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.
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.
PART II
Item 5.
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.
Item 6.
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):
Item 7.
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.
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.
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.
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.
Item 8.
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.
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
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.
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.
BERRY PETROLEUM COMPANY Statements of Shareholders' Equity Years Ended December 31, 2000, 1999 and 1998 (In Thousands, Except Per Share Data)
The accompanying notes are an integral part of these financial statements.
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.
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.
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).
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.
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.
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 ====== ====== ======= ======= =======
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.
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.
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 ======= ======== =======
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.
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%
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
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 ======== ======== ======= ====== ======
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 ======== ======== ======= ====== ======
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 ======= ====== ======= ====== ======= ======
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 ========= ========= ========
BERRY PETROLEUM COMPANY
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None. PART III
Item 10.
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.
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.
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.
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.
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.
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)
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
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.