facility for three years beginning on April and September 15, 2009. These interest rate swaps have been designated as cash flow hedges.

As of December 31, 2008, we had a total of $575 million of fixed rate positions averaging 4.8% resulting from the $200 million of 8.25% senior subordinated notes and $375 million of interest rate swaps for a fixed rate of approximately 2.2%.

The weighted average interest rate on total outstanding borrowings at December 31, 2008 and 2007 was 4.9% and 5.7%, respectively, excluding the effect of interest rate hedges.

8. 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 $0.50 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 $0.30 per share, payable quarterly in March, June, September and December. We paid a special dividend of $0.02 per share on September 29, 2006 and increased our regular quarterly dividend by 15%, from $0.065 to $0.075 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 $0.005 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.

9. Asset Retirement Obligations

Inherent in the fair value calculation of AROs 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 increased due to demand for these services, resulting in an increase in the ARO balance at year end. As of December 31, 2008, we did not have any asset retirement obligations for which no liability has been accrued.

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

	2008			2007
Beginning balance at January 1	$	36,426		$	26,135
Liabilities incurred		4,686			4,191
Liabilities settled		(4,607	)		(2,121	)
Revisions in estimated liabilities		2,006			5,779
Accretion expense		3,456			2,442

Ending balance at December 31	$	41,967		$	36,426

10. Bad Debt Expense

Of the $38.7 million recorded in bad debt expense for the year ended December 31, 2008, $38.5 million relates to the allowance for bad debt taken for the bankruptcy of BWOC with the remainder due to the bankruptcy of SemCrude earlier in 2008.

In December 2008, Flying J, Inc., and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary BWOC filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Also in December 2008, BWOC informed the Company that it was unable to receive the Company's production. We have entered into various short-term agreements with other companies to sell our California oil production. Pricing and volumes under these agreements vary with prices ranging from just above the posted price for San Joaquin heavy oil to the posted price less a discount. In January 2009, our California crude oil daily production was, on average, near levels achieved prior to BWOC's Chapter 11 filing. BWOC is evaluating several options, including a sale of the Bakersfield, California refinery. We recorded $38.5 million of bad debt expense in 2008 for the bankruptcy of BWOC. Of the $38.5 million due from BWOC, $12.4 million represents December crude oil sales by the Company and represents an administrative claim under the bankruptcy proceedings and $26.1 million represents November crude oil sales which would have the same priority as other general unsecured claims. BWOC will also be liable to us for damages under this contract for any amounts received by us under our short-term contracts which are less than what we would have otherwise received from BWOC had they been able to accept our production. We have guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, in the event that our claim is not fully collectible from BWOC. While we believe that we may recover some or all of the amounts due from BWOC, the data received from the bankruptcy proceedings to date has not provided us with adequate data from which to make a conclusion that any amounts will be collected nor as to whether BWOC will assume or reject our contract.

11. Pro Forma Results

The unaudited pro forma results presented below for the years ended December 31, 2008 and 2007 have been prepared to give effect to the E. Texas Acquisition on the Company's results of operations under the purchase method of accounting as if it had been consummated at the beginning of each of the periods presented. The unaudited pro forma results do not purport to represent the results of operations that actually would have occurred on such date or to project the Company's results of operations for any future date or period:

		Year Ended December 31, 2008		Year Ended December 31, 2007
Pro forma revenue	$	854,237	$	616,835
Pro forma income from operations	$	217,398	$	164,447
Pro forma net income	$	138,432	$	105,657
Pro forma basic earnings per share	$	3.11	$	2.40
Pro forma diluted earnings per share	$	3.05	$	2.36

The following is a calculation and allocation of purchase price to the E. Texas Acquisition assets and liabilities based on their relative fair values, as determined by the valuation of proved reserves and related assets as of the acquisition date:

Purchase price (in thousands):		As of December 31, 2008
Original purchase price	$	622,356

Closing adjustments for property costs, and operating expenses in excess of revenues between the effective date and closing date		45,506

Total purchase price allocation	$	667,862

Allocation of purchase price (in thousands):

Oil and natural gas properties	$	651,659		(i)
Pipeline		17,277
Tax receivable		1,476

Total assets acquired		670,412

Current liabilities		(1,195	)	(ii)
Asset retirement obligation		(1,355	)

Net assets acquired	$	667,862

(i) Determined by reserve analysis.
(ii) Accrual for royalties payable.

12. Income Taxes

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

	2008		2007		2006
Current:
Federal	$	3,280	$	12,939	$	12,231
State		5,795		5,299		4,547
		9,075		18,238		16,778
Deferred:
Federal		62,412		53,321		44,205
State		5,606		9,144		7,461
		68,018		62,465		51,666
Total	$	77,093	$	80,703	$	68,444

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):

	2008			2007
Deferred tax asset:
Federal benefit of state taxes	$	11,082		$	8,391
Credit carryforwards		33,636			33,588
Stock option costs		9,089			6,716
Derivatives		2,282			81,042
Other, net		4,312			3,010
		60,401			132,747
Deferred tax liability:
Depreciation and depletion		(303,413	)		(232,451	)
Derivatives		(72,801	)		(573	)
		(376,214	)		(233,024	)
Net deferred tax liability	$	(315,813	)	$	(100,277	)

At December 31, 2008, our net deferred tax assets and liabilities were recorded as a current liability of $45.5 million and a long-term liability of $270.4 million. 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.

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

	2008		2007		2006
Tax computed at statutory federal rate	35	%	35	%	35	%
State income taxes, net of federal benefit	4		5		5
Tax credits			-		-
Other	(2	)	(2	)	(1	)
Effective tax rate	37	%	38	%	39	%

We have approximately $24 million of federal and $17 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.

As of December 31, 2008, we had a gross liability for uncertain tax benefits of $12 million of which $10 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. We had accrued approximately $1.2 million and $1.1 million of interest related to our uncertain tax positions as of December 31, 2008 and 2007, respectively.

We anticipate the balance of our unrecognized tax benefits could be reduced during the next 12 months as the IRS finalizes its examination, however, we cannot reasonably estimate the impact of the examination at this time.

For the year ended December 31, 2008 we recognized a net benefit of approximately $1.6 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 $1.9 million.

For the year ended December 31, 2007 we recognized a net benefit of approximately $0.6 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 $0.2 million.

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

		2008			2007
Unrecognized tax benefits at January 1	$	12.0		$	14.6
Increases for positions taken in current year		1.2			0.5
Increases for positions taken in a prior year		0.3			(.3	)
Decreases for settlements with taxing authorities		-			-
Decreases for lapses in the applicable statute of limitations		(1.5	)		(2.8	)
Unrecognized tax benefits at December 31	$	12.0		$	12.0

As of December 31, 2008, we remain subject to examination in the following major tax jurisdictions for the tax years indicated below:

Jurisdiction:	Tax Years Subject to Exam:
Federal	2005 – 2007
California	2004 – 2007
Colorado	2004 – 2007
Utah	2005 – 2007

13. Leases Receivable

As of December 31, 2008, all of our rig leases had either expired or were terminated and the leasee did not exercise the bargain purchase option under the lease. The $5.8 million in lease receivable was capitalized under property plant and equipment as of December 31, 2008.

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):

Jurisdiction:	Tax Years Subject to Exam:
Federal	2005 – 2007
California	2004 – 2007
Colorado	2004 – 2007
Utah	2005 – 2007

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

14. 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 proceedings on the matter. There are ongoing proceedings before the CPUC in which Edison and PG&E are seeking credit against future payments they are to make for electricity purchases based on retroactive adjustment to pricing under contracts with us. Whether or not retroactive adjustments will be ordered, how such adjustments would be calculated and what period they would cover are too uncertain to estimate at this time.

Our contractual obligations not included in our Balance Sheet as of December 31, 2008 (except Long-term debt and Abandonment obligations) are as follows (in thousands):

		Total		2009		2010		2011		2012		2013		Thereafter
Long-term debt and interest	$	1,471,383	$	82,211	$	56,558	$	56,558	$	56,558	$	969,998	$	249,500
Abandonment obligations		41,967		1,643		1,642		1,642		1,642		1,642		33,756
Operating lease obligations		18,328		2,373		2,390		2,436		2,446		2,493		6,190
Drilling and rig obligations		47,049		12,789		8,030		8,030		18,200		-		-
Firm natural gas transportation contracts		165,071		19,803		19,803		19,803		19,652		17,557		68,453
Total	$	1,743,798	$	118,819	$	88,423	$	88,469	$	98,498	$	991,690	$	357,899

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, 2008, 2007 and 2006 was $1.7 million, $1.5 million and $1 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 - In the primary term (November 2004 to November 2009) of our Utah Lake Canyon project, we have a 21 gross well drilling commitment. To date, we have drilled 14 gross wells (9.8 net wells) under theTribal Lake Canyon Exploration and Development Agreement (EDA). We have 7 remaining commitment wells to drill in Lake Canyon by the end of November 2009. Our minimum obligation under our exploration and development agreement is $9.6 million, and as of December 31, 2008 the remaining obligation is $2.4 million. Also included above, under our June 2006 joint venture agreement in Piceance, we are required to have 120 wells drilled by February 2011 to avoid penalties of $0.2 million per well or a maximum of $24 million. As of December 31, 2008 we have drilled 29 of these wells..

Drilling rig obligations -We are obligated in operating lease agreements for the use of two drilling rigs, one of which resulted from the July 2008 E. Texas Acquisition (see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations).

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 light crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D on July 1, 2007. After partial completion of its refinery expansion in Salt Lake City in March 2008, the refiner increased its total purchase capacity to 5,000 Bbl/D. This contract is in effect through June 30, 2013. Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI, which ranges from $10 to $15 at WTI prices between $40 and $60. This contract is our only sales contract for our Uinta oil.

15. 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 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 we had applied the fair value method to account for unvested stock options from the original effective date. Total compensation cost recognized in the Statements of Income was $8.9 million, $8.4 million and $6.1 million in 2008, 2007 and 2006, respectively. The tax benefit related to this compensation cost was $3.8 million, $3.3 million and $2.4 million in 2008, 2007 and 2006, respectively.

Stock Options
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. During 2008, the non-employee Directors did not receive any options.

	2008	2007	2006
Expected volatility	36%	32% - 33%	32% - 33%
Weighted-average volatility	36%	33%	32%
Expected dividends	1%	1%	.8% - 1.0%
Expected term (in years)	5	4.9 - 5.6	5.3 - 5.5
Risk-free rate	3.2%	3.4% - 4.7%	4.5% - 4.8%

The following table summarizes information related to stock options outstanding and exercisable as of December 31, 2008:

			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
$7.00 - $15.00	682,650	$10.42	4.4	682,650	$10.42	4.4
$15.01 - $25.00	490,500	21.60	5.9	478,000	21.60	5.9
$25.01 - $35.00	933,551	31.85	7.5	590,900	31.54	7.5
$35.01 - $45.00	316,199	42.75	9.1	90,982	42.99	8.8
Total	2,422,900	$25.16	6.5	1,842,532	$21.70	6.0

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

	2008		2007		2006
Outstanding at January 1	$	24.33	$	20.97	$	16.76
Granted during the year		41.18		43.40		32.82
Exercised during the year		19.38		12.52		10.83
Cancelled/expired during the year		29.66		22.88		19.11
Outstanding at December 31		25.16		24.33		20.97
Exercisable at December 31		21.70		19.88		16.24

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

	2008			2007			2006
Balance outstanding, January 1		2,527,266			2,859,836			3,110,826
Granted		89,084			220,115			604,050
Exercised		(149,950	)		(444,216	)		(526,990	)
Canceled/expired		(43,500	)		(108,469	)		(328,050	)
Balance outstanding, December 31		2,422,900			2,527,266			2,859,836

Balance exercisable at December 31		1,842,532			1,558,780			1,493,067

Available for future grant		412,025			988,798			1,279,344

Weighted average remaining contractual life (years)		6.5			7.3			8
Weighted average fair value per option granted during the year based on the Black-Scholes pricing model	$	14.03		$	13.88		$	11.27

As of December 31, 2008, there was $5.2 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 1.4 years. The tax benefit realized from stock options exercised during the year ended December 31, 2008, 2007 and 2006 is $1.4 million, $3.5 million and $4.3 million, respectively.

	Stock Options
	Year ended
	December 31, 2008		December 31, 2007		December 31, 2006
Weighted average fair value per option granted during the year based on the Black-Scholes pricing model	$	14.03	$	13.88	$	11.27
Total intrinsic value of options exercised (in millions)		4.4		11.9		11.8
Total intrinsic value of options outstanding (in millions)		-		50.8		29.8
Total intrinsic value of options exercisable (in millions)		-		38.3		22.3

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 2008, the non-employee Directors did not receive any 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, 2008:

	RSUs			Weighted Average Intrinsic Value at Grant Date	Weighted Average Contractual Life Remaining
Balance outstanding, January 1	506,923		$	34.84	2.7 years
Granted	572,102			11.26
Converted	(73,414	)		33.95
Canceled/expired	(39,413	)		37.58
Balance outstanding, December 31	966,198		$	20.83	3.0 years

		RSUs Year ended
	December 31, 2008	December 31, 2007	December 31, 2006
Weighted-average grant date fair value of RSUs issued	$11.26	$ 42.36	$ 31.86
Total value of RSUs vested (in millions)	.8	2.1	1.0

The total compensation cost related to nonvested awards not yet recognized on December 31, 2008 is $13.3 million and the weighted average period over which this cost is expected to be recognized is 1.5 years.

16. 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. Our contributions to the 401(k) Plan, net of forfeitures, were $1.4 million, $1.4 million and $1.2 million for 2008, 2007 and 2006, respectively. Employees are eligible to participate in the 401(k) Plan on their date of hire and approximately 92% of our employees participated in the 401(k) Plan in 2008.

17. 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 compensation for service 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, 2008, 2007 and 2006 were 23,312, 12,866 and 13,387, 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.

18. 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. With respect to our hedging activities, we utilize multiple counterparties on our hedges and monitor each counterparty's credit rating. We are not required to issue collateral on these hedging transactions. Additionally, our valuation of derivatives reflects an adjustment for the credit risk for each party based on credit default swaps when such data is available and historical default rates when such data is not available. As of December 31, 2008 and 2007, we recorded a credit risk reduction of $632 thousand and $0, respectively, to the Fair value of derivatives asset.

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 $0.8 million was recorded in other accumulated comprehensive income (loss) 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. In 2008, $50 million of these interest rate swaps were extended one year, resulting in a fixed rate of approximately 4.8%.

In 2008 we also entered into three year interest rate swaps for a fixed rate of approximately 2.2% on an additional $275 million of our outstanding borrowings under our credit facility for three years beginning on April and September 15, 2009. These interest rate swaps have been designated as cash flow hedges.

The related cash flow impact of our derivative activities are reflected as cash flows from operating activities. At December 31, 2008, our net fair value of derivatives asset was $185.9 million as compared to a derivatives liability of $201.6 million at December 31, 2007. Based on NYMEX strip pricing as of December 31, 2008, we expect to receive hedge payments under the existing derivatives of $120.5 million during the next twelve months. At December 31, 2008 and 2007, Accumulated Other Comprehensive Income (Loss) consisted of an unrealized gain of $113.7 million and an unrealized loss of $120.7 million, respectively, net of tax, from our crude oil, natural gas and interest swaps and collars that qualified for hedge accounting treatment at December 31, 2008. Deferred net gains recorded in Accumulated Other Comprehensive Income (Loss) at December 31, 2008 and subsequent marked-to-market changes in the underlying hedging contracts are expected to be reclassified to earnings over the life of these contracts.

Most of our oil hedges are based on the West Texas Intermediate (WTI) index and our California oil sales contract with BWOC is tied to WTI which has allowed us to qualify for hedge accounting and effectively hedge our production. Our interim sales contracts are primarily based on the field posting price and we are therefore subject to potential ineffectiveness. There is a high correlation between WTI and the field posting prices which allowed us to continue hedge accounting. Additionally, under the dollar offset method, we did not have any ineffectiveness under these contracts.

19. Master Limited Partnership

On October 22, 2007, we announced plans to form a master limited partnership (MLP). We decided not to proceed with this plan due to unfavorable capital market conditions and expensed $0.6 million of legal and accounting fees during 2008 under the caption "general and administrative" in the Statements of Income related to the formation of the MLP.

20. 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 on the Statements of Income. Mr. Thomas Jamieson is a Director of Berry Petroleum Company and a director and the controlling stockholder of BFO. The tender was made to all shareholders of BFO other than Mr. Jamieson and his affiliates. The Corporate Governance and Nominating Committee, with input from the Audit Committee, approved this transaction.

21. Subsequent Events

On February 19, 2009, the company executed an amendment to its senior secured credit facility which, among other things, increased the maximum EBITDAX to total funded debt ratio to 4.75 through year-end 2009, to 4.50 through year-end 2010 and to 4.0 thereafter. A new senior secured debt to EBITDAX covenant limits the maximum EBITDAX to outstanding debt under our senior secured credit facility to 3.75 through September 2010, 3.5 from October 2010 through March 2011, 3.25 from April 2011 through September 2011 and 3.0 thereafter. Additionally, the write off of $38.5 million to bad debt expense associated with the bankruptcy of Big West will be excluded from the calculation of EBITDAX. The LIBOR and prime rate margins increased to between 2.25% and 3.0% based on the ratio of credit outstanding to the borrowing base. Additionally, the annual commitment fee on the unused portion of the credit facility increased to 0.50%, regardless of the amount outstanding. The deferred costs of this amendment of $4.5 million will be amortized over the remaining term of the facility.

22. Quarterly Financial Data (unaudited)

The following is a tabulation of unaudited quarterly operating results for 2008 and 2007 (in thousands, except per share data).

			Income (Loss)						Basic Net			Diluted Net
	Operating		Before			Net			Income(Loss)			Income(Loss)
2008	Revenues		Taxes			Income(Loss)			Per Share			Per Share
First Quarter	$	183,653	$	70,696		$	43,031		$	.97		$	.96
Second Quarter		213,842		77,795			49,141			1.10			1.08
Third Quarter		239,463		83,968			53,348			1.20			1.17
Fourth Quarter (1)		160,294		(21,837	)		(11,991	)		(0.27	)		(0.27	)
	$	797,252	$	210,622		$	133,529		$	3.00		$	2.94

2007
First Quarter	$	116,369	$	31,149		$	18,855		$	0.43		$	0.42
Second Quarter		127,293		85,778			51,957			1.18			1.16
Third Quarter		130,974		42,273			26,855			0.61			0.60
Fourth Quarter		148,383		51,431			32,261			0.73			0.71
	$	523,019	$	210,631		$	129,928		$	2.95		$	2.89

(1) Includes $38.5 million of bad debt expense related to the allowance for bad debt taken for the bankruptcy of BWOC.

23. 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	2008		2007		2006
Proved properties	$	667,996	$	-	$	33,390
Unproved properties		-		56,247		224,450
Development (1)		385,599		278,398		277,613
Exploration (2)		32,909		23,325		22,435
	$	1,086,504	$	357,970	$	557,888

(1) Development costs include $0.1 million, $1.2 million and $0.5 million charged to expense during 2008, 2007 and 2006, respectively.
(2) Exploration costs include $2.4 million, $5.2 million and $3.8 million that were charged to expense during 2008, 2007 and 2006, respectively. Exploration costs include $23.2 million and $18.1 million of capitalized interest in 2008 and 2007, respectively.

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

	2008			2007			2006
Sales to unaffiliated parties	$	697,977		$	467,400		$	430,497
Production costs		(229,996	)		(158,433	)		(132,298	)
Depreciation, depletion and amortization		(138,237	)		(93,691	)		(67,668	)
Dry hole, abandonment, impairment and exploration		(12,316	)		(13,657	)		(12,009	)
		317,428			201,619			218,522
Income tax expense		(116,179	)		(77,250	)		(85,970	)

Results of operations from producing and exploration activities	$	201,249		$	124,369		$	132,552

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, 2008, 2007 and 2006. 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, 2008, 2007 and 2006, and changes in such quantities during each of the years then ended were as follows (in thousands):

	2008						2007						2006
	Oil		Gas				Oil		Gas				Oil		Gas
	Mbbl		MMcf		MBOE		Mbbl		MMcf		MBOE		Mbbl		MMcf		MBOE
Proved developed and Undeveloped reserves:
Beginning of year	116,602		315,464		169,179		112,538		226,363		150,262		103,733		135,311		126,285
Revision of previous estimates	(10,211	)	(41,570	)	(17,139	)	(3,826	)	3,358		(3,262	)	(512	)	(222	)	(553	)
Improved recovery	7,600		-		7,600		4,500		-		4,500		11,900		-		11,900
Extensions and discoveries	18,700		145,800		43,000		17,300		101,400		34,200		4,100		78,000		17,100
Property sales	-		-		-		(6,700	)	-		(6,700	)	-		-		-
Production	(7,440	)	(25,559	)	(11,700	)	(7,210	)	(15,657	)	(9,819	)	(7,183	)	(12,526	)	(9,270	)
Purchase of reserves in place	-		330,000		55,000		-		-		-		500		25,800		4,800
End of year	125251		724,135		245,940		116,602		315,464		169,179		112,538		226,363		150,262

Proved developed reserves:
Beginning of year	78,339		147,346		102,897		84,782		104,934		102,270		78,308		70,519		90,061
End of year	74,616		361,575		134,879		78,339		147,346		102,897		84,782		104,934		102,270

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):

	2008			2007			2006
Future cash inflows	$	7,384,692		$	11,211,151		$	6,195,547
Future production costs		(2,920,664	)		(3,275,397	)		(2,497,785	)
Future development costs		(1,196,394	)		(812,070	)		(511,886	)
Future income tax expense		(511,291	)		(2,286,296	)		(892,669	)
Future net cash flows		2,756,343			4,837,388			2,293,207
10% annual discount for estimated timing of cash flows		(1,620,762	)		(2,417,882	)		(1,110,939	)
Standardized measure of discounted future net cash flows	$	1,135,581		$	2,419,506		$	1,182,268
Average sales prices at December 31:
Oil ($/Bbl)	$	30.03		$	79.19		$	46.15
Gas ($/Mcf)	$	4.85		$	6.27		$	4.45
BOE Price	$	30.92		$	66.27		$	41.23

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

	2008			2007			2006
Standardized measure - beginning of year	$	2,419,506		$	1,182,268		$	1,251,380

Sales of oil and gas produced, net of production costs		(497,866	)		(326,174	)		(300,619	)
Revisions to estimates of proved reserves:
Net changes in sales prices and production costs		(2,686,941	)		1,451,140			(350,877	)
Revisions of previous quantity estimates		(144,466	)		(78,758	)		(7,359	)
Improved recovery		64,058			108,655			158,213
Extensions and discoveries		362,435			825,775			227,348
Change in estimated future development costs		(493,778	)		(385,656	)		(333,663	)
Purchases of reserves in place		667,862			-			33,390
Sales of reserves in place		-			(98,680	)		-
Development costs incurred during the period		397,601			281,702			277,075
Accretion of discount		354,672			162,257			125,138
Income taxes		631,372			(687,103	)		109,918
Other		61,126			(15,920	)		(7,676	)

Net increase (decrease)		(1,283,925	)		1,237,238			(69,112	)

Standardized measure - end of year	$	1,135,581		$	2,419,506		$	1,182,268