-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, SJwXPw+jVDOvF+nruePYkbMh7hEOAatlrU/UJC83wYF5bbqmNsENMTpsVeiK5DBX kxBxcdEhFJuQOwrW4aeftg== 0000778438-01-000005.txt : 20010321 0000778438-01-000005.hdr.sgml : 20010321 ACCESSION NUMBER: 0000778438-01-000005 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010320 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BERRY PETROLEUM CO CENTRAL INDEX KEY: 0000778438 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 770079387 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-09735 FILM NUMBER: 1572286 BUSINESS ADDRESS: STREET 1: P O BIN X CITY: TAFT STATE: CA ZIP: 93268 BUSINESS PHONE: 8057698811 MAIL ADDRESS: STREET 1: BERRY PETROLEUM CO STREET 2: P.O. BOX X CITY: TAFT STATE: CA ZIP: 93268 10-K 1 0001.txt FORM 10-K 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, 2000 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 P.O. Box 925 Taft, California 93268 (Address of principal executive offices, including zip code) Registrant's telephone number, including area code: (661) 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 16, 2001, the registrant had 21,134,655 shares of Class A Common Stock outstanding and the aggregate market value of the voting stock held by nonaffiliates was approximately $218,111,000. This calculation is based on the closing price of the shares on the New York Stock Exchange on February 16, 2001 of $13.90. The registrant also had 898,892 shares of Class B Stock outstanding on February 16, 2001, 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. BERRY PETROLEUM COMPANY TABLE OF CONTENTS PART I Items 1 and 2. Business and Properties 3 General 3 Oil Marketing 4 Steaming Operations 5 Electricity Contracts 6 Electricity Generation 7 Environmental and Other Regulations 8 Competition 8 Employees 8 Oil and Gas Properties 9 Development 9 Exploration 10 Enhanced Oil Recovery Tax Credits 11 Oil and Gas Reserves 11 Production 11 Acreage and Wells 12 Drilling Activity 12 Title and Insurance 12 Item 3. Legal Proceedings 13 Item 4. Submission of Matters to a Vote of Security Holders 13 Executive Officers 13 PART II Item 5. Market for the Registrant's Common Equity and Related Shareholder Matters 14 Item 6. Selected Financial Data 15 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 16 Item 8. Financial Statements and Supplementary Data 20 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 40 PART III Item 10. Directors and Executive Officers of the Registrant 40 Item 11. Executive Compensation 40 Item 12. Security Ownership of Certain Beneficial Owners and Management 40 Item 13. Certain Relationships and Related Transactions 40 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 40 2 PART I Items 1 and 2. Business and Properties General Berry Petroleum Company, ("Berry" or "Company"), is an independent energy company engaged in the production, development, acquisition, exploitation and exploration of crude oil and natural gas. While the Company was incorporated in Delaware in 1985 and has been a publicly traded company since 1987, it can trace its roots in California oil production back to 1909. Currently, Berry's principal reserves and producing properties are located in Kern, Los Angeles 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, 2000. 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 returns, 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 and proved reserves, the Company will compete to acquire oil and gas properties with 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. In conjunction with the goals of being a low-cost heavy oil producer and the exploitation and development of its large heavy crude oil base, the Company owns three cogeneration facilities which are intended to provide an efficient and secure long-term supply of steam which is necessary for the economic production of heavy oil. Berry views these assets as a critical part of its long-term success. Berry believes that its primary strengths are its ability to maintain a low-cost operation, its flexibility in acquiring attractive producing properties which have significant exploitation and enhancement potential and its experienced management team. While the Company continues to seek investment opportunities in California, it is investigating several other basins which would establish another core area and provide for additional growth opportunities and diversification of the Company's predominantly heavy oil resource base. The Company has unused borrowing capacity to finance acquisitions and will consider, if appropriate, the issuance of capital stock to finance future purchases. Proved Reserves As of December 31, 2000, the Company's estimated proved reserves were 107 million barrels of oil equivalent, (BOE), of which 99.3% are heavy crude oil, i.e., oil with an API gravity of less than 20 degrees. A significant portion of these proved reserves is owned in fee. Substantially all of the Company's reserves as of December 31, 2000 were located in California, with 74%, 20% and 5% of total proved reserves in Kern, Los Angeles and Ventura Counties, respectively. 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 and the Placerita fields average 13 degree API gravity and the Montalvo field averages 16 degree API gravity). Production in 2000 was 5.5 million BOE, up 7% from 1999 production of 5.1 million BOE. For the five years 1996 through 2000, the Company's average annual reserve replacement rate was 226% and the finding and development cost was $2.97 per BOE. Operations Berry operates all of its principal oil producing properties. The Midway- Sunset and Placerita fields contain predominantly heavy crude oil which requires heat, supplied in the form of steam, injected into the oil producing formations to reduce the oil viscosity which improves the mobility of the oil flowing to the well-bore for production. Berry utilizes cyclic steam recovery methods in the Midway-Sunset field, steam-drive in the Placerita field and primary recovery methods at its Montalvo field. Berry is able to produce its heavy oil at its Montalvo field without the necessity of steam since the majority of the producing reservoir is at a depth in excess of 11,000 feet and thus the reservoir temperature is high enough to produce the oil without the assistance of additional heat from steam. 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 (LACT) units and either transferred into crude oil pipelines owned by other companies or, in the case of the Placerita field, transported via trucks. The point-of-sale is usually the LACT unit or truck loading facility. 3 Revenues The percentage of revenues by source for the prior three years is as follows: 2000 1999 1998 Sales of oil and gas 69% 67% 72% Sales of electricity 31% 33% 28% Oil Marketing The world and California crude oil markets have remained very volatile as OPEC attempts to manage crude oil prices in the midst of fluctuating inventory levels and concerns about potential demand weakness due to possible worldwide economic slowdowns. Oil remained very strong in 2000 with the price for West Texas Intermediate (WTI), the U.S. benchmark crude oil, averaging $30.26 compared to $19.30 in 1999. The All American Pipeline, which historically provided an outlet to Texas markets for California crude oil, was removed from crude oil service in late 1999 and is expected in the future to be utilized for natural gas transportation into California. In the near term, the reduction of crude oil shipments from California, coupled with regular refinery maintenance scheduling, is expected to seasonally increase differentials between WTI and California's heavy crude, although on an annual basis, the Company believes differentials will continue in the range of historical norms. The crude price differential between WTI and California's heavy crude oil continues to be volatile and has averaged $6.36, $5.97 and $5.97 for 2000, 1999 and 1998, respectively. Berry markets its crude oil production to competing buyers including independent marketing, pipeline and oil refining companies. Primarily due to the Company's ability to deliver significant volumes of crude oil over a multi-year period, the Company was able to secure a three-year crude sales agreement, beginning in April 2000, with a major California refiner whereby the Company sells substantially all of its production under a negotiated pricing mechanism. The agreement is based on a monthly determination of the highest price from any of (1) local field posted price plus a fixed bonus, (2) WTI minus a fixed differential or (3) a fixed percentage of WTI. In addition to providing a premium above field postings, the agreement effectively eliminates the Company's exposure to the risk of widening WTI-heavy crude price differentials. From time to time, the Company has entered into crude oil hedge contracts, the terms of which depend on various factors, including Management's view of future crude oil prices and the Company's future financial commitments. During 2000, the Company maintained two bracketed zero cost collar hedge contracts with two refiners entered into in previous years as part of its price protection program. This price protection program was designed to moderate the effects of a severe price downturn while allowing Berry to participate in 100% of the upside after a maximum $3.00 per barrel payment on 6,500 barrels per day (BPD). Of this 6,500 BPD, Berry participated on 5,000 BPD above $15.50 per barrel and on 1,500 BPD above $17.50 per barrel. These price triggers were based on California heavy oil postings and both contracts expired at December 31, 2000. These price protection activities resulted in a net cost to the Company of $1.31 per barrel in 2000 and $0.51 per barrel in 1999. Berry's 2000 average heavy crude oil sales price was $21.70 in 2000, up $8.62 per barrel, or 66% from $13.08 in 1999. At the present time, the Company does not have any crude oil hedges in place although its existing crude oil sales agreement does provide some protection against a severe price decline. One of the Company's properties, with production in excess of 3,000 BPD, is burdened by a price-sensitive royalty. The royalty is 75% of the heavy oil posted price above $14.02 (for 2001), escalated and calculated annually. Management regularly monitors the crude oil markets and its financial commitments to determine if, when, and at what level some form of crude oil hedging or other price protection is appropriate. 4 Steaming Operations At December 31, 2000, approximately 95% of the Company's proved reserves, or 102 million barrels, consisted of heavy crude oil produced from depths averaging less than 2,000 feet. The Company, in achieving its goal of being a low-cost heavy oil producer, has focused on reducing its steam cost through the purchase of its 38 megawatt (Mw) cogeneration facility in 1995 and another 18 Mw cogeneration facility in 1996 as part of the purchase of additional oil properties in the South Midway-Sunset field. In early 1999, the Company purchased the Placerita oilfield, this oilfield is highly dependent on low-cost steam for economic production. This purchase also included a 42 Mw cogeneration facility. Steam generation from these facilities is more efficient than conventional steam generators, as both steam and electricity are produced from the same natural gas fuel supply. In addition, the Company's ownership of these facilities allows for control over the steam supply which is crucial for the maximization of oil production and ultimate reserve recovery. The Company believes that it is advantageous to add additional productive steam capacity for its requirements at South Midway-Sunset and Placerita to allow for full development of its properties. It is now clear that California is considerably short of electrical power in the near future and, as such, the Company is well positioned to achieve increased electricity revenue through the expansion of cogeneration steam capacity at strategic locations on the Company's properties. The Company believes that continued steam generation from cogeneration facilities will continue to be significantly more efficient and cost effective than conventional steam generators. Midway-Sunset Field For its South Midway-Sunset properties, the Company's steam production for 2000 was generated by its 38 and 18 Mw cogeneration facilities (approximately 21,000 barrels of steam per day (BSPD) including duct-fire) and, as needed, from conventional steam generators. The Company also has a steam contract from an on-site, non-owned cogeneration facility for a minimum delivery of 2,000 BSPD for use in the Company's operations, although the facility is currently not operating. Conventional steam generators are used by the Company as warranted to maintain current production levels, to economically produce additional crude oil and as emergency back-up steam generation to the cogeneration facilities. On its North Midway-Sunset properties, the Company relies solely on conventional steam generators for its steam requirements. Placerita On its Placerita properties, the Company generated approximately 12,500 BSPD in 2000 from its 42 Mw cogeneration facility, may purchase additional volumes from a third party cogeneration facility when available, and has the capability of generating another 6,000 BSPD from conventional steam generators. 5 Electricity Contracts The following is a summary of the Company's cogeneration electrical contracts and various operational data:
Average Average Run Time megawatts barrels of Date Placed Contract under Berry delivered steam Location Contract(1) Territory In Service Expiration Ownership(2) for sale(3) delivered(3) Placerita Placerita I SO2 Edison 3/90 3-2009 >97% 16.7/hour 6,112/day Placerita II SO2 Edison 5/90 5-2002 >96% 16.4/hour 6,404/day South Midway-Sunset Cogen 18 SO2 PG&E 12/87 1-2002 >98% 14.3/hour 6,350/day Cogen 38 SO1 PG&E 12/86 1-2012 >95% 34.5/hour 15,115/day (1) SO is for "Standard Offer." (2) Approximate average through 2000 for Placerita I and II since February, 1999; Cogen 18 since November, 1996; Cogen 38 since August, 1995. (3) Approximate average for 2000 based on 366 day year.
Current Steam Output Conventional Steam Generation Effective December 1, 2000, the Company shut-in most of its conventional steam generation capacity due to an unprecedented increase in natural gas prices at the Southern California border (SoCal). The natural gas price for delivery into SoCal was $14.08/Million British Thermal Units (Mmbtu) in December, versus an average of $2.50/Mmbtu in the first quarter of 2000. Historically, the SoCal natural gas price has tracked very close to the NYMEX Henry Hub (HH) price. The SoCal price exploded over HH in December by approximately $7.72/Mmbtu. Given this dramatic rise in natural gas prices in California, the Company determined that to maximize cash flow, it was necessary to suspend most of its conventional steaming operations. Continued high natural gas prices in California, far in excess of HH, have persisted into 2001. As of this writing, the Company has not returned its conventional steam generation to operation. Cogeneration Steam Generation While higher natural gas prices also increased the Company's steam cost from its cogeneration facilities, it is not so dramatic as for conventional steam operations. The pricing of electricity under the Company's Standard Offer (SO) contracts is based primarily on natural gas costs, thus, as fuel costs rise so do the electrical revenues. Steam from the Company's cogeneration facilities is generally economic even at high natural gas prices. The much-publicized California electricity crisis, with California's two largest utilities (Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (Edison)) nearing bankruptcy, has negatively impacted Berry and its operations. Edison failed to pay Berry for November and December 2000 power deliveries, which were due in early January and February 2001, respectively. In addition, they have also failed to pay for January 2001 deliveries, which were due in early March. PG&E made full payment for November 2000 and only partial payments, of approximately 15%, for December 2000 and January 2001 deliveries. In response to non-payment and to preserve cash flow, the Company suspended operations at its 38 Mw and Placerita Unit II (21 Mw) cogeneration facilities effective February 1, 2001. The Company also suspended operations at its 18 Mw cogeneration facility on February 17, 2001. The Company has notified both utilities that they are in breach of the power purchase agreements and full payment is expected as soon as possible. The Company anticipates that its thermally-dependent oil production will begin to decline in the first quarter of 2001 due to this significant reduction of steam injection into its heavy oil reservoirs. 6 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. The Company has no long-term gas delivery contracts and none of the Company's cogeneration facilities are subject to any long-term gas transportation agreements. Historically, there has been sufficient capacity to deliver adequate quantities of natural gas to the Company's properties, however, it appears that, pipeline capacity into and within California is currently constrained and may be partially responsible for higher natural gas prices in California. The Company has no assurance currently that it can procure its future natural gas requirements at reasonable prices. Electricity Generation The Company's three cogeneration facilities, when combined, have electricity production capacity of 98 Mw of electricity per hour. Each facility is centrally-located on an oil property such that the steam generated by the facility is capable of being delivered to the oil properties that require the steam for production purposes. With higher natural gas prices impacting its operations so significantly, the Company is pursuing other opportunities to secure additional long-term sources of low-cost steam. The Company's investments in its cogeneration facilities have been for the express purpose of lowering the steam costs in its heavy oil operations and securing operating control of the respective steam generation. For these reasons, proceeds received from the sale of electricity have been reported as a reduction to operating costs - oil and gas production in prior years. However, with the significant increases in electricity and natural gas prices that have occurred over the last year, the significantly changed electrical situation in California, and with the Company pursuing various options to sell its electricity now that its power purchasers have breached the Company's contracts, the Company has modified its financial statement presentation to assist investors in understanding the electrical impact to the Company's business. The Company now reports its electricity proceeds and costs thereof separately. Proceeds from the sale of electricity are now reported as revenues in the Company's financial statements. Expenses of operating the cogeneration plants are analyzed monthly by field of operations. Any profits generated from cogeneration are considered profits from electricity generation. If the expenses exceed electricity revenues, the excess expenses are charged to oil and gas operating costs. During the fourth quarter of 2000, the Company experienced a significant increase in the cost of natural gas, which is used as fuel for its cogeneration plants and steam generators. To protect itself from a pending proposed decision by a CPUC board member which would have had the effect of de-linking the Company's natural gas cost from electricity sales under its standard offer contracts, the Company entered into several derivative contracts to hedge 4,500 Mmbtu/day of natural gas purchases for the three months ended March 31, 2001. During December 2000, the Company recorded operating costs of $.3 million related to the ineffective portion of these derivative instruments. Additionally, the Company recorded $.4 million (net of tax effect) in other comprehensive income related to unrecognized gains from these derivative instruments. See Notes 2 and 3 to the financial statements. The Company's immediate challenge is to locate a creditworthy buyer for its electricity and return its cogeneration facilities to operating status. The current market conditions surrounding electricity generation and sales are dominated by the legislative activity in Sacramento, California's capital. There remain major hurdles before California's electrical marketplace can return to some sort of normalcy. Berry is working vigorously with industry groups and state legislators in an effort to return its cogeneration facilities to profitable operating status as soon as possible. Management believes that it should be able to return its cogeneration facilities to full operational status by the summer of 2001, as electrical supply is expected to be in high demand and problems collecting payments for electricity sales will hopefully be resolved. However, with all of the current uncertainty and turmoil that exists in the California electrical marketplace, Management can provide no assurance as to the timing and nature of the resolution of the electrical crisis, including but not limited to the return of its cogeneration facilities to full operation or the collection of payments for electricity sales. The Company is pursuing various opportunities to expand its cogeneration capacity. The Company has a long-term need for additional substantial volumes of steam to maximize its oil production and desires to secure this steam through cogeneration. 7 Environmental and Other Regulations Berry Petroleum Company is committed to conducting its operations in a manner that protects the health and safety of employees, contractors, the public, and the quality of the environment in its operating areas. Berry Petroleum Company makes environmental, health and safety protection an integral part of all business activities, from the acquisition and management of its resources through the decommissioning and reclamation of its wells and facilities. Berry's operations are affected by federal, state, regional and local laws and regulations, including laws that govern, among other things, the issuance of permits in connection with drilling, production, electricity generation and equipment operation, allowable rates of production and land use restrictions. Also, the amounts and types of substances that may be released into the environment, the discharge and disposal of waste materials, the reclamation and abandonment of wells and facilities, the remediation of contaminated sites and other laws relating to the petroleum industry. Berry is further affected by changes in such laws and by constantly changing administrative regulations. Furthermore, these agencies may impose substantial liabilities if the Company fails to comply with such regulations or for any contamination resulting from the Company's operations. Berry has established policies and procedures that focus on preventing environmental impacts, and, when required, on timely remediation. The costs incurred to ensure compliance with environmental, health and safety laws and other regulations are inextricably connected to normal operating expenses such that the Company is unable to separate the expenses related to these matters. Although environmental, health and safety requirements do have a substantial impact upon the energy industry, generally these requirements do not appear to affect the Company any differently, or to any greater or lesser extent, than other companies in California and in the domestic oil and gas industry, as a whole. Berry believes that compliance with environmental laws and regulations will not have a material adverse effect on the Company's operations or financial condition but there can be no assurances that changes in, or additions to, laws or regulations regarding the protection of the environment will not have such an impact in the future. Berry maintains insurance coverage that it believes is customary in the industry although it is not fully insured against all environmental or other risks. The Company is not aware of any environmental claims existing as of December 31, 2000 that would have a material impact upon the Company's financial position, results of operations, or liquidity. Competition The oil and gas industry is highly competitive. As an independent producer, the Company does not own any refining or retail outlets and, therefore, it has little control over the price it receives for its crude oil. As such, 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 as integrated and independent companies, 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 Berry is in a position to compete effectively due to its low cost structure, transaction flexibility, strong financial position, experience and determination. Employees On December 31, 2000, the Company had 115 full-time employees, up from 108 employees at year-end 1999. 8 Oil and Gas Properties Development Midway-Sunset - Berry owns and operates working interests in 35 properties consisting of 3,985 acres located in the Midway-Sunset field. The Company estimates these properties account for approximately 74% of the Company's proved oil and gas reserves and approximately 74% of its current daily production. Of these properties, 18 are owned in fee. The wells produce from an average depth of approximately 1,200 feet, and rely on thermal EOR methods, primarily cyclic steaming. During 2000, the primary focus in this field was directed at the continued development of the Formax properties acquired in 1996 and the continued application of horizontal well technology in the Monarch sands. Of the 79 wells drilled in this field in 2000, 25 were drilled on the Formax properties, and 16 were horizontal wells. The Company's objectives using this developing technology are to improve ultimate recovery of original oil-in-place, reduce the development and operating costs of the properties and accelerate production. In 2001, the Company plans to drill an additional 21 development wells in this field, 9 of which will be horizontal. During 2000, three of the wells drilled were exploitation wells in the north end of the field to further evaluate the diatomite accumulation on top of the Fairfield anticline and several other targets. In 2001, one of the wells planned for drilling is a diatomite core well to further delineate this accumulation. Placerita - Following acquisition of this significant field early in 1999, the Company made significant progress in 2000 on delineation of the remaining potential. The property consists of six leases (three federal) and three fee properties (one of which we acquired in 2000) totaling approximately 750 acres. The Company estimates current proved reserves from Placerita account for approximately 21% of Berry's proved oil and gas reserves and approximately 21% of Berry's daily production. The average depth of these wells is 1800 feet and the properties rely extensively on thermal methods, primarily steam flooding. The Company drilled two wells in 2000, one of which was the first horizontal ever drilled in the field. For 2001, the Company plans to drill four wells to initiate phase one of our major development campaign at the north end of the field. Montalvo - Berry owns a 100% working interest in six leases, totaling 8,563 acres, in Ventura County, California comprising the Montalvo field. The State of California is the lessor for two of the six leases. The Company estimates current proved reserves from Montalvo account for approximately 5% of Berry's proved oil and gas reserves and approximately 5% of Berry's daily production. The wells produce from an average depth of approximately 11,500 feet. No new wells were drilled in 2000 and at this time, the Company has no firm plans for drilling or redrilling at Montalvo in 2001. 9 The following is a summary of capital expenditures incurred during 2000 and 1999 and projected capital expenditures for 2001. While the Board approved a 2001 budget of approximately $25 million in December 2000, the Company currently anticipates a much lower budget of approximately $11 million. This reduced budget is in direct response to extremely high natural gas prices in California and, more importantly, the contract breach and the ongoing non-payment by PG&E and Edison for power deliveries made in late 2000 and early 2001. As these conditions change, Berry will reevaluate its capital expenditure program. CAPITAL EXPENDITURES SUMMARY (in thousands) 2001(1) 2000 1999 (Projected) South Midway-Sunset Field New wells $ 3,800 $ 10,128 $ 3,120 Remedials/workovers 900 1,373 607 Facilities 2,850 1,333 3,463 ------- ------- ------- 7,550 12,834 7,190 ------- ------- ------- Placerita New wells 1,950 2,669 310 Remedials/workovers 250 1,001 69 Facilities 730 4,543 784 ------- ------- ------- 2,930 8,213 1,163 ------- ------- ------- North Midway-Sunset Field New wells 150 1,257 150 Remedials/workovers 0 212 25 Facilities 75 76 18 ------- ------- ------- 225 1,545 193 ------- ------- ------- Montalvo Remedials/workovers 0 420 16 Facilities 166 1,295 37 ------- ------- ------- 166 1,715 53 ------- ------- ------- Other 0 946 523 ------- ------- ------- Totals $ 10,871 $ 25,253 $ 9,122 ======= ======= ======= (1) Budgeted capital expenditures may be adjusted for numerous reasons including, but not limited to, oil, natural gas and electricity price levels. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Exploration The Company did not participate in the drilling of any exploratory wells in 2000 or 1999 and has none budgeted for 2001. In recent years, the Company has concentrated on growth through development of existing assets and strategic acquisitions. The Company is pursuing an acquisition strategy which may include some exploration drilling in the future. 10 Enhanced Oil Recovery Tax Credits The Revenue Reconciliation Act of 1990 included a tax credit for certain costs associated with extracting high-cost, capital-intensive marginal oil or gas and which utilizes at least one of nine designated "enhanced" or tertiary recovery methods. Cyclic steam and steam drive recovery methods for heavy oil, which Berry utilizes extensively, are qualifying EOR methods. In 1996, California conformed to the federal law, thus, on a combined basis, the Company is able to achieve credits approximating 12% of its qualifying costs. The credit is earned for only qualified EOR projects by investing in one of three types of expenditures: 1) drilling development wells, 2) adding facilities that are integrally related to qualified EOR production, or 3) utilizing a tertiary injectant, such as steam, to produce oil. The credit may be utilized to reduce the Company's tax liability down to, but not below, its alternative minimum tax liability. This credit is significant in reducing the Company's income tax liabilities and effective tax rate. Oil and Gas Reserves The Company continued to engage DeGolyer and MacNaughton (D&M) to estimate the proved oil and gas reserves and the future net revenues to be derived from properties of the Company for the year ended December 31, 2000. D&M is an independent oil and gas consulting firm located in Dallas, Texas. In preparing their reports, D&M reviewed and examined geologic, economic, engineering and other data considered applicable to properly determine the reserves of the Company. They also examined the reasonableness of certain economic assumptions regarding forecasted operating and development costs and recovery rates in light of the economic environment on December 31, 2000. For the Company's operated properties, these 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: 2000 1999 1998 Net annual production:(1) Oil (Mbbls) 5,434 5,060 4,359 Gas (Mmcf) 199 180 245 Total equivalent barrels( 5,467 5,090 4,399 Average sales price: Oil (per bbl) $ 21.70 $ 13.08 $ 9.02 Gas (per mcf) 4.34 1.90 2.64 Per BOE 21.72 13.07 9.05 Average operating cost - oil and gas production (per BOE)(3) 8.56 5.64 4.15 (1) Net production represents that owned by Berry and produced to its interest, less royalty and other similar interests. (2) Equivalent oil and gas information is at a ratio of 6 thousand cubic feet (mcf) of natural gas to 1 barrel (bbl) of oil. A barrel of oil (bbl) is equivalent to 42 U.S. gallons. (3) Includes monthly expenses in excess of monthly revenues from cogeneration operations (per BOE) of $0.89, $0.17 and $0.14 for 2000, 1999 and 1998, respectively. See Note 2 to the financial statements. 11 Acreage and Wells At December 31, 2000, the Company's properties accounted for the following developed and undeveloped acres: Developed Acres Undeveloped Acres Gross Net Gross Net California 7,206 7,206 7,244 7,244 Other 360 41 - - ------ ------ ------ ------ 7,566 7,247 7,244 7,244 ====== ====== ====== ====== Gross acres represent acres in which Berry has a working interest; net acres represent Berry's aggregate working interests in the gross acres. Berry currently has 2,472 gross oil wells (2,468 net) and 4 gross gas wells (3.1 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: 2000 1999 1998 Gross Net Gross Net Gross Net Exploratory wells drilled: Productive - - - - - - Dry(1) - - - - - - Development wells drilled: Productive 81 81 21 21 20 20 Dry(1) - - - - 1 1 Total wells drilled: Productive 81 81 21 21 20 20 Dry(1) - - - - 1 1 (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 Title and Insurance To the best of the Company's knowledge, there are no defects in the title to any of its principal properties including related facilities. Notwithstanding the absence of a recent title opinion or title insurance policy on all of its properties, the Company believes it has satisfactory title to its 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. 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 operating its oil and gas business. 12 Item 3. Legal Proceedings While the Company is, from time to time, a party to certain lawsuits in the ordinary course of business, the Company does not believe any of such existing lawsuits will have a material adverse effect on the Company's operations, financial condition, or liquidity. Item 4. Submission of Matters to a Vote of Security Holders None. Executive Officers Listed below are the names, ages (as of December 31, 2000) and positions of the executive officers of Berry and their business experience during at least the past five years. All officers of the Company are appointed in May of each year at an organizational meeting of the Board of Directors. There are no family relationships between any executive officer and members of the Board of Directors. JERRY V. HOFFMAN, 51, 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 in March 1997. Mr. Hoffman held the Senior Vice President and Chief Financial Officer positions from January 1988 until March 1992. RALPH J. GOEHRING, 44, Senior Vice President and Chief Financial Officer. Mr. Goehring has been Senior Vice President since April 1997, Chief Financial Officer since March 1992 and was Manager of Taxation from September 1987 until March 1992. Mr. Goehring is also an Assistant Secretary for the Company. MICHAEL R. STARZER, 39, has been Vice President of Corporate Development since March 1996 and was Manager of Corporate Development from April 1995 to March 1996. 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. BRIAN L. REHKOPF, 53, has been Vice President of Engineering since March 2000 and was Manager of Engineering from September 1997 to March 2000. Mr. Rehkopf, a registered petroleum engineer, joined the Company's engineering department in June 1997 and was previously a Vice President and Asset Manager with ARCO Western Energy, a subsidiary of Atlantic Richfield Corp. (ARCO) since 1992 and an Operations Engineering Supervisor with ARCO from 1988 to 1992. Mr. Rehkopf is also an Assistant Secretary for the Company. GEORGE T. CRAWFORD, 40, has been Vice President of Production since December 2000 and was Manager of Production, from January 1999 to December 2000. Mr. Crawford, a petroleum engineer, was previously the Production Engineering Supervisor for ARCO Western Energy. Mr. Crawford was employed by ARCO from 1989 to 1998 in numerous engineering and operational assignments including Production Engineering Supervisor, Planning and Evaluation Consultant and Operations Superintendent. DONALD A. DALE, 54, has been Controller since December 1985. KENNETH A. OLSON, 45, has been Corporate Secretary since December 1985 and Treasurer since August 1988. 13 PART II Item 5. Market for the Registrant's Common Equity and Related Shareholder 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 November 1999, the Company adopted a Shareholder Rights Agreement and declared a dividend distribution of one such Right for each outstanding share of Capital Stock on December 8, 1999. Each share of Capital Stock issued after December 8, 1999 includes one Right. The Rights expire on December 8, 2009. See Note 7 of Notes to the Financial Statements. In conjunction with the acquisition of the Tannehill assets in 1996, 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 2000 and 1999 are shown below: 2000 1999 Price Range Dividends Price Range Dividends High Low per Share High Low per Share First Quarter $ 17 7/8 $ 14 1/16 $ .10 $ 14 1/8 $ 8 11/16 $ .10 Second Quarter 17 5/16 14 5/8 .10 14 5/8 11 1/8 .10 Third Quarter 19 7/8 16 1/2 .10 14 11/16 13 1/8 .10 Fourth Quarter 18 3/16 11 5/8 .10 15 7/16 12 1/4 .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 16, 2001, December 31, 2000 and December 31, 1999 was $13.90, $13 3/8 and $15 1/8, respectively. The number of holders of record of the Company's Common Stock was 745 (and approximately 3,600 street name shareholders) as of February 16, 2001. There was one Class B Stockholder of record as of February 16, 2001. The Company paid cash dividends for many years prior to the roll-up on December 16, 1985 of the various Berry companies into Berry Petroleum Company. Since Berry's formation, the Company has paid dividends on its Common Stock for eight consecutive semi-annual periods through September 1989 and for 45 consecutive quarters through December 31, 2000. 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, financial covenants and other relevant factors. At December 31, 2000, dividends declared on 4,000,894 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. 14 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, 2000 were derived from the audited financial statements and the accompanying notes to those financial statements (in thousands, except per share, per BOE and % data):
2000 1999 1998 1997 1996 Statement of Operations Data: Sales of oil and gas $ 118,801 $ 66,615 $ 39,858 $ 67,172 $ 55,264 Sales of electricity 52,765 33,731 15,680 17,190 11,552 Operating costs - oil and gas production 46,789 28,697 18,272 22,589 18,203 Operating costs - electricity generation 48,614 27,062 15,236 17,008 10,936 General and administrative expenses(G&A) 7,754 6,269 3,975 5,907 4,820 Depreciation, depletion & amortization (DD&A) 14,030 12,294 10,080 10,138 7,323 Net income 37,183 18,006 3,879 19,260 17,546 Basic net income per share 1.69 .82 .18 .88 .80 Weighted average number of shares outstanding 22,029 22,010 22,007 21,976 21,939 Balance Sheet Data: Working capital $ (1,154) $ 8,435 $ 9,081 $ 11,499 $ 7,850 Total assets 238,359 207,649 173,804 177,724 176,403 Long-term debt 25,000 52,000 30,000 32,000 36,000 Shareholders' equity 145,224 116,213 106,924 111,871 101,009 Cash dividends per share .40 .40 .40 .40 .40 Operating Data: Cash flow from operations 65,934 24,809 19,924 31,401 29,182 Capital expenditures (excluding acquisitions) 25,253 9,122 6,981 18,597 9,333 Property/facility acquisitions 3,182 33,605 2,991 - 75,613 Oil and gas producing operations(per BOE): Average sales price $ 21.72 $ 13.07 $ 9.05 $ 14.71 $ 15.36 Average operating costs(1) 8.56 5.64 4.15 4.96 5.09 G&A 1.42 1.23 .90 1.30 1.35 Cash flow 11.74 6.20 4.00 8.45 8.92 DD&A 2.57 2.42 2.29 2.23 2.05 Operating income $ 9.17 $ 3.78 $ 1.71 $ 6.22 $ 6.87 Production (BOE) 5,467 5,090 4,399 4,550 3,573 Production (Mw) 764 728 448 446 412 Proved Reserves Information: Total BOE 107,361 112,541 92,609 101,043 102,116 Present value (PV10) of estimated future cash flow before income taxes $ 721,770 $ 714,555 $ 113,811 $ 376,459 $ 634,579 Year-end average BOE price for PV10 purposes 20.63 19.41 7.05 12.19 18.37 Other: Return on average shareholders' equity 28.5% 16.5% 3.5% 18.1% 18.2% Return on average total assets 16.8% 9.0% 2.2% 10.9% 13.3% Total debt/total debt plus equity 14.7% 30.9% 21.9% 22.2% 29.8% Year-end stock price $ 13 3/8 $ 15 1/8 $ 14 3/16 $ 17 7/16 $ 14 3/8 Year-end market capitalization $ 294,699 $ 332,920 $ 312,247 $ 383,510 $ 315,471 (1)Including monthly expenses in excess of monthly revenues from cogeneration operations $ 0.89 $ 0.17 $ 0.14 $ 0.48 $ 0.23
15 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, 2000, 1999 and 1998 and the financial condition, liquidity and capital resources as of December 31, 2000 and 1999. 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, gas and electricity sold, the type and volume of oil and gas produced and electricity generated and the results of acquisition, development, exploitation and exploration activities. The average realized prices for oil, natural gas and electricity will fluctuate from one period to another due to regional market conditions and other factors, while oil prices will also be strongly influenced by world supply and demand. The aggregate amount of oil and gas produced may fluctuate based on the success of development and exploitation of oil and gas reserves pursuant to current reservoir management. The cost of natural gas used in the Company's steaming operations and electrical generation, production rates, labor, maintenance expenses and production taxes 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 the year 2000 was $37.2 million, up 107% and 854%, respectively, from $18 million in 1999 and $3.9 million in 1998. Net income rose 22% to $9.9 million in the fourth quarter of 2000 from $8.1 million in the fourth quarter of 1999. Results for the year 2000 represented the highest net income, cash flow and production ever achieved by the Company in any fiscal year and the fourth quarter was the sixth quarter in a row of increasing net income. Record net income for the year and the fourth quarter were primarily related to record production volumes sold at historically high oil prices. The following table presents certain operating data for the years ended December 31, 2000, 1999 and 1998: 2000 1999 1998 Net production - BOE/D 14,937 13,946 12,053 Per BOE: Average sales price $ 21.72 $ 13.07 $ 9.05 Operating costs(1) 8.13 5.12 3.56 Production taxes .43 .52 .59 Total operating costs 8.56 5.64 4.15 DD&A 2.57 2.42 2.29 G&A 1.42 1.23 .90 Interest expense .58 .78 .44 (1)Including monthly expenses in excess of monthly revenues from cogeneration operations of $0.89, $0.17 and $0.14 in 2000, 1999 and 1998, respectively. BOE/D - Barrels of oil equivalent per day Operating income from oil and gas producing operations of $58.3 million was up $32.4 million, or 125%, from $25.9 million in 1999 and up $46.5 million, or 394% from $11.8 million in 1998. The improvement in 2000 compared with both 1999 and 1998 was due to higher oil prices and higher production, partially offset by higher operating costs. The average price received per BOE in 2000 was $21.72, dramatically higher than $13.07 in 1999 and the historical low of $9.05 in 1998 and represented the highest average price ever for the Company's hydrocarbon production. These prices are net of hedging costs of $1.31 and $.51 per BOE for 2000 and 1999, respectively, and include the profit from hedging of $.48 for 1998. These three years dramatically demonstrate the high degree of price volatility for the Company's crude oil. 16 The second factor which increased the Company's operating income for the year was the increase in production volumes achieved by the Company. The Company achieved production on a BOE/D basis for 2000 of 14,937, up from 13,946 in 1999 and 12,053 in 1998. On a percentage basis, these results were a 7% and 24% increase over 1999 and 1998 levels, respectively. The Company's purchase of the Placerita properties in February 1999, which currently produce approximately 3,500 BOE/D, and total Company development costs of over $34 million in 1999 and 2000 were the primary contributing factors to the production increases over 1998 levels. Operating costs per barrel in 2000 were $8.56, up from $5.64 for 1999 and $4.15 in 1998. The largest factors in the increase in 2000 compared to 1999 was a substantial increase in the price of natural gas used to fire the Company's cogeneration facilities and conventional steam generators, the cost of running conventional generators close to capacity, the added cost of operating the Company's marginal producers and certain environmental costs, 3D seismic costs and general cost increases in contractor services. Gas prices/Mmbtu averaged $4.89 in 2000, up 80% and 115% from $2.71 in 1999 and $2.27 in 1998, respectively. Effective December 1, 2000, average gas costs for the Company reached $14.14 per Mmbtu. The price of natural gas at the SoCal border broke out of its long-term historical linkage of approximating the NYMEX Henry Hub (HH) price. In December, the SoCal border price exceeded the HH price by approximately $7.30/Mmbtu, and has continued to average over $5.00/Mmbtu above HH. This phenomena is having significant negative impacts on heavy oil production in California and has significantly contributed to escalating electricity prices in the Western United States. Due to these unprecedented, extraordinarily high natural gas prices, the Company has curtailed most of its conventional steam generation. High natural gas prices have continued into the first quarter of 2001 and have rendered conventional steam generation uneconomic even at the current strong oil prices. The Company intends to resume operation of these steam generators as soon as it is economic to do so. The Company's cogeneration facilities operated close to 100% of the time, not covered by scheduled outages, for all of 2000. The Company's cogeneration facilities sell power under standard offer contracts which link electricity payments to the price of natural gas at the SoCal border. Thus, the economics of producing steam via cogeneration facilities under these contracts is superior to conventional steam generation. The much publicized California electricity crisis, with California's two largest utilities (PG&E and Edison) nearing bankruptcy, has negatively impacted Berry and its operations. Edison failed to pay Berry for November and December 2000 power deliveries, which were due in early January and February 2001, respectively. In addition, they also failed to pay for January 2001 deliveries which were due in early March. PG&E made full payments for November 2000 and only partial payments, of approximately 15%, for December 2000 and January 2001 deliveries. Effective February 1, 2001, Management determined that it was not in the Company's best interest to operate its 38 Mw facility at its South Midway-Sunset field nor one of its 21 Mw units at Placerita. In addition, effective February 17, 2001, the Company's 18 Mw facility, also located at its South Midway-Sunset field was also shut down. While the Company's future thermal oil production will suffer as a result of the significant withdrawal of steam from the oil reservoir, the Company will not allow its strong financial condition to materially deteriorate while waiting for a political solution to California's much publicized electricity crisis. The Company is vigorously pursuing every opportunity to restart its cogeneration facilities and sell its power to a creditworthy purchaser. The Company implemented a record capital budget in the year 2000 of $25.3 million. Of this total, $24.3 million was spent on well development and facility enhancements. During 2000, 81 new wells were drilled, including 17 horizontal wells and 76 workovers were completed on existing wells. As was discussed above, these expenditures were instrumental in improving production to over 17,000 barrels per day at year-end 2000 and should result in increasing the ultimate recovery of oil from the Company's properties. Depreciation, depletion and amortization (DD&A) on a per barrel basis increased to $2.57, up from $2.42 in 1999 and $2.29 in 1998. The increase from prior years, which is calculated on a units of production basis, was primarily due to production acceleration achieved through increased steaming and development activity and the higher capital program. The Company believes that its DD&A rate per barrel for 2001 will be similar or slightly higher than its 2000 rate. 17 General General and administrative (G&A) expenses in 2000 were $7.8 million, up 24% and 95% from $6.3 million in 1999 and $4 million in 1998. On a per barrel basis, these results equate to $1.42 in 2000, up from $1.23 in 1999 and $.90 in 1998. The primary reasons for the increase were higher salaries, the hiring of additional employees and higher legal fees, the majority of which related to a lawsuit that was settled in the first quarter of 2000 and which arose from a company that Berry purchased in 1988. In 1998, the Company reduced salaries, staff and numerous other costs to preserve cash flow in the low oil price environment. These measures resulted in very low, but unsustainable G&A costs on a per barrel basis. Interest expense fell to $3.2 million in 2000 from $4.0 million in 1999, but remained higher than the $1.9 million experienced in 1998. Berry acquired certain properties in the Placerita field in Los Angeles County, California in January of 1999. The financing of those properties resulted in higher interest costs in 1999. The Company aggressively reduced its total debt from $52 million at December 31, 1999 to just $25 million at December 31, 2000. This reduction, partially offset by higher interest rates, resulted in the reduced interest expense experienced in 2000 compared with 1999 results. In early 2001, the Company increased its borrowing to $70 million to ensure liquidity during this period of nonpayment for electricity deliveries by utilities and higher natural gas prices, to pay an annual price-based royalty on one of its properties and for other general purposes. Even though the Company's pre-tax net income was up sharply in 2000 versus 1999 and 1998, the Company invested heavily in the development of its thermally enhanced oil recovery (EOR) projects, both through capital expenditures and increased steam injection volumes, thus, the Company earned significant EOR tax credits. This is the third consecutive year that the Company has achieved an effective tax rate below 30%, versus the statutory rate of 40%. The Company believes it will continue to earn significant EOR tax credits in the future and have an effective tax rate well below 40%. Financial Condition, Liquidity and Capital Resources During 2000, the Company aggressively reduced its long-term debt by $27 million. As a result, working capital at December 31, 2000 was negative $1.2 million, down from positive $8.4 million in 1999 and $9.1 million in 1998. Net cash provided by operations was $65.9 million, a Company record and 166% and 231% higher than $24.8 million in 1999 and $19.9 million in 1998. The Company employed these resources to fund its $25.3 million capital program, reduce debt by $27 million, pay dividends of $8.8 million and make a $3 million acquisition. Crude oil prices remain very attractive and, while the Company has identified significant development opportunities, the Company intends to postpone the majority of those projects until the Company can restart its cogeneration facilities and inject that steam into the oil reservoirs. The 2001 budget focuses on further development of the Company's core properties and development of certain underdeveloped portions of its Placerita area properties. The Company has reduced its 2001 budget from its original $25 million to a current level of $11 million, which includes only essential projects and profitable projects based upon current economic conditions. The Company is pursuing adding additional cogeneration facilities to fully develop its properties and replace its conventional steam generation sources. As a generator of electricity, the Company is directly affected by the well-publicized California electrical crisis. As of March 7, 2001, the Company is owed a total of $25 million for electricity sales to Edison and PG&E from November 2000 through February 2001. Management anticipates that these amounts due will be paid in their entirety, however, the timing of the payments is uncertain at this time. In addition, if the Company is unable to collect a significant portion of these receivables, the write-off of such portion may have an adverse effect on the financial position or results of operations 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. 18 Recent Accounting Developments In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Standard No. 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). The statement requires the recognition of all derivatives as either assets or liabilities in the balance sheet and the measurement of those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the planned use of the derivative and the resulting designation. The adoption of SFAS 133 in the fourth quarter of 2000 did not have a significant impact on the Company's financial position, results of operations or cash flows. In December 1999, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 101, Revenue Recognition in Financial Statements (SAB 101). SAB 101 provides guidance for revenue recognition under certain circumstances. The adoption of SAB 101 in 2000 did not have a significant impact on the Company's financial position, results of operations or cash flows. In March 2000, the FASB, issued FASB Interpretation No. 44, (FIN 44), Accounting for Certain Transactions Involving Stock Compensation an Interpretation of APB Opinion No. 25. FIN 44 clarifies the application of APB Opinion No. 25 for (a) the definition of employee for purposes of applying APB Opinion No. 25, (b) the criteria for determining whether a plan qualifies as a noncompensatory plan, (c) the accounting consequence of various modifications to the terms of a previously fixed stock option or award, and (d) the accounting for an exchange of stock compensation awards in a business combination. FIN 44 became effective July 1, 2000, but certain conclusions cover specific events that occur after either December 15, 1998 or January 12, 2000. The adoption of FIN 44 did not have a significant impact on the Company's financial position, results of operations or cash flows. Forward Looking Statements "Safe harbor 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, gas and electricity, SoCal border pricing for natural gas, pipeline capacity for natural gas to and within California, the non-existence of a liquid marketplace for electricity purchases and sales within California, competition, environmental risks, litigation uncertainties, drilling, development and operating risks, uncertainties about the estimates of reserves, the prices of goods and services, the availability of drilling rigs and other support services, legislative, California Public Utilities Commission, Federal Energy Regulatory Commission, and/or judicial decisions and other government regulations. 19 Item 8. Financial Statements and Supplementary Data BERRY PETROLEUM COMPANY Index to Financial Statements and Supplementary Data Page Report of PricewaterhouseCoopers LLP, Independent Accountants 21 Balance Sheets at December 31, 2000 and 1999 22 Statements of Operations for the Years Ended December 31, 2000, 1999 and 1998 23 Statements of Comprehensive Income for the Years Ended December 31, 2000, 1999 and 1998 23 Statements of Shareholders' Equity for the Years Ended December 31, 2000, 1999 and 1998 24 Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998 25 Notes to the Financial Statements 26 Supplemental Information About Oil & Gas Producing Activities 38 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. 20 REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders and Board of Directors Berry Petroleum Company In our opinion, the accompanying balance sheets and the related statements of operations and shareholders' equity and of cash flows present fairly, in all material respects, the financial position of Berry Petroleum Company (the "Company") at December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. 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 of these statements in accordance with auditing standards generally accepted in the United States of America which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP March 9, 2001 Los Angeles, California 21 BERRY PETROLEUM COMPANY Balance Sheets December 31, 2000 and 1999 (In Thousands, Except Share Information) 2000 1999 ASSETS Current assets: Cash and cash equivalents $ 2,731 $ 980 Short-term investments available for sale 582 596 Accounts receivable 26,420 15,303 Prepaid expenses and other 5,190 2,080 -------- -------- Total current assets 34,923 18,959 Oil and gas properties (successful efforts basis), buildings and equipment, net 201,643 186,519 Other assets 1,793 2,171 -------- -------- $ 238,359 $ 207,649 ======== ======== LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable $ 28,678 $ 7,203 Accrued liabilities 2,288 1,999 Federal and state income taxes payable 5,110 1,322 -------- -------- Total current liabilities 36,076 10,524 Long-term debt 25,000 52,000 Deferred income taxes 32,059 28,912 Commitments and contingencies (Note 9) - - 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; 21,134,667 shares issued and outstanding (21,112,334 in 1999) 211 211 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 53,686 53,487 Accumulated other comprehensive income 441 - Retained earnings 90,877 62,506 -------- -------- Total shareholders' equity 145,224 116,213 -------- -------- $ 238,359 $ 207,649 ======== ======== The accompanying notes are an integral part of these financial statements. 22 BERRY PETROLEUM COMPANY Statements of Operations Years ended December 31, 2000, 1999 and 1998 (In Thousands, Except Per Share Data) 2000 1999 1998 Revenues: Sales of oil and gas $ 118,801 $ 66,615 $ 39,858 Sales of electricity 52,765 33,731 15,680 Interest and dividend income 447 674 805 Other income (expense), net 36 186 (764) -------- -------- -------- 172,049 101,206 55,579 -------- -------- -------- Expenses: Operating costs - oil and gas production 46,789 28,697 18,272 Operating costs - electricity generation 48,614 27,062 15,236 Depreciation, depletion & amortization 14,030 12,294 10,080 General and administrative 7,754 6,269 3,975 Interest expense 3,186 3,973 1,939 Impairment of properties - - 1,827 -------- -------- -------- 120,373 78,295 51,329 -------- -------- -------- Income before income taxes 51,676 22,911 4,250 Provision for income taxes 14,493 4,905 371 -------- -------- -------- Net income $ 37,183 $ 18,006 $ 3,879 ======== ======== ======== Basic net income per share $ 1.69 $ .82 $ .18 ======== ======== ======== Diluted net income per share $ 1.67 $ .82 $ .18 ======== ======== ======== Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share) 22,029 22,010 22,007 Effect of dilutive securities: Employee stock options 185 32 25 Other 26 7 5 -------- -------- -------- Weighted average number of shares of capital stock used to calculate diluted net income per share 22,240 22,049 22,037 ======== ======== ======== Statements of Comprehensive Income Years Ended December 31, 2000, 1999 and 1998 (In Thousands) 2000 1999 1998 Net income $ 37,183 $ 18,006 $ 3,879 Unrealized gains on derivatives 441 - - -------- -------- -------- Other comprehensive income $ 37,624 $ 18,006 $ 3,879 ======== ======== ======== The accompanying notes are an integral part of these financial statements. 23 BERRY PETROLEUM COMPANY Statements of Shareholders' Equity Years Ended December 31, 2000, 1999 and 1998 (In Thousands, Except Per Share Data)
Accumulated Capital in Other Excess of Retained Comprehensive Shareholders Class A Class B Par Value Earnings Income Equity Balances at January 1, 1998 $ 211 $ 9 $ 53,422 $ 58,229 $ - $ 111,871 Stock options exercised - - (58) - - (58) Deferred director fees - stock compensation - - 36 - - 36 Cash dividends declared - $.40 per share - - - (8,804) - (8,804) Net income - - - 3,879 - 3,879 ----- ----- ------- ------- ------ -------- Balances at December 31, 1998 211 9 53,400 53,304 - 106,924 Stock options exercised - - 2 - - 2 Deferred director fees - stock compensation - - 85 - - 85 Cash dividends declared - $.40 per share - - - (8,804) - (8,804) Net income - - - 18,006 - 18,006 ----- ----- ------- ------- ------ -------- Balances at December 31, 1999 211 9 53,487 62,506 - 116,213 Stock options exercised - - 90 - - 90 Deferred director fees - stock compensation - - 109 - - 109 Cash dividends declared - $.40 per share - - - (8,812) - (8,812) Unrealized gains on derivatives - - - - 441 441 Net income - - - 37,183 - 37,183 ----- ----- ------- ------- ------ -------- Balances at December 31, 2000 $ 211 $ 9 $ 53,686 $ 90,877 $ 441 $ 145,224 ===== ===== ======= ======= ====== ========
The accompanying notes are an integral part of these financial statements. 24 BERRY PETROLEUM COMPANY Statements of Cash Flows Years Ended December 31, 2000, 1999 and 1998 (In Thousands) 2000 1999 1998 Cash flows from operating activities: Net income $ 37,183 $ 18,006 $ 3,879 Depreciation, depletion and amortization 14,030 12,294 10,080 Impairment of properties - - 1,827 Increase in deferred income tax liability 3,147 263 2,740 Other, net 249 (208) (315) ------- ------- ------- Net working capital provided by operating activities 54,609 30,355 18,211 Decrease (increase) in current assets other than cash, cash equivalents and short-term investments (14,227) (7,839) 1,425 Increase in current liabilities other than notes payable 25,552 2,293 288 ------- ------- ------- Net cash provided by operating activities 65,934 24,809 19,924 ------- ------- ------- Cash flows from investing activities: Capital expenditures, excluding property acquisitions (25,253) (9,122) (6,981) Property/facility acquisitions (3,182) (33,605) (2,991) Proceeds from sale of assets 49 21 350 Purchase of short-term investments (584) (611) - Maturities of short-term investments 600 725 8 Contract purchases - (1,028) (240) ------- ------- ------- Net cash used in investing activities (28,370) (43,620) (9,854) ------- ------- ------- Cash flows from financing activities: Proceeds from issuance of long-term debt 1,000 35,000 - Payment of long-term debt (28,000) (13,000) (2,000) Dividends paid (8,812) (8,804) (8,804) Other, net (1) (463) 36 ------- ------- ------- Net cash provided by (used in) financing activities (35,813) 12,733 (10,768) ------- ------- ------- Net increase (decrease) in cash and cash equivalents 1,751 (6,078) (698) Cash and cash equivalents at beginning of year 980 7,058 7,756 ------- ------- ------- Cash and cash equivalents at end of year $ 2,731 $ 980 $ 7,058 ======= ======= ======= Supplemental disclosures of cash flow information: Interest paid $ 2,999 $ 4,546 $ 1,924 ======= ======= ======= Income taxes paid $ 9,712 $ 4,079 $ 270 ======= ======= ======= The accompanying notes are an integral part of these financial statements. 25 BERRY PETROLEUM COMPANY Notes to the Financial Statements 1. General The Company is an independent energy company engaged in the production, development, acquisition, exploitation and exploration of crude oil and natural gas. Substantially all of the Company's oil and gas reserves are located in California. Approximately 99% of the Company's production is heavy crude oil, which is principally sold to other oil companies for processing in refineries located in California. The Company has invested in cogeneration facilities which provides steam required for the extraction of heavy oil and which generates electricity for sale. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities 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 The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. 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. 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 and develop proved reserves and to drill and complete exploratory wells that find proved reserves are capitalized and depleted over the remaining life of the reserves using the units-of-production method. Exploratory dry hole 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, including cogeneration facilities and other steam generation equipment and facilities, is computed using the units-of-production method or on a straight-line basis over estimated useful lives ranging from 10 to 20 years. 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. Assets are grouped at the field level and if it is determined that the book value of long-lived assets cannot be recovered by estimated future undiscounted cash flows, they are written down to fair value. 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. 26 BERRY PETROLEUM COMPANY Notes to the Financial Statements 2. Summary of Significant Accounting Policies (cont'd) Hedging From time to time, the Company utilizes options, swaps and collars (derivative instruments) to manage its commodity price risk. On October 1, 2000 , the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) which established new accounting and reporting requirements for derivative instruments and hedging activities. SFAS 133 requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, or in the case of options based on the change in intrinsic value. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss, such as time value for option contracts, is recognized immediately as operating costs in the statement of operations. Upon adoption, the Company determined that it had contracts related to the long-term sale of crude oil and electricity that met the definition of a derivative under SFAS 133. However, these derivative instruments are considered normal sales under provisions of SFAS 133 and are, therefore, specifically exempt from the accounting and disclosures detailed above. At December 31, 2000, all of the Company's SFAS 133 derivative instruments were either exempt from the standard or designated as cash flow hedges and no amounts were reclassified into earnings as a result of the discontinuance of cash flow hedges because it was determined that the original forecasted transaction was no longer probable. See Note 3 - Fair Value of Financial Instruments. Cogeneration Operations The Company operates cogeneration facilities to help minimize the cost of producing steam, which is a necessity in its thermal oil and gas producing operations. Such cogeneration operations produce electricity as a by-product from the production of steam. In prior years, amounts billed for the sale of electricity were reported as a reduction to operating costs in the Company's financial statements. In 2000, the Company modified its financial statement presentation. These amounts are now reported as revenues from the sale of electricity. The Company has considered allocating the cost of operating the cogeneration plants between those costs incurred in producing steam and those in producing electricity, but determined any such allocation to be arbitrary and not meaningful to financial statement presentation. Therefore, in each monthly accounting period, the cost of operating the cogeneration facilities in each field of operation, up to the amount of the electricity sales, is considered operating costs from electricity generation. Costs in excess of electricity revenue during each period, if any, are considered cost of producing steam and are reported in operating costs - oil and gas production. Conventional Steam Costs The costs of producing conventional steam are included in operating costs - oil and gas production. Revenue Recognition Revenues associated with sales of crude oil, natural gas, and electricity are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from crude oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of the Company's net working interest (entitlement method). 27 BERRY PETROLEUM COMPANY Notes to the Financial Statements 2. Summary of Significant Accounting Policies (cont'd) Stock-Based Compensation As allowed in SFAS 123, "Accounting for Stock-Based Compensation", 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 of SFAS 123 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. 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 basis 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. Net Income Per Share Basic net income per share is computed by dividing income available to common shareholders (the numerator) by the weighted average number of common shares outstanding (the denominator). The computation of diluted net income per share is similar to the computation of basic net income per share except that the denominator is increased to include the dilutive effect of the additional common shares that would have been outstanding if all convertible securities had been converted to common shares during the period. Recent Accounting Developments In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS 133 "Accounting for Derivative Instruments and Hedging Activities". The statement requires the recognition of all derivatives as either assets or liabilities in the balance sheet and the measurement of those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the planned use of the derivative and the resulting designation. The adoption of SFAS 133 in the fourth quarter of 2000 did not have a significant impact on the Company's financial position, results of operations or cash flows. In December 1999, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 101, Revenue Recognition in Financial Statements (SAB 101). SAB 101 provides guidance for revenue recognition under certain circumstances. The adoption of SAB 101 in 2000 did not have a significant impact on the Company's financial position, results of operations or cash flows. In March 2000, the FASB, issued FASB Interpretation No. 44, (FIN 44), Accounting for Certain Transactions Involving Stock Compensation an Interpretation of APB Opinion No. 25. FIN 44 clarifies the application of APB Opinion No. 25 for (a) the definition of employee for purposes of applying APB Opinion No. 25, (b) the criteria for determining whether a plan qualifies as a noncompensatory plan, (c) the accounting consequence of various modifications to the terms of a previously fixed stock option or award, and (d) the accounting for an exchange of stock compensation awards in a business combination. FIN 44 became effective July 1, 2000, but certain conclusions cover specific events that occur after either December 15, 1998 or January 12, 2000. The adoption of FIN 44 did not have a significant impact on the Company's financial position, results of operations or cash flows. 28 BERRY PETROLEUM COMPANY Notes to the Financial Statements Summary of Significant Accounting Policies (cont'd) Reclassifications Certain reclassifications have been made to the 1999 and 1998 financial statements to conform with the 2000 presentation. 3. Fair Value of Financial Instruments The carrying amounts of cash and short-term investments are not materially different from their fair values because of the short maturity of those instruments. Cash equivalents consist principally of commercial paper investments. Cash equivalents of $2.3 million and $.2 million at December 31, 2000 and 1999, respectively, are stated at cost, which approximates market. The Company's short-term investments available for sale at December 31, 2000 and 1999 consist of a United States treasury note that matures in less than one year. The carrying value of the Company's long-term debt is assumed to approximate its fair value since it is carried at current interest rates. For the three years ended December 31, 2000, realized and unrealized gains and losses were insignificant to the financial statements. A United States treasury note with a market value of $.6 million is pledged as collateral to the California State Lands Commission as a performance bond on the Company's Montalvo properties. To protect the Company's revenues from potential price declines, the Company entered into bracketed zero cost collar hedge contracts with California refiners covering 3,000 BPD to 6,500 BPD of its crude oil production during 1998, 1999 and 2000. The posted price of the Company's 13 degree API gravity crude oil was used as the basis for the hedge. The most recent contracts expired on December 31, 2000. Gains and losses from these cash flow hedges are reported in revenues from oil and gas producing operations in the Company's financial statements. The Company recorded losses of $7.1 million and $2.6 million in 2000 and 1999, respectively, and a gain of $2.2 million during 1998. At the present time, the Company has no plans to enter into similar contracts, but may do so in the future if deemed appropriate as market conditions change. In December 2000, the Company entered into a series of derivative contracts to reduce exposure to unfavorable changes in natural gas prices. These contracts limit the price the Company pays for 4,500 Mmbtu/day of natural gas used by its cogeneration facilities for the three month period ending March 31, 2001. During December 2000, the Company recorded an expense of $.3 million related to the ineffective portion of these derivative instruments and, at the end of the year, recorded $.4 million in other comprehensive income, after-tax, related to unrealized gains on derivatives. 29 BERRY PETROLEUM COMPANY Notes to the Financial Statements 4. Concentration of Credit Risks The Company sells oil, gas and natural gas liquids to pipelines, refineries and major oil companies and electricity to major utility companies. Credit is extended based on an evaluation of the customer's financial condition and historical payment record. For the three years ended December 31, 2000, the Company has experienced no credit losses on the sale of oil, gas, natural gas liquids, electricity or derivatives instruments. However, the Company has not been fully paid for certain electricity sales that occurred in late 2000, see Note 9. The Company places its temporary cash investments with high quality financial institutions and limits the amount of credit exposure to any one financial institution. For the three years ended December 31, 2000, the Company has not incurred losses related to these investments. The following summarizes the accounts receivable balances at December 31, 2000 and 1999 and sales activity with significant customers for each of the years ended December 31, 2000, 1999 and 1998 (in thousands): Sales Accounts Receivable For the Year Ended December 31, Customer Dec. 31, 2000 Dec. 31, 1999 2000 1999 1998 Oil & Gas Sales: A $ 9,699 $ 3,975 $ 87,613 $ 30,289 $ 12,409 B 1,246 1,312 18,000 6,262 2,187 C - 1,627 13,080 11,467 7,281 D 24 2,040 12,390 15,064 6,282 E 391 406 5,499 7,890 10,785 ------ ------ ------- ------- ------- $ 11,360 $ 9,360 $ 136,582 $ 70,972 $ 38,944 ====== ====== ======= ======= ======= Electricity Sales: F $ 8,660 $ 3,141 $ 26,769 $ 15,603 $ 15,624 G 5,625 2,034 23,124 16,013 - ------ ------ ------- ------- ------- $ 14,285 $ 5,175 $ 49,893 $ 31,616 $ 15,624 ====== ====== ======= ======= ======= 30 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): 2000 1999 Oil and gas: Proved properties: Producing properties, including intangible drilling costs $ 160,484 $ 146,616 Lease and well equipment 138,007 123,026 -------- -------- 298,491 269,642 Less accumulated depreciation, depletion and amortization 98,925 85,319 -------- -------- 199,566 184,323 -------- -------- Commercial and other: Land 173 170 Buildings and improvements 4,086 4,072 Machinery and equipment 4,553 4,211 -------- -------- 8,812 8,453 Less accumulated depreciation 6,735 6,257 -------- -------- 2,077 2,196 -------- -------- $ 201,643 $ 186,519 ======== ======== The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed (in thousands): 2000 1999 1998 Acquisition of properties/ facilities(1) $ 3,204 $ 34,167 $ 2,991 Development 26,145 9,195 6,896 -------- -------- -------- $ 29,349 $ 43,362 $ 9,887 ======== ======== ======== (1) Includes cogeneration facility costs and certain closing and consultant costs related to the acquisitions, but excluding electricity contract costs. In 2000, the Company purchased the Castruccio property at the Placerita field for approximately $3 million, and the property has approximately 1.5 million barrels of proved reserves at year-end. In 1999, the Company completed the Placerita acquisition for a purchase price of approximately $35 million, including the purchase of a 42 megawatt cogeneration facility and related electricity contracts. These properties had proved reserves of approximately 20 million barrels upon acquisition. In 1998, the Company completed an acquisition with proved reserves of approximately 1 million barrels and a steam contract located adjacent to the Company's core South Midway-Sunset producing properties. 31 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 corporate overhead and interest costs) for the three years ended December 31 are as follows (in thousands): 2000 1999 1998 Sales to unaffiliated parties $ 118,801 $ 66,615 $ 39,858 Production costs (46,789) (28,697) (18,272) Depreciation, depletion and amortization (13,712) (12,020) (9,686) -------- -------- -------- 58,300 25,898 11,900 Income tax expenses (17,292) (5,856) (3,026) -------- -------- -------- Results of operations from producing and exploration activities $ 41,008 $ 20,042 $ 8,874 ======== ======== ======== 6. Debt Obligations 2000 1999 Long-term debt for the years ended December 31 (in thousands): Revolving bank facility $ 25,000 $ 52,000 ======== ======== On July 22, 1999, the Company executed an Amended and Restated Credit Agreement (the Agreement) with a banking group, which consists of four banks, for a $150 million five-year unsecured bullet loan. At December 31, 2000 and 1999, the Company had $25 and $52 million, respectively, outstanding under the Agreement. Subsequent to year end 2000, the Company increased its borrowings to $70 million to be utilized for general corporate purposes. The maximum amount available is subject to an annual redetermination of the borrowing base in accordance with the lender's customary procedures and practices. Both the Company and the banks have bilateral rights to one additional redetermination each year. The revolving period is scheduled to terminate on January 21, 2004. Interest on amounts borrowed is charged at the lead bank's base rate or at London Interbank Offered Rates (LIBOR) plus 75 to 150 basis points, depending on the ratio of outstanding credit to the borrowing base. The weighted average interest rate on outstanding borrowings at December 31, 2000 was 7.43%. The Company pays a commitment fee of 25 to 35 basis points on the available unused portion of the commitment. The credit agreement contains other restrictive covenants as defined in the Agreement. Previously, on January 21, 1999, the Company amended its existing credit agreement with its lead bank primarily to increase the borrowing base to $110 million and add two additional banks to its syndication. 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. 32 BERRY PETROLEUM COMPANY Notes to the Financial Statements 7. Shareholders' Equity (cont'd) In November 1999, the Company adopted a Shareholder Rights Agreement and declared a dividend distribution of one Right for each outstanding share of Capital Stock on December 8, 1999. Each Right, when exercisable, entitles the holder to purchase one one-hundredth of a share of a Series B Junior Participating Preferred Stock, or in certain cases other securities, for $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 on December 8, 2009 or may be redeemed by the Company at $.01 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 B Junior Participating Preferred Stock and reserved for issuance upon exercise of the Rights. This Shareholder Rights Agreement replaces the Shareholder Rights Agreement approved in December 1989 which expired on December 8, 1999. In conjunction with the acquisition of the Tannehill assets in 1996, 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 21,325, 2,745 and 15,268 shares in 2000, 1999 and 1998, respectively, through its stock option plan. At December 31, 2000, dividends declared on 4,000,894 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. Income Taxes The Provision for income taxes consists of the following (in thousands): 2000 1999 1998 Current: Federal $ 10,336 $ 2,661 $ (716) State 3,165 928 (881) ------- ------- ------- 13,501 3,589 (1,597) ------- ------- ------- Deferred: Federal 1,787 1,979 1,968 State (795) (663) - ------- ------- ------- 992 1,316 1,968 ------- ------- ------- Total $ 14,493 $ 4,905 $ 371 ======= ======== ======= 33 BERRY PETROLEUM COMPANY Notes to the Financial Statements 8. Income Taxes (cont'd) 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 consist of the following at December 31 (in thousands): 2000 1999 1998 Deferred tax asset Federal benefit of state taxes $ 871 $ 392 $ - Credit/deduction carryforwards 7,761 4,434 2,602 Other, net 1,261 367 322 ------- ------- ------- 9,893 5,193 2,924 ------- ------- ------- Deferred tax liability Depreciation and depletion (39,894) (33,452) (29,806) Other, net 246 (504) (565) ------- ------- ------- (39,648) (33,956) (30,371) ------- ------- ------- Net deferred tax liability $ (29,755) $ (28,763) $ (27,447) ======= ======= ======= Reconciliation of the statutory federal income tax rate to the effective income tax rate follows: 2000 1999 1998 Tax computed at statutory federal rate 35.0% 35.0% 34.0% State income taxes, net of federal benefit 3.4 .3 2.0 Tax credits (11.0) (12.9) (24.3) Other .7 (1.0) (3.0) ----- ----- ----- Effective tax rate 28.1% 21.4% 8.7% ===== ===== ===== The Company has approximately $6.1 million of federal and $4.5 million of state enhanced oil recovery (EOR) tax credit carryforwards available to reduce future income taxes. EOR credits of $7.9 million and $2.7 million will expire in 2014 and 2015, respectively. 34 BERRY PETROLEUM COMPANY Notes to the Financial Statements 9. Contingency The Company has been severely impacted by the current electricity crisis that exists in California. As of December 31, 2000, the Company was owed a total of $14.3 million from Southern California Edison Company (Edison) and Pacific Gas & Electric Company (PG&E), which represented amounts due for the sale of electricity from November and December 2000. Since year-end, the Company has received $3.2 million, of this amount, from PG&E, thus payments for a total of $11.1 million remain outstanding related to November and December deliveries. A total of $13.8 million is also due for January and February 2001 deliveries, resulting in a total receivable at March 9, 2001 of $25 million; $12.1 million and $12.9 million from PG&E and Edison, respectively. The Company shut down the majority of its cogeneration operations during February 2001 as a result of this situation and expects its receivable for March power deliveries to be approximately $2 million. The Company anticipates that this situation will be resolved, these receivables will be paid in full and the Company will return to normal operations. However, the Company cannot estimate the timing when this will occur. In addition, if the Company is unable to collect a significant portion of these receivables, the write-off of such portion may have a material adverse effect on the financial position or results of operations of the Company. 10. Stock Option Plan On December 2, 1994, the Board of Directors of the Company adopted the Berry Petroleum Company 1994 Stock Option Plan which was restated and amended in December 1997 (the 1994 Plan) and approved by the shareholders in May 1998. The 1994 Plan provides for the granting of stock options to purchase up to an aggregate of 2,000,000 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 1, 2000 and December 4, 1998, 262,000 and 434,000 options, respectively, were issued to certain key employees at an exercise price of $15.6875 and $12.50, 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. No employee options were issued in 1999. 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 5,000 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 the 1994 Plan, 40,000, 40,000 and 45,000 options, respectively, were issued on December 2, 2000, 1999 and 1998, (5,000 options to each of the non-employee Directors each year) at an exercise price of $15.6875, $14.0625 and $12.625 per share, respectively. In addition, 25,000 options were granted on May 15, 1998 to the non-employee Directors on December 2, 1997, at an exercise price of $18.9375. The Company applies APB No. 25 and related interpretations in accounting for its stock option plan. The options issued per the 1994 Plan were issued at market price. Compensation recognized related to the 1994 Plan was $.3 million in 2000, $0 in 1999 and $.4 million in 1998. Under SFAS 123, compensation cost would be recognized for the fair value of the employee's option rights. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: 2000 1999 1998 Yield 2.77% 2.75% 2.87% Expected option life - years 4.5 4.0 4.0 Volatility 36.53% 34.24% 28.13% Risk-free interest rate 4.85% 6.33% 4.68% 35 BERRY PETROLEUM COMPANY Notes to the Financial Statements 10. Stock Option Plan (cont'd) 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): 2000 1999 1998 Net income as reported $ 37,183 $ 18,006 $ 3,879 Pro forma 36,581 17,343 3,244 Net income per share as reported 1.69 .82 .18 Pro forma 1.66 .79 .15 The following is a summary of stock-based compensation activity for the years 2000, 1999 and 1998. 2000 1999 1998 Options Options Options SARs --------- --------- --------- ------ Balance outstanding, January 1 1,220,630 1,227,630 924,429 1,120 Granted 302,000 40,000 504,000 - Exercised (114,793) (22,000) (75,799) (1,120) Canceled/expired - (25,000) (125,000) - --------- --------- --------- ------ Balance outstanding, December 31 1,407,837 1,220,630 1,227,630 - ========= ========= ========= ====== Balance exercisable at December 31 872,587 697,630 449,880 - ========= ========= ========= ====== Available for future grant 364,800 666,800 681,800 - ========= ========= ========= ====== Exercise price-range $ 16.4375 $ 14.125 $ 9.80 $ 9.80 to 19.00 to 14.25 to 19.375 Weighted average remaining contractual life (years) 8 8 9 - Weighted average fair value per option granted during the year $ 4.62 $ 5.14 $ 2.82 N/A 36 BERRY PETROLEUM COMPANY Notes to the Financial Statements 10. Stock Option Plan (cont'd) Weighted average option exercise price information for the years 2000, 1999 and 1998 as follows: 2000 1999 1998 Outstanding at January 1 $ 14.15 $ 14.18 $ 14.71 Granted during the year 15.69 14.06 12.83 Exercised during the year 12.91 12.40 11.42 Expired during the year - 16.69 14.34 Outstanding at December 31 14.58 14.15 14.18 Exercisable at December 31 14.50 14.21 14.17 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 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 targets are achieved. The Company's contributions to the 401(k) Plan were $.5 million in 2000, $.3 million in 1999 and $.2 million in 1998. 12. Quarterly Financial Data (unaudited) The following is a tabulation of unaudited quarterly operating results for 2000 and 1999 (in thousands, except per share data): Basic Net Diluted Net Operating Gross Net Income Income 2000 Revenues Profit Income Per Share Per Share First Quarter $ 35,136 $ 16,069 $ 8,859 $ .40 $ .40 Second Quarter 36,446 14,886 8,894 .40 .40 Third Quarter 45,939 15,096 9,578 .43 .43 Fourth Quarter 54,045 16,403 9,852 .45 .44 -------- -------- ------- ------ ------ $ 171,566 $ 62,454 $ 37,183 $ 1.69 $ 1.67 ======== ======== ======= ====== ====== 1999 First Quarter $ 17,054 $ 1,985 $ 544 $ .02 $ .02 Second Quarter 21,804 6,405 3,247 .15 .15 Third Quarter 27,879 10,232 6,099 .28 .28 Fourth Quarter 33,609 13,944 8,116 .37 .37 -------- -------- ------- ------ ------ $ 100,346 $ 32,566 $ 18,006 $ .82 $ .82 ======== ======== ======= ====== ====== 37 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 as of December 31, 2000, 1999 and 1998. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves. The information provided does not represent Management's estimate of the Company's expected future cash flows or value of proved oil and gas reserves. Changes in estimated reserve quantities The net interest in estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas at December 31, 2000, 1999 and 1998, and changes in such quantities during each of the years then ended were as follows (in thousands): 2000 1999 1998 Oil Gas Oil Gas Oil Gas Mbbls Mmcf Mbbls Mmcf Mbbls Mmcf Proved developed and undeveloped reserves: Beginning of year 111,888 3,920 91,933 4,060 100,454 3,531 Revision of previous estimates (1,284) 463 3,126 40 (4,894) 774 Production (5,434) (199) (5,060) (180) (4,359) (245) Purchase of reserves in place 1,494 - 21,889 - 732 - ------- ------ ------- ------ ------- ------ End of year 106,664 4,184 111,888 3,920 91,933 4,060 ======= ====== ======= ====== ======= ====== Proved developed reserves: Beginning of year 86,717 1,371 83,532 1,604 86,858 1,457 ======= ====== ======= ====== ======= ====== End of year 81,132 1,635 86,717 1,371 83,532 1,604 ======= ====== ======= ====== ======= ====== 38 BERRY PETROLEUM COMPANY Supplemental Information About Oil & Gas Producing Activities (Unaudited) (Cont'd) The standardized measure has been prepared assuming year end sales prices adjusted for fixed and determinable contractual price changes, current costs and statutory tax rates (adjusted for tax credits and other items), and a ten percent annual discount rate. No deduction has been made for depletion, depreciation or any indirect costs such as general corporate overhead or interest expense. Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves (in thousands): 2000 1999 1998 Future cash inflows $ 2,268,932 $ 2,208,964 $ 656,607 Future production and development costs (653,808) (647,720) (388,546) Future income tax expenses (512,012) (502,951) (33,577) --------- --------- --------- Future net cash flows 1,103,112 1,058,293 234,484 10% annual discount for estimated timing of cash flows (599,530) (561,811) (127,967) --------- --------- --------- Standardized measure of discounted future net cash flows $ 503,582 $ 496,482 $ 106,517 ========= ========= ========= Pre-tax standardized measure of discounted future net cash flows $ 721,770 $ 714,555 $ 113,811 ========= ========= ========= Average sales prices at December 31: Oil ($/bbl) $ 20.63 $ 19.41 $ 7.05 Gas ($/mcf) $ 10.94 $ 2.11 $ 2.10 Changes in standardized measure of discounted future net cash flows from proved oil and gas reserves (in thousands): 2000 1999 1998 Standardized measure - beginning of year $ 496,482 $ 106,517 $ 267,594 --------- --------- --------- Sales of oil and gas produced, net of production costs (72,358) (44,587) (22,030) Revisions to estimates of proved reserves: Net changes in sales prices and production costs 98,744 440,729 (216,265) Revisions of previous quantity estimates (9,295) 20,919 (8,400) Change in estimated future development costs (78,328) (24,709) (17,262) Purchases of reserves in place 14,135 169,147 1,597 Development costs incurred during the period 25,253 9,122 6,728 Accretion of discount 71,455 11,381 37,539 Income taxes (3,929) (203,514) 46,293 Other (38,577) 11,477 10,723 --------- --------- --------- Net increase (decrease) 7,100 389,965 (161,077) --------- --------- --------- Standardized measure - end of year $ 503,582 $ 496,482 $ 106,517 ========= ========= ======== 39 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 captions "Security Ownership of Directors and Management" and "Principal Shareholders" 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, except that two reports were filed late by Mr. Berry and one report was filed late by Mr. Starzer in 2000. 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. 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. 40 BERRY PETROLEUM COMPANY Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (cont'd) B. Reports on Form 8-K On January 24, 2001, the Company filed a Form 8-K reporting an Item 5. Other Event to disclose the fact that Southern California Edison was delinquent in paying the Company for November 2000 electricity sales and that Pacific Gas & Electric Company anticipated that its financial circumstances would not allow it to pay for its December power purchases from the Company. In addition, the filing disclosed the Company's electricity accounts receivables position, its cogeneration contracts and the potential effect the high natural gas prices were having on the cogeneration plants and the Company's operations. 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 B Junior Participating Preferred Stock (filed as Exhibit A to the Registrant's Registration Statement on Form 8-A12B on December 7, 1999, File No. 778438-99-000016) 3.4* Registrant's First Amendment to Restated Bylaws dated August 31, 1999 (filed as Exhibit 3.4 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1999, File No.1-9735) 4.1* Rights Agreement between Registrant and ChaseMellon Shareholder Services, L.L.C. dated as of December 8, 1999 (filed by the Registrant on Form 8-A12B on December 7, 1999, File No. 778438-99-000016) 10.1* Description of Cash Bonus Plan of Berry Petroleum Company (filed as Exhibit 10.1 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-9735) 10.2* Salary Continuation Agreement dated as of December 5, 1997, by and between Registrant and Jerry V. Hoffman (filed as Exhibit 10.2 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997, File No.1-9735) 10.3* Form of Salary Continuation Agreement dated as of December 5, 1997, by and between Registrant and Ralph J. Goehring and Michael R. Starzer (filed as Exhibit 10.3 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-9735) 10.4* 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) 10.5* 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) 10.6* Warrant Certificate dated November 14, 1996, by and between Registrant and Tannehill Oil Company (filed as Exhibit 10.16 in Registrant's Form 10-K filed on March 21, 1997, File No. 1-9735) 10.7* Amended and Restated Credit Agreement, dated as of July 22, 1999, by and between the Registrant and Bank of America, N.A., the First National Bank of Chicago and other financial institutions (filed as Exhibit 10.7 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-9735) 41 Exhibits (cont'd) Exhibit No. Description of Exhibit Page 10.8* Standard Offer #2 Power Purchase Agreement dated May 1984 by and between Registrant's predecessor and Pacific Gas and Electric Company (filed as Exhibit 10.14 in Registrant's Form 10-K filed on March 21, 1997, File No. 1-9735) 10.9* Standard Offer #1 Power Purchase Agreement dated January 16, 1997, by and between Registrant and Pacific Gas and Electric Company (filed as Exhibit 10.15 in Registrant's Form 10-K filed on March 21, 1997, File No. 1-9735) 10.10* Purchase and Sale Agreement, dated as of January 26, 1999, by and between the Registrant and Aera Energy LLC (filed as Exhibit 10.1 to the Registrant's Form 8-K filed on February 26, 1999, File No. 1-9735) 10.11* Standard Offer #2 Power Purchase Agreement (Newhall Phase I), as amended, dated December 1985, between Tenneco Oil Company and Southern California Edison (filed as Exhibit 10.2 to the Registrant's Form 8-K filed on February 26, 1999, File No. 1-9735) 10.12* Standard Offer #2 Power Purchase Agreement (Newhall Phase II), as amended, dated December 1985, between Tenneco Oil Company and Southern California Edison (filed as Exhibit 10.3 to the Registrant's Form 8-K filed on February 26, 1999, File No. 1-9735) 10.13* Amended and Restated 1994 Stock Option Plan (filed as Exhibit 10.13 in Registrant's Form 10-K filed on March 16, 1999, File No. 1-9735) 23.1 Consent of PricewaterhouseCoopers LLP 44 23.2 Consent of DeGolyer and MacNaughton 45 27** Financial Data Schedule 99.1 Undertaking for Form S-8 Registration Statements 47 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 42 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 16, 2001. BERRY PETROLEUM COMPANY /s/ JERRY V. HOFFMAN /s/ RALPH J. GOEHRING /s/ DONALD A. DALE JERRY V. HOFFMAN RALPH J. GOEHRING DONALD A. DALE Chairman of the Board, Senior Vice President and Controller Director, President and Chief Financial Officer (Principal Chief 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, Director, March 16, 2001 Jerry V. Hoffman President & Chief Executive Officer /s/ William F. Berry Director March 16, 2001 William F. Berry /s/ Ralph B. Busch, III Director March 16, 2001 Ralph B. Busch, III /s/ William E. Bush, Jr. Director March 16, 2001 William E. Bush, Jr. /s/ J. Herbert Gaul, Jr. Director March 16, 2001 J. Herbert Gaul, Jr. /s/ John A. Hagg Director March 16, 2001 John A. Hagg /s/ Thomas J. Jamieson Director March 16, 2001 Thomas J. Jamieson /s/ Roger G. Martin Director March 16, 2001 Roger G. Martin /s/ Martin H. Young, Jr. Director March 16, 2001 Martin H. Young, Jr. 43 EX-23.1 2 0002.txt 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. 333-62799, 333-62871 and 333-62873)of our report dated March 9, 2001 on our audits of the financial statements of Berry Petroleum Company as of December 31, 2000 and 1999 and for the three years in the period ended December 31, 2000, which report is included in this Annual Report on Form 10-K. PRICEWATERHOUSECOOPERS LLP March 9, 2001 Los Angeles, California EXHIBIT 23.1 44 EX-23.2 3 0003.txt March 15, 2001 Berry Petroleum Company P.O. Bin X Taft, California 93268 Gentlemen: In connection with the Annual Report on Form 10-K for the fiscal year ended December 31, 2000, (the Annual Report) of Berry Petroleum Company (the Company), we hereby consent to (i) the use of and reference to (a) our report dated February 26, 2001, entitled "Appraisal Report as of December 31, 2000, on Certain Property Interests owned by Berry Petroleum Company," which pertains to interests of the Company in certain oil and gas properties located in California, Louisiana, Nevada, Oklahoma, Texas, and Wyoming; (b) our report dated February 16, 2000, entitled "Appraisal Report as of December 31, 1999, on Certain Property Interests owned by Berry Petroleum Company," which pertains to interests of the Company in certain oil and gas properties located in California, Louisiana, Nevada, Oklahoma, Texas and Wyoming; and (c) our report dated February 16, 1999, entitled "Appraisal Report as of December 31, 1998, on Certain Property Interests owned by Berry Petroleum Company," which pertains to interests of the Company in certain oil and gas properties located in California, Louisiana, Nevada, Oklahoma, Texas and Wyoming; (collectively referred to as the "Reports"), under the caption "Oil and Gas Reserves" in items 1 and 2 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 Exhibit 23.2 45 EX-27 4 0004.txt
5 0000778438 BERRY PETROLEUM COMPANY 1,000 YEAR DEC-31-2000 DEC-31-2000 2,731 582 26,420 0 0 34,923 307,303 105,660 238,359 36,076 0 0 0 220 145,004 238,359 171,566 172,049 0 109,433 7,754 0 3,186 51,676 14,493 37,183 0 0 0 37,183 1.69 1.67
EX-99.1 5 0005.txt 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. 333-62799, 333-62871 and 333-62873): 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. 47 Exhibit 99.1 -----END PRIVACY-ENHANCED MESSAGE-----