SEC Filing | Berry Corporation (bry)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1996 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) 28700 Hovey Hills Road Taft, California 93268 (Address of principal executive offices, including zip code) Registrant's telephone number, including area code: (805) 769-8811 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered Class A Common Stock, $.01 par value New York Stock Exchange (including associated stock purchase rights) Securities registered pursuant to Section 12(g) of the Act: None 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 [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] As of February 24, 1997, the registrant had 21,067,434 shares of Class A Common Stock outstanding and the aggregate market value of the voting stock held by nonaffiliates was approximately $180,735,000. This calculation is based on the closing price of the shares on the New York Stock Exchange on February 24, 1997 of $14.50. The registrant also had 898,892 shares of Class B Stock outstanding on February 24, 1997, all of which is held by an affiliate of the registrant. DOCUMENTS INCORPORATED BY REFERENCE Part III is incorporated by reference from the registrant's definitive Proxy Statement for its Annual Meeting of Shareholders to be filed, pursuant to Regulation 14A, no later than 120 days after the close of the registrant's fiscal year.

2 BERRY PETROLEUM COMPANY TABLE OF CONTENTS PART I Items 1 and 2. Business and Properties 3 Item 3. Legal Proceedings 10 Item 4. Submission of Matters to a Vote of Security Holders 10 Executive Officers 11 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters 12 Item 6. Selected Financial Data 13 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 14 Item 8. Financial Statements and Supplementary Data 17 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 36 PART III Item 10. Directors and Executive Officers of the Registrant 36 Item 11. Executive Compensation 36 Item 12. Security Ownership of Certain Beneficial Owners and Management 36 Item 13. Certain Relationships and Related Transactions 36 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 37

3 PART I Items 1 and 2. Business and Properties Introduction Berry Petroleum Company, ("Berry" or "Company"), is an independent energy company engaged in the production, development, acquisition, exploitation, exploration and marketing of crude oil and natural gas. The Company was incorporated in Delaware in 1985 and has been a publicly traded company since 1987. Berry's principal reserves and producing properties are located in Kern and Ventura Counties in California. Information contained in this report on Form 10-K reflects the business of the Company during the year ended December 31, 1996. The Company's corporate headquarters are located on its properties in the South Midway-Sunset field, near Taft, California and Management believes the current facilities are adequate. The Company's mission is to increase shareholder wealth, primarily through maximizing the value and cash flow of the Company's assets. To achieve this, Berry's corporate strategy is to remain a low cost producer and to grow the Company's asset base strategically. To increase production, the Company will compete to acquire primarily proved reserves with exploitation potential and will focus on the further development of its existing properties by application of enhanced oil recovery (EOR) methods, developmental drilling, well completions and remedial work. The Company's primary growth focus is on opportunities in California. Berry believes that its primary strengths are its ability to maintain a low cost operation and its flexibility in acquiring attractive producing properties which have significant exploitation and enhancement potential. While the Company is not currently involved in exploration activities, the Company may investigate and pursue a focused exploration program in the future. The Company has substantial unused borrowing capacity to finance acquisitions and will consider, as appropriate, the issuance of capital stock to finance future purchases. Proved Reserves As of December 31, 1996, the Company's estimated proved reserves were 102.1 million barrels of oil equivalent, (BOE), of which 99.2% is crude oil. Substantially all of the Company's reserves are located in California with 94% and 5.8% of total reserves in Kern and Ventura Counties, respectively. Approximately 75% of the reserves are owned in fee. The Company's reserves have a long life, in excess of 20 years, which is primarily a result of the Company's strong position in heavy crude oil (the Company's properties in the Midway-Sunset field average 13 degree API gravity and the Montalvo field averages 16 degree API gravity). Production in 1996 was 3.6 million BOE, up 6% from 1995 production of 3.4 million BOE. For the five years 1992 through 1996, the Company's average reserve replacement rate was 273% at a cost of $2.54 per BOE. In 1996, the Company replaced 767% of its production at $2.84 per BOE. For the five year period, the Company's reserve replacement rate is higher than the industry average, and the finding cost per barrel is lower than the industry average. Acquisitions The Company completed two significant acquisitions in 1996, both occurring in the fourth quarter. In November, the Company acquired the Tannehill producing properties (Tannehill), which included an 18 megawatt cogeneration facility, for approximately $25.5 million. In December, the Company acquired the Formax producing properties (Formax) for approximately $49.5 million. The Tannehill and Formax properties produced approximately 2,350 barrels per day of heavy crude oil as of February 24, 1997, and are located adjacent to and in-between the Company's core South Midway-Sunset properties. The proved reserves associated with these acquired properties are approximately 27 million barrels. The combined purchase price of approximately $75 million was financed by existing working capital and $39 million of long-term debt. To finance the Formax acquisition, the Company entered into a $150 million unsecured three-year revolving credit facility with a major energy lender establishing an initial borrowing base of $50 million on December 1, 1996. The financing cost of the first $50 million under the agreement is at the London Interbank Offered Rates (LIBOR) plus 60 basis points, or approximately 6.25% at current market rates.

4 Operations The Midway-Sunset field contains predominantly heavy crude oil, the production of which depends substantially on steam injection. Berry utilizes primary, cyclic steaming and steam flooding recovery methods in this field and utilizes primary recovery methods at its Montalvo field. Berry operates all of its principal oil producing properties. Field operations include the initial recovery of the crude oil and its transport through treating facilities into storage tanks. After the treating process is completed, which includes removal of water and solids by mechanical, thermal and chemical processes, the crude oil is metered through Lease Automatic Custody Transfer facilities (LACT) and transferred into crude oil pipelines owned by other oil companies. The point-of-sale is usually at the LACT unit. Revenues The percentage of revenues by source for the prior three years is as follows: 1996 1995 1994 Sales of oil and gas 97% 89% 95% Interest and other income 3% 11% 5% See Berry's Statements of Operations and accompanying Notes thereto. Oil Marketing The market for hydrocarbons continues to be quite volatile. California crude oil pricing fundamentals improved in 1996 with declining Alaska production and the legislative approval to export Alaska North Slope crude oil. These combined factors are contributing to the reduction of the excess crude supply in the California market, thus strengthening California prices relative to West Texas Intermediate (WTI) prices. Over the last several years, California heavy crude oil prices have increased as a percentage of WTI, from approximately 60% in 1990 to approximately 75% in 1996. Furthermore, a strengthened California economy is providing for increased petroleum product demand while, at the same time, past refinery investments have resulted in higher demand for the heavy barrel. Refinery upsets (fires, explosions, extended turnarounds, etc.) can impact local crude prices, for limited times, by weakening crude demand. As a result of large investments required by the refinery industry in California to meet product specifications and clean air regulations, the number of individual refineries has decreased. As a result, individual average refinery utilization has increased from approximately 75% to 95% over the past decade and, therefore, any individual refinery disruption has a more pronounced impact on downstream crude oil demand. The Company may enter into crude oil or natural gas hedge contracts depending upon various factors including Management's view of the future crude oil markets. Berry's 1996 average heavy crude oil sales price was $15.42 per barrel, up $1.86 per barrel, or 14%, from $13.56 in 1995 (both years are net of any hedging). The Company hedged approximately 3,000 barrels per day, or 31% of its 1996 production by entering into two bracketed zero cost collar hedge contracts with a California independent refiner. These contracts expired on January 31, 1997. In late February 1997, the Company entered into a similar hedge contract for approximately 25% of its current production for a term of 18 months. To provide additional marketing flexibility, the Company owns a blending facility located near its South Midway-Sunset properties. The Company suspended the blending operations in December 1993 due to the high cost of natural gasoline, the improved demand for the Company's 13 degree API gravity heavy crude oil, and the narrowing margin between the posted price of the blended crude oil and the heavy crude oil. Up to 5,000 barrels per day of the Company's heavy crude oil can be blended with lighter crude oils and natural gasolines to produce a blended crude oil of approximately 27 degree API gravity. At times, this blending operation may allow the Company to improve the profit margin on the sale of its heavy crude oil. Blending also allows the Company the option to ship through common carrier pipelines and sell directly to refiners in the Los Angeles basin, the San Francisco Bay area and the Mid-Continent. While no blending has occurred since 1993, the Company has the ability to resume blending operations if warranted by market conditions.

5 Management of the Company does not believe that the loss of any single customer or contract would materially affect its business. There are no significant delivery commitments and substantially all of the Company's oil and gas production is sold under short-term contracts at current market prices. Steaming Operations Approximately 94% of the Company's reserves, or 96 million barrels, consist of heavy crude oil produced from depths less than 2000'. This heavy crude oil requires heat in the form of steam to be injected into the oil producing formations to reduce the oil viscosity and allow the oil to flow to the well-bore for production. As is typical in EOR operations, steam represents the highest cost component of operating expenses. The Company, in achieving its goal of being a low cost heavy oil producer, has focused on reducing its steam cost by purchasing two gas-fired cogeneration facilities. Steam generation from these facilities is more efficient than conventional steam generators, as both steam and electricity are produced from the same gas supply used as fuel. Another significant benefit is that the prices received upon the sale of electricity are currently based on natural gas prices. As natural gas prices fluctuate, so does the electricity revenue; thus, the Company's steam cost is substantially hedged against higher natural gas prices. As the California electric industry continues toward deregulation, this relationship may change and electricity revenues may be impacted by other factors in addition to natural gas prices. Proceeds received from the sale of electricity produced by the Company's cogeneration facilities are reported as a reduction in operating costs. For its South Midway-Sunset properties, the Company's current steam production is generated by the two cogeneration facilities (approximately 18,500 barrels of steam per day (BSPD)) and, as needed, from conventional steam generators. In addition, the Company is making modifications to use the duct-firing capability of its 38 megawatt facility which is expected to produce up to an additional 6,000 BSPD available for delivery to the recently acquired Formax properties. On its North Midway-Sunset properties, the Company relies solely on conventional steam generators for its steam requirements. The Company has ample productive steam capacity for its requirements at both core areas. Conventional steam generation is used by the Company at its South Midway-Sunset properties only as required to maintain current production levels, when additional steam injection is expected to economically produce additional barrels and as emergency back-up steam generation to the cogeneration facilities. Conventional steam generation is the sole source of steam at the North Midway-Sunset properties. Current oil prices, near-term oil price expectations and natural gas prices are the primary factors determining steam levels generated from conventional generators. The Company's two cogeneration facilities sold electricity to a large California-based utility under Standard Offer 2 contracts (SO2) in 1996. The SO2 contract for the 38 megawatt facility expired on January 16, 1997, while the contract for the 18 megawatt facility does not expire until December 31, 2001. The SO2 contract for the 38 megawatt facility has been replaced by a Standard Offer 1 (SO1) contract effective January 16, 1997, which will result in lower electricity revenues for the 38 megawatt facility. However, under the SO1 contract, the Company will continue to receive Short Run Avoided Cost (SRAC) pricing plus a portion of the proceeds related to available capacity that were received in 1996. Proposed deregulation of the electricity generation market in California may have a positive or negative impact on the Company's future electricity revenues, however, the Company believes, at a minimum, that continued steam generation from cogeneration facilities will be significantly more efficient and cost effective than conventional steam generation. The Company has physical access to gas pipelines, such as the Kern River/El Paso and Southern California Gas Company systems, to transport its gas purchases required for steam generation. Natural gas purchases for the 38 megawatt cogeneration facility were subject to a long-term gas transportation agreement which required the Company to pay above market transportation rates for a substantial portion of the facility's gas requirements. However, this contract expires in April 1997 and the take-or- pay requirements were substantially satisfied in January 1997. As a result, the Company expects substantial reductions in its gas transportation costs in 1997 and beyond.

6 Environmental and Other Regulations The operations of Berry are affected in varying degrees by federal, state, regional and local laws and regulations, including laws governing allowable rates of production, well spacing, air emissions, water discharges, endangered species, marketing, pricing, taxes and other laws relating to the petroleum industry. Berry is further affected by changes in such laws and by constantly changing administrative regulations. Berry, as an owner and operator of oil and gas properties, is subject to various federal, state, regional and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liabilities on the owner or the lessee in the case of leased properties for the cost of pollution clean-up resulting from operations, subject the owner or lessee to liability for pollution damages, require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Berry has made and will continue to make expenditures in its efforts to comply with these requirements, which it believes are necessary business costs in the oil and gas industry. Berry has established policies for continuing compliance with environmental laws and regulations affecting its production. The costs incurred by these policies and procedures are inextricably connected to normal operating expenses such that the Company is unable to separate the expenses related to environmental matters; however, the Company does not believe any such additional future expenses are material to its financial position or results of operations. Although environmental requirements do have a substantial impact upon the energy industry, generally these requirements do not appear to affect Berry any differently, or to any greater or lesser extent, than other companies in California and in the domestic industry as a whole. Berry does not believe that compliance with federal, state, regional or local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, will have a material adverse effect upon the capital expenditures, earnings or competitive position of the Company, but there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have such an impact. Berry's properties in the Montalvo field have greater environmental risks due to their location near the Pacific Ocean. In Berry's case, a small oil spill that endangers tidal waters could immediately involve significant clean-up, regulatory investigation and penalties, any or all of which could subject the Company to a significant financial burden. In addition to purchasing insurance to cover certain environmental risks, the Company mitigates this exposure by the development and implementation of emergency response and major oil spill prevention and contingency plans. The Company is also a contract associate member of Clean Seas, an organization with significant experience and resources to contain and minimize the effects of an oil spill. The Company experienced an oil spill due to a ruptured pipe on its Montalvo field in December 1993 which required cleanup of the area directly around the pipe, an agricultural runoff pond and the nearby beach and ocean. Although 100% of the Montalvo field's wells and facilities are onshore, part of the spilled crude oil was pumped into the ocean from the agricultural runoff pond by an agricultural worker. The Company initiated procedures and made operational improvements to reduce the likelihood of a similar future event. See Item 3. "Legal Proceedings" and Note 12 to the Company's financial statements. Berry maintains insurance coverage which it believes is customary in the industry, although it is not fully insured against all environmental risks. The Company is not aware of any environmental claims, other than described herein, existing as of December 31, 1996, which would have a material impact upon the Company's financial position or results of operations.

7 Competition The oil and gas industry is highly competitive. As an independent producer, the Company does not own any refining or retail outlets. It has little control over the price it receives for its crude oil, and higher costs, fees and taxes assessed at the producer level cannot necessarily be passed on to the Company's customers. In acquisition activities, significant competition exists since integrated companies, independent companies and individual producers and operators are active bidders for desirable oil and gas properties. Although many of these competitors have greater financial and other resources than the Company, Management believes that it is in a position to compete effectively due to its low cost structure, transaction flexibility, strong financial position and experience. Employees On December 31, 1996, the Company had 98 full-time employees. Acquisition and Disposition of Properties The Company spent approximately $75 million on property acquisitions (Tannehill and Formax), including the purchase of an 18 megawatt cogeneration facility, and $9.4 million on development programs in 1996. The Company's 1997 budget for capital expenditures on development activities, including facilities, is $16.4 million of which 54% is earmarked for exploitation of Tannehill and Formax. As these activities are influenced by numerous factors including, but not limited to, drilling results, oil and natural gas prices, availability of equipment, regulatory restrictions, etc., many of which are outside the Company's control, the actual expenditure level may vary considerably from budgeted levels. In 1995, the Company sold its Rincon properties located in Ventura County, California, which comprised 1,631 acres and 15 producing wells and represented approximately 3% of its net daily production and 2% of its reserves. Oil and Gas Properties Development South Midway-Sunset - Berry owns and operates working interests in eighteen properties containing 1,730 acres located in the South Midway-Sunset field. The Company estimates these properties account for approximately 82% of the Company's proved oil and gas reserves and approximately 84% of its current daily production. The wells produce from an average depth of approximately 1200 feet. These properties rely on thermally enhanced oil recovery methods, primarily cyclic steaming. Twelve of these properties, which are owned in fee, accounted for approximately 74% of Berry's average daily production during 1996 and represent 75% of the Company's proved oil and gas reserves. During 1996, a total of 39 development wells were drilled and completed on these properties. The objective of this work was to maintain and accelerate productive capacity in the Company's single largest asset. Included in the above program were two horizontal wells. This improving technology was used on producing wells, the goal of which is to act as basal drainage points in mature areas of the Monarch reservoir, and provide more efficient reservoir depletion. The Company is monitoring these wells to determine the appropriate future application to its properties, with its objective being to accelerate production, improve ultimate recovery of original oil-in-place and to reduce the development and operating costs of the properties. North Midway-Sunset - Berry owns and operates approximately 1,824 acres in the North Midway-Sunset field which account for approximately 9% of the Company's proved oil and gas reserves and approximately 9% of its current daily production. These properties rely on thermally enhanced oil recovery methods, primarily cyclic steaming and steam flooding. Berry's interests consist of four fee properties comprising 1,009 acres and seven leases comprising 815 acres. The wells produce from an average depth of approximately 1200 feet.

8 During 1996, the Company drilled one Potter well, deepened one existing Potter well and drilled seven wells in the Mya sand reservoir. The objective of this work was to maintain productive capacity and develop proven reserves. Two of the Mya sand wells drilled were on the Section 12 property acquired in 1995. The Mya program established significant follow-up potential. Montalvo - Berry owns 100% of the working interest in six leases in Ventura County, California in the Montalvo field. Two of the six leases are owned by the State of California. The Company estimates current proved reserves from Montalvo account for approximately 6% of Berry's proved oil and gas reserves. Total production from these leases, containing 8,563 acres, represents approximately 7% of Berry's total current daily oil and gas production. The wells produce from an average depth of approximately 12,500 feet. The Company's 1996 efforts were directed at improving efficiency, lowering operating cost and further reducing environmental risk. Exploration The Company did not participate in the drilling of any exploration wells in 1996. Although the Company has significantly reduced its exploration program since 1994 to concentrate on improving profitability and strategic acquisitions, the Company may investigate and pursue a focused exploration program in the future. Oil and Gas Reserves Reserve Reports - The Company engaged DeGolyer and MacNaughton (D&M) to estimate the proved oil and gas reserves and the future net revenues to be derived from such properties of the Company for the three years ended December 31, 1996 for all of the Company's properties. D&M is an independent oil and gas reserve engineering firm. In preparing their reports for the three years ended December 31, 1996, they reviewed and examined such geological, economic, engineering and other data provided by the Company as considered necessary under the circumstances applicable to each reserve report. They also examined the reasonableness of certain economic assumptions regarding estimated operating and development costs and recovery rates in light of economic circumstances as of December 31, 1996, 1995 and 1994. For the Company's operated properties, reserve estimates are filed annually with the U.S. Department of Energy. Refer to the Supplemental Information About Oil & Gas Producing Activities (Unaudited) for the Company's oil and gas reserve disclosures. Production The following table sets forth certain information regarding production for the years ended December 31, as indicated: 1996 1995 1994 Net Annual Production(1): Oil (Mbbls) 3,491 3,277 3,250 Gas (Mmcf) 491 611 793 Total equivalent barrels (2) 3,573 3,379 3,382 Average Sales Price: Oil (per bbl) $ 15.42 $ 13.56 $ 11.61 Gas (per mcf) 1.99 1.50 1.87 Per BOE 15.36 13.48 11.60 Average Production Cost (per BOE) 4.92 5.41 6.28 (1) Net production represents production owned by Berry and produced to its interest, less royalty and other similar interests. All oil and gas produced, other than lease fuel needs, is sold at the well site. Berry does not refine any of its production. (2) Equivalent oil and gas information is at a ratio of 6,000 cubic feet of natural gas to one barrel (bbl) of oil.

9 Acreage and Wells At December 31, 1996, the Company's properties accounted for the following developed and undeveloped acres: Developed Acres Undeveloped Acres Gross Net Gross Net California 6,943 6,820 6,846 6,846 Other 1,250 220 - - ----- ----- ----- ----- 8,193 7,040 6,846 6,846 ===== ===== ===== ===== Gross acres represent all acres in which Berry has a working interest; net acres represent Berry's aggregate working interests in the gross acres. Berry currently has 2,108 gross oil wells (2,095 net) and 8 gross gas wells (4 net). Gross wells represent the total number of wells in which Berry has a working interest. Net wells represent the number of gross wells multiplied by the percentages of the working interests owned by Berry. One or more completions in the same bore hole are counted as one well. Any well in which one of the multiple completions is an oil completion is classified as an oil well. Drilling Activity The following table sets forth certain information regarding Berry's drilling activities for the periods indicated: 1996 1995 1994 Gross Net Gross Net Gross Net Exploratory Wells Drilled: Productive 0 0.0 0 0.0 0 0.0 Dry (1) 0 0.0 4 0.7 4 0.8 Development Wells Drilled: Productive 46 45.1 44 44.0 14 14.0 Dry (1) 3 2.1 1 1.0 0 0.0 Total Wells Drilled: Productive 46 45.1 44 44.0 14 14.0 Dry (1) 3 2.1 5 1.7 4 0.8 (1) A dry well is a well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. As of February 24, 1997, no exploratory wells were being drilled nor are budgeted to be drilled in 1997.

10 Title and Insurance The Company is not aware of any defect in the title to any of its principal properties. Notwithstanding the absence of a recent title opinion or title insurance policy, the Company believes it has satisfactory title to these properties, subject to such exceptions as the Company believes are customary and usual in the oil and gas industry and which the Company believes will not materially impair its ability to recover the proved oil and gas reserves or to obtain the resulting economic benefits. Title insurance was obtained by the Company on the Tannehill and Formax properties upon their acquisition. The oil and gas business can be hazardous, involving unforeseen circumstances such as blowouts or environmental damage. Although it is not insured against all risks, the Company maintains a comprehensive insurance program to address the hazards inherent in the oil and gas business. Item 3. Legal Proceedings On December 25, 1993, a crude oil spill was discovered on the Company's Montalvo field in Ventura County, California. The Company estimates that the total discharge was approximately 2,100 barrels. The Company paid $.6 million to settle all potential state criminal claims against the Company in August 1994. The Company reached a final settlement for civil damages and penalties with the federal and state governments in January 1997 and a consent decree was approved and entered by the U.S. District Court in Los Angeles, California on February 14, 1997. The Company, without admitting any liability, agreed to pay approximately $3.2 million to federal and state agencies for response and assessment costs, civil damages and penalties arising from this incident. The Company received reimbursement under its insurance policy for approximately $2.3 million of the settlement amount. As of December 31, 1996 and February 24, 1997, the Company had received approximately $9.8 million and $11.2 million, respectively, under its insurance coverage as reimbursement for costs incurred and paid by the Company associated with the spill. Management believes that its previous accruals are adequate. Information relating to the tax matters appeal to the U.S. Court of Appeals (Ninth Circuit) is set forth in Note 9 to the Company's financial statements. Item 4. Submission of Matters to a Vote of Security Holders None.

11 EXECUTIVE OFFICERS Listed below are the names, ages (as of December 31, 1996) and positions of the executive officers of Berry and their business experience during at least the past five years. JERRY V. HOFFMAN, 47, Chairman of the Board, President and Chief Executive Officer. Mr. Hoffman has been President and Chief Executive Officer since May 1994 and President and Chief Operating Officer from March 1992 until May 1994. Mr. Hoffman was added to the Board of Directors in March 1992 and named Chairman on March 21, 1997. Mr. Hoffman held the Senior Vice President and Chief Financial Officer positions from January 1988 until March 1992. Mr. Hoffman, a CPA, has held a variety of other positions with the Company and its prior subsidiaries or successors since February 1985. DONALD A. DALE, 50, Controller since December 1985. Mr. Dale, a CPA, was the Controller for Berry Holding Company from September 1985 to December 1985. RALPH J. GOEHRING, 40, Chief Financial Officer since March 1992 and Manager of Taxation from September 1987 until March 1992. Mr. Goehring, a CPA, is also the Assistant Secretary for Berry Petroleum Company. CHESTER L. LOVE, 62, Vice President of Engineering since March 1994 and Manager of Engineering from May 1992 to March 1994. Mr. Love, a registered petroleum engineer, was previously Vice President of Consulting for Scientific Software-Intercomp from 1979 to 1992. KENNETH A. OLSON, 41, Corporate Secretary since December 1985 and Treasurer since August 1988. Mr. Olson, a CPA, has held a variety of other positions with the Company and its prior subsidiaries or successors since July 1985. MICHAEL R. STARZER, 35, Vice President of Corporate Development since March 1996 and Manager of Corporate Development since April 1995. Mr. Starzer, a registered petroleum engineer, was with Unocal from August 1983 to May 1991 and from August 1993 to April 1995. Mr. Starzer was an engineering consultant and worked with the California State Lands Commission from May 1991 to August 1993. STEVEN J. THOMAS, 46, Manager of Production since March 1993, joined the Company's engineering department in September 1992. Mr. Thomas, a registered petroleum engineer, was an engineering and petroleum consultant from 1990 to 1992 and was employed by Chevron USA from 1979 to 1990 in various drilling, production and facilities engineering positions.

12 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock", are each entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $1.00 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder. In 1989, the Company adopted a Stockholder Rights Agreement and declared a dividend distribution of one such Right for each outstanding share of Capital Stock on December 22, 1989. Each share of Capital Stock issued after December 22, 1989 includes one Right. The Rights expire on December 8, 1999. See Note 7 of Notes to the Financial Statements. In conjunction with the acquisition of Tannehill, the Company issued a Warrant Certificate to the beneficial owners of Tannehill Oil Company. This Warrant authorizes the purchase of 100,000 shares of Berry Petroleum Company Class A Common Stock until November 8, 2003 at $14.06 per share. All the warrants are currently outstanding and the underlying shares will not be registered under the Securities Act of 1933. Berry's Class A Common Stock is listed on the New York Stock Exchange under the symbol "BRY". The Class B Stock is not publicly traded. The market data and dividends for 1996 and 1995 are shown below: 1996 1995 Price Range Dividends Price Range Dividends High Low per Share High Low per Share First Quarter $ 11 1/8 $ 8 3/4 $ .10 $ 10 $ 8 3/4 $ .10 Second Quarter 12 1/2 10 3/8 .10 10 7/8 9 .10 Third Quarter 11 3/4 10 3/8 .10 10 5/8 9 3/8 .10 Fourth Quarter 14 1/2 11 1/4 .10 10 7/8 9 7/8 .10 The closing price per share of Berry's Common Stock, as reported on the New York Stock Exchange Composite Transaction Reporting System for February 24, 1997, December 31, 1996 and December 31, 1995 was $14.50, $14.375 and $10.125, respectively. The number of holders of record of the Company's Common Stock and Class B Stock as of February 24, 1997 was approximately 1,010 and 1, respectively. The Company has paid cash dividends for many years prior to the roll-up of the various Berry companies into Berry Petroleum Company on December 16, 1985. However, since Berry's formation, the Company has paid dividends on its Common Stock for 8 consecutive semi-annual periods through September 1989 and for 29 consecutive quarters through December 31, 1996. The Company intends to continue the payment of dividends, although future dividend payments will depend upon the Company's level of earnings, operating cash flow, capital commitments and other relevant factors. Dividends declared on 4,366,400 shares of certain Common Stock are restricted, whereby 37.5% of the dividends declared on these shares are paid by the Company to the surviving member of a group of individuals, the B Group, for as long as this remaining member shall live.

13 Item 6. Selected Financial Data The following table sets forth certain financial information with respect to the Company and is qualified in its entirety by reference to the historical financial statements and notes thereto of the Company included in Item 8, "Financial Statements and Supplementary Data." The statement of operations and balance sheet data included in this table for each of the five years in the period ended December 31, 1996 were derived from the audited financial statements and the accompanying notes to those financial statements (in thousands, except per share and per barrel data): 1996 1995 1994 1993 1992 Statement of Operations Data: Sales of oil and gas $ 55,264 $ 45,773 $ 39,451 $ 42,843 $ 49,598 Operating costs (excluding DD&A and exploratory dry hole costs) 17,587 18,264 21,224 23,790 20,931 General and administrative expenses (G&A)(excluding DD&A) 4,820 4,578 5,118 5,999 5,511 Depreciation, depletion & amortization (DD&A) 7,323 6,847 7,270 9,983 8,123 Net income (loss) 17,546 12,203 (1,129) 32 10,115 Net income (loss) per share .80 .56 (.05) - .46 Weighted average number of shares outstanding 21,939 21,932 21,932 21,926 21,915 Balance Sheet Data: Working capital $ 7,850 $ 36,506 $ 38,273 $ 40,418 $ 50,642 Total assets 176,403 117,722 118,254 135,159 140,140 Long-term debt 36,000 - - - - Shareholders' equity 101,009 92,060 88,632 98,323 109,690 Cash dividends per share .40 .40 .40 .55 .60 Operating Data: Cash flow from operations 29,182 17,070 14,579 10,957 22,169 Capital expenditures(excluding acquisitions) 15,616 14,569 5,911 13,983 9,869 Property Acquisitions (1) 69,330 503 1,023 - 2,311 Per BOE: Sales price $ 15.36 $ 13.48 $ 11.60 $ 11.43 $ 12.75 Operating costs 4.92 5.41 6.28 6.35 5.43 G&A 1.35 1.35 1.51 1.60 1.43 ------ ------ ------ ------ ------ Cash flow 9.09 6.72 3.81 3.48 5.89 DD&A 2.05 2.03 2.15 2.67 2.11 ------ ------ ------ ------ ------ Operating income $ 7.04 $ 4.69 $ 1.66 $ .81 $ 3.78 ====== ====== ====== ====== ====== Production: Oil (Bbls) 3,491 3,277 3,250 3,617 3,683 Gas (Mcf) 491 611 793 771 1,029 Total (BOE) 3,573 3,379 3,382 3,746 3,855 Proved Reserves Information: Oil (Bbls) 101,336 77,071 75,996 72,078 72,434 Gas (Mcf) 4,682 5,983 6,530 5,476 10,003 Total (BOE) 102,116 78,068 77,084 72,991 74,101 Present value(NPV10)of estimated future cash flow before income taxes $634,579 $308,370 $263,890 $ 50,124 $155,546 (1) Excludes cogeneration facility costs and includes certain closing and consultant costs related to the acquisitions.

14 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations The following discussion provides information on the results of operations for each of the three years ended December 31, 1996 and the financial condition, liquidity and capital resources as of December 31, 1996. The financial statements and the notes thereto contain detailed information that should be referred to in conjunction with this discussion. The profitability of the Company's operations in any particular accounting period will be directly related to the average realized prices of oil and gas sold, the type and volume of oil and gas produced and the results of acquisition, development, exploitation and exploration activities. The average realized prices for oil and gas will fluctuate from one period to another due to world market conditions, regional and other factors. The aggregate amount of oil and gas produced may fluctuate based on development and exploitation of oil and gas reserves pursuant to current reservoir management plans. Production rates, steam costs, labor and maintenance expenses are expected to be the principal influences on operating costs. Accordingly, the results of operations of the Company may fluctuate from period to period based on the foregoing principal factors, among others. Results of Operations Net income for 1996 was $17.5 million, up $5.3 million and $18.6 million, respectively, from net income of $12.2 million in 1995 and a loss of $1.1 million in 1994. For the fourth quarter of 1996, net income was $5.3 million, up $1.6 million, or 43%, from $3.7 million in the fourth quarter of 1995 and $1.3 million, or 32.5%, from $4.0 million in the third quarter of 1996. The improvement in profitability in 1996 versus 1995 was primarily due to higher oil prices and production, lower operating costs and the reduction in dry hole costs, offset partially by the gain on the sale of the Rincon properties in 1995. 1996 1995 1994 Production - BOE Per Day 9,762 9,258 9,266 Averages Sales Price - Per BOE $15.36 $13.48 $11.60 Operating Cost - Per BOE 4.92 5.41 6.28 DD&A - Per BOE 2.05 2.03 2.15 G&A - Per BOE 1.35 1.35 1.51 Operating income from producing operations was $30.7 million, up $9.6 million from 1995 and $19.8 million from 1994, or 45% and 166%, respectively, from $21.2 million in 1995 and $11.6 million in 1994. The improvement was primarily due to higher oil prices, lower operating costs and higher production. The average sales price received per BOE during 1996 of $15.36 was 14% and 32% higher than $13.48 and $11.60 received in 1995 and 1994, respectively. Oil and gas production of 9,762 BOE per day was 504 and 496 BOE per day higher than 1995 and 1994, respectively, primarily due to the Company's 1996 development program and property acquisitions in the fourth quarter of 1996. Production for 1994 and 1995 includes the Rincon properties sold on November 1, 1995, which produced approximately 280 BOE per day. The Company maintained two bracketed zero cost collar hedge contracts with a California refiner to protect the Company's revenue from potential price declines. The contracts were initiated in 1995 and early 1996 and covered approximately 31% of the Company's crude oil sales. These contracts expired in January 1997. Because of the rise in crude oil prices which occurred during 1996, the hedge contract lowered the average sales price received for the Company's crude oil by approximately $.37 per BOE. In late February 1997, the Company entered into a similar hedge contract for approximately 25% of its current production for a term of 18 months.

15 Operating costs in 1996 declined 9% and 22% from 1995 and 1994, respectively, to $4.92 per BOE largely due to the benefit of owning and operating for a full year the Company's 38 megawatt cogeneration plant, which was purchased in August 1995. In addition, the Rincon properties, which incurred high operating costs, were sold in November 1995 and various cost reduction measures were initiated on the Company's properties. The Company includes production taxes in its operating costs. On a BOE basis, the amount of production taxes were $.48, $.45 and $.47 for 1996, 1995 and 1994, respectively. DD&A per BOE in 1996 increased slightly to $2.05 from $2.03 in 1995 and $2.02 in 1994. The increase was primarily related to property acquisitions in the fourth quarter of 1996. The Company expects higher DD&A costs in the future, in both real terms and on a BOE basis, due to acquisitions. On November 19, 1996, the Company acquired Tannehill, which included an 18 megawatt cogeneration facility, for approximately $25.5 million. On December 13, 1996, the Company acquired Formax for approximately $49.5 million. These producing properties are adjacent to and in-between the Company's core South Midway-Sunset producing properties and, as of February 24, 1997, produce approximately 2,350 barrels per day of 13 degree API gravity crude oil. The Company expects production from these newly acquired properties to exceed 3,500 barrels per day by the end of 1997. The 18 megawatt cogeneration facility located on Tannehill will be integrated into the Company's South Midway-Sunset operations to optimize steam usage and reduce costs. General Interest income in 1996 was $2.1 million, up from $2 million in 1995 and $1.6 million in 1994, due primarily to higher cash reserves resulting from the Company's strong cash flow in 1996. The Company anticipates that its interest income for 1997 will decrease significantly, and the Company will incur net interest expense due to the incurrence of long-term financing used to acquire Formax. G&A was $4.8 million in 1996, up 4% from $4.6 million in 1995, but down 6% from $5.1 million in 1994. The Company remains focused on cost control in all areas and, on a per barrel basis, G&A was $1.35 per BOE in 1996, unchanged from 1995, but down 11% from 1994. The Company anticipates that its total G&A costs will increase modestly in 1997, but that the G&A per BOE will decline due to the higher production levels expected in 1997. The Company's effective income tax rate in 1996 was 36%, down slightly from the 1995 effective rate of 37%. This lower rate for 1996 was the result of increased development activity by the Company which generated additional tax credits for federal and California tax purposes. The tax benefit of 42.1% for 1994 was the result of pre-tax losses for that year impacted by certain tax benefits. In the fourth quarter of 1996, the Company adopted the disclosure option of Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation." As permitted in this pronouncement, the Company opted to continue to apply the accounting provisions of Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees," to its stock-based employee compensation arrangements. The disclosure requirements of SFAS No. 123 are presented in Note 10 to the Company's financial statements. In the fourth quarter of 1995, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." This adoption resulted in no charges to the Company's financial statements in 1996 or 1995 and is not significantly different than the Company's impairment policy in effect prior to the adoption.

16 Financial Condition, Liquidity and Capital Resources Working capital as of December 31, 1996 was $7.8 million, down from $36.5 million and $38.3 million at December 31, 1995 and December 31, 1994, respectively. Cash flow provided by operating activities of $29.2 million was up 71% and 100% from $17.1 million and $14.6 million in 1995 and 1994, respectively. Cash flow was higher in 1996 due to higher oil prices, lower operating costs and higher production. Working capital declined $28.7 million from December 31, 1995, due to the use of cash and the assumption of $6.9 million in short-term debt for the two acquisitions completed in the fourth quarter of 1996. Other significant uses of working capital included the payment of $8.8 million in dividends and $9.9 million in capital expenditures primarily to develop the Company's existing producing properties including the drilling of 49 development wells. The Company's 1997 capital expenditure program, which includes the drilling of approximately 90 new wells, is estimated to be $16.4 million and will be financed through internally generated cash flow. On December 1, 1996, the Company established a $150 million unsecured three-year revolving credit facility with NationsBank of Texas. In conjunction with the purchase of Tannehill and Formax, the Company borrowed $36 million in long-term debt and incurred $6.9 million in short-term notes which were due and paid on January 6, 1997. The Company is carrying $39 million in long-term debt under this credit facility as of February 24, 1997. The total proved reserves at December 31, 1996 were 102.1 million BOE, up 31% from 78.1 million BOE at December 31, 1995 and up 32% from 77.1 million BOE at December 31, 1994. After production of 3.6 million BOE, the Company's proved reserves increased 27.6 million BOE, or 767% of 1996 production. The increase was primarily related to the acquisition of Tannehill and Formax in the fourth quarter of 1996. The Company's present value of estimated future net cash flows before income taxes, discounted at 10%, was $635 million at December 31, 1996, a 106% and 141% increase from $308 million and $264 million at December 31, 1995 and 1994, respectively. Future Developments Proposed deregulation of the electricity generation market in California may have a positive or negative impact on the Company's future electricity revenues, and may impact the beneficial hedge on gas prices the Company currently enjoys. In addition, the underlying value of the cogeneration facilities may be impacted as the outcome of deregulation becomes more apparent. In 1996, the American Institute of Certified Public Accountants issued Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities," effective for fiscal years beginning after December 15, 1996. Management does not believe that adoption of the provisions of this SOP will have a material impact on the financial statements of the Company. In 1997, the Company will adopt SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." Management does not believe that adoption of this accounting standard will have a material impact on the financial statements of the Company. Impact of Inflation The impact of inflation on the Company has not been significant in recent years because of the relatively low rates of inflation experienced in the United States. Forward Looking Statements "Safe Harbor" statement under the Private Securities Litigation Reform Act of 1995. With the exception of historical information, the matters discussed in this Form 10-K are forward-looking statements that involve risks and uncertainties. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, the timing and extent of changes in commodity prices for oil and gas, environmental risks, drilling and operating risks, uncertainties about the estimates of reserves and government regulation.

17 Item 8. Financial Statements and Supplementary Data BERRY PETROLEUM COMPANY Index to Financial Statements and Supplementary Data Page Report of Coopers & Lybrand L.L.P., Independent Accountants . . . . . 18 Balance Sheets at December 31, 1996 and 1995 . . . . . . . . . . . . 19 Statements of Operations for the Years Ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . 20 Statements of Shareholders' Equity for the Years Ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . 21 Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . 22 Notes to the Financial Statements . . . . . . . . . . . . . . . . . . 23 Supplemental Information About Oil & Gas Producing Activities . . . . 34 Financial statement schedules have been omitted since they are either not required, are not applicable, or the required information is shown in the financial statements and related notes.

18 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors Berry Petroleum Company We have audited the accompanying balance sheets of Berry Petroleum Company as of December 31, 1996 and 1995, and the related statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Berry Petroleum Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. COOPERS & LYBRAND L.L.P. /s/ Coopers & Lybrand L.L.P. February 28, 1997 Los Angeles, California

19 BERRY PETROLEUM COMPANY Balance Sheets December 31, 1996 and 1995 (In Thousands, Except Share Information) 1996 1995 ASSETS Current assets: Cash and cash equivalents $ 9,970 $ 18,759 Cash - restricted 2,570 - Short-term investments available for sale 704 15,695 Accounts receivable 11,701 8,414 Prepaid expenses and other 1,307 2,332 ------- ------- Total current assets 26,252 45,200 Oil and gas properties (successful efforts basis), buildings and equipment, net 149,510 72,042 Other assets 641 480 ------- ------- $ 176,403 $ 117,722 LIABILITIES AND SHAREHOLDERS' EQUITY ======= ======= Current liabilities: Accounts payable $ 5,154 $ 3,086 Notes payable 6,900 - Accrued liabilities 5,300 3,912 Federal and state income taxes payable 1,048 1,696 ------- ------- Total current liabilities 18,402 8,694 Long-term debt 36,000 - Deferred income taxes 20,992 16,968 Contingencies (Note 12) Shareholders' equity: Preferred stock, $.01 par value, 2,000,000 shares authorized; no shares outstanding Capital stock, $.01 par value: - - Class A Common Stock, 50,000,000 shares authorized; 21,046,885 shares issued and outstanding (21,033,055 in 1995) 210 210 Class B Stock, 1,500,000 shares authorized; 898,892 shares issued and outstanding (liquidation preference of $899) 9 9 Capital in excess of par value 53,029 52,850 Retained earnings 47,761 38,991 ------- ------- Total shareholders' equity 101,009 92,060 ------- ------- $ 176,403 $ 117,722 ======= ======= The accompanying notes are an integral part of these financial statements.

20 BERRY PETROLEUM COMPANY Statements of Operations Years ended December 31, 1996, 1995 and 1994 (In Thousands, Except Per Share Data) 1996 1995 1994 Revenues: Sales of oil and gas $ 55,264 $ 45,773 $ 39,451 Interest income (net of interest expense) 1,903 2,040 1,616 Gain on sale of assets - 3,073 113 Other income (expense), net (72) 304 155 ------- ------- ------- 57,095 51,190 41,335 ------- ------- ------- Expenses: Operating costs 17,587 18,264 21,224 Depreciation, depletion & amortization 7,323 6,847 7,270 Impairment of properties - - 2,915 Oil spill costs - - 1,344 Exploratory dry hole costs 71 2,012 5,414 General and administrative 4,820 4,578 5,118 ------- ------- ------- 29,801 31,701 43,285 ------- ------- ------- Income (loss) before income taxes 27,294 19,489 (1,950) Provision (benefit) for income taxes 9,748 7,286 (821) ------- ------- ------- Net income (loss) $ 17,546 $ 12,203 $ (1,129) ======= ======= ======= Net income (loss) per share $ .80 $ .56 $ (.05) ======= ======= ======= Weighted average number of shares of capital stock used to calculate earnings per share 21,939 21,932 21,932 ======= ======= ======= The accompanying notes are an integral part of these financial statements.

21 BERRY PETROLEUM COMPANY Statements of Shareholders' Equity Years Ended December 31, 1996, 1995 and 1994 (In Thousands, Except Per Share Data) Capital in Capital Stock Excess of Retained Shareholders' Class A Class B Par Value Earnings Equity Balances at January 1, 1994 $ 210 $ 9 $ 52,641 $ 45,463 $ 98,323 Stock options expired - - 211 - 211 Cash dividends declared-$.40 per share - - - (8,773) (8,773) Net income - - - (1,129) (1,129) ----- ----- ------- ------- ------- Balances at December 31, 1994 210 9 52,852 35,561 88,632 Stock retired - - (2) - (2) Cash dividends declared - $.40 per share - - - (8,773) (8,773) Net income - - - 12,203 12,203 ----- ----- ------- ------- ------- Balances at December 31, 1995 210 9 52,850 38,991 92,060 Stock retired - - (1) - (1) Stock options exercised - - 180 - 180 Cash dividends declared - $.40 per share - - - (8,776) (8,776) Net income - - - 17,546 17,546 ----- ----- ------- ------- ------- Balances at December 31, 1996 $ 210 $ 9 $ 53,029 $ 47,761 $ 101,009 ===== ===== ======= ======= ======= The accompanying notes are an integral part of these financial statements.

22 BERRY PETROLEUM COMPANY Statements of Cash Flows Years Ended December 31, 1996, 1995 and 1994 (In Thousands) 1996 1995 1994 Cash flows from operating activities: Net income (loss) $ 17,546 $ 12,203 $ (1,129) Depreciation, depletion and amortization 7,323 6,847 7,270 Gain on sale of assets - (3,073) (113) Exploratory dryhole costs 71 1,990 5,090 Impairment of properties - - 2,915 Increase (decrease) in deferred income tax liability 4,024 (1,985) (762) Other, net (329) (50) 504 ------- ------- ------- Net working capital provided by operating activities 28,635 15,932 13,775 Decrease (increase) in current assets other than cash, cash equivalents and short-term investments (2,262) 3,113 7,256 Increase (decrease) in current liabilities 2,809 (1,975) (6,452) ------- ------- ------- Net cash provided by operating activities 29,182 17,070 14,579 Cash flows from investing activities: Capital expenditures, excluding property acquisitions (15,616) (14,569) (5,911) Property acquisitions (69,330) (503) (1,023) Proceeds from sale of assets 352 6,242 327 Purchase of short-term investments (710) (3,078) (30,524) Maturities of short-term investments 15,700 15,000 29,874 Restricted cash deposit (2,570) - - Other, net (100) (96) (540) ------- ------- ------- Net cash provided by (used in) investing activities (72,274) 2,996 (7,797) Cash flows from financing activities: Borrowings under line of credit 36,000 - - Notes payable - Tannehill acquisition 6,900 - - Dividends paid (8,776) (8,773) (8,773) Proceeds from exercise of stock options 179 - - ------- ------- ------- Net cash provided by (used in) financing activities 34,303 (8,773) (8,773) Net increase (decrease) in cash and cash equivalents (8,789) 11,293 (1,991) Cash and cash equivalents at beginning of year 18,759 7,466 9,457 ------- ------- ------- Cash and cash equivalents at end of year $ 9,970 $ 18,759 $ 7,466 ======= ======= ======= Supplemental disclosures of cash flow information: Interest paid $ - $ 12 $ 5 ====== ====== ====== Income taxes paid $ 4,709 $ 5,554 $ 484 ====== ====== ====== The accompanying notes are an integral part of these financial statements.

23 BERRY PETROLEUM COMPANY Notes to the Financial Statements 1. General The Company is an independent energy company engaged in the production, development, acquisition, exploitation, exploration and marketing of crude oil and natural gas. Substantially all of the Company's oil and gas reserves are located in California. Approximately 98% of the Company's production is crude oil, which is principally sold to other oil companies for processing in refineries located in California. The preparation of financial statements in conformity with generally accepted accounting principles requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 2. Summary of significant accounting policies Cash and cash equivalents Cash equivalents consist principally of commercial paper investments. The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. Cash equivalents of $5.9 million and $13.4 million at December 31, 1996 and 1995, respectively, are stated at cost, which approximates market. Short-term investments All short-term investments are classified as available for sale. Short-term investments consist principally of United States treasury notes and corporate notes with remaining maturities of more than three months at date of acquisition. Such investments are stated at cost, which approximates market. The Company utilizes specific identification in computing realized gains and losses on investments sold. For the three years ended December 31, 1996, realized and unrealized gains and losses were insignificant to the financial statements. United States treasury notes with an aggregate market value of $.6 million are pledged as collateral to the California State Lands Commission as a performance bond on the Company's Montalvo properties. Oil and gas properties, buildings and equipment The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Under this method, costs to acquire mineral interests in oil and gas properties, to drill and complete development wells and drill and complete exploratory wells that find proved reserves are capitalized. Exploratory dryhole costs and other exploratory costs, including geological and geophysical costs, are charged to expense when incurred. The costs of carrying and retaining unproved properties are also expensed when incurred. Depletion of oil and gas producing properties is computed using the units-of-production method. Depreciation of lease and well equipment is computed using the units-of-production method or on a straight-line basis over estimated useful lives ranging from 10 to 20 years. The estimated costs, net of salvage value, of plugging and abandoning oil and gas wells and related facilities are accrued using the units-of-production method and are taken into account in determining DD&A expense. Buildings and equipment are recorded at cost. Depreciation is provided on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. When assets are sold, the applicable costs and accumulated depreciation and depletion are removed from the accounts and any gain or loss is included in income. Expenditures for maintenance and repairs are expensed as incurred.

24 BERRY PETROLEUM COMPANY Notes to the Financial Statements 2. Summary of significant accounting policies (cont'd) In the fourth quarter of 1995, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." This change had no effect on the Company's financial statements. Pursuant to this standard, assets are grouped at the lowest level for which there are identifiable cash flows. If it is determined that the book value of long- lived assets cannot be recovered by estimated future undiscounted cash flows, they will be written down to fair value. Steam Costs The costs of producing steam are recorded as an operating expense of the Company. Proceeds received from the sale of electricity produced by the cogeneration plants are reported as a reduction to operating costs in the Company's financial statements. Stock-Based Compensation During 1996, the Company implemented the disclosure requirements of SFAS No. 123, "Accounting for Stock-Based Compensation." This statement sets forth alternative standards for recognition of the cost of stock-based compensation and requires that a Company's financial statements include certain disclosures about stock-based employee compensation arrangements regardless of the method used to account for them. As allowed in this statement, the Company continues to apply Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," and related interpretations in recording compensation related to its plans. The supplemental disclosure requirements and further information related to the Company's stock option plans are presented in Note 10 to the Company's financial statements. Income Taxes Income taxes are provided based on the liability method of accounting pursuant to SFAS No. 109, "Accounting for Income Taxes." The provision for income taxes is based on pre-tax financial accounting income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between income tax and financial reporting, and principally relate to differences in the tax bases of assets and liabilities and their reported amounts using enacted tax rates in effect for the year in which differences are expected to reverse. If it is more likely than not that some portion or all of a deferred tax asset will not be realized, a valuation allowance is recognized. Earnings per share Earnings per share is computed by dividing net income by the weighted average number of capital shares and dilutive common stock equivalents, if any, outstanding during the year. Reclassifications Certain reclassifications have been made to the 1995 and 1994 financial statements to conform with the 1996 presentation.

25 BERRY PETROLEUM COMPANY Notes to the Financial Statements 3. Fair value of financial instruments Financial instruments consist of cash and short-term investments, whose carrying amounts are not materially different from their fair values because of the short maturity of those instruments. The Company's short-term investments available for sale at December 31, 1996 consist primarily of one United States treasury note. All of the short-term investments at December 31, 1996 mature in one year or less. The carrying value of the Company's long-term debt is assumed to approximate its fair value since it was incurred in December 1996 at current interest rates. To protect the Company's revenues from potential price declines, the Company entered into two bracketed zero cost collar hedge contracts with a California refiner covering approximately 31% of its crude oil production. The posted price of the Company's 13 degree API gravity crude oil was used as the basis for the hedge. Both of these contracts expired in January 1997. In late February 1997, the Company entered into a similar hedge contract for approximately 25% of its current production for a term of 18 months. 4. Concentration of Credit Risks The Company sells oil, gas and natural gas liquids to pipelines and refineries. Credit is extended based on an evaluation of the customer's financial condition. For the three years ended December 31, 1996, the Company has experienced no credit losses on the sale of oil, gas and natural gas liquids. The Company places its temporary cash investments with high credit quality financial institutions and limits the amount of credit exposure to any one financial institution. For the three years ended December 31, 1996, the Company has not incurred losses related to these investments. The following summarizes the accounts receivable balances at December 31, 1996 and sales activity with significant customers for each of the years ended December 31, 1996, 1995 and 1994 (in thousands): Sales Accounts Receivable For the Year Ended December 31, Customer Dec. 31, 1996 Dec. 31,1995 1996 1995 1994 A $ 2,246 $ 1,372 $ 23,067 $ 12,641 $ 16,027 B 1,845 961 14,478 12,918 11,319 C 1,282 724 10,982 9,214 - D - - - 5,265 - ------ ------ ------ ------ ------ $ 5,373 $ 3,057 $ 48,527 $ 40,038 $ 27,346 ====== ====== ====== ====== ======

26 BERRY PETROLEUM COMPANY Notes to the Financial Statements 5. Oil and gas properties, buildings and equipment Oil and gas properties, buildings and equipment consist of the following at December 31 (in thousands): 1996 1995 Oil and gas: Proved properties: Producing properties, including intangible drilling costs $ 126,361 $ 55,202 Lease and well equipment 88,539 75,470 Unproved properties 169 162 ------- ------- 215,069 130,834 Less accumulated depreciation, depletion and amortization 67,995 61,456 ------- ------- 147,074 69,378 ------- ------- Commercial and other: Land 151 151 Buildings and improvements 3,938 3,734 Machinery and equipment 3,707 4,026 ------- ------- 7,796 7,911 Less accumulated depreciation 5,360 5,247 ------- ------- 2,436 2,664 ------- ------- $ 149,510 $ 72,042 ======= ======= The following sets forth costs incurred for oil and gas property acquisition, exploration and development activities, whether capitalized or expensed (in thousands): 1996 1995 1994 Acquisition of properties(1) $ 69,330 $ 503 $ 1,023 Exploration 40 1,420 1,701 Development 15,689 14,034 4,678 ------- ------- ------- $ 85,059 $ 15,957 $ 7,402 ======= ======= ======= (1) Excludes cogeneration facility costs and includes certain closing and consultant costs related to the acquisitions. The Company completed two acquisitions in 1996 for a combined purchase price of approximately $75 million on property acquisitions (Tannehill and Formax), including the purchase of an 18 megawatt cogeneration facility. The properties, which produce approximately 2,350 barrels per day of 13 degree API gravity crude oil, on February 24, 1997, are adjacent to and in-between the Company's South Midway-Sunset producing properties. These acquisitions have proved reserves of approximately 27 million barrels, and were financed by utilizing working capital and long-term borrowings.

27 BERRY PETROLEUM COMPANY Notes to the Financial Statements 5. Oil and gas properties, buildings and equipment (cont'd) Results of operations from oil and gas producing and exploration activities The results of operations from oil and gas producing and exploration activities (excluding blending operations, corporate overhead and interest costs) for the three years ended December 31 are as follows (in thousands): 1996 1995 1994 Sales to unaffiliated parties $ 55,264 $ 45,773 $ 39,451 Production costs (17,587) (18,264) (21,224) Exploration expenses (71) (2,012) (5,414) Depletion, depreciation and amortization (6,868) (6,354) (6,627) ------- ------- ------- 30,738 19,143 6,186 Income tax expenses (10,230) (6,084) (1,723) ------- ------- ------- Results of operations from producing and exploration activities $ 20,508 $ 13,059 $ 4,463 ======= ======= ======= In 1994, the Company recorded an impairment writedown of $2.9 million related to certain oil and gas properties. 6. Debt obligations Long-term debt for the years ended December 31 1996 1995 (in thousands): Revolving bank facility $ 36,000 $ - At December 31, 1996, Berry had a $150 million unsecured three-year revolving credit facility with NationsBank of Texas. The maximum amount available is subject to an annual redetermination of the borrowing base in accordance with lender's customary procedures and practices. Both parties have bilateral rights to one additional redetermination each year. As of December 31, 1996, the borrowing base was $50 million and the principal amount outstanding was $36 million. The revolving period is scheduled to terminate on December 1, 1999, at which time any unpaid balance can be converted to a four-year term loan, amortized quarterly. Interest on amounts borrowed is charged at NationsBank base rate or at LIBOR plus .60 to 1.00 percent, depending on the ratio of outstanding credit to the borrowing base. The weighted average interest rate on outstanding borrowings at December 31, 1996 was 6.22% The Company pays a commitment fee of .20 to .35 percent on the available portion of the commitment. The credit agreement contains various restrictive covenants as defined in the agreement. In conjunction with the purchase of Tannehill, the Company incurred $6.9 million in short-term notes, which were due and paid on January 6, 1997.

28 BERRY PETROLEUM COMPANY Notes to the Financial Statements 7. Shareholders' equity Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock" are each entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $1.00 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder. In December 1989, the Company adopted a Stockholder Rights Agreement and declared a dividend distribution of one Right for each outstanding share of Capital Stock. Each Right, when exercisable, entitles the holder to purchase one one-hundredth of a share of a Series A Junior Participating Preferred Stock, or in certain cases other securities, for $38.00. The exercise price and number of shares issuable are subject to adjustment to prevent dilution. The Rights would become exercisable, unless earlier redeemed by the Company, 10 days following a public announcement that a person or group has acquired, or obtained the right to acquire, 20% or more of the outstanding shares of Common Stock or, 10 business days following the commencement of a tender or exchange offer for such outstanding shares which would result in such person or group acquiring 20% or more of the outstanding shares of Common Stock, either event occurring without the prior consent of the Company. The Rights will expire in December 1999 or may be redeemed by the Company at 1 cent per Right prior to that date unless they have theretofore become exercisable. The Rights do not have voting or dividend rights, and until they become exercisable, have no diluting effect on the earnings of the Company. A total of 250,000 shares of the Company's Preferred Stock has been designated Series A Junior Participating Preferred Stock and reserved for issuance upon exercise of the Rights. In conjunction with the acquisition of Tannehill, the Company issued a Warrant Certificate to the beneficial owners of Tannehill Oil Company. This Warrant authorizes the purchase of 100,000 shares of Berry Petroleum Company Class A Common Stock until November 8, 2003 at $14.06 per share. All the warrants are currently outstanding and the underlying shares will not be registered under the Securities Act of 1933. The Company issued 13,932, 0, and 0 shares in 1996, 1995 and 1994, respectively, through its stock option plans. Dividends declared on 4,366,400 shares of certain Common Stock are restricted, whereby 37.5% of the dividends declared on these shares are paid by the Company to the surviving member of a group of individuals, the B Group, as long as this remaining member shall live. 8. Transactions with affiliates The University Cogeneration Partners, Ltd. 1985-1, a limited partnership, was formed in 1985 to finance the construction of a cogeneration plant on the Company's properties. The Company also committed to purchase the steam generated by the plant and supply the natural gas to fuel the plant. The Company owned approximately 45% of the partnership and its investment of $1.9 million was accounted for at cost. On August 1, 1995, the Company purchased the remaining 55% interest in the cogeneration plant for approximately $5.2 million. The total cost of the cogeneration plant is included in lease and well equipment at December 31, 1996 and 1995. Amounts paid by the Company for the steam in 1995 (through July) and 1994 were $2.6 million and $4.6 million, respectively.

29 BERRY PETROLEUM COMPANY Notes to the Financial Statements 9. Income taxes The provision (benefit) for income taxes consists of the following (in thousands): 1996 1995 1994 Current: Federal $ 3,519 $ 5,089 $ 158 State 1,027 2,042 (56) ------ ------ ------ 4,546 7,131 102 ------ ------ ------ Deferred: Federal 4,322 828 (1,077) State 880 (673) 154 ------ ------ ------ 5,202 155 (923) ------ ------ ------ $ 9,748 $ 7,286 $ (821) ====== ====== ====== The current deferred tax assets and liabilities are offset and presented as a single amount in the financial statements. Similarly, the noncurrent deferred tax assets and liabilities are presented in the same manner. The following table summarizes the components of the total deferred tax assets and liabilities before such financial statement offsets. The components of the net deferred tax liability are as follows (in thousands): Dec. 31, Dec. 31, 1996 1995 Deferred tax asset Federal benefit of state taxes $ 1,710 $ 1,756 Net operating loss carryforwards 137 171 Credit/deduction carryforwards - 634 Other net 311 368 ------ ------ 2,158 2,929 ------ ------ Deferred tax liability Depreciation and depletion (18,529) (15,195) State taxes, net (4,002) (3,122) Other, net (622) (405) ------ ------ (23,153) (18,722) ------ ------ Net deferred tax liability $(20,995) $(15,793) ====== ======

30 BERRY PETROLEUM COMPANY Notes to the Financial Statements 9. Income taxes (cont'd) Income taxes computed by applying U.S. statutory federal rates to income (loss) before income taxes are reconciled to the provision (benefit) for income taxes as follows (in thousands): 1996 1995 1994 Tax (benefit) computed at statutory federal rate $ 9,553 $ 6,821 $ (663) Increase (decrease) in taxes resulting from: Asset acquisition/sale differences - 1,315 394 Percentage depletion (467) (402) (290) State taxes, net 1,240 888 98 Enhanced oil recovery, nonconventional fuel tax and alternative minimum tax credits (1,230) (1,115) (406) Other, net 652 (221) 46 ------ ------ ------ $ 9,748 $ 7,286 $ (821) ====== ====== ====== Effective tax rate 35.7% 37.4% (42.1)% The Company has $.4 million of loss carryforwards which may be utilized in future years to reduce the Company's federal income taxes. These loss carryforwards expire in the year 2000. The Company also has approximately $.2 million of enhanced oil recovery tax credit carryforwards available to reduce future state income taxes. The Company went to trial in April 1993 before the U.S. Tax Court on certain federal tax issues relating to the years 1987 through 1989. The Court's decision was rendered in May 1995, resulting in an approximate $.5 million charge in the second quarter of 1995. The Company is pursuing an appeal of the Court's decision with respect to certain issues to the U.S. Court of Appeals (Ninth Circuit) and a hearing is scheduled in March 1997 with a decision expected before year end 1997.

31 BERRY PETROLEUM COMPANY Notes to the Financial Statements 10. Stock option and stock appreciation rights plans The Company has a 1987 Nonstatutory Stock Option Plan (the NSO Plan) and a 1987 Stock Appreciation Rights Plan (the SAR Plan). The NSO Plan provided for the granting of options (Options) to purchase up to an aggregate of 700,000 shares of Common Stock. The SAR Plan originally authorized a maximum of 700,000 shares of Common Stock subject to stock appreciation rights (SARs). Holders of SARs have the right upon exercise to receive a payment, payable at the discretion of the Compensation Committee in cash or in shares of Common Stock, equal to the amount by which the market price exceeds the Base Price (as defined) with respect to the shares subject to such SARs on the date of exercise. In December 1994, the Board of Directors adopted a resolution to terminate the 1987 Stock Appreciation Rights Plan without utilizing the 307,860 SARs which were still available for issuance. The 9,200 outstanding SARs at year end are still available for exercise under the original terms of issuance. Total compensation expense recognized for the SAR Plan in 1996, 1995 and 1994 was $104,000, $9,000 and $0, respectively. On December 2, 1994, the Board of Directors of the Company adopted the Berry Petroleum Company 1994 Stock Option Plan (the 1994 Plan). The 1994 Plan was approved by the shareholders in May 1995 and provides for the granting of stock options to purchase up to an aggregate of 1,000,000 shares of Common Stock. All Options, with the exception of the formula grants to non-employee directors, will be granted at the discretion of the Compensation Committee of the Board of Directors. The term of each Option may not exceed ten years from the date the Option is granted. On December 6, 1996 and December 2, 1994, 480,000 and 300,000 Options, respectively, were issued to certain key employees at an exercise price of $14.00 and $10.75 per share, respectively, which was the closing market price of the Company's Class A Common Stock on the New York Stock Exchange on those dates. The Options vest 25% per year for four years. The 1994 Plan also allows for Option grants to the Board of Directors under a formula plan whereby all non-employee directors are eligible to receive 3,000 Options annually on December 2 at the fair value on the date of grant. The Options granted to the non-employee directors vest immediately. Through this 1994 Plan, 33,000 Options were issued on December 2, 1996, 1995 and 1994, (3,000 Options to each of the eleven nonemployee directors each year) at an exercise price of $13.75, $10.625 and $10.75 per share, respectively. The Company applies APB No. 25 and related interpretations in accounting for its stock option plans. Accordingly, since the stock options related to the 1987 plan were issued at prices below the existing current market prices and they were fully vested previously, compensation related to this plan was recorded in prior years. The Options issued per the 1994 plan were issued at market price. Compensation recognized related to this plan was $64,000 in 1996 and $0 in 1995 and 1994. Under SFAS No. 123, compensation cost would be recognized for the fair value of the employee's option rights. In determining the fair value, the Company used the Black-Scholes model, assumed a dividend of $.40 per year, an expected life of four years for all grants, an expected volatility of 24.97% and a risk free interest rate of 6.10% for all years. Had compensation cost for the 1994 plan been based upon the fair value at the grant dates for awards under this plan consistent with the method of SFAS No. 123, the Company's net income and earnings per share would have been reduced to the pro-forma amounts indicated below (in thousands, except per share data): 1996 1995 1994 Net income (loss) as reported $ 17,546 $ 12,203 $ (1,129) Pro forma $ 17,387 $ 12,066 $ (1,173) Net income (loss) per share as reported $ .80 $ .56 $ (.05) Pro forma $ .79 $ .55 $ (.05)

32 BERRY PETROLEUM COMPANY Notes to the Financial Statements 10. Stock option and stock appreciation rights plans (cont'd) The following is a summary of stock-based compensation activity for the years 1996, 1995 and 1994. 1996 1995 1994 Options SARs Options SARs Options SARs Balance outstanding, January 1 431,141 39,740 398,141 39,740 142,941 69,020 Granted 513,000 - 33,000 - 333,000 - Exercised (76,912) (30,540) - - - (5,380) Canceled/expired (6,000) - - - (77,800) (23,900) ------- ------ ------- ------ ------- ------- Balance outstanding, December 31 861,229 9,200 431,141 39,740 398,141 39,740 ======= ====== ======= ====== ======= ======= Balance exercisable at December 31 231,229 9,200 206,141 39,740 65,141 39,740 ======= ====== ======= ====== ======= ======= Available for future grant 320,800 - 827,800 - 860,800 39,740 ======= ====== ======= ====== ======= ======= Exercise price- range $ 9.80 $ 9.80 $ 9.80 $ 9.80 $ 9.80 $ 9.80 to 14.00to 10.00 to 10.75 to 10.00 to 10.75 to 10.00 ======= ====== ======= ====== ======= ======= Weighted average remaining contractual life (years) 9 2 8 3 9 4 ====== ====== ======= ====== ======= ======= Weighted average fair value per option granted during the year $ 3.22 $ 2.23 $ 2.26 ====== ====== ====== Weighted average option exercise price information for the years 1996, 1995 and 1994 as follows: 1996 1995 1994 Outstanding at January 1 $ 10.52 $ 10.51 $ 9.86 Granted during the year $ 13.98 $ 10.63 $ 10.75 Exercised during the year $ 12.82 $ - $ - Expired during the year $ 10.69 $ - $ 9.85 Outstanding at December 31 $ 12.61 $ 10.52 $ 10.51 Exercisable at December 31 $ 11.02 $ 10.45 $ 9.88 11. Retirement Plan The Company sponsors a defined contribution retirement or thrift plan (401(k) Plan) to assist all employees in providing for retirement or other future financial needs. Employee contributions (up to 6% of their earnings) are matched by the Company dollar for dollar. Effective November 1, 1992, the 401(k) Plan was modified to provide for increased Company matching of employee contributions whereby the monthly Company matching contributions will range from 6% to 9% of eligible participating employee earnings, if certain financial results are achieved. Due to improved financial results, the monthly matching contributions ranged from 6% to 9% during 1996 and 1995. For 1994, all matching contributions were at the 6% rate. The Company's contributions to the 401(k) Plan were $.3 million in 1996, $.2 million in 1995 and $.2 million in 1994.

33 BERRY PETROLEUM COMPANY Notes to the Financial Statements 12. Oil Spill On December 25, 1993, the Company experienced a crude oil spill of approximately 2,100 barrels on its PRC 735 State lease located in the Montalvo field in Ventura County, California. The spill required clean-up of the area directly around the pipe as well as the nearby beach and an agricultural runoff pond. Working closely with various regulatory agencies, the Company substantially completed the clean-up of the spill in January 1994. The Company negotiated a resolution of the state criminal investigation for a total of $.6 million in August 1994. The Company reached a final settlement for civil damages and penalties with the federal and state governments in January 1997 and a consent decree was approved and entered by the U.S. District Court in Los Angeles, California on February 14, 1997. The Company, without admitting any liability, agreed to pay approximately $3.2 million to federal and state agencies for response and assessment costs, civil damages and penalties arising from this incident. The Company received reimbursement under its insurance policy for approximately $2.3 million of the settlement amount. On December 31, 1996, the Company held cash of $2.6 million in an escrow account which was restricted for usage specifically for this pending settlement. The costs incurred and estimated to be incurred in connection with the spill not yet paid by the Company are included in accrued liabilities at December 31, 1996, and the probable remaining minimum insurance reimbursement is included in accounts receivable. As of December 31, 1996 and February 24, 1997, the Company had received approximately $9.8 million and $11.2 million, respectively, under its insurance coverage as reimbursement for costs incurred and paid by the Company associated with the spill. Management believes that it is probable that this matter, including final reimbursement, will be resolved in 1997 and that its previous accruals are adequate. 13. Quarterly financial data (unaudited) The following is a tabulation of unaudited quarterly operating results for 1996 and 1995 (in thousands, except for per share data). Operating Gross Net Net Income 1996 Revenues Profit Income Per Share First Quarter $ 12,145 $ 6,825 $ 3,861 $ .18 Second Quarter 13,219 7,820 4,398 .20 Third Quarter 13,433 7,063 4,012 .18 Fourth Quarter 16,394 8,958 5,275 .24 ------- ------- ------- ---- $ 55,191 $ 30,666 $ 17,546 $ .80 ======= ======= ======= ==== 1995 First Quarter $ 10,445 $ 3,872 $ 2,210 $ .10 Second Quarter 12,436 5,933 2,876 .13 Third Quarter 12,172 5,688 3,374 .16 Fourth Quarter 10,732 3,394 3,743 .17 ------- ------- ------- ---- $ 45,785 $ 18,887 $ 12,203 $ .56 ======= ======= ======= ====

34 BERRY PETROLEUM COMPANY Supplemental Information About Oil & Gas Producing Activities (Unaudited) The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by the Company located solely within the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion. Disclosures of oil and gas reserves which follow are based on estimates prepared by independent engineering consultants for the three years ended December 31, 1996. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves. Changes in estimated reserve quantities The net interest in estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas at December 31, 1996, 1995 and 1994, and changes in such quantities during each of the years then ended were as follows (in thousands): 1996 1995 1994 Oil Gas Oil Gas Oil Gas Mbbls Mmcf Mbbls Mmcf Mbbls Mmcf Proved developed and undeveloped reserves: Beginning of year 77,071 5,983 75,996 6,530 72,078 5,476 Revision of previous estimates 739 (810) 5,266 803 6,002 1,847 Production (3,491) (491) (3,277) (611) (3,250) (793) Sale of reserves in place - - (1,698) (739) - - Purchase of reserves in place 27,017 - 784 - 1,166 - ------- ----- ------ ----- ------ ----- End of year 101,336 4,682 77,071 5,983 75,996 6,530 ======= ===== ====== ===== ====== ===== Proved developed reserves: Beginning of year 62,856 3,380 62,718 4,727 62,261 4,810 ======= ===== ====== ===== ====== ===== End of year 76,358 2,608 62,856 3,380 62,718 4,727 ======= ===== ====== ===== ====== =====

35 BERRY PETROLEUM COMPANY Supplemental Information About Oil & Gas Producing Activities (Unaudited)(Cont'd) Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves (in thousands): The standardized measure has been prepared assuming year-end sales prices adjusted for fixed and determinable contractual price changes, current costs and statutory income tax rates previously legislated, and a ten percent annual discount rate. No deduction has been made for depletion, depreciation or any indirect costs such as general corporate overhead or interest expense. 1996 1995 1994 Future cash inflows $ 1,875,373 $ 1,039,150 $ 960,412 Future production and development costs (429,879) (311,955) (317,735) Future income tax expenses (495,412) (245,416) (213,225) --------- --------- --------- Future net cash flows 950,082 481,779 429,452 10% annual discount for estimated timing of cash flows (529,523) (273,478) (248,499) --------- --------- --------- Standardized measure of discounted future net cash flows $ 420,559 $ 208,301 $ 180,953 ========= ========= ========= Pre-tax standardized measure of discounted future net cash flows $ 634,579 $ 308,370 $ 263,890 ========= ========= ========= Average sales prices at December 31: Oil ($/Bbl) $ 18.37 $ 13.39 $ 12.49 Gas ($/Mcf) $ 3.02 $ 1.45 $ 1.78 Changes in standardized measure of discounted future net cash flows from proved oil and gas reserves (in thousands): 1996 1995 1994 Standardized measure - beginning of year $ 208,301 $ 180,953 $ 36,626 --------- --------- --------- Sales of oil and gas produced, net of production costs (37,677) (27,509) (18,227) Revisions to estimates of proved reserves: Net changes in sales prices and production costs 170,529 41,726 194,099 Revisions of previous quantity estimates 4,020 23,584 24,315 Change in estimated future development costs (19,294) (14,234) (5,470) Extensions, discoveries and improved recovery less related costs - - - Purchases of reserves in place 171,456 2,316 3,815 Sale of reserves in place - (8,645) - Development costs incurred during the period 9,305 14,034 4,678 Accretion of discount 30,837 2,639 4,602 Income taxes (101,936) (13,126) (68,416) Other (14,982) 6,563 4,931 --------- --------- --------- Net increase 212,258 27,348 144,327 --------- --------- --------- Standardized measure - end of year $ 420,559 $ 208,301 $ 180,953 ========= ========= =========

36 BERRY PETROLEUM COMPANY Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None PART III Item 10. Directors and Executive Officers of the Registrant The information called for by Item 10 is incorporated by reference from information under the caption "Election of Directors" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year. The information on Executive Officers is contained in Part I of this Form 10-K. Item 11. Executive Compensation The information called for by Item 11 is incorporated by reference from information under the caption "Executive Compensation" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year. Item 12. Security Ownership of Certain Beneficial Owners and Management The information called for by Item 12 is incorporated by reference from information under the caption "Voting Securities" and "Principal Shareholders and Ownership by Management" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year. Compliance with Section 16(a) of the Securities Exchange Act of 1934 Section 16(a) of the Securities Exchange Act of 1934 and related Securities and Exchange Commission rules require that directors and executive officers report to the Securities and Exchange Commission changes in their beneficial ownership of Berry stock, and that any late filings be disclosed. Based solely on a review of the copies of such forms furnished to the Company, or written representations that no Form 5 was required, the Company believes that all Section 16(a) filing requirements were complied with. Item 13. Certain Relationships and Related Transactions The information called for by Item 13 is incorporated by reference from information under the caption "Certain Relationships and Related Transactions" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year.

37 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K A. Financial Statements and Schedules See Index to Financial Statements and Supplementary Data in Item 8. B. Reports on Form 8-K A Form 8-K was filed on December 2, 1996 to report an Item 2 - Acquisition of Assets. The Form 8-K was filed to report the acquisition on November 19, 1996 of the Tannehill assets for $25.5 million. No financial statements were filed with this Form 8-K, however, summary financial statements and pro forma information were filed on January 30, 1997 with a Form 8-K/A. A Form 8-K was filed on December 17, 1996 to report an Item 2 - Acquisition of Assets. The Form 8-K was filed to report the acquisition on December 13, 1996 of the Formax assets for $49.5 million. No financial statements were filed with this Form 8-K, however, summary financial statements and pro forma information were filed on February 21, 1997 with a Form 8-K/A. A Form 8-K was filed on December 19, 1996 to report an Item 6 - Resignation of Registrant's Chairman of the Board of Directors effective March 21, 1997. A Form 8-K/A was filed on March 4, 1997 to amend the original Form 8-K filed on December 19, 1996 to change the resignation of a director to an Item 5 - Other Event as no disagreement or dispute existed. A Form 8-K was filed on December 18, 1996 to report an Item 5 - Other Event. The Form 8-K was filed to report the Company entering into a $150 million unsecured three-year revolving credit facility agreement with NationsBank of Texas. A Form 8-K/A was filed on January 30, 1997 to amend the original Form 8-K filed on December 2, 1996 to report the Tannehill acquisition, to update the Form 8-K to include the financial statements and pro forma financial information. A Form 8-K/A was filed on February 21, 1997 to amend the original Form 8-K filed on December 17, 1996 to report the Formax acquisition, to update the Form 8-K to include the financial statements and pro forma financial information. A Form 8-K was filed on January 23, 1997 to report an Item 5 - Other Event. The Form 8-K was filed to report a settlement with the state and federal government for the civil damages and penalties relating to the December 1993 oil pipeline release at the Company's Montalvo field in Ventura County, California.

38 C. Exhibits Exhibit No. Description of Exhibit Page 3.1* Registrant's Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Registrant's Registration Statement on Form S-1 filed on June 7, 1989, File No. 33-29165) 3.2* Registrant's Restated Bylaws (filed as Exhibit 3.2 to the Registrant's Registration Statement on Form S-1 on June 7, 1989, File No. 33-29165) 3.3* Registrant's Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock (filed as Exhibit 3.3 to the Annual Report on Form 10-K for the year ended December 31, 1989, File No. 0-11708) 4.1* Rights Agreement between Registrant and Bank of America dated as of December 8, 1989 (filed as Exhibit 1 to Form 8-K filed on December 20, 1989, File No. 0-11708) 10.1* Description of Cash Bonus Plan of Berry Petroleum Company (filed as Exhibit 10.7 to the Annual Report on Form 10-K for the year ended December 31, 1990, File No. 1-9735) 10.2* Salary Continuation Agreement dated as of March 20, 1987, as amended August 28, 1987, by and between Registrant and Jerry V. Hoffman (filed as Exhibit 10.11 to the Registration Statement on Form S-1 filed on June 7, 1989, File No. 33-29165) 10.3* Form of Salary Continuation Agreements dated as of March 20, 1987, as amended August 28, 1987, by and between Registrant and selected employees of the Company (filed as Exhibit 10.12 to the Registration Statement on Form S-1 filed on June 7, 1989, File No. 33-29165) 10.4* Instrument for Settlement of Claims and Mutual Release by and among Registrant, Victory Oil Company, the Crail Fund and Victory Holding Company effective October 31, 1986 (filed as Exhibit 10.13 to Amendment No. 1 to the Registrant's Registration Statement on Form S-4 filed on May 22, 1987, File No. 33-13240) 10.5* 1987 Nonstatutory Stock Option Plan and 1987 Stock Appreciation Rights Plan as amended March 18, 1988 (filed as Exhibit 10.14 in Registrant's Registration Statement on Form S-8 filed on July 28, 1988, File No. 33-23326) 10.6* Service Contract by and between Registrant and Pride Petroleum Services, Inc. dated November 1, 1989 (filed as Exhibit 10.23 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1989, File No. 0-11708) 10.7* 1994 Stock Option Plan (filed as Exhibit 10.8 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-9735) 10.8* Standard Offer #2 Power Purchase Agreement dated May 1984, as amended by and between Registrant and Pacific Gas and Electric Company (filed as Exhibit 10.8 in Registrant's Annual Report on Form 10-K for the year ended December 31, 1995, File No. 1-9735) 10.9* Purchase and Sale Agreement, dated as of November 8, 1996, by and between the Registrant and Tannehill Oil Company, Inc., a California corporation (filed as Exhibit 10.1 in Registrant's Form 8-K filed on December 2, 1996, File No. 1-9735) 10.10* Purchase and Sale Agreement, dated as of November 8, 1996, by and between the Registrant and Tannehill Electric Company, Inc., a California corporation (filed as Exhibit 10.2 in Registrant's Form 8-K on December 2, 1996, File No. 1-9735) 10.11* Purchase and Sale Agreement, dated as of November 8, 1996, by and between the Registrant and Tannehill Oil Company, a California general partnership, and Boyce Resource Development Company, a California corporation; Albert G. Boyce, Jr., as Trustee of Trust "B" Under the Will of Albert G. Boyce, Sr., Deceased; William J. Boyce; Albert Gallatin Boyce V; Mary Katherine Boyce; John T. Hinkle; General Western, Inc., a New Mexico corporation; Delmar R. Archibald Family Trust, dated June 22, 1982; Lisle Q. Tannehill; John W. Tannehill; Gail Kay Tannehill, as Trustee of the Gail Kay Tannehill Family Trust, dated April 9, 1996; and Thomas H. Tannehill, all acting as partners of Tannehill Oil Company and individually, jointly and severally (filed as Exhibit 10.3 in Registrant's Form 8-K filed on December 2, 1996, File No. 1-9735)

39 Exhibits (cont'd) Exhibit No. Description of Exhibit Page 10.12* Credit Agreement, dated as of December 1, 1996, by and between the Registrant and NationsBank of Texas, N.A. (filed as Exhibit 10.1 in Registrant's Form 8-K filed on December 18, 1996, File No. 1-9735) 10.13* Stock Purchase Agreement, dated December 11, 1996, by and between the Registrant and Exxon Corporation, a New Jersey corporation (filed as Exhibit 10.1 in Registrant's Form 8-K filed on December 17, 1996, File No. 1-9735) 10.14 Standard Offer #2 Power Purchase Agreement dated May 1984 43 by and between Registrant's predecessor and Pacific Gas and Electric Company. 10.15 Standard Offer #1 Power Purchase Agreement dated 129 January 16, 1997, by and between Registrant and Pacific Gas and Electric Company. 10.16 Warrant Certificate dated November 14, 1996, 211 by and between Registrant and Tannehill Oil Company. 23.1 Consent of Coopers & Lybrand L.L.P. 220 23.2 Consent of DeGolyer and MacNaughton 221 27. ** Financial Data Schedule 222 99.1 Undertaking for Form S-8 Registration Statements 223 99.2* Form of Indemnity Agreement of Registrant (filed as Exhibit 28.2 in Registrant's Registration Statement on Form S-4 filed on April 7, 1987, File No. 33-13240) 99.3* Form of "B" Group Trust (filed as Exhibit 28.3 to Amendment No. 1 to Registrant's Registration Statement on Form S-4 filed on May 22, 1987, File No. 33-13240) * Incorporated by reference ** Included in the Company's electronic filing on EDGAR

40 Pursuant to the requirements of Section 13 or 15(d) 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 on March 21, 1997. BERRY PETROLEUM COMPANY /s/ JERRY V. HOFFMAN /s/ RALPH J. GOEHRING /s/ DONALD A. DALE JERRY V. HOFFMAN RALPH J. GOEHRING DONALD A. DALE President and Chief Chief Financial Officer Controller (Principal Executive Officer (Principal Financial Officer) Accounting Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the dates so indicated. Name Office Date /s/ Jerry V. Hoffman Chairman of the Board, March 21, 1997 Jerry V. Hoffman President & Chief Executive Officer /s/ Benton Bejach Director March 21, 1997 Benton Bejach /s/ William F. Berry Director March 21, 1997 William F. Berry /s/ Gerry A. Biller Director March 21, 1997 Gerry A. Biller /s/ Ralph B. Busch, III Director March 21, 1997 Ralph B. Busch, III /s/ William E. Bush,Jr. Director March 21, 1997 William E. Bush, Jr. /s/ William B. Charles Director March 21, 1997 William B. Charles /s/ Richard F. Downs Director March 21, 1997 Richard F. Downs /s/ John A. Hagg Director March 21, 1997 John A. Hagg /s/Thomas J. Jamieson Director March 21, 1997 Thomas J. Jamieson /s/ Roger G. Martin Director March 21, 1997 Roger G. Martin

43 STANDARD OFFER #2 POWER PURCHASE AGREEMENT FOR FIRM CAPACITY AND ENERGY BETWEEN SOLAR TURBINES INCORPORATED AND PACIFIC GAS AND ELECTRIC COMPANY MAY 1984 S.O. #2 May 7, 1984 1

2 STANDARD OFFER #2: FIRM CAPACITY AND ENERGY POWER PURCHASE AGREEMENT CONTENTS Article Page 1 QUALIFYING STATUS 3 2 PURCHASE OF POWER 4 3 PURCHASE PRICE 6 4 NOTICES 6 5 DESIGNATED SWITCHING CENTER 7 6 TERMS AND CONDITIONS 7 7 TERM OF AGREEMENT 7 Appendix A: GENERAL TERMS AND CONDITIONS Appendix B: ENERGY PRICES Appendix C: FIRM CAPACITY PRICE SCHEDULE Appendix D: ADJUSTMENT OF CAPACITY PAYMENTS IN THE EVENT OF TERMINATION OR REDUCTION Appendix E: INTERCONNECTION S.O. #2 May 7, 1984 2

3 FIRM CAPACITY AND ENERGY POWER PURCHASE AGREEMENT BETWEEN SOLAR TURBINES INCORPORATED AND PACIFIC GAS AND ELECTRIC COMPANY SOLAR TURBINES INCORPORATED ("Seller"), and PACIFIC GAS AND ELECTRIC COMPANY (PGandE), referred to collectively as Parties and individually as Party, agree as follows: ARTICLE 1 QUALIFYING STATUS Seller warrants that, at the date of first power deliveries from Seller's Facility ((1)) and during the term of agreement, its Facility shall meet the qualifying facility requirements established as of the effective date of this Agreement by the Federal Energy Regulatory Commission's rules (18 Code of Federal Regulations 292) implementing the Public Utility Regulatory Policies Act of 1978 (16 U.S.C.A. 796, et seq.). ((1)) Underlining identifies those terms which are defined in Section A-1 of Appendix A. S.O. #2 May 7, 1984 3

4 ARTICLE 2 PURCHASE OF POWER (a) Seller shall sell and deliver and PGandE shall purchase and accept delivery of firm capacity and energy at the voltage level of kv ((1)) as indicated below -- 1. Contract capacity - 13,300 kW; and 2. Energy - surplus energy output ((2)). Seller may convert its energy sale option as provided in Section A-3 of Appendix A. (b) Seller shall provide the firm capacity and energy set forth above from its 17,000 kW Facility located at Township 12N, Range 24W, Section 33-34, Kern County, California. (c) The scheduled operation date of the Facility is December 1, 1986. At the end of each calendar quarter Seller shall give written notice to PGandE of any change in the scheduled operation date. ((1)) The Seller requests, and PGandE consents, that this blank not be filled in at the time of executing the Agreement, because the Seller, recognizing that the information is not yet available to make a definitive determination of the number to be inserted in this blank, shall request PGandE to perform an interconnection study to be done in its accustomed manner of making such studies to determine the number to be inserted. ((2)) Insert either "net energy output" or "surplus energy output" to show the energy sale option selected by Seller. S.O. #2 May 7, 1984 4

5 (d) To avoid exceeding the physical limitations of the interconnection facilities, Seller shall limit the Facility's actual rate of delivery into the PGandE system to ((1)) kW. (e) The primary energy source for the Facility is natural gas. (f) If Seller does not begin construction of its Facility by January 1, 1987, PGandE may reallocate the existing capacity on PGandE's transmission and/or distribution system which would have been used to accommodate Seller's power deliveries to other uses. In the event of such reallocation, Seller shall pay PGandE for the cost of any upgrades or additions to PGandE's system necessary to accommodate the output from the Facility. Such additional facilities shall be installed, owned, and maintained in accordance with the applicable PGandE tariff. (g) The transformer loss adjustment factor is ((1))((2)). ((1)) The appropriate number will be inserted upon completion of an interconnection study. ((2)) If Seller chooses to have meters placed on Seller's side of the transformer, an estimated transformer loss adjustment factor of 2 percent, unless the Parties agree otherwise, will be applied. This estimated transformer loss figure will be adjusted to a measurement of actual transformer losses performed at Seller's request and expense. S.O. #2 May 7, 1984 5

6 ARTICLE 3 PURCHASE PRICE (a) PGandE shall pay Seller for firm capacity at the contract capacity price under Option 2 set forth in Section C-5 of Appendix C. The contract capacity price is derived from PGandE's full avoided costs as approved by the CPUC. PGandE's obligation to pay for the contract capacity shall begin on the actual operation date. Seller elects to have its contract capacity price determined from the firm capacity price schedule in effect on the date of execution of this Agreement((1)). The contract capacity price shall be subject to adjustment as provided for in Appendix D. (b) PGandE shall pay Seller for energy at prices equal to PGandE's full short run avoided operating costs as approved by the CPUC. (c) The contract capacity price is applicable to deliveries of capacity beginning after December 30, 1982. (1) Insert either "the date of execution of this Agreement" or "the actual operation date". S.O. #2 May 7, 1984

7 ARTICLE 4 NOTICES All written notices shall be directed as follows: To PGandE: Pacific Gas and Electric Company Attention: Vice President- Electric Operations 77 Beale Street San Francisco, CA 94106 To Seller: Solar Turbines Incorporated Attn: Vice President Energy Services P.O. Box 85376 San Diego, CA 92138-5376 ARTICLE 5 DESIGNATED SWITCHING CENTER The designated PGandE switching center shall be unless changed by PGandE: Midway Substation Buttonwillow, CA (805) 764-5229 ARTICLE 6 TERMS AND CONDITIONS This Agreement includes the following appendices which are attached and incorporated by reference: Appendix A - GENERAL TERMS AND CONDITIONS Appendix B - ENERGY PRICES Appendix C - FIRM CAPACITY PRICE SCHEDULE Appendix D - ADJUSTMENT OF CAPACITY PAYMENTS IN THE EVENT OF TERMINATION OR REDUCTION Appendix E - INTERCONNECTION ARTICLE 7 TERM OF AGREEMENT This Agreement shall be binding upon execution and remain in effect thereafter for 15 years from the actual operation date; provided, however, that it shall terminate if the actual operation date does not occur within five years of the execution date. S.O. #2 May 7, 1984 7

8 IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed by their duly authorized representatives and effective as of the last date set forth below. SOLAR TURBINES INCORPORATED PACIFIC GAS AND ELECTRIC COMPANY BY: /s/ T. Michael May By: /s/ H.M. Howe (Type Name) (Type Name) TITLE: Vice President Energy TITLE: Chief Siting Engineer Services DATE SIGNED: November 14, 1985 DATE SIGNED: November 20, 1985 S.O. #2 May 7, 1984 8

A-1 APPENDIX A GENERAL TERMS AND CONDITIONS CONTENTS Section Page A-1 DEFINITIONS A-2 A-2 CONSTRUCTION A-6 A-3 ENERGY SALE OPTIONS A-10 A-4 OPERATION A-12 A-5 PAYMENT A-16 A-6 ADJUSTMENTS OF PAYMENTS A-17 A-7 ACCESS TO RECORDS AND PGandE DATA A-17 A-8 CURTAILMENT OF DELIVERIES AND HYDRO SPILL CONDITIONS A-18 A-9 FORCE MAJEURE A-21 A-10 INDEMNITY A-22 A-11 LIABILITY; DEDICATION A-23 A-12 SEVERAL OBLIGATIONS A-24 A-13 NON-WAIVER A-24 A-14 ASSIGNMENT A-25 A-15 CAPTIONS A-25 A-16 CHOICE OF LAWS A-25 A-17 GOVERNMENTAL JURISDICTION AND AUTHORIZATION A-26 A-18 NOTICES A-26 A-19 INSURANCE A-27 S.O. #2 May 7, 1984 A-1

A-2 APPENDIX A GENERAL TERMS AND CONDITIONS A-1 DEFINITIONS Whenever used in this Agreement, appendices, and attachments hereto, the following terms shall have the following meanings: Actual operation date - The day following the day during which all features and equipment of the Facility are demonstrated to PGandE's satisfaction to be capable of operating simultaneously to deliver power continuously into PGandE's system as provided in this Agreement. Adjusted capacity price - The $/kW-year purchase price from Table B, Appendix C for the period of Seller's actual performance. Capacity sale reduction - A reduction in the amount of capacity provided or to be provided under this Agreement, other than a temporary reduction during probationary periods under Section C-5. Contract capacity - That capacity identified in Article 2(a) except as otherwise changed as provided herein. S.O. #2 May 7, 1984 A-2

A-3 Contract capacity price - The capacity price applicable for the period from the actual operation date through the term of agreement from either the firm capacity price schedule, Table B of Appendix C, or the successor to Table B in effect on the Actual operation date. Seller has indicated its choice of firm capacity price schedule in Article 3(a). Contract termination - The early termination of this Agreement. CPUC - The Public Utilities Commission of the State of California. Current firm capacity price - The $/kW-year capacity price from the firm capacity price schedule published by PGandE at the time notice of termination or reduction of contract capacity is given, for a term equal to the period from the date of termination or reduction to the end of the term of agreement. Designated PGandE switching center - That switching center or other PGandE installation identified in Article 5. Dispatchable - The Facility is operable and can be called upon at any time to increase its deliveries of capacity to any level up to the contract capacity. S.O. #2 May 7, 1984 A-3

A-4 Facility - That generation apparatus described in Article 2 and all associated equipment owned, maintained, and operated by Seller. Firm capacity price schedule - The periodically published schedule of the $/kW-year prices that PGandE offers to pay for capacity. See Table B, Appendix C. Forced outage - Any outage resulting from a design defect, inadequate construction, operator error or a breakdown of the mechanical or electrical equipment that fully or partially curtails the electrical output of the Facility. Interconnection facilities - All means required and apparatus installed to interconnect and deliver power from the Facility to the PGandE system including, but not limited to, connection, transformation, switching, metering, communications, and safety equipment, such as equipment required to protect (1) the PGandE system and its customers from faults occurring at the Facility, and (2) the Facility from faults occurring on the PGandE system or on the systems of others to which the PGandE system is directly or indirectly connected. Interconnection facilities also include any necessary additions and reinforcements by PGandE to the PGandE system required as a result of the interconnection of the Facility to the PGandE system. S.O. #2 May 7, 1984 A-4

A-5 Net energy output - The Facility's gross output in kilowatt-hours less station use and transformation and transmission losses to the point of delivery into the PGandE system. Where PGandE agrees that it is impractical to connect the station use on the generator side of the power purchase meter, PGandE may, at its option, apply a station load adjustment. Prudent electrical practices - Those practices, methods, and equipment, as changed from time to time, that are commonly used in prudent electrical engineering and operations to design and operate electric equipment lawfully and with safety, dependability, efficiency, and economy. Scheduled operation date - The day specified in Article 2(c) when the Facility is, by Seller's estimate, expected to produce energy and capacity that will be available for delivery to PGandE. Special facilities - Those additions and reinforcements to the PGandE system which are needed to accommodate the maximum delivery of energy and capacity from the facility as provided in this Agreement and those parts of the interconnection facilities which are owned and maintained by PGandE at Seller's request, including metering and data processing equipment. S.O. #2 May 7, 1984 A-5

A-6 All special facilities shall be owned, operated, and maintained pursuant to PGandE's electric Rule No. 21, which is attached hereto. Station use - Energy used to operate the Facility's auxiliary equipment. The auxiliary equipment includes, but is not limited to, forced and induced draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant lighting, fuel handling systems, control systems, and sump pumps. Surplus energy output - The Facility's gross output, in kilowatt-hours, less station use, and any other use by Seller, and transformation and transmission losses to the point of delivery into the PGandE system. Term of agreement - The period of time during which this Agreement will be in effect as provided in Article 7. Voltage level - The voltage at which the Facility interconnects with the PGandE system, measured at the point of delivery. A-2 CONSTRUCTION A-2.1 Land Rights Seller's hereby grants to PgandE all necessary rights of way and easements, including adequate and continuing S.O. #2 May 7, 1984 A-6

A-7 access rights on property of Seller, to install, operate, maintain, replace, and remove the special facilities. Seller agrees to execute such other grants, deeds, or documents as PgandE may require to enable it to record such rights of way and easements. If any part of PgandE's equipment is to be installed on property owned by other than Seller, Seller shall, at its own cost and expense, obtain from the owners thereof all necessary rights of way and easements, in a form satisfactory to PGandE, for the construction, operation, maintenance, and replacement of PGandE's equipment upon such property. If Seller is unable to obtain such rights of way and easements, Seller shall reimburse PGandE for all costs incurred by PGandE in obtaining them. PGandE shall at all times have the right of ingress to and egress from the Facility at all reasonable hours for any purposes reasonably connected with this Agreement or the exercise of any and all rights secured to PGandE by law or its tariff schedules. A-2.2 Design, Construction, Ownership, and Maintenance (a) Seller shall design, construct, install, own, operate, and maintain all interconnection facilities, except special facilities, to the point of interconnection with the PGandE system as required for PGandE to receive firm capacity and energy from the Facility. The Facility and interconnection facilities shall meet all requirements of applicable codes and all standards of prudent electrical practices S.O. #2 May 7, 1984 A-7

A-8 and shall be maintained in a safe and prudent manner. A description of the interconnection facilities for which Seller is solely responsible is set forth in Appendix E, or if the interconnection requirements have not yet been determined at the time of the execution of this Agreement, the description of such facilities will be appended to this Agreement at the time such determination is made. (b) Seller shall submit to PGandE the design and all specifications for the interconnection facilities (except special facilities) and, at PGandE's option, the Facility, for review and written acceptance prior to their release for construction purposes. PGandE shall notify Seller in writing of the outcome of PGandE's review of the design and specifications for Seller's interconnection facilities (and the Facility, if requested) within 30 days of the receipt of the design and all of the specifications for the interconnection facilities (and the Facility, if requested). Any flaws perceived by PGandE in the design and specifications for the interconnection facilities (and the Facility, if requested) will be described in PGandE's written notification. PGandE's review and acceptance of the design and specifications shall not be construed as confirming or endorsing the design and specifications or as warranting their safety, durability, or reliability. PGandE shall not, by reason of such review or lack of review, be responsible for strength, details of design, adequacy, or S.O. #2 May 7, 1984 A-8

A-9 capacity of equipment built pursuant to such design and specifications, nor shall PGandE's acceptance be deemed to be an endorsement of any of such equipment. Seller shall change the interconnection facilities as may be reasonably required by PGandE to meet changing requirements of the PGandE system. (c) In the event it is necessary for PGandE to install interconnection facilities for the purposes of this Agreement, they shall be installed as special facilities. (d) Upon the request of Seller, PGandE shall provide a binding estimate for the installation of interconnection facilities by PGandE. A-2.3 Meter Installation (a) PGandE shall specify, provide, install, own, operate, and maintain as special facilities all metering and data processing equipment for the registration and recording of energy and other related parameters which are required for the reporting of data to PGandE and for computing the payment due Seller from PGandE. (b) Seller shall provide, construct, install, own, and maintain at Seller's expense all that is required to accommodate the metering and data processing equipment, such as, but not limited to, metal-clad switchgear, switchboards, S.O. #2 May 7, 1984 A-9

A-10 cubicles, metering panels, enclosures, conduits, rack structures, and equipment mounting pads. (c) PGandE shall permit meters to be fixed on PGandE's side of the transformer. If meters are placed on PGandE's side of the transformer, service will be provided at the available primary voltage and no transformer loss adjustment will be made. If Seller chooses to have meters placed on Seller's side of the transformer, an estimated transformer loss adjustment factor of 2 percent, unless the Parties agree otherwise, will be applied. A-3 ENERGY SALE OPTIONS A-3.1 General Seller has two energy sale options, net energy output or surplus energy output. Seller has made its initial selection in Article 2(a). A-3.2 Energy Sale Conversion (a) Seller is entitled to convert from one option to the other 12 months after execution of this Agreement, and thereafter at least 12 months after the effective date of the most recent conversion, subject to the following conditions: A-10

A-11 (1) Seller shall provide PGandE with a written request to convert its energy sale option. (2) Seller shall comply with all applicable tariffs on file with the CPUC and contracts in effect between the Parties at the time of conversion covering the existing and proposed (i) facilities used to serve Seller's premises and (ii) interconnection facilities. (3) Seller shall install and operate equipment required by PGandE to prevent PGandE from serving any part of Seller's load which is served by the Facility and not under contract for PGandE standby service. At Seller's request PGandE shall provide this equipment as special facilities. (4) If the energy sale conversion results in a capacity sale reduction, the provisions in Appendix D shall apply. (b) If, as a result of an energy sales conversion, Seller no longer requires the use of interconnection facilities installed and/or operated and maintained by PGandE as special facilities under a Special Facilities Agreement, Seller may reserve these facilities, for its future use, by continuing its performance under its Special Facilities Agreement. If Seller does not wish to reserve such facilities, it may terminate its Special Facilities Agreement. S.O. #2 May 7, 1984 A-11

A-12 If Seller's energy sale conversion results in its discontinuation of its use of PGandE facilities not covered by Seller's Special Facilities Agreement, Seller cannot reserve those facilities for future use. Seller's future use of such facilities shall be contingent upon the availability of such facilities at the time Seller requests such use. If such facilities are not available, Seller shall bear the expense necessary to install, own, and maintain the needed additional facilities in accordance with PGandE's applicable tariff. (c) PGandE shall process requests for conversion in the order received. The effective date of conversion shall depend on the completion of the changes required to accommodate Seller's energy sale conversion. A-4 OPERATION A-4.2 Inspection and Approval Seller shall not operate the Facility in parallel with PGandE's system until an authorized PGandE representative has inspected the interconnection facilities, and PGandE has given written approval to begin parallel operation. Seller shall notify PGandE of the Facility's start-up date at least 45 days prior to such date. PGandE shall inspect the interconnecting facilities within 30 days of the receipt of such notice. If parallel operation is not authorized by PGandE, PGandE shall notify Seller in writing within five days after inspection of the reason authorization for parallel operation was withheld. S.O. #2 May 7, 1984 A-12

A-13 A-4.2 Facility Operation and Maintenance Seller shall operate and maintain its Facility according to prudent electrical practices, applicable laws, orders, rules, and tariffs and shall provide such reactive power support as may be reasonably required by PGandE to maintain system voltage level and power factor. Seller shall operate the Facility at the power factors or voltage levels prescribed by PGandE's system dispatcher or designated representative. If Seller fails to provide reactive power support, PGandE may do so at Seller's expense. A-4.3 Point of Delivery Seller shall deliver the energy at the point where Seller's electrical conductors (or those of Seller's agent) contact PGandE's system as it shall exist whenever the deliveries are being made or at such other point or points as the Parties may agree in writing. The initial point of delivery of Seller's power to the PGandE system is set forth in Appendix E. S.O. #2 May 7, 1984 A-13

A-14 A-4.4 Operating Communications (a) Seller shall maintain operating communications with the designated PGandE switching center. The operating communications shall include, but not be limited to, system paralleling or separation, schedule and unscheduled shutdowns, equipment clearances, levels of operating voltage or power factor and daily capacity and generation reports. (b) Seller shall keep a daily operations log for each generating unit which shall include information on unit availability, maintenance outages, circuit breaker trip operations requiring a manual reset, and any significant events related to the operation of the Facility. (c) If Seller makes deliveries greater than one megawatt, Seller shall measure and register on a graphic recording device power in kW and voltage in kV at a location within the Facility agreed to by both parties. (d) If Seller makes deliveries greater than one and up to and including ten megawatts, Seller shall report to the designated PGandE switching center, twice a day at agreed upon times for the current day's operation, the hourly readings in kW of capacity delivered and the energy in kWh delivered since the last report. S.O. #2 May 7, 1984 A-14

A-15 (e) If Seller makes deliveries of greater than ten megawatts, Seller shall telemeter the delivered capacity and energy information, including real power in kW, reactive power in kVAR, and energy in kWh to a switching center selected by PGandE. PGandE may also require Seller to telemeter transmission kW, kVAR, and kV data depending on the number of generators and transmission configuration. Seller shall provide and maintain the data circuits required for telemetering. When telemetering is inoperative, Seller shall report daily the capacity delivered each hour and the energy delivered each day to the designated PGandE switching center. (f) If Seller provides dispatchable capacity greater than ten megawatts pursuant to Option 1 in Section C-5 of Appendix C, Seller may be required by PGandE to provide telemetering and control equipment to allow the Facility to respond to system load frequency requirements on digital control from PGandE. A-4.5 Meter Testing and Inspection (a) All meters used to provide data for the computation of the payments due Seller from PGandE shall be sealed, and the seals shall be broken only by PGandE when the meters are to be inspected, tested, or adjusted. S.O. #2 May 7, 1984 A-15

A-16 (b) PGandE shall inspect and test all meters upon their installation and annually thereafter. At Seller's request and expense, PGandE shall inspect or test a meter more frequently. PGandE shall give reasonable notice to Seller of the time when any inspection or test shall take place, and Seller may have representatives present at the test or inspection. If a meter is found to be inaccurate or defective, PGandE shall adjust, repair, or replace it at its expense in order to provide accurate metering. A-4.6 Adjustments to Meter Measurements If a meter fails to register, or if the measurement made by a meter during a test varies by more than two percent from the measurement made by the standard meter used in the test, an adjustment shall be made correcting all measurements made by the inaccurate meter for -- (1) the actual period during which inaccurate measurements were made, if the period can be determined, or if not, (2) the period immediately preceding the test of the meter equal to one-half the time from the date of the last previous test of the meter, provided that the period covered by the correction shall not exceed six months. A-5 PAYMENT PGandE shall mail to Seller not later than 30 days after the end of each monthly billing period, (1) a statement S.O. #2 May 7, 1984 A-16

A-17 showing the capacity and energy delivered to PGandE during on-peak, partial-peak, and off-peak periods during the monthly billing period, (2) PGandE's computation of the amount due Seller, and (3) PGandE's check in payment of said amount. Except as provided in Section A-6, if within 30 days of receipt of this statement Seller does not make a report in writing to PGandE of an error, Seller shall be deemed to have waived any error in PGandE's statement, computation, and payment, and they shall be considered correct and complete. A-6 ADJUSTMENTS OF PAYMENTS (a) In the event adjustments to payments are required as a result of inaccurate meters, PGandE shall use the corrected measurements described in Section A-4.6 to recompute the amount due from PGandE to Seller for the firm capacity and energy delivered under this Agreement during the period of inaccuracy. (b) The additional payment to Seller or refund to PGandE shall be made within 30 days of notification of the owing Party of the amount due. A-7 ACCESS TO RECORDS AND PGandE DATA Each Party, after giving reasonable written notice to the other Party, shall have the right of access to all S.O. #2 May 7, 1984 A-17

A-18 metering and related records including operations logs of the Facility. Data filed by PGandE with the CPUC pursuant to CPUC orders governing the purchase of power from qualifying facilities shall be provided to Seller upon request; provided that Seller shall reimburse PGandE for the costs it incurs to respond to such request. A-8 CURTAILMENT OF DELIVERIES AND HYDRO SPILL CONDITIONS (a) PGandE shall not be obligated to accept or pay for and may require Seller to interrupt or reduce deliveries of energy (1) when necessary in order to construct, install, maintain, repair, replace, remove, investigate, or inspect any of its equipment or any part of its system, or (2) if it determines that interruption or reduction is necessary because of emergencies, forced outages, force majeure, or compliance with prudent electrical practices. (b) In anticipation of a period of hydro spill conditions, as defined by the CPUC, PGandE may notify Seller that any purchases of energy from Seller during such period shall be at hydro savings prices quoted by PGandE. If Seller delivers energy to PGandE during any such period, Seller shall be paid hydro savings prices for those deliveries in lieu of prices which would otherwise be applicable. The hydro savings prices shall be calculated by PGandE using the following formula: S.O. #2 May 7, 1984 A-18

A-19 AQF - S/ AQF x PP where: AQF = Energy, in kWh, projected to be available during hydro spill conditions from all qualifying facilities under agreements containing hydro savings price provisions. S = Potential energy, in kWh, from PGandE hydro facilities which will be spilled if all AQF is delivered to PGandE. PP = Prices published by PGandE for purchases during other than hydro spill conditions. (c) PGandE shall not be obligated to accept or pay for and may require Seller with a Facility with a nameplate rating of one megawatt or greater to interrupt or reduce deliveries of energy during periods when purchases under this Agreement would result in costs greater than those which PGandE would incur if it did not make such purchases but instead generated an equivalent amount of energy itself. (d) Whenever possible, PGandE shall give Seller reasonable notice of the possibility that interruption or reduction of deliveries under subsections (a) or (c), above, may be required. PGandE shall give Seller notice of general periods when hydro spill conditions are anticipated, and shall give Seller as much advance notice as practical of any specific hydro spill period and the hydro savings price S.O. #2 May 7, 1984 A-19

A-20 which will be applicable during such period. Before interrupting or reducing deliveries under subsection (c), above, and before invoking hydro savings prices under subsection (b), above, PGandE shall take reasonable steps to make economy sales of the surplus energy giving rise to the condition. If such economy sales are made, while the surplus energy conditions exists Seller shall be paid at the economy sales price obtained by PGandE in lieu of the otherwise applicable prices. (e) If Seller is selling net energy output to PGandE and simultaneously purchasing its electrical needs from PGandE, energy curtailed pursuant to subsections (b) or (c) above shall not be used by Seller to meet its electrical needs. When Seller elects not to sell energy to PGandE at the hydro savings price pursuant to subsection (b) or when PGandE curtails deliveries of energy pursuant to subsection (c), Seller shall continue to purchase all its electrical needs from PGandE. If Seller is selling surplus energy output to PGandE, subsections (b) or (c) shall only apply to the surplus energy output being delivered to PGandE, and Seller can continue to internally use that generation it has retained for its own use. A-9 FORCE MAJEURE (a) The term force majeure as used herein means unforeseeable causes, other than forced outages, beyond the S.O. #2 May 7, 1984 A-20

A-21 reasonable control of and without the fault or negligence of the Party claiming force majeure including, but not limited to, acts of God, labor disputes, sudden actions of the elements, actions by federal, state, and municipal agencies, and actions of legislative, judicial, or regulatory agencies which conflict with the terms of this Agreement. (b) If either Party because of force majeure is rendered wholly or partly unable to perform its obligations under this Agreement, that Party shall be excused from whatever performance is affected by the force majeure to the extent so affected provided that: (1) the non-performing Party, within two weeks after the occurrence of the force majeure, gives the other Party written notice describing the particulars of the occurrence, (2) the suspension of performance is of no greater scope and of no longer duration than is required by the force majeure, (3) the non-performing Party uses its best efforts to remedy its inability to perform (this subsection shall not require the settlement of any strike, walkout, lockout or other labor dispute on terms which, in the sole judgment of the Party involved in the dispute, are contrary to its interest. It is understood and agreed that the settlement of strikes, walkouts, lockouts or other S.O. #2 May 7, 1984 A-21

A-22 labor disputes shall be at the sole discretion of the Party having the difficulty), (4) when the non-performing Party is able to resume performance of its obligations under this Agreement, that Party shall give the other Party written notice to that effect, and (5) capacity payments during such periods of force majeure on Seller's part shall be governed by Section C-2(c) of Appendix C. (c) In the event a Party is unable to perform due to legislative, judicial, or regulatory agency action, this Agreement shall be renegotiated to comply with the legal change which caused the non-performance. A-10 INDEMNITY Each Party as indemnitor shall save harmless and indemnify the other Party and the directors, officers, and employees of such other Party against and from any and all loss and liability for injuries to persons including employees of either Party, and property damages including property of either Party resulting from or arising out of (1) the engineering, design, construction, maintenance, or operation of, or (2) the making of replacements, additions, or betterments to, the indemnitor's facilities. This indemnity and save harmless provision shall apply notwithstanding the active or passive negligence of the S.O. #2 May 7, 1984 A-22

A-23 indemnitee. Neither Party shall be indemnified hereunder for its liability or loss resulting from its sole negligence or willful misconduct. The indemnitor shall, on the other Party's request, defend any suit asserting a claim covered by this indemnity and shall pay all costs, including reasonable attorney fees, that may be incurred by the other Party in enforcing this indemnity. A-11 LIABILITY; DEDICATION (a) Nothing in this Agreement shall create any duty to, any standard of care with reference to, or any liability to any person not a Party to it. Neither Party shall be liable to the other Party for consequential damages. (b) Each Party shall be responsible for protecting its facilities from possible damage by reason of electrical disturbances or faults caused by the operation, faulty operation, or nonoperation of the other Party's facilities, and such other Party shall not be liable for any such damages so caused. (c) No undertaking by one Party to the other under any provision of this Agreement shall constitute the dedication of that Party's system or any portion thereof to the other Party or to the public or affect the status of PGandE as an independent public utility corporation or Seller as an S.O. #2 May 7, 1984 A-23

A-24 independent individual or entity and not a public utility. A-12 SEVERAL OBLIGATIONS Except where specifically stated in this Agreement to be otherwise, the duties, obligations, and liabilities of the Parties are intended to be several and not joint or collective. Nothing contained in this Agreement shall ever be construed to create an association, trust, partnership, or joint venture or impose a trust or partnership duty, obligation, or liability on or with regard to either Party. Each Party shall be liable individually and severally for its own obligations under this Agreement. A-13 NON-WAIVER Failure to enforce any right or obligation by either Party with respect to any matter arising in connection with this Agreement shall not constitute a waiver as to that matter or any other matter. A-14 ASSIGNMENT Neither Party shall voluntarily assign its rights nor delegate its duties under this Agreement, or any part of such rights or duties, without the written consent of the other Party, except in connection with the sale or S.O. #2 May 7, 1984 A-24

A-25 merger of a substantial portion of its properties. Any such assignment or delegation made without such written consent shall be null and void. Consent for assignment shall not be withheld unreasonably. Such assignment shall include, unless otherwise specified therein, all of Seller's rights to any refunds which might become due under this Agreement. A-15 CAPTIONS All indexes, titles, subject headings, section titles, and similar items are provided for the purpose of reference and convenience and are not intended to affect the meaning of the contents or scope of this Agreement. A-16 CHOICE OF LAWS This Agreement shall be interpreted in accordance with the laws of the State of California, excluding any choice of law rules which may direct the application of the laws of another jurisdiction. A-17 GOVERNMENTAL JURISDICTION AND AUTHORIZATION Seller shall obtain any governmental authorizations and permits required for the construction and operation of the Facility. Seller shall reimburse PGandE for any and all losses, damages, claims, penalties, or liability it S.O. #2 May 7, 1984 A-25

A-26 incurs as a result of Seller's failure to obtain or maintain such authorizations and permits. A-18 NOTICES Any notice, demand, or request required or permitted to be given by either Party to the other, and any instrument required or permitted to be tendered or delivered by either Party to the other, shall be in writing (except as provided in Section C-3) and so given, tendered, or delivered, as the case may be, by depositing the same in any United States Post Office with postage prepaid for transmission by certified mail, return receipt requested, addressed to the Party, or personally delivered to the Party, at the address in Article 4 of this Agreement. Changes in such designation may be made by notice similarly given. A-19 INSURANCE A-19.1 General Liability Coverage (a) Seller shall maintain during the performance hereof, General Liability Insurance ((1)) of not less than $1,000,000 if the Facility is over 100 kW, $500,000 if the (1) Governmental agencies which have an established record of self-insurance may provide the required coverage through self-insurance. S.O. #2 May 7, 1984 A-26

A-27 Facility is over 20 kW to 100 kW, and $100,000 if the Facility is 20 kW or below of combined single limit or equivalent for bodily injury, personal injury, and property damage as the result of any one occurrence. (b) General Liability Insurance shall include coverage for Premises- Operations, Owners and Contractors Protective, Products/Completed Operations Hazard, Explosion, Collapse, Underground, Contractual Liability, and Broad Form Property Damage including Completed Operations. (c) Such insurance, by endorsement to the policy(ies), shall include PGandE as an additional insured if the Facility is over 100 kW insofar as work performed by Seller for PGandE is concerned, shall contain a severability of interest clause, shall provide that PGandE shall not by reason of its inclusion as an additional insured incur liability to the insurance carrier for payment of premium for such insurance, and shall provide for 30-days' written notice to PGandE prior to cancellation, termination, alteration, or material change of such insurance. A-19.2 Additional Insurance Provisions (a) Evidence of coverage described above in Section A-19.1 shall state that coverage provided is primary and is not excess to or contributing with any insurance or self-insurance maintained by PGandE. S.O. #2 May 7, 1984 A-27

A-28 (b) PGandE shall have the right to inspect or obtain a copy of the original policy(ies) of insurance. (c) Seller shall furnish the required certificates ((1)) and endorsements to PGandE prior to commencing operation. (d) All insurance certificates 1, endorsements, cancellations, terminations, alterations, and material changes of such insurance shall be issued and submitted to the following: PACIFIC GAS AND ELECTRIC COMPANY Attention: Manager - Insurance Department 77 Beale Street, Room E280 San Francisco, CA 94106 (1) A governmental agency qualifying to maintain self-insurance should provide a statement of self-insurance. S.O. #2 May 7, 1984 A-28

APPENDIX B APPENDIX B ENERGY PRICES TABLE A Energy Prices Effective May 1 - July 31, 1985 The energy purchase price calculations which will apply to energy deliveries determined from meter readings taken during May, June and July 1985 are shown below. Please note that if Diablo Canyon Unit 1 does not become operational on May 1, the Incremental Energy Rates shown in Footnote 5 below will apply until the time the plant is commercially operative. (a) (b) (c) (d) Revenue Energy Requirement Purchase Incremental Cost for Cash Price Time Period Energy Rate of Energy Working Capital (d)={(a)x(b)}+(c) ((1)) ((2)) ((3)) ((4)) (Btu/kWh) ($/10-6 Btu) ($/kWh) ($/kWh) May 1 - July 31 (Period A) Time of Delivery Basis: On-Peak 12,168 5.2445 0.00041 0.06423 Partial-Peak 11,369 5.2445 0.00038 0.06000 Off-Peak 9,429 5.2445 0.00033 0.04978 Seasonal Average (Period A) 10,515 5.2445 0.00036 0.05551 ____________________________________ ((1)) Incremental energy rates (Btu/kWh) for Seasonal Period A and Seasonal Period B are derived from the marginal energy costs (including variable operating and maintenance expense) adopted by the CPUC in Decision No. 83-12-068 (page 339). They are based upon natural gas as the incremental fuel and weighted average hydroelectric power conditions. ((2)) Cost of natural gas under PGandE Gas Schedule No. G-55 effective May 1, 1985 per Advice No. 1311-G. ((3)) Revenue Requirement for Cash Working Capital as prescribed by the CPUC in Decision No. 83-12-068. ((4)) Energy Purchase Price = (Incremental Energy Rate x Cost of Energy) + Revenue Requirement for Cash Working Capital. The energy purchase price excludes the applicable energy line loss adjustment factors. However, as ordered by Ordering Paragraph No. 12(j) of CPUC Decision No. 82-12- 120, this figure is currently 1.0 for transmission and primary distribution loss adjustments and is equal to marginal cost line loss adjustment factors for the secondary distribution voltage level. These factors may be changed by the CPUC in the future. The currently applicable energy loss adjustment factors are shown in Table C. ((5)) Note that the following incremental energy rates (IER's) will apply until Diablo Canyon Unit 1 is in commercial operation: IERs Energy Purchase Price On-Peak 14,086 $0.07428 Partial-Peak 13,382 $0.07056 Off-Peak 10,499 $0.05539 Seasonal Average 12,031 $0.06346 S.O. #2 May 7, 1984 B-1

APPENDIX B-2 TABLE B((1)) Time Periods Monday through Sundays Friday Saturdays and Holidays ((2)) ((2)) Seasonal Period A (May 1 through September 30) On-Peak 12:30 p.m. to 6:30 p.m. Partial-Peak 8:30 a.m. 8:30 a.m. to to 12:30 p.m. 10:30 p.m. 6:30 p.m. to 10:30 p.m. Off-Peak 10:30 p.m. 10:30 p.m. All Day to to 8:30 a.m. 8:30 a.m. Seasonal Period B (October 1 through April 30) On-Peak 4:30 p.m. to 8:30 p.m. Partial-Peak 8:30 p.m. 8:30 a.m. to to 10:30 p.m. 10:30 p.m. 8:30 a.m. to 4:30 p.m. Off-Peak 10:30 p.m. 10:30 p.m. All Day to to 8:30 a.m. 8:30 a.m. ____________________________________ ((1)) This table is subject to change to accord with the on-peak, partial- peak, and off-peak periods as defined in PGandE's own rate schedules for the sale of electricity to its large industrial customers. ((2)) Except the following holidays: New Year's Day, Washington's Birthday, Memorial Day, Independence Day, Labor Day, Veteran's Day, Thanksgiving Day, and Christmas Day, as specified in Public Law 90-363 (5 U.S.C.A. Section 6103(a)). S.O. #2 May 7, 1984 B-2

APPENDIX B-3 TABLE C Energy Loss Adjustment Factors ((1)) Primary Secondary Transmission Distribution Distribution Seasonal Period A (May 1 through September 30) On-Peak 1.0 1.0 1.0148 Partial-Peak 1.0 1.0 1.0131 Off-Peak 1.0 1.0 1.0093 Seasonal Period B (October 1 through April 30) On-Peak 1.0 1.0 1.0128 Partial-Peak 1.0 1.0 1.0119 Off-Peak 1.0 1.0 1.0087 ____________________________________ ((1)) The applicable energy loss adjustment factors may be revised pursuant to orders of the CPUC. S.O. #2 May 7, 1984 B-3

APPENDIX C-1 APPENDIX C FIRM CAPACITY PRICE SCHEDULE CONTENTS Section Page C-1 GENERAL C-2 C-2 PERFORMANCE REQUIREMENTS C-2 C-3 SCHEDULED MAINTENANCE C-5 C-4 ADJUSTMENTS TO CONTRACT CAPACITY C-6 C-5 PAYMENT OPTIONS C-7 C-6 DETERMINATION OF NATURAL FLOW DATA C-15 C-7 THEORETICAL OPERATION STUDY C-16 C-8 DETERMINATION OF AVERAGE DRY YEAR C-17 CAPACITY RATINGS C-9 INFORMATION REQUIREMENTS C-18 C-10 ILLUSTRATIVE EXAMPLE C-19 S.O. #2 May 7, 1984 C-1

C-2 APPENDIX C FIRM CAPACITY PRICE SCHEDULE C-1 GENERAL This Appendix C establishes conditions and prices under which PGandE shall pay for firm capacity. C-2 PERFORMANCE REQUIREMENTS (a) To receive full capacity payments the Facility must meet the following requirements: (1) The contract capacity shall be available ((1)) for all of the on-peak hours ((2)) in the peak months on the PGandE system, which are presently the months of June, July and August, subject to a 20 percent allowance for forced outages in any month. Compliance with this provision shall be based on the Facility's total on-peak availability ((1)) for each of the peak months and shall exclude any energy associated with generation levels greater than the contract capacity. ____________________________________ ((1)) For purposes of Option 1, available means either dispatchable by PGandE or actually delivered to PGandE. For purposes of Option 2, available means actually delivered to PGandE. ((2)) On-peak, partial-peak, and off-peak hours are defined in Table B, Appendix B. S.O. #2 May 7, 1984 C-2

C-3 (2) If Seller selects Option 1, the contract capacity shall be dispatchable throughout the year, subject to (i) a monthly allowance for forced outages of 20% of the hours Seller is called upon to deliver power to PGandE and (ii) the allowances for scheduled maintenance outages. Except during the peak months on the PGandE system, Seller may accumulate and apply the 20 percent allowance for forced outages for any consecutive three month period. Seller shall demonstrate that the Facility is fueled by a reliable fuel supply and adequate fuel storage is available to deliver power as requested by PGandE's system dispatcher. Such demonstration could reasonably include documentation of the current availability of the fuel, identification of the source, and production of contracts for its purchase and supply. (b) If Seller is prevented from meeting the performance requirements because of a forced outage on the PGandE system or a condition set forth in Section A-8, PGandE shall continue capacity payments. Under Option 2, capacity payments will be calculated in the same manner used for scheduled maintenance outages. (c) If Seller is prevented from meeting the performance requirements because of force majeure, PGandE shall continue capacity payments for ninety days from the occurrence of the force majeure. Thereafter, Seller shall be S.O. #2 May 7, 1984 C-3

C-4 deemed to have failed to have met the performance requirements. Under Option 2, capacity payments will be calculated in the same manner used for scheduled maintenance outages. (d) If Seller is prevented from meeting the performance requirements because of extreme dry year conditions, PGandE shall continue capacity payments. Extreme dry year conditions are drier than those used to establish contract capacity pursuant to Section C-8. Seller shall warrant to PGandE that the Facility is a hydroelectric facility and that such conditions are the sole cause of Seller's inability to meet its contract capacity obligations. Under Option 1, starting with the month in which Seller cannot provide its contract capacity, payments shall be made under Option 2 for a one-year period, and if at the end of this one-year period Seller is not able to resume the contract capacity due solely to continued extreme dry year conditions, Seller shall continue to receive payments under Option 2 for additional one-year periods as long as such conditions continue to exist. (e) If Seller is prevented from meeting the performance requirements for reasons other than those described above in Sections C-2(b), (c) or (d): (1) Seller shall receive the reduced capacity payments as provided in Section C-5 for a probationary period not to exceed 15 months, or as otherwise agreed to by the Parties. S.O. #2 May 7, 1984 C-4

C-5 (2) If, at the end of the probationary period Seller has not demonstrated that the Facility can meet the performance requirements, PGandE may derate the contract capacity pursuant to Section C-4(b). C-3 SCHEDULED MAINTENANCE Outage periods for scheduled maintenance shall not exceed 840 hours (35 days) in any 12-month period. This allowance may be used in increments of an hour or longer on a consecutive or nonconsecutive basis. Seller may accumulate unused maintenance hours from one 12-month period to another up to a maximum of 1,080 hours (45 days). This accrued time must be used consecutively and only for major overhauls. Seller shall provide PGandE with the following advance notices: 24 hours for scheduled outages less than one day, one week for a scheduled outage of one day or more (except for major overhauls), and six months for a major overhaul. Seller shall not schedule major overhauls during the peak months (presently June, July and August). Seller shall make reasonable efforts to schedule or reschedule routine maintenance outside the peak months, and in no event shall outages for scheduled maintenance exceed 30 peak hours during the peak months. Seller shall confirm in writing to PGandE pursuant to Article 4, within 24 hours of S.O. #2 May 7, 1984 C-5

C-6 the original notice, all notices Seller gives personally or by telephone for schedule maintenance. C-4 ADJUSTMENTS TO CONTRACT CAPACITY (a) Seller may increase the contract capacity with the approval of PGandE and receive payment for the additional capacity thereafter in accordance with the applicable capacity purchase price published by PGandE at the time the increase is first delivered to PGandE. (b) Seller may reduce the contract capacity at any time by giving notice thereof to PGandE, subject to the provisions of Appendix D if the reduction occurs after the actual operation date. PGandE may reduce the contract capacity in accordance with Section C-2(e) as a result of appropriate data showing Seller has failed to meet the performance requirements of Section C-2. The amount by which the contract capacity is reduced by PGandE shall be deemed a capacity sale reduction without notice as provided in Section D-3 of Appendix D. (c) Either Party may request, when it reasonably appears that the capacity of the Facility may have changed for any reason, that a new contract capacity be determined. S.O. #2 May 7, 1984 C-6

C-7 C-5 PAYMENT OPTIONS Seller has two options for calculation of capacity payments and Seller has made its selection in Article 3(a). As used below in this section, month refers to a calendar month. The two options are as follows: Option 1 When Seller meets the requirements of Section C-2 the monthly payment for capacity will be one-twelfth of the product of the contract capacity price, the contract capacity, the appropriate capacity loss adjustment factor from Table A based on the Facility's interconnection voltage, and the appropriate performance bonus factor, if any, from Table C. Capacity payments will continue during scheduled maintenance outages provided that the provisions of Section C-3 are met. During a probationary period Seller's monthly payment for capacity shall be determined by substituting for the contract capacity, the capacity at which Seller would have met the performance requirements. In any month during the probationary period that Seller does not meet the performance requirements at whatever capacity was determined for the previous month, Seller's monthly payment for capacity shall be determined by substituting the capacity at which Seller would have met the performance requirements. S.O. #2 May 7, 1984 C-7

C-8 The performance bonus factor shall not be applied during a probationary period. Option 2 The monthly payment for capacity will be the product of the Period Price Factor (PPF), the Monthly Delivered Capacity (MDC), the appropriate capacity loss adjustment factor from Table A based on the Facility's interconnection voltage, and the appropriate performance bonus factor, if any, from Table C, plus any allowable payment for outages due to scheduled maintenance. Firm capacity prices shall be applied to meter readings taken during the separate times and periods as illustrated in Table B, Appendix B. The PPF is determined by multiplying the contract capacity price by the following Option 2 Allocation Factors ((1)): Option 2 Contract PPF Allocation Factor x Capacity Price = ($/kW-month) Seasonal Period A .18540 ______________ __________ Seasonal Period B .01043 ______________ __________ ____________________________________ ((1)) These allocation factors were prescribed by the CPUC in Decision No. 83-12-068. All allocation factors are subject to change by PgandE's marginal capacity cost allocation, as determined in general rate case proceedings before the CPUC. Seasonal Periods A and B are defined in Table B, Appendix B. S.O. #2 May 7, 1984 C-8

C-9 The MDC is determined in the following manner: (1) Determine the Performance Factor (P), which is defined as the lesser of 1.0 or the following quantity: P = ___________A___________ (S 1.0) C x (B-S) x (0.8*) Where: A = Total kilowatt-hours delivered during all on-peak and partial-peak hours excluding any energy associated with generation levels greater than the contract capacity. C = Contract capacity in kilowatts. B = Total on-peak and partial-peak hours during the month. S = Total on-peak and partial-peak hours during the month Facility is out of service on scheduled maintenance. (2) Determine the Monthly Capacity Factor (MCF), which is computed using the following expression: M MCF = P x (1.0 - - ) D Where: M = The number of hours during the month Facility is out of service on scheduled maintenance. D = The number of hours in the month. ____________________________________ * 0.8 reflects a 20% allowance for forced outage. S.O. #2 May 7, 1984 C-9

C-10 (3) Determine the MDC by multiplying the MCF by C: MDC (kilowatts) = MCF x C The monthly payment for capacity is then determined by multiplying the PPF by the MDC, by the appropriate capacity loss adjustment factor presented from Table A, and by the appropriate performance bonus factor, if any, from Table C. monthly payment capacity loss performance for capacity = PPF x MDC x adjustment factor x bonus factor Furthermore, the payment for a month in which there is an outage for scheduled maintenance shall also include an amount equal to the product of the average hourly capacity payment ((1)) for the most recent month in the same type of Seasonal Period (i.e., Seasonal Period A or Seasonal Period B) during which deliveries were made times the number of hours of outage for scheduled maintenance in the current month. Capacity payments will continue during the outage periods for scheduled maintenance provided that the provisions of Section C-3 are met. During a probationary period, Seller's monthly payment for capacity shall be determined by substituting for the contract capacity, the capacity at which Seller would have met the performance requirements. In ____________________________________ ((1)) Total monthly payment divided by the total number of hours in the monthly billing period. S.O. #2 May 7, 1984 C-10

C-11 the event that during the probationary period Seller does not meet the performance requirements at whatever capacity was established for the previous month, Seller's monthly payment for capacity shall be determined by substituting the capacity at which Seller would have met the performance requirements. The performance bonus factor shall not be applied during probationary periods. TABLE A If the Facility is non-remote ((1)) the capacity loss adjustment factors are as follows: Capacity Loss Interconnection Voltage Adjustment Factor Transmission .989 Primary Distribution .991 Secondary Distribution .991 If the Facility is remote the capacity loss adjustment factor is ___________((2)). ____________________________________ ((1)) As defined by the CPUC. ((2)) The Seller acknowledges that this blank cannot be filled in at the time of executing this Agreement because the information is not yet available to make a definitive determination of whether the Facility is remote or non-remote and, if remote, the number to be inserted in this blank. Seller shall request PGandE to perform a capacity loss adjustment factor study to be done in its accustomed manner of making such studies to determine whether the Facility is remote or non-remote and, if remote the number to be inserted. If the Facility is determined to be non-remote, "N/A" shall be inserted. S.O. #2 May 7, 1984 C-11

C-12 TABLE B Firm Capacity Price Schedule (Levelized $/kW-year) Actual Operation Date Term of Agreement (Year) 1 2 3 4 5 6 7 8 9 10 1983 72 111 96 88 84 85 88 91 93 96 1984 156 111 95 88 89 92 95 98 100 103 1985 60 58 59 66 73 79 84 88 92 95 1986 56 58 69 78 85 90 95 99 103 106 1987 61 77 88 95 101 105 109 113 117 120 1988 96 104 110 114 119 122 126 129 133 136 (Year) 11 12 13 14 15 20 25 30 1983 98 100 102 104 106 115 122 128 1984 105 108 110 112 114 124 131 137 1985 99 102 104 107 110 120 129 135 1986 110 113 116 118 121 132 141 148 1987 124 127 130 132 135 147 156 163 1988 139 142 145 148 151 163 173 180 S.O. #2 May 7, 1984 C-12

C-13 TABLE C Performance Bonus Factor The following shall be the performance bonus factors applicable to the calculation of the monthly payments for capacity delivered by the Facility after it has demonstrated a capacity factor in excess of 85%. DEMONSTRATED CAPACITY FACTOR PERFORMANCE % BONUS FACTOR 85 1.000 90 1.059 95 1.118 100 1.176 After the Facility has delivered power during the span of all of the peak months on the PGandE system (presently June, July and August) in any year (span), (i) the capacity factor for each such month shall be calculated in the following manner: CAPACITY FACTOR (%) = F x 100 (N-W) x Q Where: For Option 1 F = Total kilowatt-hours delivered by Seller in any peak month during all on-peak hours that Seller is asked to deliver power to PGandE S.O. #2 May 7, 1984 C-13

C-14 excluding any energy associated with generation levels greater than the contract capacity. N = Total on-peak hours that Seller is asked to deliver power to PGandE during the month. W = Total on-peak hours during the peak month that the Facility is out of service on scheduled maintenance during the on-peak hours that Seller is asked to deliver power to PGandE. Q = Contract capacity in kilowatts. For Option 2 F = Total kilowatt-hours delivered by Seller in any peak month during all on-peak hours excluding any energy associated with generation levels greater than the contract capacity. N = Total on-peak hours during the month. W = Total on-peak hours during the peak month that the Facility is out of service on scheduled maintenance. Q = Contract capacity in kilowatts. (ii) the arithmetic average of the above capacity factors shall be determined for that span, (iii) the average of the above arithmetic average capacity factors for the most recent span(s), not to exceed 5, shall be calculated and shall become the Demonstrated Capacity Factor. S.O. #2 May 7, 1984 C-14

C-15 To calculate the performance bonus factor for a Demonstrated Capacity Factor not shown in Table D use the following formula: Performance Bonus Factor = Demonstrated Capacity Factor (%) 85% THE FOLLOWING SECTIONS SHALL APPLY ONLY TO HYDROELECTRIC PROJECTS C-6 DETERMINATION OF NATURAL FLOW DATA Natural flow data shall be based on a period of record of at least 50 years and which includes historic critically dry periods. In the event Seller demonstrates that a natural flow data base of at least 50 years would be unreasonably burdensome, PGandE shall accept a shorter period of record with a corresponding reduction in the averaging basis set forth in Section C-8. Seller shall determine the natural flow data by month by using one of the following methods: Method 1 If stream flow records are available from a recognized gauging station on the water course being developed in the general vicinity of the project, Seller may use the data from them directly. S.O. #2 May 7, 1984 C-15

C-16 Method 2 If directly applicable flow records are not available, Seller may develop theoretical natural flows based on correlation with available flow data for the closest adjacent and similar area which has a recognized gauging station using generally accepted hydrologic estimating methods. C-7 THEORETICAL OPERATION STUDY Based on the monthly natural flow data developed under Section C-6 a theoretical operation study shall be prepared by Seller. Such a study shall identify the monthly capacity rating in kW and the monthly energy production in kWh for each month of each year. The study shall take into account all relevant operating constraints, limitations, and requirements including but not limited to -- (1) Release requirements for support of fish life and any other operating constraints imposed on the project; (2) Operating characteristics of the proposed equipment of the Facility such as efficiencies, minimum and maximum operating levels, project control procedures, etc.; S.O. #2 May 7, 1984 C-16

C-17 (3) The design characteristics of project facilities such as head losses in penstocks, valves, tailwater elevation levels, etc.; and (4) Release requirements for purposes other than power generation such as irrigation, domestic water supply, etc. The theoretical operation study for each month shall assume an even distribution of generation throughout the month unless Seller can demonstrate that the Facility has water storage characteristics. For the study to show monthly capacity ratings, the Facility shall be capable of operating during all on-peak hours in the peak months on PGandE system, which are presently the months of June, July and August. If the project does not have this capability throughout each such month, the capacity rating in that month of that year shall be set at zero for purposes of this theoretical operation study. C-8 DETERMINATION OF AVERAGE DRY YEAR CAPACITY RATINGS Based on the results of the theoretical operation study developed under Section C-7, the average dry year capacity rating shall be established for each month. The average dry year shall be based on the average of the five years of the lowest annual generation as shown in the theoretical operation study. Once such years of lowest annual generation are identified, the monthly capacity rating is determined for each month by averaging the capacity S.O. #2 May 7, 1984 C-17

C-18 ratings from each month of those years. The contract capacity shown in Article 2(a) shall not exceed the lowest average dry year monthly capacity ratings for the peak months on the PGandE system, which are presently the months of June, July and August. C-9 INFORMATION REQUIREMENTS Seller shall provide the following information to PGandE for its review: (1) A summary of the average dry year capacity ratings based on the theoretical operation study as provided in Table D; (2) A topographic project map which shows the location of all aspects of the Facility and locations of stream gauging stations used to determine natural flow data; (3) A discussion of all major factors relevant to project operation; (4) A discussion of the methods and procedures used to establish the natural flow data. This discussion shall be in sufficient detail for PGandE to determine that the methods are consistent with those outlined in Section C-6 and are consistent with generally accepted engineering practices; and (5) Upon specific written request by PGandE, Seller's theoretical operation study. S.O. #2 May 7, 1984 C-18

C-19 C-10 ILLUSTRATIVE EXAMPLE (1) Determine natural flows - These flows are developed based on historic stream gauging records and are compiled by month, for a long-term period (normally at least 50 years or more) which covers dry periods which historically occurred in the 1920's and 30's and more recently in 1976 and 77. In all but unusual situations this will require application of hydrological engineering methods to records that are available, primarily from the USGS publication Water Resources Data for California. (2) Perform theoretical operation study - Using the natural flow data compiled under (1) above a theoretical operation study is prepared which determines, for each month of each year, energy generation (kWh) and capacity rating (kW). This study is performed based on the Facility's design, operating capabilities, constraints, etc., and should take into account all factors relevant to project operation. Generally such a study is done by computer which routes the natural flows through project features, considering additions and withdrawals from storage, spill past the project, releases for support of fish life, etc., to determine flow available for generation. Then the generation and capacity amounts are computed based on equipment performance, efficiencies, etc. S.O. #2 May 7, 1984 C-19

C-20 (3) Determine average dry year capacity ratings - After the theoretical project operation study is complete the five years in which the annual generation (kWh) would have been the lowest are identified. Then for each month, the capacity rating (kW) is averaged for the five years to arrive at a monthly average capacity rating. The contract capacity is then set by the Seller based on the monthly average dry year capacity ratings and the performance requirements of Appendix C. An example project is shown in the attached completed Table D. S.O. #2 May 7, 1984 C-20

C-21 EXAMPLE TABLE D Summary of Theoretical Operation Study Project: New Creek 1 Dispatchable: Yes ___ No __X__ Water Source: West Fork New Creek Mode of Operation: Run of the river Type of Turbine: Francis Design Flow: 100 cfs Design Head: 150 feet Operating Characteristics ((1)): Flow Head (feet) Output Efficiency (%) (cfs) Gross Net (kW) Turbine Generator Normal Operation 100 160 150 1,120 90 98 Maximum Operation 110 160 148 1,150 85 98 Minimum Operation 30 160 155 290 75 98 Average Dry Year Operation - Based on the average of the following lowest generation years: 1930, 1932, 1934, 1949, 1977. Energy Generation Capacity Output Percent of Total Month (kWh) (kW) Hours Operated ((2)) January 855,000 1,150 100 February 753,000 1,120 100 March 818,000 1,100 100 April 727,000 1,010 100 May 699,000 940 100 June 612,000 850 100 July 484,000 650 100 August 305,000 410 100 September 245,000 340 100 October 148,800 200 100 November 468,000 650 100 December 595,000 800 100 Maximum Contract Capacity: 410 kW ____________________________________ ((1)) If Facility has a variable head, operating curves should be provided. ((2)) For this to be less than 100%, Facility must be dispatchable. S.O. #2 May 7, 1984 C-21

D-1 APPENDIX D ADJUSTMENT OF CAPACITY PAYMENTS IN THE EVENT OF TERMINATION OR REDUCTION CONTENTS Section Page D-1 GENERAL PROVISIONS D-2 D-2 TERMINATION WITH PRESCRIBED NOTICE D-4 D-3 TERMINATION WITHOUT PRESCRIBED NOTICE D-5 D-4 TERMINATION EXAMPLES D-6 S.O. #2 May 7, 1984 D-1

D-2 APPENDIX D ADJUSTMENT OF CAPACITY PAYMENTS IN THE EVENT OF TERMINATION OR REDUCTION D-1 GENERAL PROVISIONS (a) This Appendix shall be applicable in the event there is a contract termination or a capacity sale reduction (each sometimes referred to as termination in this Appendix D). (b) The Parties agree that the amount which PGandE pays Seller for the capacity which Seller makes available to PGandE is based on the agreed value to PGandE of Seller's performance of capacity obligations during the full period of the term of agreement. The Parties further agree that in the event PGandE does not receive such full performance by reason of a termination: (1) PGandE shall be deemed damaged by reason thereof, (2) it would be impracticable or extremely difficult to fix the actual damages to PGandE resulting therefrom, (3) the refunds and payments as provided in Sections D-2 and D-3, as applicable, are in the nature of adjustments in capacity prices and liquidated damages, and not a penalty, and are fair and reasonable, and S.O. #2 May 7, 1984 D-2

D-3 (4) such refunds and payments represent a reasonable endeavor by the Parties to estimate a fair compensation for the reasonable losses that would result from such termination or reduction. (c) In the event of a capacity sale reduction, the quantity by which the contract capacity is reduced shall be used to calculate the payments due PGandE in accordance with Sections D-2 and D-3, as applicable. (d) Seller shall be invoiced by PGandE for all refunds and payments due under this Appendix D and the special facilities agreement. From the date of the notice of termination or the date of termination, whichever is earlier, Seller shall pay interest, compounded monthly, on all overdue amounts, at the published Federal Reserve Board three months' Prime Commercial Paper rate. (e) If Seller does not make payments pursuant to Section D-1(d), PGandE shall have the right to offset any amounts due it against any present or future payments due Seller. (f) Notices of termination shall be made in accordance with Section A-18 of Appendix A. S.O. #2 May 7, 1984 D-3

D-4 D-2 TERMINATION WITH PRESCRIBED NOTICE In the event Seller terminates this entire Agreement, or all or part of the contract capacity thereof, with the following prescribed written notice: Amount of Contract Capacity Length of Terminated Notice Required 1,000 kW or under 3 months over 1,000 kW through 10,000 kW 9 months over 10,000 kW through 25,000 kW 12 months over 25,000 kW through 50,000 kW 36 months over 50,000 kW through 100,000 kW 48 months over 100,000 kW 60 months Then the following provisions shall apply: (1) With respect to the amount by which the contract capacity is reduced, Seller shall refund to PGandE an amount equal to the difference between (a) the capacity payments already paid by PGandE, based on the original term of agreement and (b) the total capacity payments which PGandE would have paid based on the period of Seller's actual performance using the adjusted capacity price. Additionally, Seller shall pay interest, compounded monthly, on all overpayments, at the published Federal Reserve Board three months' Prime Commercial Paper rate. (2) From the date PGandE receives the termination notice to the date of actual termination, PGandE shall make capacity payments based on the adjusted capacity price for the amount of contract capacity being terminated. S.O. #2 May 7, 1984 D-4

D-5 (3) From the date PGandE receives the termination notice, PGandE shall continue to pay for the amount of contract capacity not being terminated, if any, at the original contract capacity price. D-3 TERMINATION WITHOUT PRESCRIBED NOTICE (a) If Seller terminates this Agreement, or all or a part of the contract capacity thereof, without the notice prescribed in Section D-2, the provisions prescribed in Section D-2 will all apply. Additionally: (b) Seller shall pay PGandE a sum equal to the amount by which the contract capacity is being terminated times the difference between the current firm capacity price on the date of termination for a term equal to the balance of the term of agreement and the contract capacity price, pro-rated for the length of notice given by multiplying by the difference between the prescribed length of notice and the actual notice given, with the difference divided by 12. In the event that the current firm capacity price is less than the contract capacity price, no payment under this Section D-3 shall be due either Party. This additional payment shall be computed using the following formula: G = CC x (T - CCP) x J - H 12 S.O. #2 May 7, 1984 D-5

D-6 Where G >= O and where: G = additional payment. CC = the amount by which the contract capacity is being terminated. T = the current firm capacity price. CCP = the contract capacity price. H = the actual number of months notice given. J = the prescribed length of notice. D-4 TERMINATION EXAMPLES These examples demonstrate how to calculate capacity payment adjustments when capacity sales are terminated. (a) Termination with Prescribed Notice (1) Example Based on Option 1 Assumptions: i. Term of Agreement is 15 years; ii. Actual operation date is July 1, 1985; iii. Prescribed notice is given on July 1, 1986; S.O. #2 May 7, 1984 D-6

D-7 iv. Contract capacity to be reduced by 10,000 kW on July 1 1987; actual performance to be from July 1, 1985 through July 1, 1987 ((1)); v. The applicable capacity loss adjustment factor is .989; and vi. No performance bonus for capacity has been earned. The amount of overpayment (E) made by PGandE to Seller during each monthly billing period is calculated as follows: E = (A-B) x C x L x U Where: A = contract capacity price per month for the actual operation date (July 1, 1985) and the term of agreement which is 15 years = $110/kW-yr \ 12 mo/yr = $9.17/kW-mo. B = adjusted capacity price per month for the actual operation date (July 1, 1984) and a two-year agreement term = $58/kW-hr \ 12 mo/yr = $4.83/kW-mo. ____________________________________ ((1)) The capacity payment is adjusted upon receiving notice, so no refund is necessary for the last month of the first twelve months of operation and all of the second twelve months (June 1, 1986 to July 1, 1987). Seller performed for eleven month prior to payment adjustment. (Note that due to the 30-day interval between delivery and payment, performance in the twelfth month (June 1986) can be paid for at the adjusted capacity price. S.O. #2 May 7, 1984 D-7

D-8 C = amount by which the contract capacity is being reduced = 10,000 kW. L = capacity loss adjustment factor = .989. U = performance bonus factor; when Seller does not qualify for a performance bonus factor, as in this example, U is removed from the above calculation of E. Therefore: E = ($9.17/kW-mo - $4.83/kW-mo) x 10,000 kW x .989 = $42,923 per month. Table A shows a step-by-step derivation of the refund Seller owes PGandE for the early termination outlined above. The $497,342 that Seller owes PGandE appears at the lower right-hand corner of the table. All other figures of this table represent intermediate calculation steps. S.O. #2 May 7, 1984 D-8

D-9 TABLE A (a) (b) (c) (d) (e) (f) (g) Interest Amount Accumu- Charge on Monthly of lated Accumulated Balance Billing Date of Over- Over- Interest Overpayment (g) = Period Payment Payment Payment Rate (f)=(d)x(e) (c)+(d)+(f) ((1)) ((2)) ((3)) ((4)) ((5)) ((6)) ((7)) $ $ % $ $ 7/85 8/30/85 42,923 0 1.2 0 42,923 8/85 9/30/85 42,923 42,923 1.0 429 86,275 9/85 10/30/85 42,923 86,275 0.9 776 129,974 10/85 11/30/85 42,923 129,974 0.8 1,040 173,937 11/85 12/30/85 42,923 173,937 0.7 1,218 218,078 12/85 1/30/86 42,923 218,078 0.8 1,745 262,746 1/86 3/ 2/86 42,923 262,746 0.9 2,365 308,034 2/86 3/30/86 42,923 308,034 1.0 3,080 354,037 3/86 4/30/86 42,923 354,037 1.1 3,894 400,854 4/86 5/30/86 42,923 400,854 1.2 4,810 448,587 5/86 6/30/86 42,923 448,587 1.3 5,832 497,342 ____________________________________ ((1)) The month in which power deliveries were made. For purposes of simplification, the monthly billing period will coincide exactly with each calendar month. ((2)) The date on which payment for the monthly billing period statedin column (a) is made. ((3)) The amount of overpayment made by PGandE to Seller during each monthly billing period. ((4)) The amount of overpayment accumulated up through last month's date of payment. ((5)) The interest rate for the period between the date of payment for the previous monthly billing period and the date of payment for this monthly billing period. These interest rates are arbitrarily chosen for use in this example. ((6)) The amount of interest charge accrued between the date of payment for the previous monthly billing period and the date of payment for this monthly billing period on the accumulated overpayment balance existing as of the previous monthly billing period's date of payment. ((7)) The amount Seller owes PGandE at this stage of the calculation. The balance (g) for a given monthly billing period equals the accumulated overpayment (d) for the monthly billing period immediately following. S.O. #2 May 7, 1984 D-9

D-10 (2) Example Based on Option 2 Assumptions: i. Term of agreement is 15 years; ii. Actual operation date is April 1, 1985; iii. Prescribed notice is given on April 1, 1987; iv. Contract capacity is reduced by 10,000 kW on April 1, 1988; actual performance is from April 1, 1985 through April 1, 1988((1)); v. Scheduled outage for maintenance: 18 days = 432 hours in both November 1985 and November 1986; vi. The applicable capacity loss adjustment factor is .989; and vii. Listed below is Seller's Performance Factor (P), the Demonstrated Capacity Factor (Y) in % (when measured), and where applicable, the performance bonus factor (U) earned for each of the monthly billing periods((2)) prior to the time capacity payment is adjusted. Also listed below are the number of hours the Facility was out of service for schedule maintenance (M) and the number of hours in the month (D) for each of these months. ____________________________________ ((1)) The capacity payment is adjusted upon receiving notice, so no refund is necessary for the last month of the first twenty-four months of operation and all of the last twelve months (March 1, 1987 to April 1, 1988). Seller performed for twenty-three months prior to payment adjustment. (Note that due to the 30-day interval between delivery and payment, performance in the twenty-fourth month (March 1987) can be paid for at the adjusted capacity price.) ((2)) For purposes of simplification, the monthly billing period will coincide exactly with each calendar month. S.O. #2 May 7, 1984 D-10

D-11 Monthly Billing Period P Y U M D April 1985 .85 - - 0 720 May 1985 .95 - - 0 744 June 1985 .90 80 - 0 720 July 1985 1.00 88 - 0 744 August 1985 .90 96 - 0 744 September 1985 1.00 - 1.035* 0 720 October 1985 .96 - 1.035 0 744 November 1985 .98 - 1.035 432 720 December 1985 1.00 - 1.035 0 744 January 1986 1.00 - 1.035 0 744 February 1986 .92 - 1.035 0 672 March 1986 .85 - 1.035 0 744 April 1986 .78 - 1.035 0 720 May 1986 1.00 - 1.035 0 744 June 1986 .94 100 1.035 0 720 July 1986 .95 95 1.035 0 744 August 1986 1.00 92 1.035 0 744 September 1986 1.00 - 1.080** 0 720 October 1986 .93 - 1.080 0 744 November 1986 .84 - 1.080 432 720 December 1986 .88 - 1.080 0 744 January 1987 .94 - 1.080 0 744 February 1987 1.00 - 1.080 0 672 ____________________________________ * This performance bonus factor was calculated by averaging the Demonstrated Capacity Factors for each of the months of June, July and August 1985, and then dividing that average by 85(%): U = 80 + 88 + 96 / 85 = 1.035 3 ** This performance bonus factor was calculated by averaging the Demonstrated Capacity Factors for each of the months of June, July and August 1985, and June, July and August 1986, and then dividing that average by 85(%): U = 80 + 88 + 96 + 100 + 95 + 92 / 85 = 1.080 6 S.O. #2 May 7, 1984 D-11

D-12 The amount of overpayment (E) made by PGandE to Seller during each monthly billing period is calculated as follows: E = [P x (1 - M) x K x L x U x (A - B) x C] + [M x R] D D Where: P = performance factor. M = number of hours of scheduled maintenance for that monthly billing period. D = number of hours in that monthly billing period. K = allocation factor from Section C-5. L = capacity loss adjustment factor = .989. U = performance bonus factor; when Seller does not qualify for a performance bonus factor, U is removed from the above calculation of E. A = Contract capacity price for the actual operation date (April 1, 1985) and term of agreement which is 15 years = $110/kW-yr. B = adjusted capacity price for the actual operation date and a three-year agreement term = $59/kW-yr. C = amount by which the contract capacity is being reduced = 10,000 kW. S.O. #2 May 7, 1985 D-12

D-13 R = amount of overpayment for the most recent monthly billing period in the same Seasonal Period (i.e., Seasonal Period A or Seasonal Period B). The results of the calculations are: Amount of Monthly Billing Period Overpayment (E) April 1985 $ 4,472 May 1985 88,838 June 1985 84,163 July 1985 93,514 August 1985 84,163 September 1985 96,787 October 1985 5,227 November 1985 5,271 December 1985 5,445 January 1986 5,445 February 1986 5,009 March 1986 4,628 April 1986 4,247 May 1986 96,787 June 1986 90,980 July 1986 91,948 August 1986 96,787 September 1986 100,995 October 1986 5,284 November 1986 5,079 December 1986 5,000 January 1987 5,341 February 1987 5,682 Table B shows a step-by-step derivation of the refund Seller owes PGandE for the early termination outlined above. The $1,136,015 that Seller owes PGandE appears at the lower right-hand corner of the table. All other figures of this table represent intermediate calculation steps. S.O. #2 May 7, 1984 D-13

D-14 TABLE B (a) (b) (c) (d) (e) (f) (g) Interest Amount Accumu- Charge on Monthly of lated Accumulated Balance Billing Date of Over- Over- Interest Overpayment (g) = Period Payment Payment Payment Rate (f)=(d)x(e) (c)+(d)+(f) ((1)) ((2)) ((3)) ((4)) ((5)) ((6)) ((7)) $ $ % $ $ 4/85 5/30/85 4,472 0 1.3 0 4,472 5/85 6/30/85 88,838 4,472 1.4 63 93,373 6/85 7/30/85 84,163 93,373 1.3 1,214 178,750 7/85 8/30/85 93,514 178,750 1.2 2,145 274,409 8/85 9/30/85 84,163 274,409 1.0 2,744 361,316 9/85 10/30/85 96,787 361,316 0.9 3,252 461,355 10/85 11/30/85 5,227 461,355 0.8 3,691 470,273 11/85 12/30/85 5,271 470,273 0.7 3,292 478,836 12/85 1/30/86 5,445 478,836 0.8 3,831 488,112 1/86 3/ 2/86 5,445 488,112 0.9 4,393 497,950 2/86 3/30/86 5,009 497,950 1.0 4,980 507,939 3/86 4/30/86 4,628 507,939 1.1 5,587 518,154 4/86 5/30/86 4,247 518,154 1.2 6,218 528,619 5/86 6/30/86 96,787 528,619 1.3 6,872 632,278 6/86 7/30/86 90,980 632,278 1.4 8,852 732,110 7/86 8/30/86 91,948 732,110 1.4 10,250 834,308 8/86 9/30/86 96,787 834,308 1.3 10,846 941,941 9/86 10/30/86 100,995 941,941 1.2 11,303 1,054,239 10/86 11/30/86 5,284 1,054,239 1.0 10,542 1,070,065 11/86 12/30/86 5,079 1,070,065 1.1 11,771 1,086,915 12/86 1/30/87 5,000 1,086,915 1.1 11,956 1,103,871 1/87 3/ 2/87 5,341 1,103,871 1.0 11,039 1,120,251 2/87 3/30/87 5,682 1,120,251 0.9 10,082 1,136,015 ____________________________________ ((1)) The month in which power deliveries were made. For purposes of simplification, the monthly billing period will coincide exactly with each calendar month. ((2)) The date on which payment for the monthly billing period stated in column (a) is made. ((3)) The amount of overpayment made by PGandE to Seller during each monthly billing period. ((4)) The amount of overpayment accumulated up through last month's date of payment. ((5)) The interest rate for the period between the date of payment for the previous monthly billing period and the date of payment for this monthly billing period. These interest rates are arbitrarily chosen for use in this example. ((6)) The amount of interest charge accrued between the date of payment for the previous monthly billing period and the date of payment for this monthly billing period on the accumulated overpayment balance existing as of the previous monthly billing period's date of payment. ((7)) The amount Seller owes PGandE at this stage of the calculation. The balance (g) for a given monthly billing period equals the accumulated overpayment (d) for the monthly billing period immediately following. S.O. #2 May 7, 1984 D-14

D-15 (b) Termination without Prescribed Notice If Seller terminates without prescribed notice, Seller will owe PGandE a refund [the calculation of which is described in Sections D-4(a)(1) and D-4(a) (2) of this example] and payment (G). This example demonstrates how the payment (G) is calculated. Assumptions: i. Term of agreement is 15 years; ii. Actual operation date is July 1, 1985; iii. Notice is given on January 1, 1990; and iv. Contract capacity is to be reduced by 10,000 kW on July 1, 1990; actual performance is from July 1, 1985 through July 1, 1990. The payment (G) is calculated as follows: (G) = CC x (T-CCP) x J-H G >= 0 12 Where: CC = The amount of contract capacity being terminated = 10,000 kW. T = the current firm capacity price $140/kW-yr is arbitrarily chosen for use in this example for a July 1, 1990 Operation Date and 10-year agreement term. CCP = the contract capacity price = $110/kW-yr. H = the actual number of months notice given = six months. J = the prescribed notice = twelve months. S.O. #2 May 7, 1984 D-15

D-16 The sample calculation is: G = CC x (T - CCP) x (J-H) 12 G = 10,000 kW x ($140/kW-yr - $110/kW-yr) x (12 mos. - 6 mos.) 12 mos./yr G = $150,000 S.O. #2 May 7, 1984 D-16

E-1 APPENDIX E INTERCONNECTION CONTENTS Section Page E-1 INTERCONNECTION TARIFFS E-2 E-2 POINT OF DELIVERY LOCATION SKETCH E-3 E-3 INTERCONNECTION FACILITIES FOR WHICH SELLER E-4 IS RESPONSIBLE S.O. #2 May 7, 1984 E-1

E-2 E-1 INTERCONNECTION TARIFFS (The applicable tariffs in effect at the time of execution of this Agreement shall be attached.) S.O. #2 May 7, 1984 E-2

E-3 E-2 POINT OF DELIVERY LOCATION SKETCH The Seller requests, and PGandE consents, that the location sketch not be made at the time of executing the Agreement, because the Seller, recognizing that the information is not yet available to make a definitive determination of the sketch to be inserted here, shall request PGandE to perform an interconnection study to be done in its accustomed manner of making such studies to determine the sketch to be inserted. S.O. #2 May 7, 1984 E-3

E-4 E-3 INTERCONNECTION FACILITIES FOR WHICH SELLER IS RESPONSIBLE The Seller requests, and PGandE consents, that this listing of facilities not be filled in at the time of executing the Agreement, because the Seller, recognizing that the information is not yet available to make a definitive determination of the listing of facilities to be inserted here, shall request PGandE to perform an interconnection study to be done in its accustomed manner of making such studies to determine the listing of facilities to be inserted. S.O. #2 May 7, 1984 E-4

129 PACIFIC GAS AND ELECTRIC COMPANY UNIFORM STANDARD OFFER 1 AS-AVAILABLE CAPACITY AND ENERGY POWER PURCHASE AGREEMENT QFID NO. 25C099

i TABLE OF CONTENTS SECTION PAGE 1 PROJECT SUMMARY 1 2 DEFINITIONS 5 3 TERM AND TERMINATION 10 4 PROJECT FEE 11 5 PROJECT DEVELOPMENT MILESTONES 12 6 GENERATING FACILITY 15 7 OPERATING OPTIONS 19 8 INTERCONNECTION FACILITIES 22 9 REVIEW AND DISCLAIMER 24 10 REAL PROPERTY RIGHTS 26 11 METERING 28 12 QUALIFYING FACILITY STATUS AND PERMIT 30 13 ENERGY PURCHASE 31 14 CAPACITY PURCHASE 32 15 CURTAILMENT 33 16 INTERRUPTION OF DELIVERIES 36 17 PAYMENT AND BILLING 37 18 INDEMNITY AND LIABILITY 38 19 INSURANCE 41 20 FORCE MAJEURE 43 21 REVIEW OF RECORDS AND DATA 44 22 ASSIGNMENT 45 23 ABANDONMENT 45 i

ii TABLE OF CONTENTS (Contd.) SECTION 24 NON-DEDICATION 46 25 NON-WAIVER 46 26 SECTION HEADINGS 47 27 GOVERNING LAW 47 28 AMENDMENT, MODIFICATION OR WAIVER 47 29 SEVERAL OBLIGATIONS 47 30 SIGNATURES 48 APPENDIX A: TIME PERIODS APPENDIX B: ENERGY LOSS ADJUSTMENT FACTORS APPENDIX C: CAPACITY LOSS ADJUSTMENT FACTORS APPENDIX D: PACIFIC GAS AND ELECTRIC COMPANY'S ELECTRIC RULE-NO. 21 APPENDIX E: [omitted] APPENDIX F: SITE LOCATION METES AND BOUNDS DESCRIPTION (IF REQUIRED FOR PURPOSES OF SECTION 1.1(c)) APPENDIX G: EFFECTIVE CAPACITY CONVERSION FACTORS APPENDIX H: POINT OF DELIVERY SKETCH

1 PACIFIC GAS AND ELECTRIC COMPANY AS-AVAILABLE CAPACITY AND ENERGY POWER PURCHASE AGREEMENT BERRY PETROLEUM COMPANY ("Seller") and PACIFIC GAS AND ELECTRIC COMPANY ("PG&E"), referred to collectively as "Parties" and individually as "Party", agree as follows: 1. PROJECT SUMMARY 1.1 Seller's Generating Facility: (a) QFID Number: 25C099 (b) Nameplate rating: 37,200 kW at 0.9 power factor. (Net of Station Use) If the Generating Facility is comprised of more than one (1) electrical generator and Seller has not commenced Initial Operation of each generator within five (5) years of the effective date of this Agreement, the Nameplate Rating shall be derated to the nameplate rating of the electrical generators which have achieved Initial Operation prior to the end of the five (5) year period. Seller may not increase the Nameplate Rating after the effective date of this Agreement. (c) Location: Section 28, Township 12 North, Range 24 West, 3 1/2 miles south of Taft, California, Kern County, California. See Appendix F. 1

2 (d) Type: (Check One) X Cogeneration facility. natural gas(primary energy source) Small power production facility (primary energy source) 1.2 Expected annual energy deliveries: 290,000,000 kWh. 1.3 Seller's initial estimate of the Scheduled Operation Date is January 16, 1997 (Generating Facility is already constructed and operating). The Scheduled Operation Date shall not be later than five (5) years from the effective date of this Agreement. 1.4 The term of this Agreement is 15 years from January 16, 1997, unless terminated sooner by Seller in accordance with Section 3 of this Agreement. 1.5 Project Development Material Milestones: (Omitted) 1.6 Operating Options Pursuant to Section 7: (Check One) X Operating Option I (Buy/Sell): Entire Generating Facility output less Station Use sold to PG&E. Operating Option II (Surplus Sale): The Generating Facility output, less Station Use and any other use by Seller, sold to PG&E. Capacity allocated to other use by Seller: 2

3 kW. 1.7 Metering Location: (Check One) Seller selects metering location pursuant to Section 11 as follows: X High-voltage side of the Interconnection Facilities transformer. Low-voltage side of the Interconnection Facilities transformer with the transformer loss compensation factor determined in accordance with Section 11.2. 3

4 1.8 Notices. Any written notice, demand, or request required or authorized in connection with the Agreement shall be deemed properly given if delivered in person or sent by first class mail, postage prepaid, to the person specified below: PG&E: Pacific Gas & Electric Company Manager - Power Contracts 77 Beale Street, Mail Code B23C P.O. Box 770000 San Francisco, CA 94177 Seller: Berry Petroleum Company Post Office Bin X Taft, CA 93268 Seller's notices to PG&E pursuant to this Section 1.8 shall refer to the QFID number set forth in Section l.l(a). The designated addresses may be changed at any time upon similar notice by the Party's authorized representative. 1.9 Location of PG&E Designated Switching Center PG&E Midway Substation Buttonwillow, CA (805) 764-5299 1.10 Seller's arrangement includes Host(s): (Check one) yes X no 4

5 If yes, the following sections shall apply 2. Host(s): (b) Seller has made arrangements with Host(s) to: (Check one or both) 2. Sell all or a portion of the electrical output of the Generating Facility to Host(s). ii. Sell useful thermal output from the Generating Facility to Host(s). (c) Seller shall, within thirty (30) days of the effective date of the Agreement, provide PG&E with the name(s) and address(es) of representative(s) of the Host(s) who is (are) authorized to act on behalf of the Host(s) in matters related to the arrangement identified in this Section 1.10. Seller shall notify PG&E of any change(s) of authorized representative(s) within thirty (30) days of being notified of such change. (d) Any references to Host(s) contained in this Agreement are not intended and shall not be construed to create any third party rights or remedies. 2. DEFINITIONS When underlined, whether in the singular or in the plural, the following terms shall have the following meanings: 5

6 2.1 Agreement: This document and appendices, as amended from time to time, including PG&E's Electric Rule No. 21, in effect at the time of execution of this Agreement. 2.2 As-Available Capacity: The capacity delivered to PG&E from the Generating Facility that PG&E is contractually obligated to purchase at its published As-Available Capacity price as approved by the CPUC. 2.3 CPUC: The Public Utilities Commission of the State of California. 2.4 Designated Switching Center: described in Section 1.9. 2.5 Electric Rule No. 21: PG&E's interconnection standards for cogenerators and small power producers interconnected with the PG&E system, attached hereto as Appendix D and incorporated herein by reference. 2.6 Emergency: An actual or imminent condition or situation which jeopardizes PG&E Electric System Integrity. 2.7 Force Majeure: Any occurrence, other than Forced Outages, beyond the reasonable control of and without the fault or negligence of the Party claiming Force Majeure which causes the Party to be unable to perform its obligations, which by exercise of due foresight such Party could not reasonably have been expected to avoid and which the Party is unable to overcome by the exercise of due diligence. Such an occurrence may include, but is not limited to, acts of God, labor disputes, sudden actions of the 6

7 elements, actions or inactions by federal, state, and municipal agencies, and actions or inactions of legislative, judicial, or regulatory agencies. 2.8 Forced Outage: Any outage of the Generating Facility or Seller's Interconnection Facilities resulting from a design defect, inadequate construction, operator error, interruption in fuel supply unless excused as a Force Majeure, or a breakdown of the mechanical or electrical equipment that fully or partially curtails the electrical output of the Generating Facility. Generating Facility: All of Seller's generating units, together with all protective and other associated equipment and improvements owned, maintained, and operated by Seller, which are necessary to produce electrical power, excluding associated land, land rights, and interests in land. 2.10 Host(s): The entity or entities identified in Section 1.10 which will purchase: (a) useful thermal output of the cogenerator; or (b) all or a portion of the electric output of the Generating Facility; or (c) both. 2.11 Initial Operation: The day the Generating Facility first operates in parallel with the PG&E system. 2.12 Interconnection Facilities: All means required, and apparatus installed, to interconnect and deliver power from the Generating Facility to the PG&E system in accordance with PG&E's Electric Rule No. 21, including, 7

8 but not limited to, connection, transformation, switching, metering, communications, control, and safety equipment, such as equipment required to protect (a) the PG&E system and its customers from faults occurring at the Generating Facility, and (b) the Generating Facility from faults occurring on the PG&E system or on the systems of others to which the PG&E system is directly or indirectly connected. Interconnection Facilities also include any necessary additions and reinforcements by PG&E to the PG&E system required as a result of the interconnection of the Generating Facility to the PG&E system. 2.13 Interconnection Study: PG&E's determination of the Interconnection Facilities required to interconnect Seller's Generating Facility with the PG&E system, including an estimate of costs and construction lead time. 2.14 Nameplate Rating: The gross generating capacity of the Generating Facility less Station Use. For purposes of this Agreement, Nameplate Rating is that rating specified in Section 1.1(b) of the Agreement. 2.15 PG&E Electric System Integrity: The state of operation of PG&E's electric system in a manner which is deemed to minimize the risk of injury to persons and/or property and enables PG&E to provide adequate and reliable electric service to its customers. 2.16 Point of Delivery: The point where Seller's electrical conductors contact PG&E's system as it shall exist 8

9 whenever the deliveries are being made or at such other point or points as the Parties may agree in writing. A Point of Delivery sketch is attached in Appendix H. 2.17 Preliminary Interconnection Study or Preliminary Study: PG&E's preliminary estimate of the costs and equipment necessary for the interconnection of Seller's Generating Facility to PG&E's system. This study may also establish the date by which Seller must request an Interconnection Study under Section 5.5(a). 2.18 Protective Apparatus: All relays, meters, power circuit breakers, synchronizers, and other control devices as shall be agreed to by the Parties in accordance with the requirements of PG&E as necessary for proper and safe operation of the Generating Facility in parallel with PG&E's electric system. 2.19 Prudent Electrical Practices: Those practices, methods, and equipment, as changed from time to time, that are commonly used in prudent electrical engineering and operations to design and operate electric equipment lawfully and with safety, dependability, efficiency, and economy. 2.20 Scheduled Operation Date: The date specified in Section 1.3 when the Generating Facility is, by Seller's estimate, expected to begin Initial Operation. 9

10 2.21 Short-Run Avoided Operating Costs: CPUC-approved costs, updated from time to time, which are the basis of PG&E's published energy prices. 2.22 Special Facilities: Those Interconnection Facilities consisting of additions and reinforcements to the PG&E system which are needed to accommodate the maximum delivery of energy and capacity from the Generating Facility as provided in this Agreement and those other parts of the Interconnection Facilities, if any, which are owned and maintained by PG&E at Seller's request, including metering and data processing equipment. All Special Facilities shall be owned, operated and maintained pursuant to PG&E's Electric Rule No. 21, which is attached hereto. 2.23 Station Use: Energy used to operate the Generating Facility's auxiliary equipment. The auxiliary equipment includes, but is not limited to, forced and induced draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant lighting, fuel handling systems, control systems, and sump pumps. 3. TERM AND TERMINATION This Agreement shall be binding upon execution by the Parties and remain in effect thereafter for the number of years specified in Section 1.4, which shall not exceed thirty (30) years from Initial Operation. This Agreement may be terminated 10

11 sooner by Seller upon providing thirty (30) days prior written notice in accordance with Section 1.8. 4. PROJECT FEE [omitted] 5. PROJECT DEVELOPMENT MILESTONES To assure Seller's establishment of Initial Operation in the time provided in this Agreement and to afford PG&E with early notification in the event Seller will be unable to establish Initial Operation, Seller shall complete each Project Development Milestone as provided in this Section 5. 5.1 Project Development Milestones (a) The following events shall constitute Project Development Milestones: (1) Submittal of Quarterly Status Reports (pursuant to Section 5.2) (2) Maintenance of Site Control (pursuant to Section 5. 3) (3) Provision of information for and payment of costs of Preliminary Interconnection Study (pursuant to Section 5.4) (4) Provision of information for and payment of costs of Interconnection Study (pursuant to Section 5.5) Commencement of Initial Operation no later than five (5) years from the effective date of this Agreement (pursuant to Section 5.6). 11

12 (b) If Seller fails to complete each Project Development Milestone in the time and manner provided in Sections 5.2 through 5.6: (l) PG&E may terminate this Agreement; (2) Seller shall relinquish transmission priority, if established; and (3) the Project Fee, if any, shall be paid to PG&E pursuant to Section 4.2(b). (b) If PG&E terminates this Agreement pursuant to this Section 5.1, Seller may execute another power purchase agreement with PG&E only if Seller has satisfied all its outstanding obligations to PG&E arising under this Agreement, including payment of any costs which PG&E may have incurred as a result of Seller's failure to perform under this Agreement. Nothing in this Section 5.1(c) shall limit PG&E's remedies at law under this Agreement. 5.2 Submit Quarterly Status Reports omitted 5.3 Maintain Site Control (a) Seller warrants that it possessed Site Control of the site described in Section 1.1(c) as of the date Sellers executed this Agreement and that Seller shall maintain continuous Site Control for the term of this Agreement. 12

13 (b) Site Control: Site Control shall consist of one of the following, or other form of Site Control acceptable to PG&E in its sole discretion: (l) Seller's ownership of the location of Seller's Generating Facility specified in Section l.l(c); (2) Seller's leasehold interest in the location specified in Section 1.1(c), which leasehold interest shall specifically include the right to construct and operate the Generating Facility at such location; (3) Seller's exclusive and irrevocable contractual right to construct and operate the Generating Facility at the location specified in Section l.l(c); or, (4) Seller's exclusive and irrevocable option to obtain any of the rights described in Section 5.3(b)(1) through Section 5.3(b)(3) above. This alternative shall only constitute Site Control prior to the commencement of construction of Seller's Generating Facility. (c) Seller shall provide PG&E with prompt notice of any change in the status of its Site Control. If, at any time, PG&E has reason to believe that Seller has lost Site Control, PG&E may request from Seller evidence that Seller continues to possess Site Control. If Seller fails to provide such evidence within thirty 13

14 (30) calendar days after Seller receives PG&E's request, the provisions of Section 5.1(b) shall apply. (d) Where the term of Seller's Site Control does not extend for the full term of this Agreement, Seller shall advise PG&E of the date Site Control is scheduled to expire. Seller shall provide to PG&E, no later than the date Seller's Site Control is scheduled to expire, evidence that Seller's Site Control has been renewed or extended. If Seller fails to provide such evidence, PG&E shall notify Seller in writing that Seller is not in compliance with this Section 5.3(d). Unless Seller provides PG&E with evidence that Site Control has been renewed or extended within thirty (30) calendar days after PG&E's notification, the provisions of Section 5.1(b) shall apply. This Agreement is project and site specific; however, Seller may with PG&E's prior consent, be permitted to adjust the location of Seller's Generating Facility within the proximity of the site specified in Section 1.1(c) if necessary for project development. 5.4 Provide Information for and Pay Costs of Preliminary Interconnection Study omitted (e) 5.5 Provide Information for and Pay Costs of Interconnection Study omitted 14

15 5.6 Commence Initial Operation of the Generating Facility: Seller shall commence Initial Operation of Seller's Generating Facility no later than five (5) years from the effective date of this Agreement. If Seller fails to commence Initial Operation by said date, the provisions of Section 5.1(b) shall apply. 6. GENERATING FACILITY The Generating Facility shall be owned by Seller. The Generating Facility shall be designed, constructed, operated, and maintained as follows: 6.1 Design (a) Seller, at Seller's sole expense, shall: (1) Design the Generating Facility; (2) Acquire all permits and other approvals necessary for the construction, operation, and maintenance of the Generating Facility; and (3) Complete all environmental impact studies necessary for the construction, operation, and maintenance of the Generating Facility. (b) At PG&E's request, Seller shall provide to PG&E Seller's electrical specifications and design drawings pertaining to Seller's Generating Facility for PG&E's review prior to finalizing design of the Generating Facility and before beginning construction work based on such specifications and drawings. 15

16 Seller shall provide to PG&E reasonable advance written notice of any changes in Seller's Generating Facility and provide to PG&E specifications and design drawings of any such changes for PG&E's review and approval. (c) The total installed capacity (net of station use) of Seller's Generating Facility shall not exceed the Nameplate Rating set forth in Section 1.1(b) of this Agreement. 6.2 Construction (a) Seller, at Seller's sole expense, shall construct the Generating Facility. (b) PG&E shall have the right to review and consult with Seller regarding Seller's construction schedule. Seller, at its option, may be present at such inspection. (c) PG&E shall have the right to periodically inspect the Generating Facility prior to Initial Operation upon advance notice to Seller. Seller, at its option, may be present at such inspection. 6.3 Operation (a) Seller shall operate the Generating Facility in accordance with Prudent Electrical Practices. (b) Seller shall operate the Generating Facility to generate such reactive power or provide individual power factor correction as necessary to maintain voltage levels and reactive power support as may be required by PG&E, in accordance with PG&E's Electric 16

17 Rule No. 21, attached hereto. Seller shall not deliver excess reactive power to PG&E unless otherwise agreed upon between the Parties. If Seller fails to provide reactive power support, PG&E may do so at Seller's expense. (c) The Generating Facility shall be operated with all of Seller's Protective Apparatus in service whenever the Generating Facility is connected to, or is operated in parallel with, the PG&E electric system. Any deviation for brief periods of Emergency or maintenance shall only be by agreement of the Parties. (d) Seller shall maintain operating communications with the PG&E Designated Switching Center. The operating communications shall include, but not be limited to, system parallel operation or separation, scheduled and unscheduled outages, equipment clearances, protective relay operations, levels of operating voltage and reactive power, and daily capacity and generation reports. (e) Seller shall keep a daily operations log for the Generating Facility which shall include information on availability, maintenance outages, circuit breaker trip operations requiring a manual reset, and any significant events related to the operation of the Generating Facility, including but not limited to: real and reactive power production; changes in 17

18 operating status and protective apparatus operations; and any unusual conditions found during inspections. Changes in setting shall also be logged for Seller's generator(s) if it is "block-loaded" to a specific kW capacity. (f) Seller shall maintain complete daily operations records applicable to the Generating Facility, including but not limited to fuel consumption, cogeneration fuel efficiency, maintenance performed, kilowatts, kilovars and kilowatt hours generated and settings or adjustments of the generator control equipment and protective devices. Such information shall be available pursuant to Section 21. (g) If Seller's Generating Facility has a Nameplate Rating greater than one (1) and up to and including ten (10) megawatts, PG&E may require Seller to report to the Designated Switching Center, twice a day at agreed upon times for the current day's operation, the hourly readings in kW of capacity delivered and the energy in kWh delivered since the last report. (h) If Seller's Generating Facility has a Nameplate Rating greater than ten (10) megawatts, PG&E shall provide, at Seller's expense, telemetering equipment pursuant to Section 11.3. (i) PG&E may require Seller, at Seller's expense, to demonstrate to PG&E's satisfaction the correct 18

19 calibration and operation of Seller's Protective Apparatus at any time PG&E has reason to believe that said Protective Apparatus may impair the PG&E Electric System Integrity. 6.4 Maintenance (a) Seller shall maintain the Generating Facility in accordance with Prudent Electrical Practices. (b) Seller shall notify PG&E (1) by January 1, May 1, and September 1 of each year, of the estimated scheduled maintenance and estimated daily energy and capacity deliveries for the succeeding four months and (2) by September 1 of each year, of the estimated scheduled maintenance and estimated daily energy and capacity deliveries for the following calendar year. 7. OPERATING OPTIONS 7.1 Seller shall operate the Generating Facility in parallel with PG&E's electric system pursuant to one of the following options as designated in Section 1.6: (a) Operating Option I (Buy/Sell): Seller sells the entire Generating Facility output less Station Use to PG&E. (b) Operating option II (Surplus Sale): Seller sells Generating Facility output, less Station Use and any other use by Seller, to PG&E. 19

20 7.2 Seller may convert from Operating Option I to Operating Option II, or vice versa, no earlier than twelve (12) months after execution of this Agreement, and thereafter no earlier than twelve (12) months after the effective date of the most recent conversion, subject to the following conditions: (a) Seller shall provide PG&E with a written request to convert its operating option. (b) Seller shall comply with all applicable tariffs and rules on file with the CPUC and contracts in effect between the Parties at the time of conversion covering the existing and proposed (1) facilities used to serve Seller's premises and (2) Interconnection Facilities. (c) Seller shall bear the expense necessary to install, own, and maintain any needed additional interconnection facilities in accordance with PG&E's applicable tariffs and rules on file with the CPUC. 7.3 If, as a result of an operating option conversion, Seller no longer requires the use of Interconnection Facilities installed and/or operated and maintained by PG&E as Special Facilities under an agreement for Special Facilities, Seller may either: (a) Reserve these facilities, for its future use, by continuing its performance under its agreement for Special Facilities; or 20

21 (b) If Seller does not wish to reserve such facilities, it may terminate its agreement for Special Facilities in accordance with the terms of that agreement. If Seller's operating option conversion results in its discontinuation of its use of PG&E facilities not covered by the agreement for Special Facilities, Seller shall not reserve those facilities for future use. Seller's future use of such facilities shall be contingent upon the availability of such facilities at the time Seller requests such use. If such facilities are not available, Seller shall bear the expense necessary to install, own, and maintain the needed additional facilities in accordance with PG&E's applicable tariffs and rules on file with the CPUC. 7.4 Unless provided for pursuant to Section 7.3 above, PG&E shall not be required to remove or reserve capacity of Interconnection Facilities made idle by a change in operating options. PG&E may, without penalty, dedicate any such Interconnection Facilities idled by Seller's change in operating option at any time to serve customers or to interconnect with other electric power sources. 7.5 PG&E shall process requests for operating option conversion in the order received and institute any changes made necessary by such request in as reasonably expeditious manner as possible given other PG&E commitments. The effective date of conversion shall be 21

22 the date PG&E completes all of the changes required to accommodate Seller's operating option conversion. Notwithstanding this Section 7.5, Seller may convert from Operating Option I to Operating Option II, or vice versa, no earlier than twelve (12) months after execution of this Agreement, and thereafter no earlier than twelve (12) months after the effective date of the most recent conversion. 7.6 Seller agrees to use reasonable efforts and shall take no action which would encumber, impair or diminish Seller's ability to deliver to PG&E As-Available Capacity and the energy associated with that capacity. Seller acknowledges that it intends no other use for the generation committed to PG&E under this Agreement than expressly set forth in Sections 1.6 and 1.10 of this Agreement. 8. INTERCONNECTION FACILITIES 8.1 The Parties have executed an agreement for Special Facilities which shall provide for the ownership, construction, operation and maintenance of the Interconnection Facilities pursuant to PG&E's Electric Rule No. 21. 8.2 The Interconnection Facilities for which Seller is responsible and the Point of Delivery shall be set forth either in equipment lists or by appropriate one-line 22

23 diagrams which shall be attached to the agreement for Special Facilities. 8.3 Seller, at Seller's sole expense, shall acquire all permits and approvals and complete all environmental impact studies necessary for the design, construction, installation, operation, and maintenance of the Interconnection Facilities other than Special Facilities. 8.4 [omitted] 8.5 Seller shall provide written notice to PG&E at least fourteen (14) calendar days prior to the initial and subsequent testing of Seller's Protective Apparatus. Seller's Protective Apparatus shall be tested thereafter at intervals not to exceed three (3) years using qualified personnel. PG&E shall have the right to have a representative present at the initial and subsequent testing of Seller's Protective Apparatus and to receive copies of the test results. 8.6 Seller shall be allocated existing line capacity in accordance with PG&E's Electric Rule No. 21. 8.7 Seller shall be solely responsible for the design, purchase, construction, operation, and maintenance of the Interconnection Facilities, owned by Seller, necessary to protect PG&E's electric system, employees and customers from damage or injury arising out of or connected with the operation of the Generating Facility. Seller shall 23

24 operate and maintain the Interconnection Facilities owned by Seller in accordance with Prudent Electrical Practices. 8.8 Seller shall provide to PG&E Seller's electrical specifications and design drawings pertaining to the Interconnection Facilities for PG&E's review prior to finalizing design of the Interconnection Facilities and before beginning construction work based on such specification and drawings. Seller shall provide to PG&E reasonable advance written notice of any changes in the Interconnection Facilities and provide to PG&E specifications and design drawings of any such changes for PG&E's review and approval. PG&E may require modifications to such specifications and designs as it deems necessary to allow PG&E to operate PG&E's system in accordance with Prudent Electrical Practices. 8.9 Seller shall pay for any changes in the Interconnection Facilities as may be reasonably required to meet the changing requirements of the PG&E system in accordance with PG&E's Electric Rule No. 21. 9. REVIEW AND DISCLAIMER 9.1 Review by PG&E of the design, construction, operation, or maintenance of Seller's Interconnection Facilities except Special Facilities or Generating Facility shall not constitute any representation as to the economic or technical feasibility, operational capability, or 24

25 reliability of such facilities. Seller shall in no way represent to any third party that any such review by PG&E of such facilities including but not limited to any review of the design, construction, operation; or maintenance of such facilities by PG&E is a representation by PG&E as to the economic or technical feasibility, operational capability, or reliability of such facilities. Seller is solely responsible for economic and technical feasibility, operational capability, and reliability of Seller's Interconnection Facilities except Special Facilities and the Generating Facility. 9.2 PG&E shall notify Seller in writing of the outcome of PG&E's review of the design and all of the specifications, drawings, and explanatory material for Seller's Interconnection Facilities except Special Facilities (and the Generating Facility, if requested by PG&E) within thirty (30) calendar days of the receipt of the design and all of the specifications, drawings, and explanatory material for Seller's Interconnection Facilities (and the Generating Facility, if requested by PG&E). Any flaws in the design perceived by PG&E in the review of all of the specifications, drawings, and explanatory material for Seller's Interconnection Facilities (and the Generating Facility, if requested by PG&E) shall be described in PG&E's written notification. 25

26 10. REAL PROPERTY RIGHTS 10.1 Seller agrees to grant PG&E all necessary easements and rights of way, including adequate and continuing access rights, on property of Seller to transport, install, operate, maintain, replace, and remove the Interconnection Facilities, and any equipment or line extension that may be provided, owned, operated and maintained by PG&E on the property of Seller. Seller agrees to grant such easements and rights of way to PG&E at no cost and in a form satisfactory to PG&E and capable of being recorded in the office of the County Recorder. 10.2 If any part of PG&E's Interconnection Facilities, equipment, and/or line extension is to be installed on property owned by other than Seller, or under the jurisdiction or control of any other individual, agency or organization, PG&E may, at its discretion and at Seller's cost and expense obtain necessary easements and from the owners thereof all rights of way including adequate and continuing access rights, and/or such other grants, consents and licenses, in a form satisfactory to PG&E, fork the construction, operation, maintenance, and replacement of PG&E's Interconnection Facilities, equipment, and/or line extension upon such property. If PG&E does not elect to obtain or cannot obtain such easements and rights of way, Seller shall obtain them at its cost and expense. If Seller requests, PG&E shall cooperate with and assist 26

27 Seller in obtaining said easements and rights of way. In any event, Seller shall reimburse PG&E for all costs incurred by PG&E in obtaining, attempting to obtain or assisting in obtaining such easements and rights of way 10.3 PG&E shall have the right of ingress to and egress from the Generating Facility at all reasonable hours for any purposes reasonably connected with this Agreement or the exercise of any and all rights secured to PG&E by law or its tariff schedules and rules on file with the CPUC. 10.4 PG&E shall have no obligation to Seller for any loss, liability, damage, claim, cost, charge, or expense due to PG&E's inability to acquire a satisfactory right of way, easement or other real property interest necessary to PG&E's performance of its obligations under this Agreement. 10.5 If Seller exercises due diligence to obtain easements and rights of way for PG&E's Interconnection Facilities pursuant to Section 10.2, and if PG&E in its sole discretion elects not to exercise its power of eminent domain to acquire such easements and rights of way, Seller shall have no obligation to PG&E for any loss, liability, damage, claim, cost, charge or expense due to Seller's inability to acquire such easements and rights of way. 10.6 Nothing in this Section 10 shall be construed to require PG&E to acquire land rights through condemnation or any other means for Seller either inside or outside of PG&E's 27

28 service territory unless PG&E shall in its sole discretion elect to do so. 11. METERING 11.1 All meters and equipment used for the measurement of power for determining PG&E's payments to Seller pursuant to this Agreement shall be provided, owned, and maintained by PG&E at Seller's sole expense in accordance with PG&E's Electric Rule No. 21 attached hereto. 11.2 All the meters and equipment used for measuring the power delivered to PG&E shall be located on the side of the Interconnection Facilities transformer as selected by Seller in section 1.7. If Seller chooses to have meters placed on the low-voltage side of the Interconnection Facilities transformer, a transformer loss compensation factor will be applied. At Seller's sole expense, manufacturer's certified test reports of transformer losses, in accordance with current national standards, will be provided and used to determine a transformer loss compensation factor, unless another method for determination of transformer losses has been mutually agreed upon to determine the actual measured value of losses. 11.3 Pursuant to PG&E's Electric Rule No. 21, telemetering shall be required at Seller's expense if Seller's Generating Facility has a Nameplate Rating greater 28

29 than ten (10) MW. 11.4 PG&E's meters shall be sealed and the seals shall be broken only when the meters are to be inspected, tested, or adjusted by PG&E. Seller shall be given reasonable notice of testing and shall have the right to have a representative present on such occasions. 11.5 PG&E shall inspect and test all meters upon their installation and annually thereafter. At Seller's request and expense, PG&E shall inspect or test a meter more frequently. 11.6 Metering equipment determined by PG&E to be inaccurate or defective shall be repaired, adjusted, or replaced by PG&E such that the metering accuracy of said equipment shall be within two (2) percent. If a meter fails to register or if the measurement made by a meter during a test varies by more than two (2) percent from the metering standard used in the test, an adjustment shall be made correcting all measurements made by the inaccurate meter for (a) the actual period during which inaccurate measurements were made, if the period can be determined, or if not, (b) the period immediately preceding the test of the meter equal to one-half the time from the date of the last previous test of the meter, provided that the period covered by the correction shall not exceed six (6) months. 29

30 12. QUALIFYING FACILITY STATUS AND PERMITS 12.1 Seller warrants that, beginning on the date of initial energy deliveries and continuing until the end of this Agreement, the Generating Facility shall meet the qualifying facility requirements established as of the effective date of this Agreement by the Federal Energy Regulatory Commission's rules (18 Code of Federal Regulations Section 292) implementing the Public Utility Regulatory Policies Act of 1978 (16 U.S.C.A. Sections 796, et seq.). 12.2 Seller shall reimburse PG&E for any loss of whatever kind which PG&E incurs as a result of: (a) Seller's failure to obtain or maintain any necessary permit or approval, including completion of required environmental studies, necessary for the construction, operation, and maintenance of the Generating Facility. (b) Seller's failure to comply with necessary permits and approvals or with any applicable law. Seller's breach of that warranty in Section 12.1 above. 12.3 If a loss of qualifying facility status occurs due to a change in the law governing qualifying facility status occasioned by regulatory, legislative, or judicial action, the Seller shall compensate PG&E for any economic detriment incurred by PG&E should Seller choose not to 30

31 make the changes necessary to continue its qualifying facility status. 13. ENERGY PURCHASE 13.1 Subject to the terms and conditions of this Agreement, Seller shall sell and deliver, at the Point of Delivery, and PG&E shall purchase and accept delivery of, at the Point of Delivery, energy produced by the Generating Facility as specified in Sections 1.6 and 1.7. 13.2 PG&E shall pay Seller for energy at prices equal to PG&E's Short-Run Avoided Operating Costs. 13.3 Payment for energy shall be based on the time of delivery. The time periods currently in effect are shown in Appendix A. Time period definitions may change from time to time as determined by the CPUC. 13.4 PG&E has contracted to purchase the energy associated with the Generating Facility of the Nameplate Rating described in Section l.l(b) of this Agreement. If Seller installs a Generating Facility with a Nameplate Rating greater than that specified in Section 1.1(b) of this Agreement, PG&E shall not be required to accept or pay for energy associated with the incremental increase in Nameplate Rating under this Agreement. 13.5 Energy payments made to Seller pursuant to this Agreement will be multiplied by an energy loss adjustment factor, as approved by the CPUC. The currently applicable energy 31

32 loss adjustment factors are shown in Appendix B. 14. CAPACITY PURCHASE 14.1 Subject to the terms and conditions of this Agreement, Seller shall sell and deliver, at the Point of Delivery, and PG&E shall purchase and accept delivery of, at the Point of Delivery, As-Available Capacity produced by the Generating Facility, as specified in Sections 1.6 and 1.7. 14.2 PG&E shall pay Seller for As-Available Capacity at prices authorized from time to time by the CPUC and which are derived from PG&E's avoided costs as approved by the CPUC. 14.3 Payment for capacity shall be based on time of delivery. The time periods currently in effect are shown in Appendix A. Time period definitions may change from time to time as determined by the CPUC. 14.4 PG&E has contracted to purchase the As-Available Capacity associated with the Generating Facility of the Nameplate Rating described in Section 1.1(b) of this Agreement. If Seller installs a Generating Facility with a Nameplate Rating greater than that specified in Section 1.1(b) of this Agreement, PG&E shall not be required to accept or pay for As-Available Capacity associated with the incremental increase in Nameplate Rating under this Agreement. 14.5 As-Available Capacity payments made to Seller pursuant to this Agreement will be multiplied by a capacity loss 32

33 adjustment factor, as approved by the CPUC. The currently applicable capacity loss adjustment factors are shown in Appendix C. 15. CURTAILMENT 15.1 Hydro Spill (a) In anticipation of a period of hydro spill conditions, as defined by the CPUC, PG&E may notify Seller that any purchases of energy from Seller during such period shall be at hydro savings prices quoted by PG&E. If Seller delivers energy to PG&E during any such period, Seller shall be paid hydro savings prices for those deliveries in lieu of prices which would otherwise be applicable. The hydro savings prices shall be calculated by PG&E using the following formula: Hydro Savings Price = (AQF-S)/AQF X SOC (> 0 ) Where: AQF = energy for each time period, in kWh, projected to be available during hydro spill conditions from all qualifying facilities under agreements containing hydro savings price provisions; S = potential energy for each time period, in kWh, from PG&E hydro facilities which will be 33

34 spilled if all AQF is delivered to PG&E; and SOC = Short-Run Avoided Operating Cost (b) PG&E shall give Seller notice of general periods when hydro spill conditions are anticipated, and shall give Seller as much advance notice as practical of any specific hydro spill period and the hydra savings price which will be applicable during such period. 15.2 Negative Avoided Costs PG&E shall not be obligated to accept or pay for and may require Seller with a Generating Facility with a Nameplate Rating of one (1) megawatt or greater to interrupt or reduce deliveries of energy and As-Available Capacity during any period in which, due to operational circumstances, the acceptance of deliveries of power from Seller will result in PG&E system costs greater than those which PG&E would incur if it did not accept such deliveries, but instead generated an equivalent amount of energy itself; provided, however, that PG&E may not require Seller to interrupt or reduce deliveries of, or refuse to pay for energy and As-Available Capacity solely because PG&E's instantaneous avoided cost is lower than the applicable energy price to be paid Seller pursuant to this Agreement. As described in CPUC Decision No. 82-01-103 and Decision No. 82-04-071, and for illustrative purposes only, an example of such a period is a period when PG&E would be forced to shut down baseload or 34

35 intermediate load plants in order to accept deliveries from Seller and such baseload or intermediate load plants could not then be restarted and brought up to their rated output to meet the next day's peak load and PG&E would be required to utilize costly or less efficient generation with faster start-up or make an expensive emergency purchase of capacity to meet the demand that could have been met by the baseload or intermediate load plants but for such purchases from Seller, even if such purchases from Seller were at a price of zero (0). Whenever possible, PG&E shall give Seller reasonable notice of the possibility that interruption or reduction of deliveries may be required. 15.3 Before interrupting or reducing deliveries under Section 15.2, and before invoking hydro savings prices under Section 15.1, PG&E shall take reasonable steps to make economy sales of surplus energy giving rise to the condition. If such economy sales are made while the surplus energy condition exists, Seller shall be paid at the economy sales price obtained by PG&E in lieu of the otherwise applicable prices. 15.4 If Seller is under Operating Option I and Seller elects not to sell energy to PG&E at the hydro savings price pursuant to Section 15.1 or when PG&E curtails deliveries of energy pursuant to Section 15.2, Seller shall not use such energy to meet its electrical needs but shall 35

36 continue to purchase all its electrical needs from PG&E. If Seller is under Operating Option II, Sections 15.1 or 15.2 shall only apply to the excess Generating Facility output being delivered to PG&E, and Seller can continue use of that generation it has retained for Station Use and any other use by Seller. 16. INTERRUPTION OF DELIVERIES 16.1 PG&E shall not be obligated to accept or pay for and may require Seller to interrupt or reduce deliveries of capacity and energy (a) when necessary in order to construct, install, maintain, repair, replace, remove, investigate, or inspect any of its equipment or any part of its system; or (b) if it determines that interruption or reduction is necessary because of an Emergency, forced outage, Force Majeure, or compliance with Prudent Electrical Practices; provided that PG&E shall not interrupt deliveries pursuant to this Section solely in order to take advantage, or make purchases, of less expensive energy elsewhere. 16.2 Notwithstanding any other provisions of this Agreement, if at any time PG&E determines that, (a) continued parallel operation of the Generating Facility may endanger PG&E personnel, (b) continued parallel operation of the Generating Facility may endanger the PG&E Electric System Integrity, or (c) Seller's Protective Apparatus is not 36

37 fully in service, PG&E shall have the right to disconnect the Generating Facility from PG&E's system. The Generating Facility shall remain disconnected until such time as PG&E is satisfied that the condition(s) referenced in this Section 16 have been corrected. 16.3 Whenever possible, PG&E shall give Seller reasonable notice of the possibility that interruption or reduction of deliveries may be required. 17. PAYMENT AND BILLING 17.1 PG&E shall mail to Seller not later than thirty (30) calendar days after the end of each monthly billing period (a) a statement showing the energy and capacity delivered to PG&E during on-peak, partial-peak, off-peak, and super-off-peak periods during the monthly billing period, (b) PG&E's computation of the amount due Seller, and (c) PG&E's check in payment of said amount. 17.2 PG&E reserves the right to provide Seller's statement concurrently with any bill to Seller for electric service provided by PG&E to Seller at the location specified in Section 1.1(c) or any bill to Seller for any charges under this Agreement owing and unpaid by Seller and to apply the value of PG&E's purchase of energy and capacity toward such bill(s). Seller shall pay any amount owing for electric service provided by PG&E to Seller in 37

38 accordance with applicable tariff schedules. Nothing in this Section 17.2 shall limit PG&E's rights under applicable tariff schedules. 17.3 In the event adjustments to payments are required as a result of inaccurate meters, PG&E shall use the corrected measurements described in Section 11.6 to recompute the amount due from PG&E to Seller for the capacity and energy delivered under this Agreement during the period of inaccuracy. Any refund due and payable to PG&E resulting from inaccurate metering shall be made within thirty (30) calendar days of written notification to Seller by PG&E of the amount due. Any additional payment to Seller resulting from inaccurate metering shall be made within thirty (30) calendar days of PG&E's recomputation of the amount due from PG&E to Seller. 17.4 Monthly charges associated with Interconnection Facilities shall be billed pursuant to the agreement for Special Facilities and applicable tariffs. 18. INDEMNITY AND LIABILITY 18.1 Each Party as indemnitor shall defend, save harmless and indemnify the other Party and the directors, officers, employees, and agents of such Party against and from any and all loss, liability, damage, claim, cost, charge, demand, or expense (including any direct, indirect, or consequential loss, liability, damage, claim, cost, 38

39 charge, demand, or expense, including attorneys' fees) for injury or death to persons, including employees of either Party, and damage to property including property of either Party arising out of or in connection with (a) the engineering, design, construction, maintenance, repair, operation, supervision, inspection, testing, protection or ownership of, or (b) the making of replacements, additions, betterments to, or reconstruction of, the indemnitor's facilities; provided, however, Seller's duty to indemnify PG&E hereunder shall not extend to loss, liability, damage, claim, cost, charge, demand, or expense resulting from interruptions in electrical service to PG&E's customers other than Seller or electric customers of Seller. This indemnity shall apply notwithstanding the active or passive negligence of the indemnitee. However, neither Party shall be indemnified hereunder for its loss, liability, damage, claim, cost, charge, demand or expense resulting from its sole negligence or willful misconduct. 18.2 Notwithstanding the indemnity of Section 18.1 and except for a Party's willful misconduct or sole negligence, each Party shall be responsible for damage to its facilities resulting from electrical disturbances or faults. 18.3 Seller releases and shall defend, save harmless and indemnify PG&E from any and all loss, liability, damage, claim, cost, charge, demand or expense arising out of or 39

40 in connection with any representation made by Seller inconsistent with Section 9.1. 18.4 The provisions of this Section 18 shall not be construed to relieve any insurer of its obligations to pay any insurance claims in accordance with the provisions of any valid insurance policy. 18.5 Except as otherwise provided in Section 18.1, neither Party shall be liable to the other Party for consequential damages incurred by that Party. 18.6 If Seller fails to comply with the provisions of Section 19, Seller shall, at its own cost, defend, save harmless and indemnify PG&E, its directors, officers, employees, and agents, assignees, and successors in interest from and against any and all loss, liability, damage, claim, cost, charge, demand, or expense of any kind or nature (including any direct, indirect, or consequential loss, damage, claim, cost, charge, demand, or expense, including attorneys' fees and other costs of litigation), resulting from injury or death to any person or damage to any property, including the personnel or property of PG&E, to the extent that PG&E would have been protected had Seller complied with all of the provisions of Section 19. The inclusion of this Section 18.6 is not intended to create any express or implied right in Seller to elect not to provide the insurance required under Section 19. 40

41 19. INSURANCE 19.1 In connection with the Generating Facility, associated land, land rights, and interests in land, and with Seller's performance of and obligations under this Agreement, Seller shall maintain, during the term of the Agreement, General Liability Insurance with a combined single limit of not less than: (a) one million dollars ($1,000,000) for each occurrence if the Generating Facility is over one hundred (100) kW; (b) five hundred thousand dollars ($500,000) for each occurrence if the Generating Facility is over twenty (20) kW and less than or equal to one hundred (100) kW; and (c) one hundred thousand dollars ($100,000) for each occurrence if the Generating Facility is twenty (20) kW or less. Such General Liability Insurance shall include coverage for Premises-Operations, Owners and Contractors Protective, Products/Completed Operations Hazard, Explosion, Collapse, Underground, Contractual Liability, and Broad Form Property Damage including Completed Operations. 19.2 The General Liability Insurance required in section 19.1 shall, by endorsement to the policy or policies, (a) include PG&E as an additional insured; (b) contain a severability of interest clause or cross-liability clause; (c) provide that PG&E shall not by reason of its inclusion as an additional insured incur liability to the insurance carrier for payment of premium for such insurance; and (d) 41

42 provide for thirty (30) calendar days written notice to PG&E prior to cancellation, termination, alternation, or material change of such insurance. 19.3 If the requirement of Section 19.2(a) prevents Seller from obtaining the insurance required in Section 19.1, then upon written notification by Seller to PG&E, Section 19.2(a) shall be waived. 19.4 Evidence of the insurance required in Section 19.1 shall state that coverage provided is primary and is not in excess to or contributing with any insurance or self-insurance maintained by PG&E. 19.5 PG&E shall have the right to inspect or obtain a copy of the original policy or policies of insurance. 19.6 Seller shall furnish the required certificates and endorsements to PG&E prior to Initial Operation. 19.7 A Seller who is a self-insured governmental agency with an established record of self-insurance may comply with the following in lieu of Sections 19.1 through 19.6: (a) Seller shall provide to PG&E at least thirty (30) calendar days prior to the date of Initial Operation evidence of an acceptable plan to self-insure to a level of coverage equivalent to that required under Section 19.1. (b) If Seller ceases to self-insure to the level required hereunder, or if the Seller is unable to provide continuing evidence of Seller's ability to self 42

43 insure, Seller shall immediately obtain the coverage required under Section 19.1. 19.8 All insurance certificates, statements of self insurance, endorsements, cancellations, terminations, alterations, and material changes of such insurance shall be issued and submitted to the following: Pacific Gas and Electric Company Manager - Power Contracts 77 Beale Street, Mail Code: B23C P.O. Box 770000 San Francisco, CA 94177 20. FORCE MAJEURE 20.1 If either Party because of Force Majeure is unable to perform its obligations under this Agreement, that Party shall be excused from whatever performance is affected by the Force Majeure to the extent so affected, except as to obligations to pay money, provided that: (a) The non-performing Party, within two weeks after the commencement of the Force Majeure, gives the other Party written notice describing the particulars of the occurrence. (b) The suspension of performance is of no greater scope and of no longer duration than is required by the Force Majeure. (c) The non-performing Party uses its best efforts to remedy its inability to perform. 20.2 When the non-performing Party is able to resume 43

44 performance of its obligations under this Agreement, that Party shall give the other Party written notice to that effect. 20.3 This Section 20 shall not require the settlement of any strike, walkout, lockout or other labor dispute on terms which, in the sole judgment of the Party involved in the dispute, are contrary to its interest. It is understood and agreed that the settlement of strikes, walkouts, lockouts or other labor disputes shall be at the sole discretion of the Party having the difficulty. 20.4 In the event a Party is unable to perform due to legislative, judicial, or regulatory agency action, this Agreement shall be renegotiated to comply with the legal change which caused the non-performance. // // // 21. REVIEW OF RECORDS AND DATA Each Party, after giving written notice to the other Party, shall have the right to review and obtain copies of metering records and operations and maintenance logs of the Generating Facility. 44

45 22. ASSIGNMENT Neither Party shall voluntarily assign its rights nor delegate its duties under this Agreement without the written consent of the other Party, except in connection with the sale or merger of a substantial portion of its properties. Any such assignment or delegation made without such written consent shall be null and void. Consent for assignment shall not be withheld unreasonably. 23. ABANDONMENT 23.1 If, in any six (6) month period, Seller fails to deliver to PG&E at least the number of kilowatt-hours derived from the product of four-hundred and thirty-eight (438) hours times the Nameplate Rating, less any capacity dedicated other use as specified in Sections 1.6 and 1.10, times the appropriate effective capacity conversion factor listed in Appendix G. Seller shall provide to PG&E all of the following: (a) a written description of the reasons for Seller's low level of performance; (b) a summary of the action Seller is taking to improve its performance; and (c) a schedule for increasing seller's deliveries. 23.2 In any fifteen (15) month period, Seller shall deliver to PG&E not less than the number of kilowatt hours derived 45

46 from the product of one thousand and ninety-five (1,095) hours times the Nameplate Rating (less any capacity dedicated to other use as specified in sections 1.6 and l.l0) times the appropriate effective capacity conversion factor listed in Appendix G. If for any reason, Seller fails to deliver this minimum amount, PG&E may terminate this Agreement on written notice. 24. NON-DEDICATION No undertaking by one Party to the other under any provision of this Agreement shall constitute the dedication of that Party's system or any portion thereof to the other Party or to the public or affect the status of PG&E as an independent public utility corporation or Seller as an independent individual or entity and not a public utility. 25. NON-WAIVER None of the provisions of the Agreement shall be considered waived by either Party except when such waiver is given in writing. The failure of any Party at any time or times to enforce any right or obligation with respect to any matter arising in connection with this Agreement shall not constitute a waiver as to future enforcement of that right or obligation or any right or obligation of this Agreement. 46

47 26. SECTION HEADINGS Section headings appearing in this Agreement are inserted for convenience only and shall not be construed as interpretations of text. 27. GOVERNING LAW This Agreement shall be interpreted, governed, and construed under the laws of the State of California as if executed and to be performed wholly within the State of California. 28. AMENDMENT, MODIFICATION OR WAIVER Any amendments or modifications to this Agreement shall be in writing and agreed to by both Parties. The failure of any Party at any time or times to require performance of any provision hereof shall in no manner affect the right at a later time to enforce the same. No waiver by any Party of the breach of any term or covenant contained in this Agreement, whether by conduct or otherwise, shall be deemed to be construed as a further or continuing waiver of any such breach or a waiver of the breach of any other term or covenant unless such waiver is in writing. 29. SEVERAL OBLIGATIONS Except where specifically stated in this Agreement to be otherwise, the duties, obligations, and liabilities of the 47

48 Parties are intended to be several and not joint or collective. Nothing contained in this Agreement shall be construed to create an association, trust, partnership, or joint venture or impose a trust or partnership duty, obligation, or liability on or with regard to either Party. Each Party shall be liable individually and severally for its own obligations under this Agreement. 30. SIGNATURES IN WITNESS WHEREOF, the Parties hereto have caused two originals of this Agreement to be executed by their duly authorized representatives. This Agreement is effective as of January 16. 1997. BERRY PETROLEUM COMPANY By Jerry V. Hoffman Title President and Chief Executive Officer January 21, 1997 PACIFIC GAS AND ELECTRIC COMPANY By E. J. Malias Title Vice President and General Manager February 4, 1997 48

APPENDIX A1 TABLE Al - TIME PERIODS Monday Saturdays, Through Sundays, Friday2 and Holidays Seasonal Period A (May 1 - October 31) Peak Noon None to 6:00 p.m. Partial-Peak 8:30 a.m. None to noon 6:00 p.m. to 9:30 p.m. Off-Peak 9:30 p.m. to 1:00 a.m. 5:00 a.m. 5:00 a.m. to to 8:30 a.m. 1:00 a.m. Super Off-Peak 1:00 a.m. 1:00 a.m. to to 5:00 a.m. 5:00 a.m. Seasonal Period B (November 1 - April 30) Partial Peak 8:30 a.m. None to 9:30 p.m. Off-Peak 9:30 p.m. to 1:00 a.m. 5:00 a.m. 5:00 a.m. to to 8:30 a.m. 1:00 a.m. Super Off-Peak 1:00 a.m. 1:00 a.m. to to 5:00 a.m. 5:00 a.m. This table is subject to change to accord with the peak, partial-peak, off-peak, and super off-peak periods as defined by CPUC decision. Except for the following holidays: New Years Day, Washington's Birthday, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day, as specified in Public Law 90-363 (5 U.S.C.A. Section 6103(a)). A-1

APPENDIX B Table B Energy Loss Adjustment Factors (1) Primary Secondary Transmission Distribution Distribution Seasonal Period A (May 1 through October 31) On-Peak 1.0 1.0 1.0148 Partial-Peak 1.0 1.0 1.0131 Off-Peak 1.0 1.0 1.0093 Super Off-Peak 1.0 1.0 1.0093 Seasonal Period B (November 1 through April 30) On-Peak N/A N/A N/A Partial-Peak 1.0 1.0 1.0119 Off-Peak 1.0 1.0 1.0087 Super Off-Peak 1.0 1.0 1.0087 1. The applicable energy loss adjustment factors may be revised pursuant to orders of the CPUC . B-1

APPENDIX C Table C Capacity Loss Adjustment Factors For Non-Remote Facilities Voltage Level Loss Adjustment Factor Transmission 0.989 Primary Distribution 0.991 Secondary Distribution 0.991 If the Generating Facility is remote, the capacity loss adjustment factor is: (2) 1) The capacity loss adjustment factor non-remote Generating Facilities are subject to change pursuant to orders of the CPUC. 2) The capacity loss adjustment factors for remote Generating Facilities are determined individually. C - 1

APPENDIX D APPENDIX D PACIFIC GAS AND ELECTRIC COMPANY'S ELECTRIC RULE 21

D1 Pacific Gas and Electric Company San Francisco, Califomia Revised Cal. P.U.C. Sheet No. 11410-E Cancelling Revised Cal. P.U.C. Sheet No. 9737-E RULE 21--NONUTILITY-OWNED PARALLEL GENERATION This describes the minimum operation, metering and interconnection requirements for any generating source or sources paralleled with PG&E's electric system. Such source or sources may include, but are not limited to, hydroelectric generators, wind-turbine generators, steam or gas-driven turbine generators and photovoltaic systems. A. GENERAL 1. The type of interconnection and voltage available at any location and PG&E's specific interconnection requirements shall be determined by inquiry at PG&E's local office. 2. The Power Producer (Producer) will normally connect to PG&E's facilities at or above the minimum nominal voltage indicated in the table below. Net Generator Output Minimum Nominal Voltage (MVA) (kv) 0 to less than 12 None 12 to less than 30 60, 70 30 to less than 90 115 90 to less than 250 230 greater than 250 To be determined on a case-by-case basis PG&E shall determine where the Producer may connect to its system. Any deviation from this table shall be at the sole discretion of PG&E. 3. The Producer shall ascertain and be responsible for compliance with the requirements of all governmental authorities having jurisdiction.

D2 RULE 21- NONUTILITY-OWNED PARALLEL GENERATION (Continued) Advice letter No. 1310-E Decision No. Issued by Gordon R. Smith/ Vice President and Chief Financial Officer Date Filed July 31, 1990 Effective September 9, 1990 Resolution No. 9/15/95

B2 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) GENERAL (Cont'd.) 4. The Producer shall sign PG&E's written form of power purchase agreement or parallel operation agreement and a "Standard Operating Agreement for Facilities 40 kw and Larger" before connecting or operating a generating source in parallel with PG&E's system. 5. The Producer shall be fully responsible for the costs of designing, installing, owning, operating and maintaining all interconnection facilities defined in Section B.1. 6. The Producer shall submit to PG&E, for PG&E's review and written acceptance, equipment specifications and detailed plans for the installation of all interconnection facilities to be furnished by the Producer prior to their purchase or installation. PG&E's review and written acceptance of the Producer's equipment specifications and detailed plans shall not be construed as confirming or endorsing the Producer's design or as warranting the equipment's safety, durability or reliability. PG&E shall not, by reason of such review or lack of review, be responsible for strength, details of design adequacy, or capacity of equipment built pursuant to such specifications, nor shall PG&E's acceptance be deemed an endorsement of any such equipment. 7. No generating source shall be operated in parallel with PG&E's system until the interconnection facilities have been inspected by PG&E and PG&E has provided written approval to the Producer. 8. Only duly authorized employees of PG&E are allowed to connect Producer-installed interconnection facilities to, or disconnect the same from, PG&E's facilities. (Continued)

B3 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) B. INTERCONNECTION FACILITIES 1. GENERAL Interconnection facilities are all means required, and apparatus installed, to interconnect the Producer's generation with PG&E's system. Where the Producer desires to sell power to PG&E, interconnection facilities are also all means required, and apparatus installed, to enable PG&E to receive power deliveries from the Producer. Interconnection facilities may include, but are not limited to: a. connection, transformation, switching, metering, communications, control, protective and safety equipment; and b. any necessary additions to and reinforcements of PG&E's system by PG&E. Interconnection facilities shall be categorized as either: 1) Producer-Specific Facilities -- those interconnection facilities that have a direct benefit only to the Producer(s). 2) Multipurpose Facilities -- those interconnection facilities that have a direct benefit to PG&E's system as well as the Producer(s). 2. CONTROL, PROTECTION AND SAFETY EQUIPMENT a. GENERAL: PG&E has established functional requirements essential for safe and reliable parallel operation of the Producer's generation. These requirements provide for control, protective and safety equipment to:

B4 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) INTERCONNECTION FACILITIES (Cont'd.) CONTROL, PROTECTION AND SAFETY EQUIPMENT (Cont'd.) a. GENERAL (Cont'd.) 1) sense and properly react to failure and malfunction on PG&E's system; 2) assist PG&E in maintaining its system integrity and reliability; and 3) protect the safety of the public and PG&E's personnel. b. Listed below are the various devices and features generally required by PG&E as a prerequisite to parallel operation of the Producer's generation:

B5 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) B. INTERCONNECTION FACILITIES (Cont'd.) 2. CONTROL, PROTECTION AND SAFETY EQUIPMENT (Cont'd.) b. (Cont'd.) GENERATOR SIZE Device 10 kW or 11 kW to 41 kW to 101 kW to 401 kW to Over or Feature Less 40 kw 100 kW 400 kW 1.000 kW 1.000kW Dedicated - X X X X X Transformer2 Interconnection X X X X X X Disconnect Device Generator X X X X X X Circuit Breaker Over-voltage X X X X X X Protection Under-voltage - - X X X X Protection Under/Over X X X X X X Frequency Protection Ground Fault - - X X X X Protection Over-current - - - - X X Relay w/Voltage Restraint Synchro- nizing3 Manual Manual Manual Manual Manual Automatic Power Factor - - X X X X or Voltage Regulation Equipment Fault X X X Interrupting Device 4 1. Detailed requirements are specified in PG&E's current operating, metering and equipment protection publications, as revised from time to time by PG&E and available to the Producer upon request. For a particular generator application, PG&E will furnish its specific control, protective and safety requirements to the Producer after the exact location of the generator has been agreed upon and the interconnection voltage level has been established. (Continued)

B6 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) INTERCONNECTION FACILITIES (Cont'd.) CONTROL, PROTECTION AND SAFETY EQUIPMENT (Cont'd.) b. (Cont'd.) 2. This is a transformer interconnected with no other Producers and serving no other Utility customers. Although the dedicated transformer is not a requirement for generators rated 10 kW or less, its installation is recommended by PG&E. 3. This is a requirement for synchronous and other types of generators with stand-alone capability. For all such generators, PG&E will also require the installation of "reclose blocking" features on its system to block certain operations of PG&E's automatic line restoration equipment. 4. To be installed by the Producer at the point where his ownership changes with PG&E. (Continued)

B7 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) B. INTERCONNECTION FACILITIES (Cont'd.) 2. CONTROL, PROTECTION AND SAFETY EQUIPMENT (Cont'd.) c. DISCONNECT DEVICE The Producer shall provide, install, own and maintain the interconnection disconnect device required by Section B.2.b at a location readily accessible to PG&E. Such device shall normally be located near PG&E's meter or meters for sole operation by PG&E. The interconnection disconnect device and its precise location shall be specified by PG&E. At the Producer's option and request, PG&E will provide, install, own and maintain the disconnect device on PG&E's system as special facilities in accordance with Section F. 3. METERING a. A Producer desiring to sell power to PG&E shall provide, install, own and maintain all facilities necessary to accommodate metering equipment specified by PG&E. Such metering equipment may include meters, telemetering (applicable where deliveries to the utility exceed 10 mw) and other recording and data to PG&E. Except as provided for in Section B.3.b following, PG&E shall provide, install, own and maintain all metering equipment as special facilities in accordance with Section F. b. The Producer may at its option provide, install, own and maintain current and potential transformers rated above 600 volts and a non-revenue type graphic recorded where applicable. Such metering equipment, its installation and maintenance shall all be in conformance with PG&E's specifications. (Continued)

B8 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) INTERCONNECTION FACILITIES (Cont'd.) METERING (Cont'd.) c. If the nameplate rating of the Producer's generating facility is greater than one (1) megawatt, PG&E may require Producer to measure and register, on a graphic recording device, power in kw and voltage in kv at a location within the generating facility agreed to by both parties. d. PG&E's meters shall be equipped with detents to prevent reverse registration so that power deliveries to and from the Producer's equipment can be separately recorded. 4. UTILITY SYSTEM ADDITIONS AND REINFORCEMENTS a. Except as provided for in Section B.5, all additions to and reinforcements of PG&E's system necessary to interconnect with and receive power deliveries from the Producer's generation will be provided, installed, owned and maintained by PG&E. All prudent and reasonable costs of multipurpose facilities are the responsibility of PG&E. Costs of all producer-specific facilities and costs of those multipurpose facilities which are not deemed prudent and reasonable are the responsibility of the Producer(s) and will be billed as special facilities in accordance with Section F. b. The Producer shall advance to PG&E its estimated costs of performing a preliminary or detailed engineering study as may be reasonably required to identify and Producer-Related Utility system additions and reinforcements. Where the Producer has requested a detailed study, PG&E will complete its study within 120 days of receiving all necessary plans, specifications and fees from the Producer. (Continued)

B9 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) B. INTERCONNECTION FACILITIES (Contid.) 5. PRODUCER-INSTALLED UTILITY-OWNED LINE EXTENSIONS The Producer may at its option employ a qualified contractor/subcontractor (as defined in Rule 1) to provide and install an extension of PG&E's distribution or transmission lines where required to complete the Producer's interconnection with PG&E. Such extension shall be installed in accordance with PG&E's design and specifications. The Producer shall pay PG&E PG&E's estimated costs of design, administration compliance with PG&E's requirements. Upon final inspection and acceptance by PG&E, the Producer shall transfer ownership of the line extension and it shall be owned and maintained as special facilities in accordance with Section F. This provision does not preclude the Producer from installing owning and maintaining a distribution or transmission line extension as part of its other Producer-owned interconnection facilities. 6. COSTS OF FUTURE UTILITY SYSTEM ALTERATIONS The Producer shall be responsible for the costs of only those future Utility system alterations which are directly related to the Producer's presence or necessary to maintain the Producer's interconnection in accordance with PG&E's applicable operating, metering and equipment publication in effect when the Producer and PG&E entered into a written form of power purchase agreement. Such alterations may include, but are not limited to, relocation or undergrounding of PG&E's distribution or transmission facilities as may be ordered by a governmental authority having jurisdiction. Alterations made at the Producer's expense shall specifically exclude increase of existing line capacity necessary to accommodate other Producers or PG&E customers. (Continued)

B10 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) INTERCONNECTION FACILITIES (Cont'd.) ALLOCATION OF PG&E'S EXISTING LINE CAPACITY a. Producers seeking access to limited transmission and/or distribution line capacity for power deliveries shall establish and maintain an interconnection priority in accordance with the Qualifying Facilities Milestone Procedure (QFMP) as adopted in Commission Decision No. 85-01-038 in OII 84-04-077 and as modified in subsequent decisions. Such priority will be site- and project-specific and may not be transferred to other projects or locations. Failure to meet any QFMP milestone may result in termination of the power purchase agreement and loss of interconnection priority. b. The following Producers shall be exempt-from-QFMP-compliance (1) projects of less than 100 kW design capacity; (2) projects using all power internally; (3) projects with a special facilities agreement executed prior to January 16, 1985; (4) Producers that sign final Standard Offer 4 contracts; and (a) Producers that sign Uniform Standard Offer 1. c. For a Producer that (1) is not subject to the QFMP, and that (2) signs a final Standard Offer 4, entitlement to available capacity on PG&E's transmission/distribution system and a priority to such line capacity is established as of the date that the Producer's bid is determined to be a winner. The Producer thereafter retains its priority so long as it does not default in performance of its agreement. d. Producers that sign Uniform Standard Offer 1 establish priority for access to available capacity on PG&E's transmission/distribution system as of the date the Producer pays the project fee and provides information for and pays the cost of the Preliminary Interconnection Study or the Interconnection Study in accordance with its power purchase agreement. (Continued)

B11 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) C. ELECTRIC SERVICE FROM PG&E If the Producer requires regular, supplemental, interruptible or standby service from PG&E, the Producer shall enter into separate contractual arrangements with PG&E in accordance with PG&E's applicable electric tariffs on file with and authorized by the Public Utilities Commission. D. OPERATION 1. PREPARALLEL INSPECTION In accordance with Section A.7, PG&E will inspect the Producer's interconnection facilities prior to providing it with written authorization to commence parallel operation. Such inspection shall determine whether or not the Producer has installed certain control, protective and safety equipment to PG&E's specifications. Where the Producer's generation has a rated output in excess of 100 kW, the Producer shall pay PG&E its estimated costs of performing the inspection. 2. JURISDICTION OF PG&E'S SYSTEM DISPATCHER The Producer's generation while operating in parallel with PG&E's system is at all times under the jurisdiction of PG&E's system dispatcher. The system dispatcher shall normally delegate such control to PG&E's designated switching center. 3. COMMUNICATIONS The Producer shall maintain telephone service from the local telephone company to the location of the Producer's generation. In the event such location is remote or unattended, telephone service shall be provided to the nearest building normally occupied by the Producer's generator operator. PG&E and the Producer shall maintain operating communications through PG&E's designated switching center. (Continued)

B12 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION D. OPERATION (Cont'd.) 4. GENERATOR LOG The Producer shall at all times keep and maintain a detailed generator operations log. Such log shall include, but not be limited to, information on unit availability, maintenance usages, circuit breaker trip operations requiring manual reset and unusual events. PG&E shall have the right to revise the producer's log. 5. REPORTING ABNORMAL CONDITIONS PG&E shall advise the Producer of abnormal conditions which PG&E has reason to believe could affect PG&E's operating conditions or procedures. The Producer shall keep PG&E similarly informed. 6. POWER FACTOR The Producer shall furnish reactive power as may be reasonably required by PG&E. a. PG&E will specify that generators with power factor control capability, including synchronous generators, be capable of operating continuously at any power factor between 95 percent leading (absorbing vars) and 90 percent lagging (producing vars) at any voltage level within +- 5.0 percent of rated voltage. For other types of generators with no inherent power factor control capability, PG&E reserves the right to specify the installation of capacitors by the Producer to correct generator output to near 95 percent leading power factor. PG&E may also require the installation of switched capacitors on its system to produce the amount of reactive support equivalent to that provided by operating a synchronous generator of the same size. 1) Detailed requirements are specified in PG&E's current operating, metering equipment protection publications, as revised from time to time by PG&E and available to the Producer upon request. For a particular generator application, PG&E will furnish its specific control, protective and safety requirements to the Producer after the exact location of the generator has been agreed upon and the interconnection voltage level has been established. (Continued)

B13 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) D. OPERATION (Cont'd.) 6. POWER FACTOR (Cont'd.) b. Where either the Producer or PG&E determines that it is not practical for the Producer to furnish PG&E's required level of reactive power or when PG&E specifies switched capacitors in its system pursuant to Section D.6.a, PG&E will provide, install, own and maintain the necessary devices on its system in accordance with Section F. E. INTERFERENCE WITH SERVICE AND COMMUNICATION FACILITIES 1. GENERAL PG&E reserves the right to refuse to connect to any new equipment or to remain connected to any existing equipment of a size or character that may be detrimental to PG&E's operations or service to its customers. 2. The Producer shall not operate equipment that superimposes upon PG&E's system a voltage or current which causes interference with PG&E's operations, service to PG&E's customers or interference to communication facilities. If the Producer causes service interference to others, the Producer must diligently pursue and take corrective action at the Producer's expense after being given notice and reasonable time to do so by PG&E. If the Producer does not take timely corrective action, or continues to operate the equipment causing the interference without restriction or limit, PG&E may, without liability, disconnect the Producer's equipment from PG&E's system until a suitable permanent solution provided by the Producer is operational at the Producer's expense. (Continued)

B14 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) F. SPECIAL FACILITIES 1. Where the Producer requests PG&E to furnish interconnection facilities or where it is necessary to make additions to or reinforcements of PG&E's system and PG&E agrees to do so, such facilities shall be deemed to be special facilities and the costs thereof shall be borne by the Producer, in accordance with Section B.4.a and B.4.b, including such continuing ownership costs as may be applicable. 2. Special facilities are: (a) those facilities installed at the Producer's request which PG&E does not normally furnish under its tariff schedule, or (b) a prorata portion of existing facilities requested by the Producer, allocated for the sole use of such Producer, which would not normally be allocated for such sole use. Unless otherwise provided by PG&E's filed tariff schedules, special facilities will be installed, owned and maintained or allocated by PG&E as an accommodation to the Producer only if acceptable for operation by PG&E and the reliability of service to PG&E's customers is not impaired. 3. Special Facilities will be furnished under the terms and conditions of PG&E's "Agreement for Installation or Allocation of Special Facilities for Parallel Operation of Nonutility-owned Generation and/or Electrical Standby Service" (Form 79-280), and its Appendix A, "Detail of Special Facilities Charges" (Form 79-702). Prior to the Producer signing such an agreement, PG&E shall provide the Producer with a breakdown of special facilities costs in a form having detail sufficient for the information to be reasonably understood by the Producer. The special facilities agreement will include, but is not limited to, a binding quotation of charges to the Producer and the following general terms and conditions: (Continued)

B15 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) F. SPECIAL FACILITIES (Cont'd.) 3. (Cont'd.) a. Where facilities are installed by PG&E for the Producer's use as special facilities, the Producer shall advance to PG&E its estimated installed cost of the special facilities. The amount advanced is subject to the monthly ownership charge applicable to customer-financed special facilities as set forth in Section 1 of PG&E's Rule 2. b. At the Producer's option, and where such Producer's generation is a qualifying facility and the Producer has established credit worthiness to PG&E's satisfaction, PG&E shall finance those special facilities it deems to be removable and reusable equipment. Such equipment shall include, but not be limited to, transformation, disconnection and metering equipment. c. Existing facilities allocated for the Producer's use as special facilities and removable and reusable equipment financed by PG&E in accordance with Section F.3.b are subject to the monthly ownership charge applicable to Utility-financed special facilities as set forth in Section 1 of Rule 2. d. Where the Producer elects to install and deed to PG&E an extension of PG&E's distribution or transmission lines for use as special facilities in accordance with Section B.5, PG&E's estimate of the installed cost of such extension shall be subject to the monthly ownership charge applicable to customer-financed special facilities as set forth in Section 1 of Rule 2. 1) A qualifying facility is one which meets the requirements established by the Federal Energy Regulatory Commission's rules (18 Code of Federal Regulations 292) implementing the Public Utility Regulatory Policies Act of 1978 (16 U.S.C.A. 796, et seq.). (Continued)

B16 RULE 21--NONUTILITY-OWNED PARALLEL GENERATION (Continued) F. SPECIAL FACILITIES (Cont'd.) 4. Where payment or collection of continuing monthly ownership charges is not practicable, the Producer shall be required to make an equivalent one-time payment in lieu of such monthly charges. 5. Costs of special facilities borne by the Producer may be subject to downward adjustment when such special facilities are used to furnish permanent service to a customer of PG&E. This adjustment will be based upon the extension allowance or other such customer allowance which PG&E would have utilized under its then applicable tariffs if the special facilities did not otherwise exist. In no event shall such adjustment exceed the original installed cost of that portion of the special facilities used to serve a new customer. An adjustment, where applicable, will consist of a refund applied to the Producer's initial payment for special facilities and/or a corresponding reduction of the ownership charge. G. EXCEPTIONAL CASES Where the application of this rule appears impractical or unjust, either PG&E or the Producer may refer the matter to the Public Utilities Commission for special rulings. The test for approving variations from this rule will be proof of indifference to PG&E's ratepayers. The burden of proof will fall to the party requesting the variance. H. INCORPORATION INTO POWER PURCHASE AGREEMENTS Pursuant to Decision No. 83-10-093, if in accordance with Section A.4 the Producer enters into a written form of power purchase agreement with Utility, a copy of the Rule 21 in effect on the date of execution will be appended to, and incorporated by reference into, such power purchase agreement. The rule appended to such power purchase agreement shall then be applicable for the term of the Producer's power purchase agreement with PG&E. Subsequent revisions to this rule will not be incorporated into the rule appended to such power purchase agreement.

APPENDIX E APPENDIX E [OMITTED]

APPENDIX F APPENDIX F SITE LOCATION METES AND BOUNDS DESCRIPTION (including fax transmittal cover sheet from Berry Petroleum) BERRY PETROLEUM COMPANY Corporate Development (805)769-8000 Number Of Pages (including this cover): January 14, 1997 8:00 AM (PST) Pacific Gas and Electric Company Attn.: Tom Bantz, Power Contracts (415) 973 9012 fax (415) 973-5601-voice Mike Starzer Vice President, Corporate Development

F2 SITE LOCATION METES AND BOUNDS DESCRIPTION "All that portion of Section 28, T.12N., R.24W., S.B.B.&M, in the County of Kern, State of California, more particularly described as follows: "Commencing at the S.W. corner of Section 31, T.32S., R.24E., M.D.B.&M.: thence S 89 degrees 12' 37" E, 497.89 feet; thence N 83 degrees 47' 58" E, 173.34 feet; thence S 89 degrees 07' 14" E, 20.00 feet; thence N 00 degrees 52' 46" E, 10.00 feet to the true point of beginning; thence N 86 degrees 52' 46" E, 330.00 feet; thence S 15 degrees 55' 30" W. 189.52 feet; thence N 89 degrees 07' 14" W. 280.00 feet; thence N 00 degrees 52' 46" E, 160.00 feet to the true point of beginning and containing 1.19 acres. " P. 02

APPENDIX G TABLE G Effective Capacity Conversion Factors Technology Conversion Factors Biomass 0.40 Cogeneration 0.40 Geothermal 0.25 Hydroelectric 0.29 Solar 0.24 Wind 0.15 G-1

APPENDIX H APPENDIX H POINT OF DELIVERY SKETCH (NOT REPRODUCED)

211 THIS WARRANT AND THE SECURITIES ISSUABLE UPON THE EXERCISE HEREOF HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE "SECURITIES ACT"), IN RELIANCE UPON EXEMPTIONS CONTAINED IN SECTION 4(2) OF THE SECURITIES ACT AND REGULATION D PROMULGATED PURSUANT THERETO, NOR HAVE THE SECURITIES BEEN QUALIFIED IN ANY STATE IN RELIANCE UPON EXEMPTIONS FROM QUALIFICATION UNDER APPLICABLE STATE SECURITIES LAWS. ACCORDINGLY, THE SECURITIES RECEIVED HEREBY MAY NOT BE RESOLD OR TRANSFERRED BY A SHAREHOLDER UNLESS THEY ARE SUBSEQUENTLY REGISTERED UNDER FEDERAL AND APPLICABLE STATE SECURITIES LAWS OR UNLESS EXEMPTIONS FROM REGISTRATION AND QUALIFICATION ARE AVAILABLE. WARRANT CERTIFICATE For Purchase of Shares of Class A Common Stock of BERRY PETROLEUM COMPANY November 14, 1996 THIS CERTIFIES THAT, for value received, TANNEHILL OIL COMPANY, a California general partnership ("Warrant Holder"), is entitled, subject to the terms and conditions hereinafter set forth, to purchase from BERRY PETROLEUM COMPANY, a Delaware corporation (the "Company"), one hundred thousand (100,000) fully paid and nonassessable shares (which number is hereinafter sometimes referred to as the "Initial Exercise Number") of Class A Common Stock, par value $.01 per share, of the Company (the "Common Stock"), upon presentation and surrender of this Warrant Certificate, together with a completed and executed Election to Purchase in the form attached hereto, at any time during the Exercise Period (as hereinafter defined), at the principal office of the Company and upon payment therefore to the Company of the purchase price by wire transfer, cash or certified check, in lawful money of the United States of America. The Initial Exercise Number shall be subject to adjustment as hereinafter set forth. This Warrant ("Warrant") is issued to the Warrant Holder in partial consideration for the transactions set forth in the Purchase and Sale Agreement (the "Agreement"), dated as of November 14, 1996, by and between the Company, the Warrant Holder and the individual partners of the Warrant Holder. In certain contingencies provided for below, the number of shares of Common Stock subject to purchase hereunder or the purchase price thereof are subject to adjustment, but the

2 shares of Common Stock of the Company subject to purchase hereunder are the shares of such stock of the Company as they may exist on the date of the exercise of this Warrant, whether or not the rights or interests represented by such shares are equivalent to the rights or interests represented by the shares of Common Stock of the Company authorized as of the date hereof. This Warrant is subject to the following terms and conditions: 1. Exercise of Warrant. The purchase rights represented by this Warrant are exercisable at the option of the holder hereof, in whole at any time, or in part from time to time (but not as to a fractional share of Common Stock) during the Exercise Period (as defined below). In the case of the purchase of less than all the shares purchasable under this Warrant, the Company shall cancel this Warrant upon the surrender hereof and shall execute and deliver a new Warrant of like tenor for the balance of the shares purchasable hereunder. The term "Exercise Period" shall mean and refer to the period commencing on the date hereof and ending on November 8, 2003. 2. Price. The purchase price for each share of Common Stock purchasable pursuant to the exercise of this Warrant (the "Exercise Price") shall be equal to the Market Value (as defined below), plus two dollars ($2.00) per share in funds of the United States of America (or shall be such other amount per share if and as adjusted as provided in Section 3 below). The term "Market Value" shall mean the average closing price per share of Class A Common Stock traded on the New York Stock Exchange for the twenty (20) trading days prior to the trading day before the closing of the transactions contemplated by the Agreement (the "Closing"). For example, assuming the respective closing prices of the Class A Common Stock for the twenty (20) trading days prior to Closing are as follows: 10/15 $11-1/2 10/3 $11 10/14 $11-1/2 10/2 $11-1/2 10/11 $11-3/4 10/1 $11-3/4 10/10 $11-3/4 9/30 $12 10/9 $11-1/2 9/27 $12 10/8 $11 9/26 $11-3/4 10/7 $11-1/4 9/25 $11-1/2 10/6 $11 9/24 $11-1/2 10/5 $11-3/4 9/23 $11-1/4 10/4 $11-1/2 9/22 $11-1/4 the aggregate total of the closing prices is 230 and the average closing price per share is equal to 11.5 (i.e., 230 / 20). Pursuant to the above calculation and utilizing November 13, 1996, as the last trading day before the closing of the transaction contemplated herein, the Exercise Price per share shall be $14.06.

3 3. Adjustments to Exercise Price and Number of Shares. 3.1 The Exercise Price and number of shares of Common Stock purchasable pursuant to the exercise of this Warrant shall be subject to adjustment from time to time as follows: a. Adjustment for Combinations or Consolidations of Common Stock. In the event the Company, at any time after the date hereof (hereinafter referred to as the "Original Issue Date"), effects a subdivision or combination of its outstanding Common Stock into a greater or lesser number of shares, then and in each such event, the Exercise Price and the number of shares of Common Stock purchasable pursuant to the exercise of this Warrant shall be decreased or increased, respectively, proportionately. b. Adjustment for Certain Dividends and Distributions. In the event the Company at any time after the Original Issue Date shall make or issue, or fix a record date for the determination of holders of Common Stock entitled to receive, a dividend or other distribution payable in additional shares of Common Stock, then and in each such event the maximum number of shares (as set forth in the instrument relating thereto without regard to any provisions contained therein for a subsequent adjustment to such number) of Common Stock issuable in payment of such dividend or distribution shall be deemed to be issued and outstanding as of the time of such issuance or, in the event such a record date shall have been fixed, as of the close of business on such record date. In each such event, the Exercise Price shall be decreased as of the time of such issuance or, in the event such a record date shall have been fixed, as of the close of business on such record date, by multiplying the Exercise Price by a fraction, (1) the numerator of which shall be the total number of shares of Common Stock issued and outstanding or deemed to be issued and outstanding immediately prior to the time of such issuance or the close of business on such record date; and (2) the denominator of which shall be the total number of shares of Common Stock issued and outstanding or deemed to be issued and outstanding immediately prior to the time of such issuance or the close of business on such record date plus the number of shares of Common Stock issuable in payment of such dividend or distribution; provided, however, that if such record date shall have been fixed and such dividend not fully paid or if such distribution is not fully made on the date fixed therefor, the Exercise Price shall be recomputed accordingly as of the close of business on such record date and thereafter the Exercise Price shall be adjusted pursuant to paragraph 3.1(b) as of the time of actual payment of such dividends or distribution. c. Adjustments for Reclassifications and for Other Dividends and Distributions. In the event the Company at any time after the Original Issue Date shall effect a reclassification of its Common Stock (other than one resulting in the issuance of additional shares of Common Stock) or shall make or issue, or fix a record date for the determination of

4 holders of Common Stock entitled to receive, a dividend or other distribution to its stockholders payable in securities of the Company other than shares of Common Stock, then and in each such event provision shall be made so that the holder of this Warrant shall receive, upon exercise thereof, the securities of the Company which such holder would have received had this Warrant been exercised and the Common Stock issuable on exercise been received on the date of such event. 3.2 Upon any adjustment of the Exercise Price and of the number of shares of Common Stock and, if applicable, other securities and property issuable upon exercise of this Warrant, pursuant to this Section 3, the Company, within twenty (20) days thereafter, shall cause to be prepared a certificate of the Chief Financial Officer of the Company setting forth the Exercise Price after such adjustment and setting forth in reasonable detail the method of calculation used. 3.3 In case: a. The Company shall authorize the issuance to all holders of Common Stock of rights or warrants to subscribe for or purchase capital stock of the Company or of any other subscription rights or warrants; or b. the Company shall authorize the distribution to all holders of Common Stock of evidences of its indebtedness or assets (other than cash dividends or cash distributions payable out of consolidated earnings or earned surplus or dividends payable in Common Stock); or c. of any consolidation or merger to which the Company is a party and for which approval of any stockholders of the Company is required, or of the conveyance or transfer of the properties and assets of the Company substantially as an entirety, or of any capital reorganization or any reclassification of the Common Stock (other than a change in par value, or from par value to no par value, or from no par value to par value, or as a result of a subdivision or combination); or d. of the voluntary or involuntary dissolution, liquidation or winding up of the Company; or e. the Company proposes to take any other action which would require an adjustment of the Exercise Price or number or kind of shares issuable upon exercise of this Warrant, pursuant to this Section 3; then the Company shall cause to be given to the registered holder of the outstanding Warrant at its address in the records of the Company at least thirty (30) calendar days (or fifteen (15) calendar days in any case specified in paragraph a or b above) prior to the applicable record date hereinafter specified, by first-class mail, postage prepaid, written notice stating (i) the date as of which the holders of record of shares of Common Stock to be entitled to receive any rights, warrants or distribution are to be determined or (ii) the date on which any consolidation, merger,

5 conveyance, transfer, reorganization, reclassification, dissolution, liquidation or winding up is expected to become effective, and the date as of which it is expected that holders of record of shares of Common Stock shall be entitled to exchange the shares for securities or other property, if any, deliverable upon the consolidation, merger, conveyance, transfer, reorganization, reclassification, dissolution, liquidation or winding up. 3.4 Irrespective of any adjustments in the Exercise Price or the number or kind of shares purchasable upon exercise of the Warrant, the Warrant theretofore or thereafter issued may continue to express the same price and number and kind of shares as are stated in the similar Warrant initially issued. 4. Elimination of Fractional Interests. The Company shall not be required to issue certificates representing fractions of shares of Common Stock, but will make a payment in cash based on the Exercise Price in effect at that time. 5. Covenants of the Company. The Company covenants and agrees that all shares which may be issued upon the exercise of this Warrant shall, upon issuance, be duly authorized, validly issued, fully paid and non-assessable and free from all preemptive rights of any stockholder and all taxes, liens and charges with respect to the issue thereof (other than taxes in respect of any transfer occurring contemporaneously with such issue). The Company further covenants and agrees that during the Exercise Period within which the rights represented by this Warrant may be exercised, the Company will at all times have authorized, and reserved, a sufficient number of shares of its Common Stock to provide for the exercise of the rights represented by this Warrant. 6. Restrictions on Transferability of Securities; Compliance with Securities Act. 6.1 Restrictions on Transferability. This Warrant and shares of Common Stock issuable upon exercise of this Warrant are restricted shares and shall not be transferable, except upon the conditions specified in this Section 6, which conditions are intended to insure compliance with the provisions of the Securities Act of 1933, as amended (the "Securities Act"). The holder of this Warrant shall cause any proposed transferee of this Warrant, or the shares of Common Stock issuable upon exercise of this Warrant held by that holder, to agree to take and hold those securities subject to the provisions and upon the conditions specified in this Section 6. 6.2 Certain Definitions. As used in this Section 6, the term "Restricted Securities" means (i) the Warrants, (ii) the shares of Common Stock issuable or issued upon exercise of the Warrants, and (iii) any shares of Common Stock of the Company issued as a dividend or other distribution with respect to, or in exchange or in replacement of the Warrants or such shares of Common Stock. 6.3 Restrictive Legend. Each certificate representing (i) the Warrants, (ii) shares of the Company's Common Stock issued upon exercise of the Warrants, or (iii) any other securities issued in respect of the Warrants or the Common Stock issued upon exercise of the

6 Warrants upon any stock split, stock dividend, recapitalization, merger, consolidation or similar event, shall be stamped or otherwise imprinted with a legend in the following form (in addition to any legend required under applicable state securities laws): THESE SECURITIES HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE "SECURITIES ACT"), NOR HAVE THE SECURITIES BEEN QUALIFIED UNDER ANY STATE SECURITIES LAWS. ACCORDINGLY, THE SECURITIES MAY NOT BE SOLD OR OFFERED FOR SALE UNLESS SUCH SECURITIES ARE SUBSEQUENTLY REGISTERED UNDER FEDERAL AND APPLICABLE STATE SECURITIES LAWS OR UNLESS EXEMPTIONS FROM REGISTRATION AND QUALIFICATION ARE AVAILABLE. Upon request of a holder of such a certificate, the Company shall remove the foregoing legend from the certificate or issue to such holder a new certificate therefor free of any transfer legend, if, with such request, the Company shall have received the opinion referred to in Section 6.4 to the effect that any transfer by such holder of the securities evidenced by such certificate will not violate the Securities Act and applicable state securities laws. 6.4 Notice of Proposed Transfers. The holder of each certificate representing Restricted Securities by acceptance thereof agrees to comply in all respects with the provisions of this Section 6.4. Prior to any proposed transfer of any Restricted Securities, the holder thereof shall give written notice to the Company of such holder's intention to effect such transfer. Each such notice shall describe the manner and circumstances of the proposed transfer in sufficient detail, and shall be accompanied (except in transactions in compliance with Rule 144) by a written opinion of legal counsel who shall be reasonably satisfactory to the Company, addressed to the Company and reasonably satisfactory in form and substance to the Company's counsel, to the effect that the proposed transfer of the Restricted Securities may be effected without registration under the Securities Act, whereupon the holder of such Restricted Securities shall be entitled to transfer such Restricted Securities in accordance with the terms of the notice delivered by the holder to the Company. Each certificate evidencing the Restricted Securities transferred as above provided shall bear the appropriate restrictive legend set forth in Section 6.3 above, except that such certificate shall not bear such restrictive legend if the opinion of counsel letter referred to above is to the further effect that such legend is not required in order to establish compliance with any provision of the Securities Act. 6.5 Reports Under Securities Exchange Act of 1934. With a view to making available to the holders the benefits of Rule 144 promulgated under the Securities Act and any other rule or regulation of the Commission that may at any time permit a Holder to sell securities of the Company to the public without registration, the Company agrees to use its best efforts to: a. make and keep public information available (as provided in Rule 144) at all times;

7 b. file with the Commission in a timely manner all reports and other documents required of the Company under the Securities Act and the Securities Exchange Act of 1934 (the "Exchange Act"); and c. furnish to any Holder so long as such Holder owns any of the Restricted Securities upon request a written statement by the Company that it has complied with the reporting requirements of Rule 144 and of the Securities Act and the Exchange Act, a copy of the most recent annual or quarterly report of the Company, and such other reports and documents so filed by the Company as may be reasonably requested in availing any holder of any rule or regulation of the Commission permitting the selling of any such Restricted Securities without registration. 7. Exchange and Replacement of Warrant. Upon receipt by the Company of evidence reasonably satisfactory to it of the loss, theft, destruction or mutilation of this Warrant, and, in case of loss, theft or destruction, of an indemnity agreement or bond reasonably satisfactory to it, and reimbursement to the Company of all reasonable expenses incidental thereto, and upon surrender and cancellation of this Warrant, if mutilated, the Company will make and deliver a new Warrant of like tenor, in lieu of this Warrant. 8. Rights Prior to Exercise of Warrant. Prior to the exercise of this Warrant, the holder of this Warrant shall not be entitled to any rights of a stockholder of the Company, including without limitation the right to vote, to receive dividends or other distributions or to exercise any preemptive rights, as to those shares of Common Stock subject to this Warrant, and shall not be entitled to receive any notice of any proceedings of the Company except as provided herein. 9. Notices. Any and all notices, demands, requests or other communications required or permitted by this Warrant or by law to be served on, given to or delivered to any party hereto by any other party to this Warrant shall be in writing and shall be deemed duly served, given or delivered upon delivery by facsimile transmission (confirmed by any of the methods that follow), by courier service (with proof of service), by hand delivery, or by certified or registered mail (return receipt requested and first-class postage prepaid) and addressed as follows: If to the Warrant Holder: with copies to: Tannehill Oil Company Roger Coley, Esq. c/o Boyce Resource Development Co. 330 H Street, No. 7 Attn: Mr. Albert G. Boyce, Jr. Bakersfield, California 93304 Managing General Partner 120 Manteca Avenue P.O. Box 871 Facsimile No. (805) 327-9120 Manteca, California 95336 Confirmation No. (805) 328-5575 Facsimile No. (209) 239-7886 Confirmation No. (209) 239-4014

8 If to the Company: with copies to: Berry Petroleum Company Nordman, Cormany, Hair & Compton 28700 Hovey Hills Road Attn: Laura K. McAvoy, Esq. Post Office Bin X 1000 Town Center Drive, Sixth Floor Taft, California 93268 Post Office Box 9100 Attn: President Oxnard, California 93031-9100 Facsimile No. (805) 769-8960 Facsimile No. (805) 988-8387 Confirmation No. (805) 769-8811 Confirmation No. (805) 485-1000 Any notice which is addressed and mailed in the manner herein provided shall be conclusively presumed to have been duly given to the party to which it is addressed at the close of business, local time of the recipient, on the third day after the day it is so placed in the mail. Either party may change their address for the purposes of this Warrant, by giving notice of the change, in the manner required by this Section, to the other party. 10. Successors. This Warrant shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, executors, personal representatives, successors and assigns and shall be binding upon any person, firm, corporation or other entity to whom this Warrant and any shares of Common Stock issuable upon exercise hereof are transferred (even if in violation of the provisions of this Warrant) and the heirs, executors, personal representatives, successors and assigns of such person, firm, corporation or other entity. 11. Governing Law. This Warrant shall be construed in accordance with and be governed by the laws of the State of Delaware, without regard to its conflict of laws principles. IN WITNESS WHEREOF, the Company has caused this Warrant to be duly executed and delivered by its duly authorized officers. BERRY PETROLEUM COMPANY, a Delaware corporation By: _______________________________ Jerry V. Hoffman, President and Chief Executive Officer By: _______________________________ Kenneth A. Olson, Secretary

9 ELECTION TO PURCHASE To: BERRY PETROLEUM COMPANY The undersigned owner of the accompanying Warrant hereby irrevocably exercises the option to purchase ___________ shares of Class A Common Stock in accordance with the terms of such Warrant, directs that the shares issuable and deliverable upon such purchase (together with any check for a fractional interest) be issued in the name of and delivered to the undersigned, and makes payment in full therefor at the Exercise Price provided in such Warrant. COMPLETE FOR REGISTRATION OF SHARES OF COMMON STOCK ON THE STOCK TRANSFER RECORDS MAINTAINED BY BERRY PETROLEUM COMPANY: ________________________________________________________________ Name of Warrant Holder ________________________________________________________________ Address ________________________________________________________________ ________________________________________________________________ Social Security or Other Identifying Number Signature: __________________________________ Date: _______________________________________

220 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Berry Petroleum Company on Form S-8 (File No. 33-23326 and 33-61337) of our report dated February 28, 1997 on our audits of the financial statements of Berry Petroleum Company as of December 31, 1996 and 1995 and for the three years in the period ended December 31, 1996, which report is included in this Annual Report on Form 10-K. COOPERS & LYBRAND L.L.P. Los Angeles, California March 13, 1997 EXHIBIT 23.1

221 DeGolyer and MacNaughton One Energy Square Dallas, Texas 75206 March 7, 1997 Berry Petroleum Company P.O. Bin X Taft, CA 93268 Gentlemen: In connection with the Annual Report on Form 10-K for the fiscal year ended December 31, 1996, (the Annual Report) of Berry Petroleum Company (the Company), we hereby consent to (i) the use of and reference to our report dated February 12, 1997, entitled "Appraisal Report as of December 31, 1996 on Certain Property Interests owned by Berry Petroleum Company," our report dated February 12, 1996, entitled "Appraisal Report as of December 31, 1995 on Certain properties owned by Berry Petroleum Company," and our report dated February 23, 1995, entitled "Appraisal Report as of December 31, 1994 on Certain Properties owned by Berry Petroleum Company"(collectively referred to as the "Reports"), all three of which pertain to interests of the Company in certain oil and gas properties located in California, Louisiana, Nevada, and Texas, under the caption "Oil and Gas Reserves- Reserve Reports" in items 1 and 2 of the Annual Report, in item 6 of the Annual Report, and under the caption "Supplemental Information About Oil and Gas Producing Activities (Unaudited)" in item 8 of the Annual Report and (ii) the use of and reference to the name DeGolyer and MacNaughton as the independent petroleum engineering firm that prepared the Reports under such items; provided, however, that since the cash-flow calculations in the Annual Report include estimated income taxes not included in the Reports, we are unable to verify the accuracy of the cash flow values in the Annual Report. Very truly yours, DeGOLYER and MacNAUGHTON

5 0000778438 BERRY PETROLEUM COMPANY 1,000 YEAR DEC-31-1996 DEC-31-1996 12,540 704 11,701 0 0 26,252 222,865 73,355 176,403 18,402 0 0 0 219 100,790 176,403 55,264 57,095 0 24,981 4,820 0 0 27,294 9,748 17,546 0 0 0 17,546 .80 .80

223 UNDERTAKING FOR FORM S-8 REGISTRATION STATEMENT For purposes of complying with the amendments to the rules governing Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the Company hereby undertakes as follows, which undertaking shall be incorporated by reference into the Company's Registration Statements on Form S-8 (No. 33- 23326 and No. 33-61337 filed on July 28, 1988 and July 27, 1995, respectively): Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to director, officers and controlling persons of the Company pursuant to the foregoing provisions, or otherwise, the Company has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Company of expenses incurred or paid by a director, officer or controlling person of the Company in the successful defense of any action, suit or proceeding is asserted by such director, officer or controlling person in connection with the securities being registered, the Company will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. Exhibit 99.1