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BERRY PETROLEUM COMPANY FORM 10-Q FOR THE FIRST QUARTER ENDED 03-31-07

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2007

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

For the transition period from __to ___

Commission file number 1-9735

BERRY PETROLEUM COMPANY

(Exact name of registrant as specified in its charter)

	DELAWARE		77-0079387
	(State of incorporation or organization)		(I.R.S. Employer Identification Number)

5201 Truxtun Avenue, Suite 300

Bakersfield, California 93309

(Address of principal executive offices, including zip code)

Registrant's telephone number, including area code: (661) 616-3900

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

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

Large accelerated filerx Accelerated filero Non-accelerated filero

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

As of April 18, 2007, the registrant had 42,196,896 shares of Class A Common Stock ($.01 par value) outstanding. The registrant also had 1,797,784 shares of Class B Stock ($.01 par value) outstanding on April 18, 2007 all of which is held by an affiliate of the registrant.

BERRY PETROLEUM COMPANY

FIRST QUARTER 2007 FORM 10-Q

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION		Page

	Item 1. Financial Statements

	Unaudited Condensed Balance Sheets at March 31, 2007 and December 31, 2006	3

	Unaudited Condensed Statements of Income for the Three Month Periods Ended March 31, 2007 and 2006	4

	Unaudited Condensed Statements of Comprehensive Income for the Three Month Periods Ended March 31, 2007 and 2006	4

	Unaudited Condensed Statements of Cash Flows for the Three Month Periods Ended March 31, 2007 and 2006	5

	Notes to Unaudited Condensed Financial Statements	6

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	10

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	18

	Item 4. Controls and Procedures	20





PART II. OTHER INFORMATION

	Item 1. Legal Proceedings	21

	Item 1A. Risk Factors	21

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	21

	Item 3. Defaults Upon Senior Securities	21

	Item 4. Submission of Matters to a Vote of Security Holders	21

	Item 5. Other Information	21

	Item 6. Exhibits	21

BERRY PETROLEUM COMPANY

Unaudited Condensed Balance Sheets

(In Thousands, Except Share Information)

		March 31, 2007			December 31, 2006
ASSETS
Current assets:
Cash and cash equivalents	$	95		$	416
Short-term investments		665			665
Accounts receivable		77,893			67,905
Deferred income taxes		5,415			-
Fair value of derivatives		7,936			7,349
Assets held for sale		8,870			8,870
Prepaid expenses and other		15,813			13,604
Total current assets		116,687			98,809
Oil and gas properties (successful efforts basis), buildings and equipment, net		1,142,892			1,080,631
Fair value of derivatives		700			2,356
Other assets		16,618			17,201
	$	1,276,897		$	1,198,997
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	63,884		$	69,914
Property acquisition payable		54,400			54,400
Revenue and royalties payable		13,801			45,845
Accrued liabilities		24,848			20,415
Line of credit		7,000			16,000
Other current liabilities		1,691			-
Deferred income taxes		-			745
Fair value of derivatives		22,942			8,084
Total current liabilities		188,566			215,403
Long-term liabilities:
Deferred income taxes		102,758			103,515
Long-term debt		470,000			390,000
Abandonment obligation		30,958			26,135
Unearned revenue		1,133			1,437
Other long-term liabilities		9,290			-
Fair value of derivatives		39,936			34,807
		654,075			555,894
Shareholders' equity:
Preferred stock, $.01 par value, 2,000,000 shares authorized; no shares outstanding		-			-
Capital stock, $.01 par value:
Class A Common Stock, 100,000,000 shares authorized; 42,191,896 shares issued and outstanding (42,098,551 in 2006)		422			421
Class B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and outstanding (liquidation preference of $899)		18			18
Capital in excess of par value		53,594			50,166
Accumulated other comprehensive loss		(32,347	)		(19,977	)
Retained earnings		412,569			397,072
Total shareholders' equity		434,256			427,700
	$	1,276,897		$	1,198,997

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

BERRY PETROLEUM COMPANY

Unaudited Condensed Statements of Income

Three Month Periods Ended March 31, 2007 and 2006

(In Thousands, Except Per Share Data)

		Three months ended March 31,
		2007			2006 (1)
REVENUES
Sales of oil and gas	$	101,773		$	101,932
Sales of electricity		14,596			15,169
Interest and other income, net		1,110			493
		117,479			117,594
EXPENSES
Operating costs - oil and gas production		33,610			25,738
Operating costs - electricity generation		14,170			14,332
Production taxes		3,815			3,233
Depreciation, depletion & amortization - oil and gas production		18,725			13,223
Depreciation, depletion & amortization - electricity generation		762			767
General and administrative		10,307			8,314
Interest		4,292			1,577
Commodity derivatives		-			4,828
Dry hole, abandonment, impairment and exploration		649			7,498
		86,330			79,510
Income before income taxes		31,149			38,084
Provision for income taxes		12,294			14,833

Net income	$	18,855		$	23,251

Basic net income per share	$	.43		$	.53

Diluted net income per share	$	.42		$	.52

Dividends per share	$	.075		$	.065

Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share)		43,916			43,988
Effect of dilutive securities:
Equity based compensation		603			918
Director deferred compensation		112			98
Weighted average number of shares of capital stock used to calculate diluted net income per share		44,631			45,004

Unaudited Condensed Statements of Comprehensive Income
Three Month Periods Ended March 31, 2007 and 2006
(In Thousands)
Net income	$	18,855		$	23,251
Unrealized gains (losses) on derivatives, net of income taxes of ($7,885) and ($14,184), respectively		(11,828	)		(21,276	)
Reclassification of realized losses included in net income net of income taxes of ($361) and ($2,545), respectively		(542	)		(3,818	)
Comprehensive income	$	6,485		$	(1,843	)

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

(1) The 2006 per share and share amounts have been restated to give retroactive effect to the two-for-one stock split that became effective on May 17, 2006. See Note 2.

BERRY PETROLEUM COMPANY

Unaudited Condensed Statements of Cash Flows

Three Month Periods Ended March 31, 2007 and 2006

(In Thousands)

		Three months ended March 31,
		2007			2006
Cash flows from operating activities:
Net income	$	18,855		$	23,251
Depreciation, depletion and amortization		19,487			13,990
Dry hole		188			5,209
Abandonment and impairment		(256	)		(224	)
Commodity derivatives		439			4,828
Stock-based compensation expense, net of taxes		1,792			1,014
Deferred income taxes, net		12,311			7,464
Other, net		209			52
(Increase) in current assets other than cash, cash equivalents and short-term investments		(13,289	)		(1,936	)
(Decrease) in current liabilities other than book overdraft, line of credit, property acquisition payable and fair value of derivatives		(28,119	)		(28,331	)
Net cash provided by operating activities		11,617			25,317
Cash flows from investing activities:
Exploration and development of oil and gas properties		(73,472	)		(41,345	)
Property acquisitions		(1,088	)		(159,016	)
Additions to vehicles, drilling rigs and other fixed assets		(1,018	)		(5,723	)
Deposit on potential sale of asset		3,000			-
Capitalized interest and other		(3,998	)		-
Net cash used in investing activities		(76,576	)		(206,084	)
Cash flows from financing activities:
Proceeds from issuance of line of credit		21,000			51,000
Payment of line of credit		(30,000	)		(53,000	)
Proceeds from issuance of long-term debt		90,000			219,750
Payment of long-term debt		(10,000	)		(45,750	)
Dividends paid		(3,295	)		(2,867	)
Change in book overdraft		(4,711	)		9,881
Repurchase of shares of common stock		-			(1,802	)
Proceeds from stock option exercises		1,148			1,144
Excess tax benefit and other		496			1,806
Net cash provided by financing activities		64,638			180,162

Net decrease in cash and cash equivalents		(321	)		(605	)
Cash and cash equivalents at beginning of year		416			1,990
Cash and cash equivalents at end of period	$	95		$	1,385
Supplemental non-cash activity:
(Decrease) in fair value of derivatives:
Current (net of income taxes of $5,358 and $5,468, respectively)	$	(8,037	)	$	(8,203	)
Non-current (net of income taxes of $2,889 and $11,261, respectively)		(4,333	)		(16,891	)
Net (decrease) to accumulated other comprehensive income	$	(12,370	)	$	(25,094	)

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

BERRY PETROLEUM COMPANY

Notes to the Unaudited Condensed Financial Statements

1. General

All adjustments which are, in the opinion of Management, necessary for a fair statement of Berry Petroleum Company’s (the “Company”) financial position at March 31, 2007 and December 31, 2006 and results of operations and cash flows for the three month periods ended March 31, 2007 and 2006 have been included. All such adjustments are of a normal recurring nature. The results of operations and cash flows are not necessarily indicative of the results for a full year.

The accompanying unaudited condensed financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2006 financial statements. The December 31, 2006 Form 10-K should be read in conjunction herewith. The year-end condensed balance sheet was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Our cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at March 31, 2007, December 31, 2006 and March 31, 2006 is $12.5 million, $17.2 million and $11.8 million, respectively, representing outstanding checks in excess of the bank balance (book overdraft).

In December 2004, Statement of Financial Accounting Standards (SFAS) No. 123(R), Share-Based Payment, was issued which establishes standards for transactions in which an entity exchanges its equity instruments for goods or services. As a result, we adopted this statement 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. Accordingly, the adoption of SFAS No. 123(R) using the modified prospective method did not have a material impact on our condensed financial statements for the year ended December 31, 2006. We previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation effective January 1, 2004. The modified prospective method was selected as described in SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, we recognized stock option compensation expense as if it had applied the fair value method to account for unvested stock options from its original effective date.

2. Stock Split

On March 1, 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 on June 2, 2006 each shareholder received one additional share for each share owned 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.

3. Recent Accounting Developments

In June 2006, the 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. This interpretation is effective for fiscal years beginning after December 15, 2006, and we adopted this interpretation in the first quarter of 2007. See Note 6.

In September 2006, SFAS No. 157, Fair Value Measurements was issued by the Financial Accounting Standards Board (FASB). This statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 will become effective for our fiscal year beginning January 1, 2008, and we are currently assessing the potential impact of this Statement on our financial statements.

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

BERRY PETROLEUM COMPANY

Notes to the Unaudited Condensed Financial Statements

3. Recent Accounting Developments (Cont’d)

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

4. Hedging

The related cash flow impact of all of our hedges are reflected in cash flows from operating activities. At March 31, 2007, our net fair value of derivatives liability was $54.2 million as compared to $33.2 million at December 31, 2006. At March 31, 2007, Accumulated Other Comprehensive Loss consisted of $32.3 million, net of tax, of unrealized losses from our crude oil and natural gas swaps and collars that qualified for hedge accounting treatment at March 31, 2007. Deferred net losses recorded in Accumulated Other Comprehensive Loss at March 31, 2007 and subsequent marked-to-market changes in the underlying hedging contracts are expected to be reclassified to earnings over the life of these contracts. Our liability is primarily related to the time value of the underlying instruments and based on current prices the amount expected to be reclassified to earnings over the next 12 months is not significant.

As of February 28, 2007, we have converted 2,000 Bbl/D of our 2007 oil collars beginning on March 1, 2007 to a swap with a strike price of $60 West Texas Intermediate (WTI). This swap is considered to be an effective cash flow hedge. Additionally, we entered into oil swaps for 1,000 Bbl/D at $64.55 from March 2007 through December 2007 and entered into oil collars for 1,000 Bbl/D at $60 floor and $75 ceiling prices for 2010.

Additionally, on June 8, 2006 and July 10, 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.

5. Asset Retirement Obligations

Inherent in the fair value calculation of the asset retirement obligation (ARO) are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. In 2007, we reassessed our estimate as costs have increased due to demand for related services, resulting in an increase in the ARO balance at quarter end.

Under SFAS 143, the following table summarizes the change in abandonment obligation for the quarter ended March 31, 2007 (in thousands):


Beginning balance at January 1	$	26,135
Liabilities incurred		1,274
Liabilities settled		(256	)
Revisions in estimated liabilities		3,272
Accretion expense		533

Ending balance at March 31	$	30,958

BERRY PETROLEUM COMPANY

Notes to the Unaudited Condensed Financial Statements

6. Income Taxes

The effective tax rate was 39% for the first quarter of 2007 compared to 38% for the fourth quarter of 2006 and 39% for the first quarter of 2006.

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

We adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no material adjustment to retained earnings. As of the date of adoption, we had a gross liability for uncertain tax benefits of $14.6 million of which $10.8 million if recognized, would affect the effective tax rate. We recognize potential accrued interest and penalties related to unrecognized tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. As of January 1, 2007, we had accrued approximately $.9 million of interest related to our uncertain tax positions.

We have not had any material changes to our unrecognized tax benefits since adoption, nor do we anticipate significant changes to the total amount of unrecognized tax benefits within the next 12 months.

As of January 1, 2007, we remain subject to examination in the following major tax jurisdictions for the tax years indicated below:

Jurisdiction:	Tax Years Subject to Exam:
Federal	2003 - 2006
California	2002 - 2006
Colorado	2002 - 2006
Utah	2003 - 2006

7. Long-term and Short-term Obligations

Long-term debt

In October 2006, we issued in a public offering $200 million of 8.25% senior subordinated notes due 2016 (the Notes). 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. The net proceeds from the offering were used to 1) repay approximately $145 million of borrowings under the bank credit facility, which were $170 million as of the issuance date after the application of this payment, and 2) approximately $50 million was used to pay the November 1, 2006 installment under the joint venture agreement to develop properties in the Piceance basin.

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

The total outstanding debt under the credit facility’s borrowing base was $270 million and the short-term line of credit was $7 million at March 31, 2007, leaving $223 million in borrowing capacity available. Interest on amounts borrowed under this debt is charged at LIBOR plus a margin of 1.00% to 1.75% or the prime rate, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. We are required under the Agreement to pay a commitment fee of .25% to .375% on the unused portion of the credit facility annually.

BERRY PETROLEUM COMPANY

Notes to the Unaudited Condensed Financial Statements

7. Long-term and Short-term Obligations (Cont’d)

The Agreement contains restrictive covenants which, among other things, require us to maintain a certain debt to EBITDA ratio and a minimum current ratio, as defined. The $200 million Notes are subordinated to our credit facility indebtedness. Our Notes covenants limit debt to the greater of $750 million or 40% of Adjusted Consolidated Net Tangible Assets (as defined). Additionally, as long as the interest coverage ratio (as defined) is met, we may incur additional debt. We were in compliance with all such covenants as of March 31, 2007. The weighted average interest rate on the long-term outstanding credit facility borrowings at March 31, 2007 was 6.6%.

Short-term debt

In November 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. The Line of Credit may be terminated at any time upon written notice by either us or the lender. At March 31, 2007 the outstanding balance under this Line of Credit was $7 million. Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1%. The weighted average interest rate on outstanding borrowings on the Line of Credit at March 31, 2007 was 6.2%.

8. Contingencies and Commitments

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 accrued. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not require substantial accruals. 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 operations or liquidity.

On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly Corporation (Holly) for a portion of our Uinta basin crude oil. Under the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July 1, 2007. Upon completion of their Woods Cross refinery expansion in Salt Lake City, which is expected in late 2008, Holly will increase total purchased volumes to 5,000 Bbl/D through June 30, 2013. During the term of the contract, the minimum number of delivered units (“base daily volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion of the refinery upgrade. Holly may, but is not obligated to, purchase volumes in excess of the base daily volumes when notified by us at the beginning of any contract year.

9. Assets Held for Sale

Net oil and gas properties and equipment classified as held for sale is $8.9 million at March 31, 2007 in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. On March 19, 2007 we announced that we have entered into an agreement to sell our non-core West Montalvo assets, near Ventura, California. We estimate a sales price of approximately $63 million before adjustments and expect to transfer the properties in the second quarter of 2007. The completion of the transaction is subject to certain conditions and there is no assurance that all such conditions will be satisfied.

10. Subsequent Event

We paid the third and final installment of approximately $54 million utilizing our credit facility on May 1, 2007 for the North Parachute Ranch property located in the Piceance basin.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General. The following discussion provides information on the results of operations for the three month periods ended March 31, 2007 and 2006 and our financial condition, liquidity and capital resources as of March 31, 2007. The financial statements and the notes thereto contain detailed information that should be referred to in conjunction with this discussion.

The profitability of our operations in any particular accounting period will be directly related to the realized prices of oil, gas and electricity sold, the type and volume of oil and gas produced and electricity generated and the results of development, exploitation, acquisition, exploration and hedging activities. The realized prices for natural gas and electricity will fluctuate from one period to another due to regional market conditions and other factors, while oil prices will be predominantly influenced by world supply and demand. The aggregate amount of oil and gas produced may fluctuate based on the success of development and exploitation of oil and gas reserves pursuant to current reservoir management. The cost of natural gas used in our steaming operations and electrical generation, production rates, labor, equipment costs, maintenance expenses, and production taxes are expected to be the principal influences on operating costs. Accordingly, our results of operations may fluctuate from period to period based on the foregoing principal factors, among others.

Overview. Our mission is to increase shareholder value through consistent growth in our production and reserves, both through the drill bit and acquisitions. We strive to operate our properties in an efficient manner to maximize the cash flow and earnings of our assets. The strategies to accomplish these goals include:

·	Developing our existing resource base

·	Acquiring additional assets with significant growth potential

·	Utilizing joint ventures with respected partners to enter new basins

·	Accumulating significant acreage positions near our producing operations

·	Investing our capital in a disciplined manner and maintaining a strong financial position

Notable First Quarter Items.

·	Production averaged 25,490 BOE/D, up 9% from the first quarter of 2006

·	Entered into a long-term crude oil sales contract for our Uinta basin, Utah production

·	Restored Uinta basin production to approximately 6,000 BOE/D from a low of 3,800 BOE/D in January 2007

·	Production at Midway-Sunset diatomite averaged 600 Bbl/D compared to 400 Bbl/D in the fourth quarter of 2006

·	Improvements made in the Piceance basin program in personnel, services, rigs, drilling and completions

·	Entered into an agreement to sell our non-core West Montalvo assets, near Ventura, California for an estimated sales price of approximately $63 million cash before adjustments

Notable Items and Expectations for the Second Quarter of 2007.

·	Completing over 20 Piceance basin wells with total Piceance net production estimated at 9.6 MMcf/D

·	Production at Midway-Sunset diatomite is approaching 1,000 BOE/D and the steam to oil ratio is improving

·	Accelerating Poso Creek development by drilling 40 wells and installing an additional steam generator

·	Transferring Montalvo properties with proceeds estimated at $63 million before adjustments

·	Production is projected to average between 26,500 BOE/D and 27,500 BOE/D for the second quarter of 2007

Overview of the First Quarter of 2007. In the first quarter we were unable to sell all of our Uinta basin production due to a refinery shutdown. On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly for a portion of our Uinta basin crude oil. This contract will allow us to stabilize our basis differentials on these barrels beginning on July 1, 2007 and assures us of the ability to sell this regional crude oil. Our activities in the Piceance basin included completion of a pipeline. Eleven wells have been connected since the pipeline was completed, allowing production to rise to over 8.5 net MMcf/D in April from 6.4 net MMcf/D in the first quarter of 2007.

View to the Second Quarter. Our 2007 drilling program will continue to drive our production growth. Operationally, we are focused on executing our drilling program on our Piceance basin asset where we expect to drill 16 wells during the second quarter of 2007. Furthermore, based on higher than expected performance at Poso Creek, we are planning to accelerate development there by drilling 40 wells and installing a third steam generator during the second quarter. On May 1, 2007, the final installment for our Piceance basin joint venture was paid.

Results of Operations. The following companywide results are in millions (except per share data) for the three months ended:

	March 31, 2007 (1Q07)		March 31, 2006 (1Q06)		1Q07 to 1Q06 Change	December 31, 2006 (4Q06)		1Q07 to 4Q06 Change
Sales of oil	$	80.9	$	83.3	(3%)	$	84.2	(4%)
Sales of gas		20.9		18.6	12%		17.6	19%
Total sales of oil and gas	$	101.8	$	101.9	-%	$	101.8	-%
Sales of electricity		14.6		15.2	(4%)		13.4	9%
Interest and other income, net		1.1		.5	120%		1.0	10%
Total revenues and other income	$	117.5	$	117.6	-%	$	116.2	1%
Net income	$	18.9	$	23.3	(19%)	$	19.1	(1%)
Net income per share (diluted)	$	.42	$	.52	(19%)	$	.43	(2%)

Our revenues may vary significantly from period to period as a result of changes in commodity prices and/or production volumes. For the three months ended March 31, 2007, gas sales improved while oil sales declined when compared to three months ended March 31, 2006. Improvement to gas sales is due to higher production primarily from our Piceance basin acquisition, partially offset by lower gas prices. Oil sales decreased due to lower prices partially offset by higher volumes primarily from our NMWSS and Poso Creek properties.

Similarly, for the three months ended March 31, 2007 compared to the three months ended December 31, 2006, gas sales improved while oil sales declined. Improvement in realized gas prices during the first three months of 2007 were due to increased weather related demand and a tighter supply and demand balance, while oil sales declined primarily due to lower production.

Operating data. The following table is for the three months ended:

		March 31, 2007	%		March 31, 2006	%		December 31, 2006	%
Oil and Gas
Heavy Oil Production (Bbl/D)		16,140	63		15,407	66		16,833	63
Light Oil Production (Bbl/D)		3,233	13		3,303	14		3,363	13
Total Oil Production (Bbl/D)		19,373	76		18,710	80		20,196	76
Natural Gas Production (Mcf/D)		36,704	24		28,507	20		40,157	24
Total (BOE/D)		25,490	100		23,461	100		26,889	100

Per BOE:
Average sales price before hedging	$	43.62		$	50.04		$	41.53
Average sales price after hedging		43.84			48.45			42.00

Oil, per Bbl:
Average WTI price	$	58.23		$	63.48		$	60.17
Price sensitive royalties		(3.74	)		(5.41	)		(4.28	)
Quality differential and other		(8.78	)		(6.36	)		(9.06	)
Crude oil hedges		.03			(2.04	)		(.01	)
Average oil sales price after hedging	$	45.74		$	49.67		$	46.82

Gas, per MMBtu:
Average Henry Hub price	$	7.18		$	7.92		$	7.24
Natural gas hedges		.13			(.03	)		.33
Location, quality differentials and other		(.70	)		(1.05	)		(2.68	)
Average gas sales price after hedging	$	6.61		$	6.84		$	4.89

Gas Basis Differential. The gas prices in the Rockies continue to be volatile due to various factors, including takeaway pipeline capacity, supply volumes, and regional demand issues. We expect the basis differential to narrow upon the startup of the Rockies Express pipeline which is anticipated in 2008. We have contracted 10,000 Mcf/D on this pipeline to provide assurance of gas delivery. The Colorado Interstate Gas (CIG) basis differential averaged $1.18 below Henry Hub (HH) and ranged from $.51 to $1.67 below HH in the first quarter. Although related to CIG, the actual basin price varies. Gas from the DJ basin was sold slightly above the CIG price, Piceance basin gas was slightly below the CIG price while Uinta basin gas sold for approximately $.40 below CIG pricing.

Oil Contracts. Utah - As of March 31, 2007, our Utah light crude oil is sold under multiple contracts with different purchasers for varying pricing terms and ranging from one month to six months. In April 2007, contracts were in place to sell approximately 5,000 BOE/D during the month. These contracts have marginally improved since December 31, 2006 and are currently priced at approximately $12 to $17 per barrel below WTI with certain volumes tied to field posting, and in some cases our realized price is further reduced by transportation charges. As operator we deliver all produced volumes pursuant to these contracts, although our working interest partners or royalty owners have the right to take their respective volumes in kind and market their own volumes. Our net volumes from our Brundage Canyon properties approximate 80% of the total gross volumes. Assuming all the Brundage Canyon wells are producing, the gross production could exceed these contracted volumes. Our Utah crude oil is a paraffinic crude and can be processed efficiently by only a limited number of refineries.

On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly for a portion of our Uinta basin crude oil. Under the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July 1, 2007. Holly has begun to take delivery of approximately 1,000 Bbl/D in the first quarter of 2007, which stabilizes our realized sales price and reduces our transportation costs. Upon completion of their Woods Cross refinery expansion in Salt Lake City, which is expected in late 2008, Holly will increase total purchased volumes to 5,000 Bbl/D through June 30, 2013. Pricing under the contract, which includes transportation, is a fixed percentage of WTI and approximates our expected field posted price of $13 to $16 below WTI. This contract provides the pricing assurance we need to proceed with the long-term development of our Uinta basin assets. From October 1, 2003 through April 30, 2006 we were able to sell our Utah crude oil at approximately $2.00 per barrel below WTI and from May 1, 2006 through September 30, 2006, we were selling the majority of our Utah crude at approximately $9.00 per barrel below WTI. We may adjust our capital expenditures in the Uinta basin due to various factors, including the timing of refinery demand for the Uinta basin barrels and the actual or expected change in our realized price.

Hedging. See Note 4 to the unaudited condensed financial statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Electricity. We consume natural gas as fuel to operate our three cogeneration facilities which are intended to provide an efficient and secure long-term supply of steam necessary for the economic production of heavy oil. Revenue and operating costs for the three months ended March 31, 2007 were down from the three months ended March 31, 2006 due to 6% lower electricity prices and 12% lower fuel gas cost, respectively. Conversely, revenue and operating costs in the three months ended March 31, 2007 were up from the three months ended December 31, 2006 due to 8% higher electricity prices and 4% higher natural gas prices, respectively. The following table is for the three months ended:

		March 31, 2007		March 31, 2006		December 31, 2006
Electricity
Revenues (in millions)	$	14.6	$	15.2	$	13.4
Operating costs (in millions)	$	14.2	$	14.3	$	12.1
Electric power produced - MWh/D		2,117		2,080		2,093
Electric power sold - MWh/D		1,914		1,884		1,861
Average sales price/MWh	$	81.08	$	85.93	$	75.05
Fuel gas cost/MMBtu (including transportation)	$	6.70	$	7.65	$	6.44

Oil and Gas Operating, Production Taxes, G&A and Interest Expenses. The following table presents information about our operating expenses for each of the three month periods ended:

	Amount per BOE						Amount (in thousands)
	March 31, 2007		March 31, 2006		December 31, 2006		March 31, 2007		March 31, 2006		December 31, 2006
Operating costs - oil and gas production	$	14.65	$	12.19	$	13.69	$	33,610	$	25,738	$	33,804
Production taxes		1.66		1.53		1.15		3,815		3,233		2,840
DD&A - oil and gas production		8.16		6.26		8.24		18,725		13,223		20,335
G&A		4.49		3.94		4.55		10,307		8,314		11,231
Interest expense		1.69		.75		1.27		4,292		1,577		3,503
Total	$	30.65	$	24.67	$	28.90	$	70,749	$	52,085	$	71,713

Our total operating costs, production taxes, G&A and interest expenses for the three months ended March 31, 2007, stated on a unit-of-production basis, increased 24% over the three months ended March 31, 2006 and increased 6% over the three months ended December 31, 2006. The changes were primarily related to the following items:

Operating costs: Operating costs per BOE in the first quarter of 2007 were 20% higher than the first quarter of 2006 primarily due to an increase in steam costs, company and contract labor as well as transportation, compression and gathering costs. Similarly, operating costs per BOE were 7% higher in the first quarter of 2007 as compared to the fourth quarter of 2006, as production volumes were down. Cost pressures do remain, but we are working to offset them with improved efficiencies. The cost of our steaming operations on our heavy oil properties in California varies depending on the cost of natural gas used as fuel and the volume of steam injected. The following table presents steam information:

	March 31, 2007	March 31, 2006	1Q07 to 1Q06 Change	December 31, 2006	1Q07 to 4Q06 Change
Average volume of steam injected (Bbl/D)	86,132	75,138	15%	85,349	1%
Fuel gas cost/MMBtu (including transportation)	$ 6.70	$ 7.65	(12%)	$ 6.44	4%

As we remain in a strong commodity price environment, we anticipate that cost pressures within our industry may continue due to greater field activity and rising service costs in general. Based on current plans, we are targeting average steam injection in 2007 of approximately 90,000 to 95,000 barrels of steam per day (BSPD). Natural gas prices impact our cost structure in California by approximately $1.60 per California BOE for each $1.00 change in natural gas price.

Production taxes: Our production taxes have increased over 2006 as the value of our oil and natural gas assets has increased. Severance taxes, which are prevalent in Utah and Colorado, are directly related to the cost of the field sales price of the commodity. In California, our production is burdened with ad valorem taxes on our total proved reserves. We expect production taxes, in general, to track the commodity price.

Depreciation, depletion and amortization: DD&A increased per BOE in the three months ended March 31, 2007 compared to the same period in the prior year due to an increase in capital spending over the last year and particularly more extensive development in fields with higher drilling costs and leasehold acquisition costs. Our capital program is also experiencing cost pressures in our labor and for goods and services commensurate with other energy developers. As these costs increase, our DD&A rates per BOE will also increase.

General and administrative: Approximately 70% of our G&A is compensation or compensation related costs. To remain competitive in workforce compensation and achieve our growth goals, our general and administrative cost increased significantly due to additional staffing, higher compensation levels, bonuses, stock compensation and benefit costs. We also incurred higher employee travel and other G&A costs associated with our growth activities.

Interest expense: Our outstanding borrowings, including our senior unsecured money market line of credit and senior subordinated notes, was $477 million at March 31, 2007 compared to $406 million at December 31, 2006. Our average borrowings increased during the three months ended March 31, 2007 as a result of our capital expenditure program and due to the annual payment of a price-based royalty for $38 million. Beginning in 2006, a certain portion of our interest cost related to our Piceance basin acquisition and joint venture has been capitalized into the basis of the assets, and we anticipate a portion will continue to be capitalized until the remainder of our probable reserves have been recategorized to proved developed reserves. For the quarter ended March 31, 2007, $4 million has been capitalized and we expect to capitalize approximately $20 million of interest cost during the full year of 2007.

Estimated 2007 Oil and Gas Operating, G&A and Interest Expenses.

	Anticipated range
	in 2007 per BOE
Operating costs-oil and gas production (1)	$	14.50 to 15.50
Production taxes		1.50 to 2.00
DD&A		7.75 to 8.75
G&A		3.50 to 4.00
Interest expense		1.00 to 2.00
Total	$	28.25 to 32.25

(1) Assuming natural gas prices of approximately NYMEX HH $7.50 MMBtu, we plan to inject approximately 15% greater steam levels in 2007 compared to 2006 levels.

Income Taxes. See Note 6 to the unaudited condensed financial statements. Our effective tax rate will be similar in 2007 as compared to 2006. We experienced an effective tax rate in the three months ended March 31, 2007 of 39%, which is in line with our projections.

Development, Exploitation and Exploration Activity. We drilled 124 gross (88 net) wells during the first quarter of 2007, realizing a gross success rate of 99 percent. Excluding any future acquisitions, our targeted 2007 developmental capital budget is between $227 million and $267 million. As of March 31, 2007, we have five rigs drilling on our properties under long-term contracts and have one more rig scheduled to begin in mid-2007.

Drilling Activity. The following table sets forth certain information regarding drilling activities for the three months ended March 31, 2007:


	Gross Wells	Net Wells
SMWSS	20	20
NMWSS	11	11
Socal	18	18
Piceance	18	5
Uinta	15	13
DJ (1)	42	21
Totals	124	88

(1)

Includes 1 gross well (.5 net well) that was a dry hole in Yuma County, Colorado.

Production

California’s three asset teams are South Midway-Sunset (SMWSS, which has been realigned to include Ethel D), North Midway-Sunset (NMWSS) (which includes diatomite) and Southern California (Socal) (which includes Poso Creek, Placerita and Montalvo). The Rocky Mountain/Mid-Continent region’s three asset teams are Piceance, Uinta and DJ basins.

SMWSS, San Joaquin Valley Basin (SJVB) - During the three months ended March 31, 2007, production averaged approximately 9,900 Bbl/D compared to approximately 10,800 Bbl/D and 10,700 Bbl/D during the three month periods ended March 31, 2006 and December 31, 2006, respectively. During the three months ended March 31, 2007, we completed four horizontal infill wells and improved subsurface steam monitoring to determine best heat placement into the remaining oil column to maximize recovery and value. Additionally, a number of horizontal wells were pulled off production for cyclic steaming. Cyclic steaming of these horizontal wells is necessary to place steam effectively into the remaining oil column. In the second quarter of 2007, we plan to drill approximately 14 infill horizontal wells. Increased production from these activities is expected to slow the natural decline. We expect to manage our decline rate to approximately 6% to 7% for 2007.

We have completed our 2007 drilling program on our Ethel D property and production has increased by over 200 Bbl/D. We may expand our program depending on reservoir performance.

NMWSS, SJVB - Our Midway-Sunset diatomite oil project is performing above expectations due to a more aggressive approach in our use of steam. During the three months ended March 31, 2007, production from the diatomite project averaged approximately 600 Bbl/D up from approximately 200 Bbl/D and 400 Bbl/D during the three month periods ended March 31, 2006 and December 31, 2006, respectively. Our 2007 capital is focused on drilling the diatomite first phase development wells and adding steam generation equipment and various facilities. Diatomite wells will not begin to be drilled until the third quarter of 2007.

Socal, SJVB and Los Angeles Basin - Poso Creek is performing solidly above plan due to strong steam flood performance and our infill drilling. During the three months ended March 31, 2007, production averaged approximately 1,500 Bbl/D up from approximately 600 Bbl/D and 1,400 Bbl/D during the three month periods ended March 31, 2006 and December 31, 2006, respectively. We are planning to accelerate development drilling with over 70 infill producing wells this year, expanding the steam drive by 14 patterns and installing a third steam generator in the second quarter of 2007.

Piceance Basin, Colorado - We currently have four drilling rigs operating in the basin and expect to maintain this level for the remainder of the year. Newly constructed pipelines to the mesa plateaus were completed late in the first quarter and since completion, three North Parachute Ranch wells and eight Garden Gulch wells have been put into production. Twelve additional wells are forecasted to be drilled and connected by the end of the second quarter of 2007. Average daily production in the Piceance basin for the first quarter was 6.4 net MMcf/D. The recent well connects have increased April monthly production to over 8.5 net MMcf/D. Significant progress has been made to lower the days required to drill wells. Construction has begun on the Garden Gulch road extension, which, coupled with the mountain road, will greatly improve access to our operations on the Garden Gulch acreage.

Uinta Basin, Utah - Our 2007 capital is directed at additional Brundage Canyon 40-acre development wells, drilling the Ashley Forest extension to the south of Brundage Canyon, continued Lake Canyon assessment and drilling 20-acre infill wells in Brundage Canyon. During the first quarter, we drilled 13 net wells in Brundage Canyon. Well performance results continue to be positive and preliminary results from four 20-acre pilot wells indicate the possibility of new production opportunities.

Average daily production during the first quarter from all Uinta basin assets was 4,800 net BOE/D. In the fourth quarter of 2006, oil sales were interrupted due to refinery and trucking limitations. The refinery resumed operations in mid-January 2007. Improved market conditions late in the first quarter resulted in a daily production exit rate of 6,100 net BOE/D for the quarter. We continue to have one drilling rig operating in the basin. In February 2007, we signed a six year oil contract with Holly for 3,200 BOE/D starting in July 2007 with up to 5,000 BOE/D through June 30, 2013 upon the certified completion of their refinery upgrade. This contract along with our other oil marketing arrangements provides us the ability to sell all of our crude oil production in the Uinta basin.

Post winter season access to our Ashley Forest acreage and Lake Canyon area will open up in May of 2007, with our second and third quarter drilling focusing in these areas. Six drilling permits have been received for Ashley Forest and four permits received for Lake Canyon wells with an additional 16 permits anticipated in the second quarter to support the mid-May to December drilling window.

In December 2004, we entered into a development agreement with an industry partner to develop their Coyote Flats prospect. In the first and early second quarter of 2006, we established gas sales from three Ferron wells. The combined net production from the three wells is approximately 1.0 MMcf/D. We will continue the production tests to further assess the Ferron’s potential at Coyote Flats. As the result of establishing production in the three wells, we were assigned a 50% interest in approximately 43,700 gross acres from our industry partner.

DJ Basin - Our first quarter activity in the DJ basin has focused on Niobrara development drilling in Yuma County, Colorado. Production early in the quarter was hampered by severe snow on Colorado’s eastern plains. Average daily production in the DJ for the first quarter was 17.4 net MMcf/D and by the end of the quarter, production has recovered to approximately 18 MMcf/D.

We drilled 41 Niobrara wells during the first quarter of 2007. In addition, 28.5 square miles of 3-D seismic data was acquired in the quarter. This 3-D data and the existing drilling location inventory supports the 2007 drilling program of 168 wells.

Company Owned Drilling Rigs. During 2005 and 2006, we purchased three drilling rigs, two of which are drilling for us. Owning these rigs allows us to successfully meet a portion of our drilling needs in the Uinta and Piceance basins.

Financial Condition, Liquidity and Capital Resources. Substantial capital is required to replace and grow reserves. We achieve reserve replacement and growth primarily through successful development and exploration drilling and the acquisition of properties. Fluctuations in commodity prices have been the primary reason for short-term changes in our cash flow from operating activities. The net long-term growth in our cash flow from operating activities is the result of growth in production as affected by period to period fluctuations in commodity prices. In the second quarter of 2006, we revised our senior unsecured revolving credit facility to increase

our maximum credit amount under the facility to $750 million and increased our current borrowing base to $500 million. On October 24, 2006, we completed the sale of $200 million of ten year 8.25% senior subordinated notes and paid down our borrowings under our facility by $141 million. As of March 31, 2007, we had total borrowings under the senior unsecured revolving credit facility and senior unsecured money market line of credit of $277 million and $200 million under our senior subordinated ten year notes.

Capital Expenditures. We establish a capital budget for each calendar year based on our development opportunities and the expected cash flow from operations for that year. Acquisitions are typically debt financed. We may revise our capital budget during the year as a result of acquisitions, drilling outcomes and/or changes in commodity prices that influence our decision to change capital expenditures to closely match operating cash flows. Excess cash generated from operations is expected to be applied toward capital expenditures, debt reduction or other corporate purposes.

Management is closely monitoring the capital development program in relation to estimated cash flows and expects to commit capital in the $227 million to $267 million range, excluding acquisitions. The capital development program may be revised due to lower commodity price expectations, timing of crude deliveries out of the Uinta basin, equipment availability, permitting or other factors. We have reevaluated the development plan in the Piceance basin to maximize capital efficiency by minimizing rig moves. Consequently, we estimate that companywide proved reserves will approximate 170 to 180 million BOE at year end 2007, including the effect of the expected sale of the Montalvo assets which consist of 7 million BOE of reserves. During the three months ended March 31, 2007, capital expenditures totaled $75.5 million of which $28 million related to the 2007 capital budget and $47.5 million related to the 2006 capital budget.

Our 2007 expenditures will be directed toward developing reserves, increasing oil and gas production and exploration opportunities. For 2007, we plan to invest up to approximately $176 million, or 66%, in our Rocky Mountain/Mid-Continent region assets, and up to $91 million, or 34%, in our California assets.

On March 19, 2007 we announced that we have entered into an agreement to sell our non-core West Montalvo assets, near Ventura, California. We estimate a sales price of approximately $63 million before adjustments and expect to transfer the assets in the second quarter of 2007. Production from the property is approximately 700 BOE/D, which is less than 3% of current production and, as of December 31, 2006, the property had 7 million BOE of proved reserves which is less than 5% of the 2006 year end total of 150 million BOE. The completion of the transaction is subject to certain conditions and there is no assurance that all such conditions will be satisfied.

Dividends. Our annual dividend is currently $.30 per share, payable quarterly in March, June, September and December.

Working Capital and Cash Flows. Cash flow from operations is dependent upon the price of crude oil and natural gas and our ability to increase production and manage costs. Combined crude oil and natural gas prices increased in the first three months of 2007 (see graphs on page 11) and production decreased since December 2006 by 5%.

Our working capital balance fluctuates as a result of the amount of borrowings and the timing of repayments under our credit arrangements. We used our long-term borrowings under our senior unsecured revolving credit facility primarily to fund property acquisitions. Generally, we use excess cash to pay down borrowings under our credit arrangement. As a result, we often have a working capital deficit or a relatively small amount of positive working capital.

The table below compares financial condition, liquidity and capital resources changes for the three month periods ended (in millions, except for production and average prices):

	March 31, 2007 (1Q07)	March 31, 2006 (1Q06)	1Q07 to 1Q06 Change	December 31, 2006 (4Q06)	1Q07 to 4Q06 Change
Average production (BOE/D)	25,490	23,461	9%	26,889	(5%)
Average oil and gas sales prices, per BOE after hedging	$ 43.84	$ 48.45	(10%)	$ 42.00	4%
Net cash provided by operating activities	$ 12	$ 25	(52%)	$ 58	(79%)
Working capital, excluding line of credit	$ (65)	$ (50)	(30%)	$ (101)	36%
Sales of oil and gas	$ 102	$ 102	-%	$ 102	-%
Long-term debt, including line of credit	$ 477	$ 259	84%	$ 406	17%
Capital expenditures, including acquisitions and deposits on acquisitions	$ 76	$ 206	(63%)	$ 127	(40%)
Dividends paid	$ 3.3	$ 2.9	14%	$ 3.3	-%

Contractual Obligations. Our contractual obligations as of March 31, 2007 are as follows (in millions):

		Total		2007		2008		2009		2010		2011		Thereafter
Long-term debt and interest	$	715.1	$	34.3	$	34.3	$	34.3	$	34.3	$	295.4	$	282.5
Abandonment obligations		30.9		.7		.9		1.0		1.0		1.0		26.3
Property acquisition payable		54.4		54.4		-		-		-		-		-
Operating lease obligations		13.9		1.4		1.7		1.4		1.4		1.4		6.6
Drilling and rig obligations		89.8		19.6		25.3		42.7		2.2		-		-
Firm natural gas
transportation contracts		72.7		3.6		7.6		8.5		8.7		8.7		35.6
Total	$	976.8	$	114.0	$	69.8	$	87.9	$	47.6	$	306.5	$	351.0

Long-term debt and interest - Our credit facility borrowings and related interest of approximately 6.6% can be paid before its maturity date without significant penalty on borrowings under our credit facility. Our 8.25% senior subordinated notes mature in November 2016, but are not redeemable until November 1, 2011 and are not redeemable without any premium until November 1, 2014.

Operating leases - We lease corporate and field offices in California, Colorado and Texas. We lease an airplane for business travel under a ten year operating lease beginning December 2006.

Drilling obligation - We intend to participate in the drilling of over 16 gross wells on our Lake Canyon prospect over the four year contract, beginning in 2006. Our minimum expenditure obligation under our exploration and development agreement is $9.6 million. Also included above, under our June 2006 joint venture agreement in the Piceance basin, we must have 120 wells drilled by 2010 to avoid penalties of $.2 million per well or a maximum of $24 million.

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

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

On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly for a portion of our Uinta basin crude oil. Under the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July 1, 2007. Upon completion of their Woods Cross refinery expansion in Salt Lake City, which is expected in late 2008, Holly will increase their total purchased volumes to 5,000 Bbl/D through June 30, 2013. During the term of the contract, the minimum number of delivered units (“base daily volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion of the refinery upgrade. Holly may, but is not obligated to, purchase volumes in excess of the base daily volumes when notified by us at the beginning of any contract year.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

As discussed in Note 4 to the unaudited condensed financial statements, 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. The terms of contracts depend on various factors, including management's view of future crude oil and natural gas prices, acquisition economics on purchased assets and our future financial commitments. This price hedging program is designed to moderate the effects of a severe crude oil and natural gas price downturn while allowing us to participate in any commodity price increases. In California, we benefit from lower natural gas pricing as we are a consumer of natural gas in our operations and elsewhere, we benefit from higher natural gas pricing. We have hedged, and may hedge in the future both natural gas purchases and sales as determined appropriate by management. Management regularly monitors the crude oil and natural gas markets and our financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging and/or basis adjustments or other price protection is appropriate in accordance with policy established by our board of directors.

Currently, our hedges are in the form of swaps and collars. However, we may use a variety of hedge instruments in the future to hedge WTI or the index gas price. We have crude oil sales contracts in place which are priced based on a correlation to WTI. Natural gas (for cogeneration and conventional steaming operations) is purchased at the SoCal border price and we sell our produced gas in Colorado and Utah at CIG and Questar index prices, respectively.

The following table summarizes our hedge position as of March 31, 2007:

	Average			Average
	Barrels	Floor/Ceiling		MMBtu	Floor/Ceiling
Term	Per Day	Prices	Term	Per Day	Prices
Crude Oil Sales (NYMEX WTI)			Natural Gas Sales (NYMEX HH)
Collars			Collars
Full year 2007	8,000	$47.50 / $70.00	2^nd Quarter 2007	13,000	$8.00 / $8.82
Full year 2008	10,000	$47.50 / $70.00	3^rd Quarter 2007	14,000	$8.00 / $9.10
Full year 2009	10,000	$47.50 / $70.00	4^th Quarter 2007	15,000	$8.00 / $11.39
Full year 2010	5,000	$56.00 / $78.95	1^st Quarter 2008	16,000	$8.00 / $15.65
Full year 2010	1,000	$60.00 / $75.00	2^nd Quarter 2008	17,000	$7.50 / $8.40
			3^rd Quarter 2008	19,000	$7.50 / $8.50
			4^th Quarter 2008	21,000	$8.00 / $9.50

			Natural Gas Sales (NYMEX HH TO CIG)
Swaps		Price	Basis Swaps		Price
2^nd through 4^th quarter 2007	1,000	$64.55	April 2007	13,000	$1.77
2^nd through 4^th quarter 2007	2,000	$60.00	May 2007	13,000	$1.70
			June 2007	13,000	$1.69
			July 2007	14,000	$1.56
			August 2007	14,000	$1.51
			September 2007	14,000	$1.58
			October 2007	15,000	$1.63
			November & December 2007	15,000	$1.71
			1^st Quarter 2008	16,000	$1.74
			2^nd Quarter 2008	17,000	$1.43
			3^rd Quarter 2008	19,000	$1.40
			4^th Quarter 2008	21,000	$1.46

The collar strike prices will allow us to protect a significant portion of our future cash flow if 1) oil prices decline below $47.50 per barrel while still participating in any oil price increase up to $78.95 per barrel on these volumes and if 2) gas prices decline below approximately $8 per MMBtu. These hedges improve our financial flexibility by locking in significant revenues and cash flow upon a substantial decline in crude oil or natural gas prices. It also allows us to develop our long-lived assets and pursue exploitation opportunities with greater confidence in the projected economic outcomes and allows us to borrow a higher amount under our senior unsecured revolving credit facility.

While we have designated our hedges as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, it is possible that a portion of the hedge related to the movement in the WTI to California heavy crude oil price differential may be determined to be ineffective. Likewise, we may have some ineffectiveness in our natural gas hedges due to the movement of HH pricing as compared to actual sales points. If this occurs, the ineffective portion will directly impact net income rather than being reported as Other Comprehensive Income. While we believe that the differential will narrow and move closer toward its historical level over time, there are no assurances as to the movement in the differential. If the differential were to change significantly, it is possible that our hedges, when marked-to-market, could have a material impact on earnings in any given quarter and, thus, add increased volatility to our net income. The marked-to-market values reflect the liquidation values of such hedges and not necessarily the values of the hedges if they are held to maturity.

We entered into derivative contracts (natural gas swaps and collar contracts) on March 1, 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 the first quarter of 2006 at their fair value on the balance sheet and we recognized an unrealized net loss of approximately $4.8 million on the income statement 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, causing an unrealized net gain of $5.6 million to be recognized in the second quarter of 2006. The difference of $.8 million was recorded in other comprehensive income at the date the hedges were designated.

On June 8, 2006 and July 10, 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. These interest rate swaps have been designated as cash flow hedges.

The related cash flow impact of all of our derivative activities are reflected as cash flows from operating activities.

Irrespective of the unrealized gains reflected in Other Comprehensive Income, the ultimate impact to net income over the life of the hedges will reflect the actual settlement values. 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.

Based on NYMEX futures prices as of March 31, 2007, (WTI $68.72; HH $8.50) we would expect to make pre-tax future cash payments or to receive payments over the remaining term of our crude oil and natural gas hedges in place as follows:

					Impact of percent change in futures prices
		March 31, 2007			on earnings
		NYMEX Futures			-20%		-10%		+ 10%			+ 20%
Average WTI Futures Price (2007 - 2010)	$	68.72		$	54.98	$	61.85	$	75.59		$	82.46
Crude Oil gain/(loss) (in millions)		(5.7	)		11.6		.1		(69.6	)		(147.6	)
Average HH Futures Price (2007 - 2008)		8.50			6.80		7.65		9.35			10.2
Natural Gas gain (in millions)		5.7			16.1		8.8		3.3			(2.2	)

Net pre-tax future cash (payments) and receipts by year (in millions):
2007 (WTI $68.27; HH $8.24)	$	.6		$	16.8	$	8.3	$	(16.6	)	$	(38.6	)
2008 (WTI $69.97; HH $8.70)		(.6	)		5.0		.6		(28.0	)		(57.7	)
2009 (WTI $69.05)		-			-		-		(21.7	)		(46.9	)
2010 (WTI $67.49)		-			5.9		-		-			(6.6	)
Total	$	-		$	27.7	$	8.9	$	(66.3	)	$	(149.8	)

Interest Rates. Our exposure to changes in interest rates results primarily from long-term debt. On October 24, 2006, we issued $200 million of 8.25% senior subordinated notes due 2016 in a public offering. Total long-term debt outstanding including our short-term line of credit, at March 31, 2007 was $477 million. Interest on amounts borrowed under our revolving credit facility is charged at LIBOR plus 1.0% to 1.75%, with the exception of the $100 million of principal for which we have a hedge in place to fix the interest rate at approximately 5.5% plus the senior unsecured revolving credit facility’s margin through June 30, 2011. Based on March 31, 2007 credit facility borrowings, a 1% change in interest rates would have an annual $1.1 million after tax impact on our financial statements.

Item 4. Controls and Procedures

As of March 31, 2007, we have carried out an evaluation under the supervision of, and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities and Exchange Act of 1934, as amended.

Based on their evaluation as of March 31, 2007, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There was no change in our internal control over financial reporting during the most recently completed calendar quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Forward Looking Statements

“Safe harbor under the Private Securities Litigation Reform Act of 1995:” Any statements in this Form 10-Q that are not historical facts are forward-looking statements that involve risks and uncertainties. Words such as “will,” “intend,” “continue,” “target(s),” “expect,” “achieve,” “future,” “may,” “could,” “goal(s),”, “forecast,” “anticipate,” or other comparable words or phrases, or the negative of those words, and other words of similar meaning indicate forward-looking statements and important factors which could affect actual results. Forward-looking statements are made based on management’s current expectations and beliefs concerning future developments and their potential effects upon Berry Petroleum Company. These items are discussed at length in Part I, Item 1A on page 15 of our Form 10-K filed with the Securities and Exchange Commission, under the heading “Risk Factors” and all material changes are updated in Part II, Item 1A within this 10-Q.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

None.

Item 1A. Risk Factors

We may not be able to deliver minimum crude oil volumes required by our sales contract. Production volumes from our Uinta properties over the next six years are uncertain and there is no assurance that we ill be able to consistently meet the minimum requirement. On February 27, 2007, we entered into a six year multi-staged crude oil sales contract with a subsidiary of Holly for a portion of our Uinta basin crude oil. Under the agreement, we will begin delivering 3,200 Bbl/D beginning July 1, 2007. Upon completion of their Woods Cross refinery expansion in Salt Lake City, which is expected in late 2008, Holly will increase their total purchased volumes to 5,000 Bbl/D through June 30, 2013. During the term of the contract, the minimum number of delivered units (“base daily volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion of the refinery upgrade.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit No. Description of Exhibit

10.1* Purchase and sale agreement between the Company and Venoco, Inc. dated March 19, 2007.

31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

BERRY PETROLEUM COMPANY

/s/ Shawn M. Canaday

Shawn M. Canaday

Controller

(Principal Accounting Officer)

Date: May 2, 2007

PURCHASE AND SALE AGREEMENT BETWEEN THE COMPANY AND VENOCO, INC.

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

PURCHASE AND SALE AGREEMENT

between

BERRY PETROLEUM COMPANY,

as Seller,

and

VENOCO, INC.,

as Buyer,

Ventura County, California

Dated March 19, 2007

Effective January 1, 2007

CONFIDENTIAL

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

TABLE OF CONTENTS

		Page
	TABLE OF CONTENTS

ARTICLE 1	PURCHASE AND SALE	1

1.1	Purchase and Sale	1

1.2	Assets	1

1.3	Effective Time	2

ARTICLE 2	PURCHASE PRICE	2

2.1	Purchase Price	2

2.2	Deposit	2

2.3	Adjustments to Purchase Price	3

2.4	Allocated Values	4

ARTICLE 3	DUE DILIGENCE INSPECTION	4

3.1	Access to Records	4

3.2	No Representation or Warranty	5

3.3	Access to the Assets and Indemnity	5

3.4	PRC 3314.1 LEASE	5

ARTICLE 4	TITLE MATTERS	5

4.1	Defensible Title	5

4.2	Permitted Encumbrances	6

4.3	Title Defect	7

4.4	Notice of Title Defects	7

4.5	Seller’s Right to Cure	7

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

TABLE OF CONTENTS

(continued)

		Page

4.6	Remedies for Title Defects	7

4.7	Title Thresholds	8

4.8	Title Dispute Resolution	8

4.9	Depletion and Depreciation of Personal Property	8

4.10	Consents	9

4.11	Casualty Loss	9

ARTICLE 5	ENVIRONMENTAL MATTERS	9

5.1	Definitions	9

5.2	Spills and NORM	10

5.3	Environmental Assessment	10

5.4	Notice of Environmental Defects	11

5.5	Remedies for Environmental Defects	11

5.6	Environmental Thresholds	12

5.7	Environmental Dispute Resolution	12

5.8	“As Is, Where Is” Purchase	12

5.9	Disposal of Materials, Substances and Wastes	13

5.10	Buyer’s Indemnity	13

5.11	Seller’s Indemnity	14

ARTICLE 6	SELLER’S REPRESENTATIONS AND WARRANTIES	14

6.1	Existence	14

6.2	Power	14

6.3	Authorization	15

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

TABLE OF CONTENTS

(continued)

		Page

6.4	Execution and Delivery	15

6.5	Liabilities for Brokers’ Fees	15

6.6	Liens	15

6.7	Taxes	15

6.8	Litigation	15

6.9	COMPLIANCE WITH LAWS	15

6.10	Contracts	15

6.11	Governmental Authorizations	16

6.12	Consents and Preference Rights	16

ARTICLE 7	BUYER’S REPRESENTATIONS AND WARRANTIES	17

7.1	Existence	17

7.2	Power and Authority	17

7.3	Authorization	17

7.4	Execution and Delivery	17

7.5	Liabilities for Brokers’ Fees	17

7.6	Litigation	17

7.7	Independent Evaluation	17

7.8	Qualification	18

7.9	Funds	18

ARTICLE 8	COVENANTS AND AGREEMENTS	18

8.1	Covenants and Agreements	18

iii

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

TABLE OF CONTENTS

(continued)

		Page

8.2	Financial Statements	19

ARTICLE 9	CONDITIONS TO CLOSING	20

9.1	Seller’s Conditions	20

9.2	Buyer’s Conditions	20

ARTICLE 10	RIGHT OF TERMINATION AND ABANDONMENT	21

10.1	Termination	21

10.2	Liabilities Upon Termination	21

ARTICLE 11	CLOSING	22

11.1	Date of Closing	22

11.2	Closing Obligations	22

ARTICLE 12	POST-CLOSING OBLIGATIONS	23

12.1	Post-Closing Adjustments	23

12.2	Suspense Accounts	23

12.3	Dispute Resolution	24

12.4	Records	24

12.5	Further Assurances	24

12.6	Disclaimers of Representations and Warranties	24

ARTICLE 13	TAXES	25

13.1	Apportionment of Ad Valorem and Property Taxes	25

13.2	Transfer Taxes and Recording Fees	25

13.3	Other Taxes	25

13.4	Tax Reports and Returns	25

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

TABLE OF CONTENTS

(continued)

		Page

ARTICLE 14	ASSUMPTION AND RETENTION OF OBLIGATIONS; INDEMNIFICATION	26

14.1	Buyer’s Assumption of Liabilities and Obligations	26

14.2	Seller’s Retention of Liabilities and Obligations	26

14.3	Buyer’s Plugging and Abandonment Obligations	26

14.4	Indemnification	27

14.5	Procedure	27

14.6	No Insurance; Subrogation	29

14.7	Reservation as to Non-Parties	29

ARTICLE 15	MISCELLANEOUS	29

15.1	Exhibits	29

15.2	Expenses	29

15.3	Notices	29

15.4	Amendments	30

15.5	Assignment	30

15.6	Confidentiality	30

15.7	Press Releases	30

15.8	Headings	30

15.9	Counterparts	31

15.10	References	31

15.11	Governing Law	31

15.12	Removal of Signs	31

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

TABLE OF CONTENTS

(continued)

		Page

15.13	Binding Effect	31

15.14	Survival	31

15.15	No Third-Party Beneficiaries	31

15.16	Limitation on Damages	31

15.17	Severability	31

15.18	Knowledge	31

ARTICLE 16	EXCHANGE RIGHT	32

16.1	Exchange Cooperation	32

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

EXHIBITS

Exhibit/Schedule	Description	Section Where Defined

A-1	Leases and Lands	1.2.a

A-2	Wells	1.2.b

A-3	Rights-of-Way and Surface Leases	1.2.e

A-4	Equipment and Facilities	1.2.e

B	Material Agreements	1.2.d

C	Allocated Values	2.4

D	Temporary Access Agreement	3.3

E	Form of Assignment and Bill of Sale	11.2.a

F	Form of Assumption Agreement	11.2.a

G	Seller’s Wire Instructions	2.2

H	Seller’s Officer’s Certificate	11.2.e

I	Buyer’s Officer’s Certificate	11.2.f

J	Non-Foreign Affidavit	11.2.g

K	Suspense Accounts	12.2

6.12	Consents and Preference Rights	6.12

-vii-

Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

PURCHASE AND SALE AGREEMENT

This PURCHASE AND SALE AGREEMENT (“Agreement”), dated March 19, 2007, is by and between Berry Petroleum Company, a Delaware corporation, 5201 Truxtun Avenue, Suite 300, Bakersfield, California 93309-0640 (“Seller”) and Venoco, Inc., a Delaware corporation, whose address is 370 17^th Street, Suite 3900, Denver, Colorado 80202-1370 (“Buyer”).

RECITALS

A. Seller owns and desires to sell certain real and personal property interests located in Ventura County, California, as more fully described in Section 1.2 below (the “Assets”).

B. Buyer desires to purchase the Assets upon the terms and conditions set forth in this Agreement.

AGREEMENT

In consideration of the mutual promises contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Seller and Buyer agree as follows:

ARTICLE 1

PURCHASE AND SALE

1.1 Purchase and Sale. Seller agrees to sell and convey to Buyer, and Buyer agrees to purchase and receive from Seller, all of Seller’s right, title and interest in the Assets, pursuant to the terms and conditions of this Agreement.

1.2 Assets. The “Assets” are all of Seller’s right, title, and interest in and to the following real and personal property interests located in Ventura County, California:

a. The oil and gas leases described on Exhibit A-1 (the “Leases”), insofar and only insofar as the Leases cover the lands described on Exhibit A-1 (the “Lands”); and the oil, gas and all other hydrocarbons (“Hydrocarbons”), in, on or under or that may be produced from the Lands.

b. The oil and gas wells located on the Leases and Lands, or lands pooled or unitized therewith, including without limitation the oil and gas wells described on Exhibit A-2 (the “Wells”), all injection and disposal wells on the Leases and Lands, and all personal property and equipment associated with the Wells as of the Effective Date.

c. The rights, to the extent transferable, in and to all existing and effective unitization, pooling and communitization agreements, declarations and orders, to the extent that they relate to or affect any of the interests described in Sections 1.2.a. and 1.2.b. or the post-Effective Time production of Hydrocarbons from the Leases and Lands.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

d. The rights, to the extent transferable, in and to Hydrocarbon, gathering and processing contracts, operating agreements, balancing agreements, joint venture agreements, partnership agreements, farmout agreements and other contracts, agreements and instruments relating to the interests described in Sections 1.2.a., 1.2.b. and 1.2.c, including without limitation the agreements described on Exhibit B (the “Material Agreements”), but specifically excluding any marketing or production sales agreements.

e. All of the personal property, fixtures, improvements (including without limitation the equipment and facilities described on Exhibit A-4) (the “Equipment and Facilities”) and permits, licenses, approvals, servitudes, rights-of-way, easements, surface leases (including without limitation the rights-of-way easements and surface leases described on Exhibit A-3) and other surface rights, tanks, boilers, buildings, improvements, injection facilities, saltwater disposal facilities, other appurtenances and facilities located on and used in connection with or otherwise related to the exploration for or production, gathering, treatment, processing, storing, or transporting of Hydrocarbons or water produced from the Assets described in Sections 1.2.a. through 1.2.d.

f. Seller’s Lease and well files; gas processing files; division order files; abstracts; title opinions; land surveys; well logs; maps; engineering data and reports; reserve studies and evaluations (insofar as they cover and exist within the boundaries of the Lands), geological and geophysical data (including seismic data) and all technical evaluations, interpretive data and technical data and information relating to the Assets; provided, however, the foregoing shall not include any files, records, data or information which is attorney work product or subject to attorney client privilege or any files, data or information which by agreement Seller is required to keep confidential except and to the extent a waiver in writing is obtained of any such confidential requirements or any files, data or information related to any events concerning or related to an oil spill that occurred on the Assets in December 1993 (the “1993 Oil Spill”) (the “Records”).

1.3 Effective Time. The purchase and sale of the Assets shall be effective as of January 1, 2007 at 12:01 a.m., Pacific Time (the “Effective Time”).

ARTICLE 2

PURCHASE PRICE

2.1 Purchase Price. The purchase price for the Assets shall be SIXTY-THREE MILLION DOLLARS ($63,000,000.00) (the “Purchase Price”). At Closing, Buyer shall pay Seller the Purchase Price as adjusted pursuant to Sections 2.2 and 2.3 below by wire transfer of immediately available funds to Seller or as directed by Seller.

2.2 Deposit. Concurrently with the execution of this Agreement, Buyer shall wire to Seller in immediately available funds the amount of Three Million Dollars ($3,000,000.00) (the “Deposit”) as directed on Exhibit G. The Deposit shall be held by Seller and, subject to the terms of Article 10 of this Agreement, either (i) applied against the Purchase Price (without interest) in the event the Closing is consummated, (ii) returned to Buyer with interest at the rate of the average of the daily commercial paper overnight repurchase rate as published in The Wall Street Journal for the period from the time the Deposit is paid to Seller until it is returned to Buyer (“Interest”) if (x) Seller refuses to close after all conditions specified in Section 9.1 have been satisfied (or waived by Seller) and Buyer certifies to Seller in writing that it is ready, willing and able to perform under Article 11 or (y) the conditions specified in Section 9.2 have not been satisfied (or waived by Buyer), or (iii) retained by Seller if all conditions specified in Section 9.2 have been satisfied and Seller certifies to Buyer in writing that Seller is ready, willing and able to perform under Article 11.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

2.3 Adjustments to Purchase Price. The Purchase Price shall be adjusted according to this Section without duplication. For all adjustments known as of Closing, the Purchase Price shall be adjusted at Closing pursuant to a “Preliminary Settlement Statement” approved by Seller and Buyer on or before Closing. A draft of the Preliminary Settlement Statement will be prepared by Seller and provided to Buyer two (2) business days prior to Closing. The Preliminary Settlement Statement shall set forth the Purchase Price as adjusted as provided in this Section using the best information available at the Closing Date which amount shall be paid at Closing and is referred to as the “Closing Amount.” The Closing Amount shall be paid at Closing by wire transfer of immediately available funds in accordance with the wiring instructions set forth in Section 2.1. After Closing, final adjustments to the Purchase Price shall be made pursuant to the Final Settlement Statement to be delivered pursuant to Section 12.1. For the purposes of this Agreement, the term “Property Expenses” shall mean all capital expenses, joint interest billings, lease operating expenses, lease rental and maintenance costs, royalties, overriding royalties, Taxes (as defined and apportioned as of the Effective Time pursuant to Article 13), drilling expenses, workover expenses, geological, geophysical and any other exploration or development expenditures chargeable under applicable operating agreements or other agreements consistent with the standards established by the Council of Petroleum Accountant Societies of North America that are attributable to the maintenance and operation of the Assets during the period in question.

a. Upward Adjustments. The Purchase Price shall be adjusted upward by the following:

(i) An amount equal to all Property Expenses, including prepaid expenses, attributable to the Assets after the Effective Time that were paid by Seller (all to be apportioned as of the Effective Time except as otherwise provided), including without limitation, prepaid utility charges, prepaid rentals and royalties, including lease rentals, and prepaid drilling and completion costs (to be apportioned as of the Effective Time based on drilling days).

(ii) The proceeds of production attributable to the Assets occurring before the Effective Time (including production from the Assets that occurred before the Effective Time but, because such production is in pipelines or in processing, had not been sold as of the Effective Time times the price for which production from the Assets was sold immediately prior to the Effective Time) and received by Buyer, net of royalties and taxes measured by production.

(iii) To the extent that there are any pipeline imbalances, if the net of such imbalances is an overdelivery imbalance (that is, at the Effective Time, Seller has delivered more gas to the pipeline than the pipeline has redelivered for Seller), the Purchase Price shall be adjusted upward by the product of the price received by Seller times the net overdelivery imbalance in MMbtus.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

(iv) An amount equal to Seller’s share of any oil or condensate in tanks or storage facilities produced from or credited to the Leases and Lands prior to the Effective Time based upon the quantities in oil or condensate tanks or storage facilities as measured by and reflected in Seller’s records multiplied by the price in effect for such inventory on the Closing Date; and

(v) Any other amount provided in this Agreement or agreed upon by Seller and Buyer.

b. Downward Adjustments. The Purchase Price shall be adjusted downward by the following:

(i) An amount equal to the sum of all Title Purchase Price Adjustments as defined in Section 4.7;

(ii) An amount equal to Environmental Purchase Price Adjustment, as defined in Section 5.6;

(iii) The proceeds of production attributable to the Assets occurring on or after the Effective Time and received by Seller, net of royalties and taxes measured by production;

(iv) To the extent that there are any pipelines imbalances, if the net of such imbalances is an underdelivery imbalance (that is, at the Effective Time, Seller has delivered less gas to the pipeline than the pipeline has redelivered for Seller), the Purchase Price shall be adjusted downward by the product of the price received by Seller times the net underdelivery balance in MMbtus.

(v) An amount equal to the Seller Property Tax, as defined in Section 13.1;

(vi) An amount equal to the Suspense Accounts, as defined in Section 12.2; and

(vii) Any other amount provided in this Agreement or agreed upon by Seller and Buyer.

2.4 Allocated Values. Seller and Buyer agree to allocate the Purchase Price among the Assets as set forth in Exhibit C.

ARTICLE 3

DUE DILIGENCE INSPECTION

3.1 Access to Records. Subject to the provisions of the Confidentiality Agreement dated December 4, 2006 between Seller and Buyer, Seller will disclose and make available to Buyer and its representatives at Seller’s offices and during Seller’s normal business hours, all Records in Seller’s possession or control relating to the Assets for the purpose of permitting Buyer to perform its due diligence review including, but not limited to, all well, leasehold, unit and title files and title opinions. Seller agrees to reasonably cooperate with Buyer in Buyer’s efforts to obtain, at Buyer’s sole expense, such additional information relating to the Assets as Buyer may reasonably desire. Buyer may inspect the Records only to the extent it may so do without violating any obligation, confidence or contractual commitment of Seller to a third party. Seller shall use reasonable efforts to obtain the necessary consents to allow Buyer’s examination of any confidential information that is material to this transaction, but shall not be required to incur any costs or additional liabilities to obtain any such consents.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

3.2 No Representation or Warranty. Seller makes no representation or warranty as to the accuracy, completeness, or content of the Records maintained by Seller and made available to Buyer, including, without limitation, any seismic, geological, or geophysical data or interpretations, as well as any engineering or reserve studies and evaluations. Buyer agrees that any conclusions drawn from the Records shall be the result of its own independent review and judgment. Seller further makes no representations or warranties, express or implied, as to the condition of the Assets, or their fitness for Buyer’s intended use or operations.

3.3 Access to the Assets and Indemnity. Prior to Closing, Seller shall permit Buyer, and the officers, employees, agents and advisors of Buyer access to the Assets upon Buyer’s execution of a Temporary Access Agreement dated March 19, 2007 between Seller and Buyer (the “Temporary Access Agreement”) which is attached as Exhibit D.

3.4 PRC 3314.1 Lease. Buyer acknowledges that Seller has disclosed to Buyer that in connection with certain of the Leases (PRC 3314.1) comprising a portion of the Assets, Seller obtained drilling deferments from the California State Lands Commission. The last deferment was granted by the California State Lands Commission in 2001 and expired in 2002. Since that time, while outside of any formally approved period of drilling deferment, Seller has worked with California State Lands Commission staff to develop a drilling and production program, and on June 26, 2006, the California State Lands Commission approved Seller’s application to re-drill two idle onshore wells into the offshore lease. Buyer acknowledges that it has been provided a copy of the approved drilling and production program, together with related correspondence with the California State Lands Commission in connection therewith, and Buyer further acknowledges that operations must be undertaken on the lease in accordance with such drilling and production program (or other programs that may be approved by the California State Lands Commission) to ensure that operations are in compliance with the terms of the lease.

ARTICLE 4

TITLE MATTERS

4.1 Defensible Title. The term “Defensible Title” means such title of Seller in and to the Assets that, subject to and except for the Permitted Encumbrances: (i) entitles Seller to receive not less than the net revenue interest described on Exhibit A-2 (“NRI”); (ii) obligates Seller to bear costs and expenses relating to the Assets in an amount not greater than the working interest described on Exhibit A-2 (“WI”); and (iii) is free and clear of material liens, taxes, encumbrances, mortgages, claims and production payments and any defects that would create a material impairment of use and enjoyment of or loss of interest in the affected Asset.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

4.2 Permitted Encumbrances. The term “Permitted Encumbrances” shall mean:

a. Lessors’ royalties, overriding royalties, net profits interests, production payments, reversionary interests and similar burdens if the net cumulative effect of such burdens does not operate to reduce the NRIs below those set forth on Exhibit A-2;

b. Any required governmental or third-party consents to assignment of the Assets and preferential purchase rights which are handled exclusively under Sections 4.10, 4.11 and 9.2d below;

c. Liens for taxes or assessments not yet due or not yet delinquent or, if delinquent, that are being contested in good faith in the normal course of business, provided, however, that Seller shall be responsible for the prompt payment of all taxes attributable to the Assets for all pre-Effective Time periods. This Section 4.2c does not change the apportionment of taxes under Article 13 of this Agreement;

d. Rights of reassignment, to the extent any exist as of the date of this Agreement, prior to the surrender or expiration of any lease;

e. Easements, rights-of-way, servitudes, permits, surface leases and other rights with respect to surface operations, on, over or in respect of any of the properties or any restriction on access thereto which are of record or which do not materially interfere with the operation of the affected property;

f. Materialmen’s, mechanics’, repairmen’s, employees’, contractors’, operators’ or other similar liens or charges arising in the ordinary course of business incidental to construction, maintenance or operation of the Assets (i) if they have not been filed pursuant to law and the time for filing them has expired, (ii) if filed, they have not yet become due and payable or payment is being withheld as provided by law, or (iii) if their validity is being contested in good faith by appropriate action. Provided, however, that it shall be Seller’s responsibility to promptly discharge and remove all such liens or charges at Seller’s sole expense;

g. Rights reserved to or vested in any municipality or governmental, statutory, or public authority to control or regulate any of the Assets in any manner; and all applicable laws, rules, regulations and orders of general applicability in the area;

h. Liens for post-Effective Time operations arising under operating agreements, unitization and pooling agreements securing amounts not yet accrued or due or;

i. The terms of the Material Agreements and any and all other agreements that are ordinary and customary in the oil, gas, sulfur and other mineral exploration, development or extraction business, or in the business of processing of gas and gas condensate for the extraction of products therefrom.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

j. Any encumbrance, encroachment, irregularity, defect in or objection to real property title which would otherwise constitute a “Title Defect” under Section 4.3 below, but which is of record, or which is disclosed or reasonably discernible by a review of the Records or an inspection of the Assets.

4.3 Title Defect. The term “Title Defect” means any encumbrance, encroachment, irregularity, defect in or objection to real property title, excluding Permitted Encumbrances, that alone or in combination with other defects:

a. Renders title to an Asset less than Defensible Title;

b. Reduces, impairs or prevents Buyer from receiving payment from the purchasers of production from an Asset; and/or

c. Restricts or extinguishes Buyer’s right to use an Asset as owner, lessee, licensee or permittee, as applicable.

4.4 Notice of Title Defects. Buyer shall deliver to Seller a written “Notice of Title Defects” on or before April 12, 2007, 5:00 p.m., Pacific Time. The Notice of Title Defects shall (i) describe the Title Defect, (ii) describe the basis of the Title Defect and (iii) describe Buyer’s good faith estimate of the reduction in the Asset’s Allocated Value caused by the Title Defect (“Title Defect Value”) and all calculations and documentation substantiating the existence of the Title Defect. Buyer will be deemed to have conclusively waived any Title Defect about which it fails to so notify Seller in writing prior to April 12, 2007 at 5:00 p.m. Pacific Time. Seller may contest the Title Defect or the Title Defect Value by so notifying Buyer. The agreement of Seller and Buyer as to the Title Defect Value shall result in the “Actual Title Defect Value”.

4.5 Seller’s Right to Cure. Seller shall have the option, but not the obligation, to attempt to cure any Title Defects. Seller shall notify Buyer prior to Closing of its election to cure any Title Defect, and shall thereafter provide to Buyer as soon as practicable prior to Closing evidence that any such Title Defect is cured.

4.6 Remedies for Title Defects. In the event that any Title Defect is not cured on or before Closing, Seller shall, at its sole election, elect one of the following by so notifying Buyer not later than two (2) business days prior to Closing:

a. Subject to the specific limitations set forth in Section 4.7, indemnify Buyer against all liability, loss, cost and expense resulting from such Title Defect, but in an amount not to exceed the Allocated Value of the Asset that is subject to such Title Defect, in which event the parties shall proceed to Closing and the Asset that is subject to such Title Defect shall be conveyed by Seller to Buyer subject to such Title Defect, with no payment or settlement at Closing as a result of such Title Defect and no reduction or adjustment to the Purchase Price;

b. Subject to the specific limitations set forth in Section 4.7, credit Buyer with the amount of the Actual Title Defect Value for an Asset (the “Title Defect Adjustment”), in which event the parties shall proceed to Closing and the Asset that is subject to such Title Defect shall be conveyed by Seller to Buyer subject to such Title Defect and Buyer shall pay to Seller the Purchase Price as so adjusted; or

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

c. Retain the Asset subject to such Title Defect and reduce the Purchase Price by an amount equal to the Allocated Value of such Asset, in which event the parties shall proceed to Closing and the Asset that is subject to such Title Defect shall be retained by Seller and Buyer shall pay to Seller the Purchase Price as so adjusted.

4.7 Title Thresholds. Seller shall have no obligation under Section 4.6 and there shall be no indemnification by Seller of Buyer under Section 4.6.a or reduction to the Purchase Price under Sections 4.6.b or 4.6.c unless Seller’s share of a proposed indemnity amount or reduction to the Purchase Price as to any single incident exceeds *** (the “Single Title Incident Threshold Amount”). For the purposes of application of the foregoing threshold, “single incident” shall be on a lease-by-lease basis for all oil and gas leasehold interests. In addition, there shall be no indemnity obligation under Section 4.6.a or reduction to the Purchase Price under Sections 4.6.b or 4.6.c until such time as the total of these excess amounts *** of the Purchase Price (the “Title Threshold Amount”). If the Title Threshold Amount is exceeded, the Purchase Price reduction shall include the Single Title Incident Threshold Amount for those title Defects that exceed such threshold and are conveyed to Buyer under Section 4.6.b and shall include the Allocated Value of those Assets with an Allocated Value *** that are retained by Seller under Section 4.6.c. The total of the Purchase Price reductions under Sections 4.6.b and 4.6.c is the “Title Purchase Price Adjustment.”

4.8 Title Dispute Resolution. Seller and Buyer agree to resolve disputes concerning the following matters pursuant to this Section: (i) the existence and scope of a Title Defect, (ii) the Defect Value of that portion of the Asset affected by a Title Defect, (iii) , the adequacy of Seller’s Title Defect curative materials (the “Disputed Title Matters”). The parties agree to attempt to initially resolve all Disputed Title Matters through good faith negotiations. If the parties cannot resolve such disputes within fourteen (14) days prior to Closing, the Disputed Title Matters shall be finally determined by a mutually agreeable accounting, petroleum engineering, or law firm or consultant (the “Title Arbiter”), taking into account the factors set forth in this Agreement. On or before ten (10) days prior to Closing, Buyer and Seller shall present their respective positions in writing to the Title Arbiter, together with such evidence as each party deems appropriate. The Arbiter shall be instructed to resolve the dispute through a final decision within five (5) days after submission of the parties’ respective positions to the Title Arbiter. The costs incurred in employing the Arbiter shall be borne equally by Seller and Buyer. The Title Arbiter’s final decision may be filed with a court of competent jurisdiction and entered as a judgment which shall be binding on the parties.

4.9 Depletion and Depreciation of Personal Property. Buyer shall assume all risk of loss with respect to, and any change in the condition of, the Assets from the Effective Time until Closing for production of oil, gas and/or other hydrocarbons through depletion (including the watering-out of any well, collapsed casing or sand infiltration of any well) and the depreciation of personal property due to ordinary wear and tear.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

4.10 Consents. Seller and Buyer shall jointly use reasonable efforts to obtain all required consents to assignment of leases and contracts. If Buyer discovers properties for which consents to assign are applicable during the course of Buyer’s due diligence activities, Buyer shall notify Seller immediately. Except for consents and approvals which are customarily obtained post-Closing (including without limitation certain federal or state or governmental approvals) and those consents which would not invalidate the conveyance of the Assets, if a necessary consent (with the exception of consents required from the California State Lands Commission (the “SLC”) which is handled as a condition to Closing under Section 9.2.c) to assign any Asset has not been obtained as of the Closing, then (i) the portion of the Assets for which such consent has not been obtained shall be included with the Assets at the Closing, and the Purchase Price for that Asset shall be included in the Preliminary Settlement Statement, (ii) Seller shall employ reasonable efforts to obtain such consent as promptly as possible following Closing and (iii) if such consent has not been obtained as of the Final Settlement Date (unless Seller and Buyer otherwise mutually agree in writing), the Allocated Value of the Asset shall be a downward adjustment to the Purchase Price on the Final Settlement Statement and Buyer shall reassign such Asset to Seller, effective as of the Effective Time. Buyer shall reasonably cooperate with Seller in obtaining any required consent including providing assurances of reasonable financial conditions, plans of development or any other information reasonably requested by the party whose consent is required.

4.11 Casualty Loss. Prior to Closing, if any of the Assets is destroyed by fire or other casualty or any of the Assets is taken or threatened to be taken in condemnation or under the right of eminent domain (“Casualty Loss”), Seller shall promptly provide notice of the Casualty Loss to Buyer. Buyer shall not be obligated to purchase an Asset that is the subject of a Casualty Loss if Buyer provides written notice to Seller prior to Closing of Buyer’s election not to purchase such Asset. If Buyer so elects not to purchase such Asset, the Purchase Price shall be adjusted as agreed to by Buyer and Seller. If Buyer elects to purchase such Asset, the Purchase Price shall be reduced by the estimated cost to repair such Asset (with equipment of similar utility) as agreed to by Buyer and Seller (the reduction being the “Net Casualty Loss”). The Net Casualty Loss shall not, however, exceed the Allocated Value of such Asset. Seller, at its sole option, may elect to cure such Casualty Loss. If Seller elects to cure such Casualty Loss, Seller may replace any personal property that is the subject of a Casualty Loss with equipment of similar grade and utility, or replace any real property with real property of similar nature and kind if such property is acceptable to Buyer. If Seller elects to cure the Casualty Loss to the satisfaction of Buyer, the Asset subject to such Casualty Loss shall be purchased by Buyer and there shall be no adjustment to the Purchase Price. If Seller elects not to cure the Casualty Loss to the satisfaction of Buyer and the Net Casualty Loss exceeds the amount of the Deposit, Buyer may, by written notice to Seller, elect to terminate this Agreement and receive the Deposit.

ARTICLE 5

ENVIRONMENTAL MATTERS

5.1 Definitions. For the purposes of the Agreement, the following terms shall have the following meanings:

“Environmental Defect” means a condition in, on or under the Assets (including, without limitation, air, land, soil, surface and subsurface strata, surface water, ground water, or sediments) that causes an Asset to be in material violation of an Environmental Law or a condition that can reasonably be expected to give rise to costs or liability under applicable Environmental Laws. NORM (defined in Section 5.2) contaminated pipe, meters, tubing and wellheads shall not be an Environmental Defect.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

“Environmental Defect Value” means the cost to Remediate an Environmental Defect. The Environmental Defect Value shall be limited to the net present value before federal income taxes, calculated using a ten percent discount rate (PV10), of the most cost effective means to achieve the Remediation required by applicable federal, state or local law or other governmental or judicial directive and not for any other cost.

“Environmental Law” means any statute, rule, regulation, code or order, issued by any federal, state, or local governmental entity in effect on or before the Effective Time (collectively, “Laws”) relating to the protection of the environment or the release or disposal of waste materials.

“Remediation” or “Remediate” means actions taken to correct an Environmental Defect and “Remediation Costs” means the actual, or good faith estimates of the costs to conduct such Remediation.

5.2 Spills and NORM. Buyer specifically acknowledges being advised of the 1993 Oil Spill. Buyer acknowledges that in the past there may have been other spills of wastes, crude oil, condensate, produced water, or other materials (including, without limitation, any toxic, hazardous or extremely hazardous substances) onto the Lands. In addition, some production equipment may contain asbestos and/or Naturally Occurring Radioactive Material (“NORM”). In this regard Buyer expressly understands that NORM may affix or attach itself to the inside of wells, materials and equipment as scale or in other forms, that said wells, materials and equipment located on the Lands or included in the Assets described herein may contain NORM and that NORM-containing material may have been buried or otherwise disposed of on the Lands. Buyer also expressly understands that special procedures may be required for the Remediation, removal, transportation and disposal of asbestos or NORM from the Assets and Lands where such material may be found and that Buyer assumes all liability for or in connection with the assessment, containment, removal, Remediation, transportation and disposal of any such materials, in accordance with all past, present or future applicable laws, rules, regulations and other requirements of any governmental or judicial entities having jurisdiction and also with the terms and conditions of all applicable leases and other contracts.

5.3 Environmental Assessment. Prior to Closing, Buyer may conduct an on-site inspection, environmental assessment and compliance audit of the Assets (an “Environmental Assessment”) at Buyer’s cost and expense. Such Environmental Assessment shall be conducted in accordance with the Temporary Access Agreement. Seller shall provide Buyer with access to the Assets and to information in Seller’s possession or control pertaining to the environmental condition of the Assets, including, but not limited to, status or any environmental reports, permits, records and assessments in Seller’s possession or control, and shall make available to Buyer all present personnel who would reasonably be expected to have knowledge or information regarding the environmental status or condition of the Assets. Seller makes no representation or warranty as to the accuracy or completeness of the records maintained by Seller and made available to Buyer. Buyer shall provide Seller five (5) days prior written notice of any environmental inspections and tests, including the scope of same, and Buyer shall give Seller the opportunity to participate in all such inspections and tests. Buyer shall promptly provide Seller, at no cost to Seller, all reports of environmental inspections and tests, provided that all such reports shall be deemed to be confidential between the parties and subject to the Confidentiality Agreement dated December 4, 2006 between Seller and Buyer and the Temporary Access Agreement. Buyer agrees to release, indemnify, defend, and hold harmless Seller against all Losses (as defined in Section 14.4) arising from or related to the activities of Buyer, its employees, agents, contractors and other representatives in connection with Buyer’s Environmental Assessment regardless of the negligence or strict liability of Seller.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

5.4 Notice of Environmental Defects. Buyer shall deliver to Seller a written “Notice of Environmental Defects” on or before April 12, 2007, 5:00 p.m., Pacific Time. The Notice of Environmental Defects shall (i) describe the Environmental Defect, (ii) provide evidence of the Environmental Defect and the documentation in Buyer’s possession pertaining to such Environmental Defect, and, (iii) describe Buyer’s good faith estimate of the Remediation Costs associated with the Environmental Defect. Buyer will be deemed to have conclusively waived any Environmental Defect for which it fails to provide Seller a Notice of Environmental Defect prior to April 12, 2007 at 5:00 p.m., Pacific Time. Seller may contest the existence and scope of the Environmental Defect or Environmental Defect Value by so notifying Buyer. The agreement of Seller and Buyer as to the Environmental Defect Value shall result in the “Actual Environmental Defect Value”.

5.5 Remedies for Environmental Defects. Upon the receipt by Seller of notice from Buyer pursuant to Section 5.4 of any Environmental Defect, Seller shall have the option, but not the obligation, to attempt to Remediate any Environmental Defect. In the event that any such Environmental Defect has not been Remediated by Seller such that the applicable Asset(s) will not be brought into compliance with the applicable Environmental Laws on or before Closing, Seller shall, at its sole election, elect one of the following by so notifying Buyer not later than two (2) business days prior to Closing.

a. Subject to the specific limitations set forth in Section 5.6, indemnify Buyer against all liability, loss, cost and expense resulting from such Environmental Defect in which event the parties shall proceed to Closing and the Asset that is subject to such Environmental Defect shall be conveyed by Seller to Buyer subject to such Environmental Defect, with no payment by Seller or other settlement at Closing as a result of such Environmental Defect and no reduction or adjustment to the Purchase Price;

b. Subject to the specific limitations set forth in Section 5.6, credit Buyer with the amount of the Actual Environmental Defect Value (the “Environmental Defect Adjustment”), in which event the parties shall proceed to Closing and the Asset that is subject to such Environmental Defect shall be conveyed by Seller to Buyer subject to such Environmental Defect and Buyer shall pay to Seller the Purchase Price as so adjusted; or

c. Retain the Asset subject to such Environmental Defect and reduce the Purchase Price by an amount equal to the Allocated Value of such Asset, in which event the parties shall proceed to Closing and the Asset that is subject to such Environmental Defect shall be retained by Seller and Buyer shall pay to Seller the Purchase Price as so adjusted.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

5.6 Environmental Thresholds. Seller shall have no obligation under Section 5.5 and there shall be no indemnification by Seller of Buyer under Section 5.5.a or reduction to the Purchase Price under Sections 5.5.b or 5.5.c unless Seller’s share of a proposed indemnity amount or reduction to the Purchase Price as to any single incident *** (the “Single Environmental Incident Threshold Amount”). For the purposes of application of the foregoing threshold, “single incident” shall be applicable on a well by well or property by property basis. In addition, if Seller’s share of the proposed indemnity amount under Section 5.5.a or reduction to the Purchase Price under Sections 5.5.b or 5.5.c as to any single incident exceeds ***, there shall be no indemnification by Seller of Buyer under Section 5.5.a or reduction to the Purchase Price under Sections 5.5.b or 5.5.c until such time as the total of these excess amounts *** of the Purchase Price (the “Environmental Threshold Amount”). If the Environmental Threshold Amount is exceeded, the Purchase Price reduction shall include the Single Environmental Incident Threshold Amount for those Environmental Defects that exceed such threshold and are conveyed to Buyer under Section 5.5.b and shall include the Allocated Value of those Assets with an Allocated Value in excess of *** that are retained by Seller under Section 5.5.c. The total of the Purchase Price reductions under Sections 5.5.b and 5.5.c is the “Environmental Purchase Price Adjustment”.

5.7 Environmental Dispute Resolution. The parties agree to resolve disputes concerning the following matters pursuant to this Section: (i) the existence and scope of an Environmental Defect, (ii) Buyer’s estimate of Remediation Costs of an Environmental Defect and (iii) the effectiveness of Seller’s Remediation (the “Disputed Environmental Matters”). The parties agree to attempt to initially resolve all Disputed Environmental Matters through good faith negotiations. If the parties cannot resolve such disputes within fourteen (14) days prior to Closing, the Disputed Environmental Matters shall be finally determined by a mutually agreeable environmental consulting firm (the “Environmental Arbiter”), taking into account the factors set forth in this Agreement. On or before ten (10) days prior to Closing, Buyer and Seller shall present their respective positions in writing to the Environmental Arbiter, together with such evidence as each party deems appropriate. The Environmental Arbiter, shall be instructed to resolve the dispute through a final decision within five (5) days after submission of the parties’ respective positions to the Environmental Arbiter. The costs incurred in employing the Environmental Arbiter shall be borne equally by Seller and Buyer. The Environmental Arbiter’s final decision may be filed with a court of competent jurisdiction and entered as a judgment which shall be binding upon the parties.

5.8 “As Is, Where Is” Purchase. Buyer shall acquire the Assets (including Assets for which a notice was given under Section 5.4 above) in an “AS IS, WHERE IS” condition and shall assume all risks that the Assets may contain waste materials (whether toxic, hazardous, extremely hazardous or otherwise) or other adverse physical conditions, including, but not limited to, the presence of unknown abandoned oil and gas wells, water wells, sumps, pits, pipelines or other waste or spill sites which may not have been revealed by Buyer’s investigation. With the exception of matters for which Seller indemnifies Buyer under Section 5.5.a and except for the 1993 Oil Spill, on and after the Effective Time, all responsibility and liability related to all such conditions, whether known or unknown, fixed or contingent, whenever arising, will be transferred from Seller to Buyer.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

5.9 Disposal of Materials, Substances and Wastes. Buyer shall properly handle, remove, transport and dispose of any material, substance or waste (whether toxic, hazardous, extremely hazardous or otherwise) from the Assets or Lands (including, but not limited to, produced water, drilling fluids and other associated wastes), whether present before or after the Effective Time, in accordance with applicable local, state and federal laws and regulations. Buyer shall keep records of the types, amounts and location of materials, substances and wastes which are transported, handled, discharged, released or disposed onsite and offsite. When and if any Lease is terminated, Buyer shall take whatever additional testing, assessment, closure, reporting or remedial action with respect to the Assets or Lands as is necessary to meet any local, state or federal requirements directed at protecting human health or the environment in effect at that time.

5.10 Buyer’s Indemnity.

a. With the exception of (i) matters for which Seller indemnifies Buyer under Section 5.5.a, (ii) the 1993 Oil Spill, and (iii) offsite disposal of hazardous substances relating to the Assets prior to the Effective Time by Seller, its employees and contractors only and not any such disposal by Seller’s predecessors in title (“Seller’s Retained Environmental Obligations”), Buyer shall indemnify, hold harmless, release and defend Seller from and against all damages, losses, claims, demands, causes of action, judgments and other costs (including but not limited to any civil fines, penalties, costs of assessment, clean-up, removal and Remediation of pollution or contamination, and expenses for the modification, repair or replacement of facilities on the Lands) brought by any and all persons and any agency or other body of federal, state or local government, on account of any personal injury, illness or death, any damage to, destruction or loss of property, and any contamination or pollution of natural resources (including soil, air, surface water or groundwater) to the extent any of the foregoing directly or indirectly is caused by or otherwise involves any environmental condition of the Assets or Lands, whether created or existing before, on or after the Closing, including, but not limited to, the presence, disposal or release of any material (whether hazardous, extremely hazardous, toxic or otherwise) of any kind in, on or under the Assets or the Lands.

b. Buyer’s indemnification obligations for environmental matters for which it is responsible as described in Section 5.10.a., above, shall extend to and include, but not be limited to (i) the negligence or other fault of Seller, Buyer and third parties, whether such negligence is active or passive, gross, joint, sole or concurrent, (ii) Seller’s or Buyer’s strict liability, and (iii) Seller’s or Buyer’s liabilities or obligations under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (42 U.S.C. §§ 9601 et seq.), the Resource Conservation and Recovery Act of 1976 (42 U.S.C. § 6901 et seq.), the Clean Water Act (33 U.S.C. §§ 466 et seq.), the Safe Drinking Water Act (14 U.S.C. §§ 1401-1450), the Hazardous Materials Transportation Act (49 U.S.C. §§ 1801 et seq.), the Toxic Substances Control Act (15 U.S.C. §§ 2601-2629), the Clean Air Act (42 U.S.C. § 7401 et seq.) as amended, the Clean Air Act Amendments of 1990 and all state and local laws and any replacement or successor legislation or regulation thereto. Buyer’s indemnification obligations for environmental matters for which it is responsible as described in Section 5.10.a, above, however, shall not extend to and include offsite disposal of hazardous substances relating to the Assets prior to the Effective Time by Seller’s predecessors in title. This indemnification shall be in addition to any other indemnity provisions contained in this Agreement, and it is expressly understood and agreed that any terms of this Section shall control over any conflicting or contradicting terms or provisions contained in this Agreement.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

5.11 Seller’s Indemnity.

(a) With respect to Seller’s Retained Environmental Obligations, Seller shall indemnify, hold harmless, release and defend Buyer from and against all damages, losses, claims, demands, causes of action, judgments and other costs (including but not limited to any civil fines, penalties, costs of assessment, clean-up, removal and Remediation of pollution or contamination, and expenses for the modification, repair or replacement of facilities on the Lands) brought by any and all persons and any agency or other body of federal, state or local government, on account of any personal injury, illness or death, any damage to, destruction or loss of property, and any contamination or pollution of natural resources (including soil, air, surface water or groundwater) associated with such retained obligations.

(b) Seller’s indemnification obligations for environmental matters for which it is responsible as described in Section 5.11.a., above, shall extend to and include, but not be limited to (i) the negligence or other fault of Seller and third parties, whether such negligence is active or passive, gross, joint, sole or concurrent, (ii) Seller’s strict liability, and (iii) Seller’s liabilities or obligations under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (42 U.S.C. §§ 9601 et seq.), the Resource Conservation and Recovery Act of 1976 (42 U.S.C. § 6901 et seq.), the Clean Water Act (33 U.S.C. §§ 466 et seq.), the Safe Drinking Water Act (14 U.S.C. §§ 1401-1450), the Hazardous Materials Transportation Act (49 U.S.C. §§ 1801 et seq.), the Toxic Substances Control Act (15 U.S.C. §§ 2601-2629), the Clean Air Act (42 U.S.C. § 7401 et seq.) as amended, the Clean Air Act Amendments of 1990 and all state and local laws and any replacement or successor legislation or regulation thereto. This indemnification shall be in addition to any other indemnity provisions contained in this Agreement, and it is expressly understood and agreed that any terms of this Section shall control over any conflicting or contradicting terms or provisions contained in this Agreement.

ARTICLE 6

SELLER’S REPRESENTATIONS AND WARRANTIES

Seller makes the following representations and warranties as of the date of this Agreement:

6.1 Existence. Seller is a corporation duly organized and validly existing under the laws of the State of Delaware.

6.2 Power. Seller has all requisite power and authority to carry on its business as presently conducted, to enter into this Agreement and each of the documents contemplated to be executed by Seller at Closing, and to perform its obligations under this Agreement and under such documents. To Seller’s knowledge, (except for any consents which are the subject of Section 4.10 or which are customarily obtained after Closing) the consummation of the transaction contemplated by this Agreement and each of the documents contemplated to be executed by Seller at Closing will not violate, nor be in conflict with, (i) any provision of Seller’s organizational or governing documents, (ii) any agreement or instrument to which Seller is a party or is bound, or (iii) any judgment, decree, order, statute, rule or regulation applicable to Seller.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

6.3 Authorization. The execution, delivery and performance of this Agreement and each of the documents contemplated to be executed by Seller at Closing and the contemplated transaction has been duly and validly authorized by all requisite corporate and shareholder action on the part of Seller.

6.4 Execution and Delivery. This Agreement has been duly executed and delivered on behalf of Seller, and at the Closing all documents and instruments required hereunder to be executed and delivered by Seller will be duly executed and delivered. This Agreement does, and such documents and instruments shall, constitute legal, valid and binding obligations of Seller enforceable in accordance with their terms, subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium and other similar laws of general application with respect to creditors, (ii) general principles of equity and (iii) the power of a court to deny enforcement of remedies generally based upon public policy.

6.5 Liabilities for Brokers’ Fees. Seller has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transaction contemplated by this Agreement for which Buyer shall have any responsibility whatsoever.

6.6 Liens. To Seller’s knowledge, except for the liens created by or arising under joint operating agreements covering the Assets or applicable state statutes, or which are disclosed of record, the Assets are free and clear of all liens.

6.7 Taxes. To Seller’s knowledge, all taxes and assessments pertaining to the Assets based on or measured by the ownership of property for all taxable periods prior to the taxable period in which this Agreement is executed have been properly paid. All income taxes and obligations relating thereto that could result in a lien or other claim against any of the Assets have been properly paid, unless contested in good-faith by appropriate proceeding.

6.8 Litigation. There is no action, suit, proceeding, claim or, to Seller’s knowledge, investigation by any person, entity, administrative agency or governmental body, pending or, to Seller’s knowledge, threatened, against Seller that (i) relates to the Assets, or (ii) impedes or is likely to impede Seller’s ability to consummate the transaction contemplated by this Agreement and to assume the abilities to be assumed by Seller under this Agreement.

6.9 Compliance with Laws. To Seller’s knowledge, Seller’s operation of the Assets is in compliance in all material respects with the provisions and requirements of all material laws, rules and regulations applicable to the ownership, operation, development, maintenance, or use of the Assets.

6.10 Contracts. To Seller’s knowledge, the Material Agreements, Leases, and instruments listed on Exhibit A-3 represent all of the following material contracts, agreements, and commitments which are included in the Assets or by which any of the Assets will be bound as of the Effective Time and/or following the Closing: (i) any agreement with any affiliate; (ii) any agreement or contract for the sale, exchange, or other disposition of hydrocarbons produced from or attributable to Seller’s interest in the Assets or for the purchase, processing or transportation of any hydrocarbons, in each case that is not cancelable without penalty or other material payment on not more than 90 days prior written notice, other than terms of operating agreements or gas balancing agreements which permit an operator or other co owner to take or market production of a non taking co owner; (iii) any agreement of or binding upon Seller to sell, lease, farmout, or otherwise dispose of any interest in any of the Assets after the date hereof, other than non consent penalties for nonparticipation in operations under operating agreements, conventional rights of reassignment arising in connection with Seller’s surrender or release of any of the Assets, or agreements under clause (ii) above, (iv) any tax partnership agreement of or binding upon Seller affecting any of the Assets (v) creates a purchase option, right of first refusal, call or preferential purchase right on any Hydrocarbons; (vi) creates any area of mutual interest or similar provision with respect to the acquisition by Seller or its assigns of any interest in any hydrocarbons, land or asset, or contains any restrictions on the ability of Seller or its assigns to compete with any other person; (vii) is a participation, partnership, joint venture, farmin or similar agreement; (viii) evidences an obligation in excess of $75,000 to pay a deferred purchase price of property, except accounts payable arising in the ordinary course of business; and (ix) any lease or rental of any land, building or other improvements, excluding Leases, or any other agreement that could reasonably be expected to result in aggregate payments by Buyer with respect to the Assets of more than $75,000 during the current or any subsequent year. To Seller’s knowledge, Seller is not in default under any Material Agreement, except as disclosed on Exhibit B.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

6.11 Governmental Authorizations. To Seller’s knowledge, Seller has obtained and is maintaining all material federal, state and local governmental licenses, permits, franchises, orders, exemptions, variances, waivers, authorizations, certificates, consents, rights, privileges and applications therefor (the “Governmental Authorizations”) that are presently necessary or required for the ownership and operation of the Assets as currently owned and operated. To Seller’s knowledge (i) Seller is operating the Assets in material compliance with the conditions and provisions of all Governmental Authorizations that are presently necessary or required for the ownership and operation of the Assets as currently owned and operated, and (ii) no written notices of violation have been received by Seller from a governmental body, and no proceedings are pending (with service of process on Seller) or, to Seller’s knowledge, threatened (or pending without service of process on Seller) that might result in any material modification, revocation, termination or suspension of any such Governmental Authorizations or which would require any corrective or remediation action by Seller.

6.12 Consents and Preference Rights. To Seller’s knowledge, except for preference rights and transfer requirements as are set forth on Schedule 6.12, none of the Assets, or any portion thereof, is subject to any preference right or transfer requirement, which may be applicable to the transactions contemplated by this Agreement.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

ARTICLE 7

BUYER’S REPRESENTATIONS AND WARRANTIES

Buyer makes the following representations and warranties as of the date of this Agreement:

7.1 Existence. Buyer is a corporation, duly organized, validly existing and formed under the laws of the State of Delaware, and Buyer by Closing will be duly qualified and in good standing in the State of California.

7.2 Power and Authority. Buyer has all requisite power and authority to carry on its business as presently conducted, to enter into this Agreement and each of the documents contemplated to be executed by Buyer at Closing, and to perform its obligations under this Agreement and under such documents. The consummation of the transaction contemplated by this Agreement and each of the documents contemplated to be executed by Buyer at Closing will not violate, nor be in conflict with, (i) any provision of Buyer’s organizational or governing documents, (ii) any agreement or instrument to which Buyer is a party or is bound, or (iii) any judgment, decree, order, statute, rule or regulation applicable to Buyer.

7.3 Authorization. The execution, delivery and performance of this Agreement and each of the documents contemplated to be executed by Buyer at Closing and the contemplated transaction has been duly and validly authorized by all requisite action on the part of Buyer.

7.4 Execution and Delivery. This Agreement has been duly executed and delivered on behalf of Buyer, and at the Closing all documents and instruments required hereunder to be executed and delivered by Buyer will be duly executed and delivered. This Agreement does, and such documents and instruments shall, constitute legal, valid and binding obligations of Buyer enforceable in accordance with their terms, subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium and other similar laws of general application with respect to creditors, (ii) general principles of equity and (iii) the power of a court to deny enforcement of remedies generally based upon public policy.

7.5 Liabilities for Brokers’ Fees. Buyer has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transaction contemplated by this Agreement for which Seller shall have any responsibility whatsoever.

7.6 Litigation. There is no action, suit, proceeding, claim or investigation by any person, entity, administrative agency or governmental body pending or, to Buyer’s knowledge, threatened in writing, against Buyer before any governmental authority that impedes or is likely to impede Buyer’s ability to consummate the transactions contemplated by this Agreement and to assume the liabilities to be assumed by Buyer under this Agreement.

7.7 Independent Evaluation. Buyer is an experienced and knowledgeable investor in the oil and gas business. Buyer has been advised by and has relied solely upon its own expertise in legal, tax, reservoir engineering and other professional counsel concerning this transaction, the Assets and the value thereof.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

7.8 Qualification. Buyer is now or at closing will be and thereafter will continue to be qualified to own and operate any federal or state oil and gas lease that constitutes part of the Assets, including meeting all bonding requirements. Completing the transactions set out in this Agreement will not cause Buyer to be disqualified or to exceed any acreage limitation imposed by law, statute or regulation.

7.9 Funds. Buyer has arranged to have available by the Closing Date sufficient funds to enable Buyer to pay in full the Purchase Price and otherwise perform its obligations under this Agreement.

ARTICLE 8

COVENANTS AND AGREEMENTS

8.1 Covenants and Agreements. As to the period of time from the execution hereof until Closing, Seller and Buyer agree as follows:

a. Operation Prior to Closing. Except as otherwise consented to in writing by Buyer or provided in this Agreement, from the date of execution hereof to the Closing, Seller shall use Seller’s commercially reasonable efforts to ensure that the Assets are maintained and operated in a good and workmanlike manner. Subject to the provisions of Section 2.3, Seller shall pay or cause to be paid its proportionate share of all costs and expenses incurred in connection with such operations. To the extent Seller receives written AFEs or actual notice of such, Seller shall notify Buyer of ongoing activities and major capital expenditures in excess of Twenty-five Thousand Dollars ($25,000.00) per activity net to Seller’s interest conducted on the Assets and shall consult with Buyer regarding all such matters and operations.

b. Restriction on Operations. Subject to Section 8.1.a., unless Seller obtains the prior written consent of Buyer to act otherwise, Seller will use good-faith efforts within the constraints of the applicable operating agreements and other applicable agreements not to (i) abandon any part of the Assets (except in the ordinary course of business or the abandonment of leases upon the expiration of their respective primary terms or if not capable of production in paying quantities), (ii) except for capital projects which are deemed to be approved, approve any operations on the Assets anticipated in any instance to cost the owner of the Assets more than Twenty-five Thousand Dollars ($25,000) per activity net to Seller’s interest (excepting emergency operations, operations required under presently existing contractual obligations, ongoing commitments under existing AFEs and operations undertaken to avoid a monetary penalty or forfeiture provision of any applicable agreement or order), (iii) convey or dispose of any material part of the Assets (other than replacement of equipment or sale of oil, gas, and other liquid products produced from the Assets in the regular course of business) or enter into any farmout, farmin or other similar contract affecting the Assets (iv) let lapse any insurance now in force with respect to the Assets, or (v) materially modify or terminate any contract material to the operation of the Assets.

c. Legal Status. Seller and Buyer shall use all reasonable efforts to maintain their respective legal statuses from the date hereof until the Final Settlement Date and to assure that as of the Closing Date they will not be under any material corporate, legal or contractual restriction that would prohibit or delay the timely consummation of the transaction contemplated hereby.

d. Notices of Claims. Seller shall promptly notify Buyer and Buyer shall promptly notify Seller, if, between the date hereof and the Closing Date, Seller or Buyer, as the case may be, receives notice of any claim, suit, action or other proceeding of the type referred to in Sections 6.8 and 7.6.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

e. Compliance with Laws. During the period from the date of this Agreement to the Closing Date, Seller shall attempt in good faith to comply in all material respects with all applicable statutes, ordinances, rules, regulations and orders relating to the ownership and operation of the Assets.

f. Government Reviews and Filings. Before and after the Closing, Buyer and Seller shall cooperate to provide requested information, make required filings with, prepare applications to and conduct negotiations with each governmental agency as required to consummate the transaction contemplated hereby. Each party shall make any governmental filings occasioned by its ownership or structure. Buyer shall make all filings after the Closing at its expense with governmental agencies necessary to transfer title to the Assets or to comply with laws and shall indemnify and hold harmless Seller from and against all claims, costs, expenses, liabilities and actions arising out of Buyer’s holding of such title after the Closing and prior to the securing of any necessary governmental approvals of the transfer.

g. Confidentiality. Confidentiality is governed by the terms of the Confidentiality Agreement dated December 4, 2006 between Seller and Buyer and Section 15.6 of this Agreement. The terms of the Confidentiality Agreement dated December 4, 2006 between Seller and Buyer shall terminate at Closing or, if Closing does not occur, survive for the term set forth in the Confidentiality Agreement.

8.2 Financial Statements. Seller shall use its commercially reasonable efforts to prepare, at the sole cost and expense of Buyer, either (i) if relief is granted by the SEC, statements of revenues and direct operating expenses and all notes thereto related to the Assets or (ii) if such relief is not granted by the SEC, the financial statements required by the SEC (such financial statements set forth in the foregoing clauses (i) and (ii), as applicable, the “Statements of Revenues and Expenses”) in each case of clauses (i) and (ii), that will be required of Buyer or any of its Affiliates in connection with reports, registration statements and other filings to be made by Buyer or any of its Affiliates related to the transactions contemplated by this Agreement with the SEC pursuant to the Securities Act, or the Exchange Act, in such form that such statements and the notes thereto can be audited. Seller (x) shall cooperate with and permit Buyer to reasonably participate in the preparation of the Statements of Revenues and Expenses and (y) shall provide Buyer and its representatives with reasonable access to the personnel of Seller and its Affiliates who engage in the preparation of the Statements of Revenues and Expenses. Promptly after the date of this Agreement, Seller shall engage PricewaterhouseCoopers to perform an audit of the Statements of Revenues and Expenses and shall use commercially reasonable efforts to cause PricewaterhouseCoopers to issue unqualified opinions with respect to Statements of Revenues and Expenses (the Statements of Revenues and Expenses and related audit opinions being hereinafter referred to as the “Audited Financial Statements”) and provide its written consent for the use of its audit reports with respect to Statements of Revenues and Expenses in reports filed by Buyer or any of its Affiliates under the Exchange Act or the Securities Act, as needed. Buyer shall promptly reimburse Seller for all fees charged by PricewaterhouseCoopers pursuant to such engagement. Seller shall take all action as may be necessary to facilitate the completion of such audit and delivery of the Audited Financial Statements to Buyer or any of its Affiliates as soon as reasonably practicable, but no later than five (5) days prior to the date that such Audited Financial Statements would be required to be filed by Buyer or any of its Affiliates with a report on Form 8-K or an amendment thereto under the Exchange Act. Seller shall provide to Buyer a draft of the Audited Financial Statements no later than ten (10) days prior to the date that such Audited Financial Statements would be required to be filed by Buyer or any of its Affiliates with a report on Form 8-K or an amendment thereto under the Exchange Act. Seller shall use its commercially reasonable efforts to keep Buyer regularly informed regarding the progress of such audit and also shall periodically provide Buyer with copies of drafts of the Audited Financial Statements and related audit opinions.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

ARTICLE 9

CONDITIONS TO CLOSING

9.1 Seller’s Conditions. The obligations of Seller at the Closing are subject, at the option of Seller, to the satisfaction at or prior to Closing of the following conditions precedent:

a. Representations, Warranties and Covenants. All representations and warranties of Buyer contained in Article 7 of this Agreement shall be true and correct in all material respects on and as of the Closing, and Buyer shall have performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Buyer at or prior to the Closing in all material respects;

b. Closing Documents. Buyer shall have executed and delivered the documents which are contemplated to be executed and delivered by it pursuant to Article 11 of this Agreement prior to or on the Closing Date;

c. No Action. No order shall have been entered by any court or governmental agency having jurisdiction over the parties or the subject matter of this Agreement that restrains or prohibits the purchase and sale contemplated by this Agreement and which remains in effect at the time of Closing or seeks to recover damages from Seller resulting therefrom.

9.2 Buyer’s Conditions. The obligations of Buyer at the Closing are subject, at the option of Buyer, to the satisfaction on or prior to the Closing of the following conditions precedent:

a. Representations, Warranties and Covenants. The representations and warranties of Seller contained in Article 6 of this Agreement shall be true and correct in all material respects on and as of the Closing Date, and Seller shall have performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Buyer at or prior to the Closing in all material respects;

b. Closing Documents. Seller shall have executed and delivered the documents which are contemplated to be executed and delivered by it pursuant to Article 11 of this Agreement prior to or on the Closing Date;

c. SLC Consent. The SLC shall have given all consents necessary to transfer the Assets to Buyer.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

d. No Action. No order shall have been entered by any court or governmental agency having jurisdiction over the parties or the subject matter of this Agreement that restrains or prohibits the purchase and sale contemplated by this Agreement and which remains in effect at the time of Closing or seeks to recover damages from Buyer resulting therefrom.

ARTICLE 10

RIGHT OF TERMINATION AND ABANDONMENT

10.1 Termination. This Agreement may be terminated in accordance with the following provisions:

a. by Seller if the conditions set forth in Section 9.1 are not satisfied, through no fault of Seller, or waived by Seller in writing, as of the Closing Date; or

b. by Buyer if the conditions set forth in Section 9.2 are not satisfied, through no fault of Buyer, or waived by Buyer in writing, as of the Closing Date.

c. by Seller or Buyer if the aggregate of Title Defect Adjustments and Environmental Defect Adjustments ***.

d. by Seller or Buyer if Closing does not occur on or before May 16, 2007, or if the SLC consent necessary to transfer the Assets to Buyer has not been obtained by such date, a date which is three business days after the next scheduled meeting of the SLC.

10.2 Liabilities Upon Termination.

a. Buyer’s Default. If the transactions contemplated by this Agreement are not consummated on or before the date specified in Section 11.1 by reason of Buyer’s wrongful failure to tender performance at Closing, and if Seller is not in material default under the terms of this Agreement and is ready, willing and able to Close, and Seller terminates this Agreement, Seller shall be entitled, at Seller’s election, to (i) specific performance or (ii) retention of the Deposit, and any accrued interest, as liquidated damages. If Seller does not elect specific performance of this Agreement, Seller and Buyer agree that Seller’s damages in the event Buyer fails to close are difficult to measure and both Seller and Buyer agree that the amount of the Deposit bears a reasonable relationship to and is a reasonable estimation of such damages.

b. Seller’s Default. If the transactions contemplated by this Agreement are not consummated on or before the date specified in Section 11.1 by reason of Seller’s wrongful failure to tender performance at Closing and if Buyer is not in material default under this Agreement and is ready, willing and able to Close, and Buyer terminates this Agreement, Buyer shall be entitled, at Buyer’s election (i) specific performance, or (ii) to a prompt refund of the Deposit with interest accrued thereon.

c. Other Termination. If Seller and Buyer agree to terminate this Agreement, or if either party terminates the Agreement under Sections 10.1.c, then each party shall release the other party from any and all liability for termination of this Agreement, and Buyer shall be entitled to a refund of the Deposit with accrued Interest.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

ARTICLE 11

CLOSING

11.1 Date of Closing. Subject to Seller’s and Buyer’s rights to terminate in Article 10, the closing of the transaction contemplated by this Agreement (“Closing” or “Closing Date”) shall be held on or before the later of May 1, 2007 or five (5) business days after Buyer’s condition to Closing set forth in Section 9.2.c is satisfied or waived by Buyer, at Seller’s office in Bakersfield, California, at 8:30 a.m. or at such other time and place as the parties may agree in writing.

11.2 Closing Obligations. At Closing, the following events shall occur, each being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

a. Assignment of Assets. Seller and Buyer shall execute, acknowledge and deliver to Buyer an Assignment and Bill of Sale of the Assets effective as of the Effective Time (in sufficient counterparts to facilitate filing and recording) (i) substantially in the form of Exhibit E with a special warranty of title by, through and under Seller but not otherwise; with no warranties, express or implied, as to the personal property, fixtures or condition of the Assets which are conveyed “as is, where is;” (ii) such other assignments, bills of sale, or deeds necessary to transfer the Assets to Buyer, including without limitation any conveyances on official forms and related documentation necessary to transfer the Assets to Buyer in accordance with requirements of state and federal governmental regulations; and (iii) an Assignment and Assumption Agreement in the form of Exhibit F under which Seller assigns various contractual interests included in the Assets and under which Buyer assumes the obligations thereunder in accordance with the terms of this Agreement.

b. Preliminary Settlement Statement. Seller shall deliver to Buyer and Seller and Buyer shall execute and deliver the Preliminary Settlement Statement.

c. Purchase Price. Buyer shall deliver to Seller the Closing Amount by wire transfer of immediately available funds to Seller or as directed by Seller.

d. Letters in Lieu. Seller and Buyer shall execute and deliver all necessary letters in lieu of transfer orders directing all purchasers of production to pay Buyer the proceeds attributable to production from the Assets from and after the Effective Time.

e. Seller’s Officer’s Certificate. Seller shall execute and deliver to Buyer an officer’s certificate in form and substance similar to Exhibit H, stating that all conditions precedent to Closing have been satisfied.

f. Buyer’s Officer’s Certificate. Buyer shall execute and deliver to Seller an officer’s certificate in form and substance similar to Exhibit I, stating that all conditions precedent to Closing have been satisfied.

g. Non-Foreign Affidavit. In compliance with Section 1445 of the United States Internal Revenue Code, Seller shall execute and deliver to Buyer a Non-Foreign Affidavit in the form of Exhibit J.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

ARTICLE 12

POST-CLOSING OBLIGATIONS

12.1 Post-Closing Adjustments. As soon as practicable after the Closing, but on or before one hundred twenty (120) days after Closing, Seller, with the assistance of Buyer’s staff and with access to such records as necessary, shall prepare and deliver to Buyer a final settlement statement (the “Final Settlement Statement”) setting forth each adjustment or payment that was not finally determined as of the Closing and showing the calculation of such adjustment and the resulting final purchase price (the “Final Purchase Price”). As soon as practicable after receipt of Seller’s proposed Final Settlement Statement, but on or before fifteen (15) days after receipt of Seller’s proposed Final Settlement Statement, Buyer shall deliver to Seller a written report containing any changes that Buyer proposes to make to the Final Settlement Statement. Buyer’s failure to deliver to Seller a written report detailing changes to the proposed Final Settlement Statement by that date shall be deemed an acceptance by Buyer of the Final Settlement Statement as submitted by Seller. The parties shall endeavor to agree with respect to the changes proposed by Buyer, if any, no later than fifteen (15) days after receipt by Seller of Buyer’s comments to the proposed Final Settlement Statement. The date upon which such agreement is reached or upon which the Final Purchase Price is established for the transaction shall be called the “Final Settlement Date.” If the Final Purchase Price is more than the Closing Amount, Buyer shall pay Seller the amount of such difference. If the Final Purchase Price is less than the Closing Amount, Seller shall pay to Buyer the amount of such difference. Any payment by Buyer or Seller shall be by wire transfer in immediately available funds. Any such payment shall be within five (5) days of the Final Settlement Date.

12.2 Suspense Accounts. Seller currently maintains suspense accounts pertaining to oil and gas heretofore produced comprising monies payable to royalty owners, mineral owners and other persons with an interest in production that Seller has been unable to pay because of title defects (the “Suspense Accounts”). A preliminary listing of the Suspense Accounts is set forth in Exhibit K. At Closing, a downward adjustment to the Purchase Price will be made to convey the Suspense Accounts to Buyer and the Suspense Accounts will be included in the Preliminary Settlement Statement, with an adjustment made in the Final Settlement Statement, if necessary. Buyer will assume full and complete responsibility and liability for proper payment of the funds comprising the Suspense Accounts as set forth on the “Final Suspense Account Statement,” which shall be provided by Seller to Buyer with the Final Settlement Statement required in Section 12.1 (including any liability under any unclaimed property law or escheat statute). Buyer agrees to indemnify, defend and hold Seller, its parent, subsidiary and affiliated entities, together with their respective officers, directors, employees, agents and their respective successors and assigns, harmless from and against any and all liability, claims, demands, penalties and expenses (including attorneys’ fees) arising out of or pertaining to the proper payment and administration of the Suspense Accounts, limited, however to the total amount of the Suspense Accounts.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

12.3 Dispute Resolution. If the parties are unable to resolve disputes concerning the Final Settlement Statement or Final Purchase Price on or before thirty (30) days after the Final Settlement Statement is received by Buyer, such disputes shall be resolved in accordance with Section 14.5.d.

12.4 Records. Seller shall make the Records available for pick up by Buyer at a mutually agreeable time within ten (10) days of Closing. At Seller’s request, Buyer shall make the Records available to Seller for review and copying during normal business hours. Buyer agrees not to destroy or otherwise dispose of the Records for a period of six years after the Closing without giving Seller reasonable notice and an opportunity to copy the Records.

12.5 Further Assurances. From time to time after Closing, Seller and Buyer shall each execute, acknowledge and deliver to the other such further instruments and take such other action as may be reasonably requested in order more effectively to assure to the other the full beneficial use and enjoyment of the Assets in accordance with the provisions of this Agreement and otherwise to accomplish the purposes of the transaction contemplated by this Agreement.

12.6 Disclaimers of Representations and Warranties. The express representations and warranties of Seller contained in this Agreement are exclusive, are in lieu of all other representations and warranties, express, implied or statutory, and the representations and warranties contained in Sections 6.9 through and including 6.12 shall terminate upon and shall not survive the Closing. BUYER ACKNOWLEDGES THAT SELLER HAS NOT MADE, AND SELLER HEREBY EXPRESSLY DISCLAIMS AND NEGATES, AND BUYER HEREBY EXPRESSLY WAIVES, ANY REPRESENTATION OR WARRANTY, EXPRESS, IMPLIED, AT COMMON LAW, BY STATUTE OR OTHERWISE RELATING TO (A) PRODUCTION RATES, RECOMPLETION OPPORTUNITIES, DECLINE RATES, GAS BALANCING INFORMATION OR THE QUALITY, QUANTITY OR VOLUME OF THE RESERVES OF HYDROCARBONS, IF ANY, ATTRIBUTABLE TO THE ASSETS, (B) THE ACCURACY, COMPLETENESS OR MATERIALITY OF ANY INFORMATION, DATA OR OTHER MATERIALS (WRITTEN OR ORAL) NOW, HERETOFORE OR HEREAFTER FURNISHED TO BUYER BY OR ON BEHALF OF SELLER, (C) THE ENVIRONMENTAL CONDITION OF THE ASSETS, THEIR COMPLIANCE WITH ENVIRONMENTAL LAWS, AND THE PRESENCE OR ABSENCE OF HAZARDOUS SUBSTANCES OR NATURALLY OCCURRING RADIOACTIVE MATERIALS, (D) ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, (E) ANY IMPLIED OR EXPRESS WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE, (F) ANY IMPLIED OR EXPRESS WARRANTY OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS, (G) ANY RIGHTS OF PURCHASERS UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION, (H) ANY CLAIMS BY BUYER FOR DAMAGES BECAUSE OF DEFECTS, WHETHER KNOWN OR UNKNOWN AS OF THE EFFECTIVE TIME OR THE CLOSING DATE, AND (I) ANY AND ALL IMPLIED WARRANTIES EXISTING UNDER APPLICABLE LAW, IT BEING THE EXPRESS INTENTION OF BOTH BUYER AND SELLER THAT THE ASSETS WILL BE CONVEYED TO BUYER IN THEIR PRESENT CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE. THE PARTIES AGREE THAT THIS SECTION 12.5 CONSTITUTES A CONSPICUOUS LEGEND.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

ARTICLE 13

TAXES

13.1 Apportionment of Ad Valorem and Property Taxes. All ad valorem taxes, real property taxes, personal property taxes and similar obligations (the “Property Taxes”) attributable to the Assets with respect to the tax period in which the Effective Time occurs shall be apportioned as of the Effective Time between Seller and Buyer. Prior to Closing, Seller shall determine an estimate of the portion of the Property Taxes (based on the latest information then available), for the period in which the Effective Time occurs attributable to the period prior to the Effective Time (the “Seller Property Tax”). Seller shall credit to Buyer, through a downward adjustment to the Purchase Price, the amount of the Seller Property Tax. Buyer shall file or cause to be filed all required reports and returns incident to the Property Taxes and shall pay or cause to be paid to the taxing authorities all Property Taxes relating to the tax period in which the Effective Time occurs. If the Property Taxes used in determining the Seller Property Tax are not the actual Property Taxes for the tax period in which the Effective Time occurs, then upon the determination of the actual Property Taxes for such period, the Seller Property Tax shall be recalculated based upon such actual Property Taxes (the “Revised Seller Property Tax”) and (i) if the Revised Seller Property Tax is greater than the Seller Property Tax, Seller shall promptly pay the difference between such amounts or (ii) if the Revised Seller Property Tax is less than the Seller Property Tax, Buyer shall promptly pay Seller the difference between such amounts.

13.2 Transfer Taxes and Recording Fees. The Purchase Price excludes, and Buyer shall be liable for any stamp, documentary, filing, licensing, processing, recording authorization and similar fees and charges. Seller and Buyer shall each bear one half of any sales or transfer taxes assessed in connection with the transaction.

13.3 Other Taxes. All severance, production, excise, conservation and similar taxes attributable to the Assets that are based upon or measured by the production of Hydrocarbons (excluding Property Taxes which are addressed in Section 13.1) shall be apportioned between the Seller and Buyer as of the Effective Time. All such taxes that have accrued with respect to the period prior to the Effective Time have been or will be properly paid or withheld by Seller, and all statements, returns, and documents pertinent thereto have been or will be properly filed. Buyer shall be responsible for paying or withholding or causing to be paid or withheld all such taxes that have accrued after the Effective Time and for filing all statements, returns, and documents incident thereto.

13.4 Tax Reports and Returns. For tax periods in which the Effective Time occurs, Seller agrees to immediately forward to Buyer copies of any tax reports and returns received by Seller after Closing and provide Buyer with any information Seller has that is necessary for Buyer to file any required tax reports and returns related to the Assets. Buyer agrees to file all tax returns and reports applicable to the Assets that Buyer is required to file after the Closing.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

ARTICLE 14

ASSUMPTION AND RETENTION OF

OBLIGATIONS; INDEMNIFICATION

14.1 Buyer’s Assumption of Liabilities and Obligations. Upon Closing, Buyer shall assume and pay, perform, fulfill and discharge all claims, costs, expenses, liabilities and obligations (“Obligations”) accruing or relating to (i) the owning, developing, exploring, operating or maintaining of the Assets or the producing, transporting and marketing of Hydrocarbons from the Assets from and after the Effective Time, including, without limitation, the payment of Property Expenses, the obligation to plug and abandon all wells located on the Lands and reclaim all well sites located on the Lands regardless of when the plugging, abandonment and reclamation obligations arose, the make-up and balancing obligations for overproduction of gas from the Wells, all liability for royalty and overriding royalty payments made and Taxes paid with respect to the Assets for periods after the Effective Time and (ii) the environmental condition of the Assets except for any condition for which Buyer is indemnified by Seller under Section 5.5.a, and (iii) all Obligations accruing or relating to the ownership or operation of the Assets before the Effective Time for which Seller is not liable pursuant to the provisions of Section 14.2 (collectively, the “Assumed Liabilities”).

14.2 Seller’s Retention of Liabilities and Obligations. Upon Closing, Seller shall retain and pay (i) all Property Expenses of Seller relating to the ownership and operation of the Assets and the producing, transporting and marketing of Hydrocarbons from the Assets prior to the Effective Time, but only as to Claims asserted within two years after the Closing Date, (ii) all liability for personal injury and employment claims related to the ownership and operation of the Assets prior to the Effective Time (iii) all liability for royalty and overriding royalty payments due, owing or made and Taxes due, owing or paid prior to the Effective Time with respect to the Assets, (iv) any liability arising directly out of the 1993 Oil Spill, and (v) any liability for offsite disposal of hazardous substances relating to the Assets prior to the Effective Time by Seller, its employees and contractors only and not any such disposal by Seller’s predecessors in title (collectively, the “Retained Liabilities”).

14.3 Buyer’s Plugging and Abandonment Obligations. In addition to the Assumed Liabilities, upon Closing Buyer assumes full responsibility and liability for the following plugging and abandonment obligations related to the Assets (“Buyer’s Plugging and Abandonment Obligations”), regardless of whether they are attributable to the ownership or operation of the Assets before or after the Effective Time. All operations by Buyer under this Section shall be conducted in a good and workmanlike manner and in compliance with all applicable laws and regulations.

a. The necessary and proper plugging, replugging and abandonment of all wells on the Assets;

b. The necessary and proper removal, abandonment and disposal of all structures, pipelines, equipment, abandoned property, trash, refuse and junk located on or comprising part of the Assets;

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

c. The necessary and proper capping and burying of all associated flow lines located on or comprising part of the Assets;

d. The necessary and proper restoration of the surface used for operation of the Assets and subsurface to the condition required by applicable laws, regulations or contract;

e. All obligations relating to the items described in Section 14.3.a. through Section 14.3.d. arising from contractual requirements and demands made by courts, authorized regulatory bodies or parties claiming a vested interest in the Assets; and

f. Obtaining and maintaining all bonds, or supplemental or additional bonds, that may be required contractually or by governmental authorities.

14.4 Indemnification. “Losses” shall mean any actual losses, costs, expenses (including court costs, reasonable fees and expenses of attorneys, technical experts and expert witnesses and the costs of investigation), liabilities, damages, demands, suits, claims, and sanctions of every kind and character (including civil fines) arising from, related to or reasonably incident to matters indemnified against; excluding however any special, consequential, punitive or exemplary damages, diminution of value of an Asset, loss of profits incurred by a party hereto or Loss incurred as a result of the indemnified party indemnifying a third party.

After the Closing, Buyer and Seller shall indemnify each other as follows:

a. Seller’s Indemnification of Buyer. Seller assumes all risk, liability, obligation and Losses in connection with, and shall defend, indemnify, and save and hold harmless Buyer, its officers, directors, employees and agents, from and against all Losses which arise from or in connection with (i) the Retained Liabilities, (ii) any material breach of any representation or warranty made by Seller other than those contained in Sections 6.9 through and including 6.12, which shall terminate upon and not survive the Closing, (iii) matter for which Seller has agreed to indemnify Buyer under this Agreement, and (iv) any material breach by Seller of this Agreement.

b. Buyer’s Indemnification of Seller. Buyer assumes all risk, liability, obligation and Losses in connection with, and shall defend, indemnify, and save and hold harmless Seller, Seller’s officers, directors, employees and agents, from and against all Losses which arise from or in connection with (i) the Assumed Liabilities, (ii) any material breach of any representation or warranty made by Buyer, (iii) any matter for which Buyer has agreed to indemnify Seller under this Agreement, and (iv) any material breach by Buyer of this Agreement.

14.5 Procedure. The indemnifications contained in Section 14.4 shall be implemented as follows:

a. Coverage. Such indemnity shall extend to all Losses suffered or incurred by the Indemnified Party, as defined below.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

b. Claim Notice. The party seeking indemnification under the terms of this Agreement (“Indemnified Party”) shall submit a written “Claim Notice” to the other party (“Indemnifying Party”) which, to be effective, must state: (i) the amount of each payment claimed by an Indemnified Party to be owing, (ii) the basis for such claim, with supporting documentation, and (iii) a list identifying to the extent reasonably possible each separate item of Loss for which payment is so claimed. The amount claimed shall be paid by the Indemnifying Party to the extent required herein within ten (10) days after receipt of the Claim Notice, or after the amount of such payment has been finally established, whichever last occurs.

c. Information. Within twenty (20) days after the Indemnified Party receives notice of a claim or legal action that may result in a Loss for which indemnification may be sought under this Article 14 (“Claim”), the Indemnified Party shall give a Claim Notice to the Indemnifying Party. If the Indemnifying Party or its counsel so requests, the Indemnified Party shall furnish the Indemnifying Party with copies of all pleadings and other information with respect to such Claim. At the election of the Indemnifying Party made within sixty (60) days after receipt of the Claim Notice, the Indemnified Party shall permit the Indemnifying Party to assume control of such Claim (to the extent only that such Claim, legal action or other matter relates to a Loss for which the Indemnifying Party is liable), including the determination of all appropriate actions, the negotiation of settlements on behalf of the Indemnified Party, and the conduct of litigation through attorneys of the Indemnifying Party’s choice; provided, however, that no such settlement can result in any liability or cost to the Indemnified Party for which it is entitled to be indemnified hereunder without its consent. If the Indemnifying Party elects to assume control, (i) any expense incurred by the Indemnified Party thereafter for investigation or defense of the matter shall be borne by the Indemnified Party, and (ii) the Indemnified Party shall give all reasonable information and assistance, other than pecuniary, that the Indemnifying Party shall deem necessary to the proper defense of such Claim, legal action, or other matter. In the absence of such an election, the Indemnified Party will use its best efforts to defend, at the Indemnifying Party’s expense, any claim, legal action or other matter to which such other party’s indemnification under this Article 14 applies until the Indemnifying Party assumes such defense, and, if the Indemnifying Party fails to assume such defense within the time period provided above, settle the same in the Indemnified Party’s reasonable discretion at the Indemnifying Party’s expense. If such a Claim requires immediate action, both the Indemnified Party and the Indemnifying Party will cooperate in good faith to take appropriate action so as not to jeopardize defense of such Claim or either party’s position with respect to such Claim.

d. Dispute Resolution. If the existence of a valid Claim or amount to be paid by an Indemnifying Party is in dispute, the parties agree to submit determination of the existence of a valid Claim or the amount to be paid pursuant to the Claim Notice to binding arbitration. The arbitration shall be before a three person panel of neutral arbitrators, consisting of one person each to be selected by Seller and Buyer, and the third to be selected by the arbitrators selected by Seller and Buyer. The arbitrators shall conduct a hearing no later than sixty (60) days after submission of the matter to arbitration, and a written decision shall be rendered by the arbitrators within thirty (30) days of the hearing. Any payment due pursuant to the arbitration shall be made within fifteen (15) days of the arbitrators’ decision. This Section excludes those matters addressed in Sections 4.8 and 5.7 of this Agreement.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

14.6 No Insurance; Subrogation. The indemnifications provided in this Article 14 shall not be construed as a form of insurance. Seller and Buyer waive for themselves, their successors or assigns, including without limitation, any insurers, any rights to subrogation for Losses for which each of them is respectively liable or against which each respectively indemnifies the other, and, if required by applicable policies, Seller and Buyer shall obtain waiver of such subrogation from their respective insurers.

14.7 Reservation as to Non-Parties. Nothing in this Agreement is intended to limit or otherwise waive any recourse Seller or Buyer may have against any non-party for any obligations or liabilities that may be incurred with respect to the Assets.

ARTICLE 15

MISCELLANEOUS

15.1 Exhibits. The Exhibits referred to in this Agreement are hereby incorporated in this Agreement by reference and constitute a part of this Agreement.

15.2 Expenses. Except as otherwise specifically provided, all fees, costs and expenses incurred by Seller or Buyer in negotiating this Agreement or in consummating the transaction contemplated by this Agreement shall be paid by the party incurring same, including, without limitation, legal and accounting fees, costs and expenses.

15.3 Notices. All notices and communications required or permitted under this Agreement shall be in writing and addressed as follows:

If to Seller:	Berry Petroleum Company
	5201 Truxtun Avenue, Suite 300
	Bakersfield, California 93309
	Attention:	Manager Land Department
	Telephone:	(661) 616-3900
	Facsimile:	(661) 616-3886

	and

	Laura K. McAvoy, Esq.
	Musick, Peeler & Garrett LLP
	2801 Townsgate Road, Suite 200
	Westlake Village, California 91361
	Telephone:	(805) 418-3115
	Facsimile:	(805) 418-3101

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

If to Buyer:	Venoco, Inc.
	370 17^th Street, Suite 3900
	Denver, Colorado 80202
	Attention:	Terry Sherban
	Telephone:	(303) 626-8303

	and

	Venoco, Inc.
	6267 Carpinteria Ave.
	Carpinteria, CA 90313
	Attention:	Terry Anderson
	Telephone:	(805) 745-2253

Any communication or delivery hereunder shall be deemed to have been duly made and the receiving party charged with notice (i) if personally delivered, when received, (ii) if faxed, when received if receipt is confirmed by telephone by the sender, (iii) if mailed, certified mail, return receipt requested, on the date set forth on the return receipt or (iv) if sent by overnight courier, one day after sending. Any party may, by written notice so delivered to the other party, change the address or individual to which delivery shall thereafter be made.

15.4 Amendments. Except for waivers specifically provided for in this Agreement, this Agreement may not be amended nor any rights hereunder waived except by an instrument in writing signed by the party to be charged with such amendment or waiver and delivered by such party to the party claiming the benefit of such amendment or waiver.

15.5 Assignment. Prior to Closing, neither party shall assign all or any portion of its respective rights or delegate all or any portion of its respective duties hereunder without the prior written consent of the other party.

15.6 Confidentiality. Seller and Buyer agree the provisions of this Agreement shall be kept confidential except as disclosure may be required by applicable law, rules and regulations of governmental agencies or stock exchanges. Buyer shall inform Seller of all such disclosures by Buyer.

15.7 Press Releases. In the event that either party wishes or is required to make a press release or include such information in another document prior to Closing, such party will endeavor to provide the other with a draft of a press release or other document for review at least one business day before its release, filing or delivery. The parties will attempt in good faith to expeditiously reach agreement on such statement and the contents thereof. Failure to provide comments back to the other party within one business day of receipt of the press release or other document will be deemed consent to the public disclosure of the press release or other document and the content thereof.

15.8 Headings. The headings of the articles and sections of this Agreement are for guidance and convenience of reference only and shall not limit or otherwise affect any of the terms or provisions of this Agreement.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

15.9 Counterparts. This Agreement may be executed by Seller and Buyer in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute one and the same instrument. Execution can be evidenced by fax signatures with original signature pages to follow in due course.

15.10 References. References made in this Agreement, including use of a pronoun, shall be deemed to include, where applicable, masculine, feminine, singular or plural, individuals, partnerships or corporations. As used in this Agreement, “person” shall mean any natural person, corporation, partnership, court, agency, government, board, commission, trust, estate or other entity or authority.

15.11 Governing Law. This Agreement and the transactions contemplated hereby shall be construed in accordance with, and governed by, the laws of the State of California without regard to principles of conflicts of law. The validity of the various conveyances affecting the title to real property Assets shall be governed by and construed in accordance with the laws of the State of California.

15.12 Removal of Signs. Buyer shall remove all of Seller’s well and lease signs within five (5) days of the Closing Date.

15.13 Binding Effect. This Agreement shall be binding upon, and shall inure to the benefit of, the parties hereto, and their respective successors and assigns.

15.14 Survival. The following shall survive Closing: (i) all post-closing obligations and indemnities of Seller and Buyer subject to the limitations set forth herein, (ii) Seller’s representations and warranties in Article 6 and, (iii) Buyer’s representations and warranties in Article 7.

15.15 No Third-Party Beneficiaries. This Agreement is intended only to benefit the parties hereto and their respective permitted successors and assigns.

15.16 Limitation on Damages. Consistent with Article 14, the parties hereto expressly waive any and all rights to consequential, special, incidental, punitive or exemplary damages, or loss of profits resulting from breach of this Agreement.

15.17 Severability. It is the intent of the parties that the provisions contained in this Agreement shall be severable. Should any provisions, in whole or in part, be held invalid as a matter of law, such holding shall not affect the other portions of this Agreement, and such portions that are not invalid shall be given effect without the invalid portion.

15.18 Knowledge. As used throughout this Agreement, the term “knowledge” or “best knowledge” or “best of Seller’s knowledge,” whether or not such term is written in lower or upper case, means the actual knowledge without investigation of those officers and employees of Seller as of the Closing Date which are involved at a supervisory or higher level of any fact, circumstance, or condition.

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Confidential Portions Redacted and Filed with the Commission [***] Symbolizes Language Omitted Pursuant to an Application For Confidential Treatment.

ARTICLE 16

EXCHANGE RIGHT

16.1 Exchange Cooperation. Buyer shall cooperate (at no cost or liability to Buyer) with Seller so that Seller's transfer of the Assets to Buyer shall at Seller's election, be accomplished in a manner enabling the transfer to qualify as a part of a like-kind exchange of property by Seller within the meaning of Section 1031 of the Internal Revenue Code. If Seller so elects, Buyer shall reasonably cooperate with Seller to effect such like-kind exchange, which cooperation shall include, without limitation, taking such actions as Seller reasonably requests in order to pay the Deposit and the Purchase Price in a manner which enables such transfer to qualify as part of a like-kind exchange of property within the meaning of Section 1031 of the Code, and Buyer agrees that Seller may assign its rights (but not its obligations) under this Agreement to a qualified intermediary as defined in Treasury Regulations Section 1.1031(k)-1(g)(4)(iii) under United States Treasury Regulations, to qualify the transfer of the Purchase Price as a part of a like-kind exchange of property within the meaning of Sections 1031 of the Code.

Executed on the dates set forth in the acknowledgments below.

	Seller:

	BERRY PETROLEUM COMPANY
	a Delaware corporation


	By:


	Buyer:

	VENOCO, INC.
	a Delaware corporation


	By:

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CERTIFICATION OF CHIEF EXECUTIVE OFFICER SECTION 302

Exhibit 31.1

Certification of Chief Executive Officer

Pursuant to Section 302 of Sarbanes Oxley Act of 2002

I, Robert F. Heinemann, President, Chief Executive Officer, and Director certify that:

	1.	I have reviewed this report on Form 10-Q of Berry Petroleum Company (the Company);

	2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

	3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

	4.	The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a - 15(e) and 15d - (e) and internal control over financial reporting (as defined in Exchange Act Rules 13a - 15(f) and 15d - 15(f)) for the Company and have:

	a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designated under our supervision, 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;

	c)	evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions abut the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

	d)	disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting.

The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors:

	a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal controls over financial reporting.



	/s/ Robert F. Heinemann
	Robert F. Heinemann
May 2, 2007	President, Chief Executive Officer, and Director

CERTIFICATION OF CHIEF FINANCIAL OFFICER SECTION 302

Exhibit 31.2

Certification of Chief Financial Officer

Pursuant to Section 302 of Sarbanes Oxley Act of 2002

I, Ralph J. Goehring, Executive Vice President and Chief Financial Officer, certify that:

	1.	I have reviewed this report on Form 10-Q of Berry Petroleum Company (the Company);

	2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

	3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

	4.	The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a - 15(e) and 15d - (e) and internal control over financial reporting (as defined in Exchange Act Rules 13a - 15(f) and 15d - 15(f)) for the Company and have:

	a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designated under our supervision, 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;

	c)	evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

	d)	disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting;

The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting to the Company’s auditors and the audit committee of the Company’s board of directors:

	a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal controls over financial reporting.



	/s/ Ralph J. Goehring
	Ralph J. Goehring
May 2, 2007	Executive Vice President and Chief Financial Officer

CERTIFICATION OF CHIEF EXECUTIVE OFFICER SECTION 906

Exhibit 32.1

Certification of Chief Executive Officer

Pursuant to Section 906 of Sarbanes Oxley Act of 2002

In Connection with the Quarterly Report of Berry Petroleum Company (the “Company”) on Form 10-Q for the period ending March 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert F. Heinemann, President, Chief Executive Officer and Director of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, that:

	1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



	/s/ Robert F. Heinemann
	Robert F. Heinemann
May 2, 2007	President, Chief Executive Officer and Director

CERTIFICATION OF CHIEF FINANCIAL OFFICER SECTION 906

Exhibit 32.2

Certification of Chief Financial Officer

Pursuant to Section 906 of Sarbanes Oxley Act of 2002

In Connection with the Quarterly Report of Berry Petroleum Company (the “Company”) on Form 10-Q for the period ending March 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ralph J. Goehring, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, that:

	1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



	/s/ Ralph J. Goehring
	Ralph J. Goehring
Msy 2, 2007	Executive Vice President and Chief Financial Officer