UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. For the quarterly period ended June 30, 2002 Commission file number 1-9735 BERRY PETROLEUM COMPANY (Exact name of registrant as specified in its charter) DELAWARE 77-0079387 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 5201 Truxtun Avenue, Suite 300, Bakersfield, California 93309-0645 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (661) 616-3900 Former name, Former Address and Former Fiscal Year, if Changed Since Last Report: 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 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 ( ) The number of shares of each of the registrant's classes of capital stock outstanding as of June 30, 2002, was 20,844,095 shares of Class A Common Stock ($.01 par value) and 898,892 shares of Class B Stock ($.01 par value). All of the Class B Stock is held by a shareholder who owns in excess of 5% of the outstanding stock of the registrant. 1 BERRY PETROLEUM COMPANY JUNE 30, 2002 INDEX PART I. Financial Information Page No. Item 1. Financial Statements Condensed Balance Sheets at June 30, 2002 and December 31, 2001 3 Condensed Income Statements for the Three Month Periods Ended June 30, 2002 and 2001 4 Condensed Income Statements for the Six Month Periods Ended June 30, 2002 and 2001 5 Condensed Statements of Comprehensive Income for the Six Month Periods Ended June 30, 2002 and 2001 5 Condensed Statements of Cash Flows for the Six Month Periods Ended June 30, 2002 and 2001 6 Notes to Condensed Financial Statements 7 Item 2. Management's Discussion and Analysis Of Financial Condition and Results of Operations 8 PART II. Other Information Item 4. Submission of Matters to a Vote of Security Holders 12 Item 6. Exhibits and Reports on Form 8-K 13 SIGNATURES 13 2 BERRY PETROLEUM COMPANY Part I. Financial Information Item 1. Financial Statements Condensed Balance Sheets (In Thousands, Except Share Information) June 30, December 31, 2002 2001 (Unaudited) ASSETS Current Assets: Cash and cash equivalents $ 6,309 $ 7,238 Short-term investments available for sale 659 594 Accounts receivable 13,607 17,577 Prepaid expenses and other 3,845 2,792 Total current assets 24,420 28,201 Oil and gas properties (successful efforts basis), buildings and equipment, net 207,100 203,413 Other assets 823 912 $ 232,343 $ 232,526 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable $ 10,052 $ 11,197 Fair value of derivatives 2,710 - Federal and state income taxes payable 4,699 4,078 Accrued Liabilities and other 4,191 7,089 Total current liabilities 21,652 22,364 Long-term debt 15,000 25,000 Deferred income taxes 33,149 32,009 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; 20,844,095 shares issued and outstanding at June 30, 2002 (20,833,094 at December 31, 2001) 208 208 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 48,820 48,905 Accumulated other comprehensive income (1,626) - Retained earnings 115,131 104,031 Total shareholders' equity 162,542 153,153 $ 232,343 $ 232,526 The accompanying notes are an integral part of these financial statements. 3 BERRY PETROLEUM COMPANY Part I. Financial Information Item 1. Financial Statements Condensed Income Statements Three Month Periods Ended June 30, 2002 and 2001 (In Thousands, Except Per Share Information) (Unaudited) 2002 2001 Revenues: Sales of oil and gas $ 25,568 $ 27,731 Sales of electricity 6,477 1,316 Interest and other income, net 1,167 357 33,212 29,404 Expenses: Operating costs - oil and gas production 10,893 11,166 Operating costs - electricity generation 6,477 1,316 Depreciation, depletion and amortization 4,278 3,896 General and administrative 2,032 2,021 Interest 261 1,155 23,941 19,554 Income before income taxes 9,271 9,850 Provision for income taxes 2,444 2,875 Net income $ 6,827 $ 6,975 Basic net income per share $ .31 $ .32 Diluted net income per share $ .31 $ .32 Cash dividends per share $ .10 $ .10 Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share) 21,735 22,034 Effect of dilutive securities: Stock options 198 29 Other 41 21 Weighted average number of shares of capital stock used to calculate diluted net income per share 21,974 22,084 The accompanying notes are an integral part of these financial statements. 4 BERRY PETROLEUM COMPANY Part I. Financial Information Item 1. Financial Statements Condensed Income Statements Six Month Periods Ended June 30, 2002 and 2001 (In Thousands, Except Per Share Information) (Unaudited) 2002 2001 Revenues: Sales of oil and gas $ 45,246 $ 58,428 Sales of electricity 13,791 18,534 Interest and other income, net 1,545 979 60,582 77,941 Expenses: Operating costs - oil and gas production 18,979 21,806 Operating costs - electricity generation 13,460 18,335 Depreciation, depletion and amortization 8,270 8,675 General and administrative 3,894 3,938 Write-off (recovery) of electricity receivables (3,631) 6,645 Interest 684 2,312 41,656 61,711 Income before income taxes 18,926 16,230 Provision for income taxes 3,479 4,233 Net income $ 15,447 $ 11,997 Basic net income per share $ .71 $ .54 Diluted net income per share $ .70 $ .54 Cash dividends per share $ .20 $ .20 Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share) 21,734 22,034 Effect of dilutive securities: Stock options 140 36 Other 41 18 Weighted average number of shares of capital stock used to calculate diluted net income per share 21,915 22,088 Condensed Statements of Comprehensive Income Six Month Periods Ended June 30, 2002 and 2001 (in Thousands) 2002 2001 Net income $ 15,447 $ 11,997 Unrealized losses on derivatives (net of income taxes of $1,084) (1,626) - Reclassification of realized gain on derivatives (net of income taxes of $294) - (441) Comprehensive income $ 13,821 $ 11,556 The accompanying notes are an integral part of these financial statements. 5 BERRY PETROLEUM COMPANY Part I. Financial Information Item 1. Financial Statements Condensed Statements of Cash Flows Six Month Periods Ended June 30, 2002 and 2001 (In Thousands) (Unaudited) 2002 2001 Cash flows from operating activities: Net income $ 15,447 $ 11,997 Depreciation, depletion and amortization 8,270 8,674 Deferred income tax liability 1,140 1,210 Other comprehensive income (1,626) (441) Other, net (64) (63) Net working capital provided by operating activities 23,167 21,377 Decrease (increase) in accounts receivable,prepaid expenses and other 2,917 (4,125) Decrease in current liabilities (712) (17,413) Net cash provided by (used in) operating activities 25,372 (161) Cash flows from investing activities: Capital expenditures (11,738) (4,302) Property acquisitions - (2,149) Purchase of short-term investments (659) - Maturity of short-term investments 594 - Other, net 21 (6) Net cash used in investing activities (11,782) (6,457) Cash flows from financing activities: Proceeds from issuance of long-term debt - 45,000 Payment of long-term debt (10,000) (4,000) Dividends paid (4,347) (4,407) Other (172) - Net cash provided by (used in) financing activities (14,519) 36,593 Net (decrease) increase in cash and cash equivalents (929) 29,975 Cash and cash equivalents at beginning of year 7,238 2,731 Cash and cash equivalents at end of period $ 6,309 $ 32,706 The accompanying notes are an integral part of these financial statements. 6 BERRY PETROLEUM COMPANY Part I. Financial Information Notes to Condensed Financial Statements June 30, 2002 (Unaudited) 1. All adjustments which are, in the opinion of management, necessary for a fair presentation of the Company's financial position at June 30, 2002 and December 31, 2001 and results of operations for the three and six month periods ended June 30, 2002 and 2001 and cash flows for the six month periods ended June 30, 2002 and 2001 have been included. All such adjustments are of a normal recurring nature. The results of operations and cash flows are not necessarily indicative of the results for a full year. 2. The accompanying unaudited financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2001 financial statements. The December 31, 2001 Form 10-K and the March 31, 2002 Form 10-Q should be read in conjunction herewith. The year-end condensed balance sheet was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. 3. In March 2002, the Company entered into a series of put and call crude oil option contracts with two independent counterparties, effectively creating a zero-cost collar on 5,000 barrels per day covering the period April 1, 2002 through March 31, 2003. For the second quarter ended June 30, 2002, the Company recorded an after-tax net loss of approximately $.4 million related to those crude oil hedge contracts. Due to the change in the fair value of the remaining barrels on the hedging instruments during the quarter, the Company recorded an after-tax charge of $1.6 million to "accumulated other comprehensive income" on the Company's balance sheet with an offset to the caption "fair value of derivatives" in current liabilities at June 30, 2002. In July 2002, two bracketed zero-cost collars were executed for the period April 2003 through March 2004 which hedges 5,000 barrels per day for an additional year. 4. In July 2002, the Company entered into a series of "swap transactions" on 30 Mwh of offpeak power. The first of these agreements is effective August 1, 2002 through September 2002 and, in conjunction with the Company's existing open market electricity contracts, effectively establishes a fixed price of $20/Mwh for the offpeak period each day during the term of the contract. Additional transactions for the same quantity of offpeak power were executed from October 1, 2002 through May 2003 at rates slightly above $20/Mwh. The Company also entered into transactions for 25 Mwh of onpeak power for August and September. The above agreements were executed to protect the Company from future low power rates and are part of the Company's risk management program to remove a portion of the price volatility risk from its operating margins. 7 BERRY PETROLEUM COMPANY Part I. Financial Information Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations The Company earned net income of $6.8 million, or $.31 per share, on revenues of $33.2 million in the second quarter of 2002, down 3% from $7.0 million, or $.32 per share, on revenues of $29.4 million in the second quarter of 2001. Net income for the six months ended June 30, 2002 was $15.4 million, or $.71 per share, on revenues of $60.6 million, up 28% from $12.0 million, or $.54 per share, on revenues of $77.9 million for the same period in 2001. Net income in the second quarter of 2002 includes the sale of surplus emission credits to a major utility company for $1.1 million, pre-tax. The year-to-date results for 2002 also include the recovery of $3.6 million of electricity receivables which were previously written off in the first quarter of 2001. Three Months Ended Six Months Ended June 30, March 31, June 30, June 30, June 30, 2002 2002 2001 2002 2001 Oil and gas: Net Production - BOE per day 14,060 13,799 13,611 13,930 14,445 Per BOE: Realized sales price(1) $19.99 $15.87 $21.14 $17.96 $21.83 Operating costs (2) 7.96 5.96 8.57 6.98 7.75 Production taxes .55 .56 .45 .55 .43 Total operating costs 8.51 6.52 9.02 7.53 8.18 Depreciation/Depletion (DD&A) 3.34 3.21 3.15 3.28 3.32 General & administrative expenses (G&A) 1.59 1.50 1.63 1.54 1.51 Interest expense .20 .34 .93 .27 .88 Electricity: Production - Mwh per day 1,935 2,051 268 1,992 712 Sales - Mwh per day 1,748 1,890 224 1,819 654 Average sales price - $/Mwh 39.46 42.99 62.17 36.79 79.14 Fuel gas cost - $/Mmbtu 2.97 2.49 10.54 2.73 14.00 (1) Includes realized hedge losses of $.51 and $.26 for the three and six months ended June 30, 2002, respectively. Excludes unrealized hedging gains of $.91 and $.42 for the three and six months ended June 30, 2001, respectively. (2) Includes monthly expenses in excess of monthly revenues from cogeneration operations of $1.73, $.31 and $2.32 for the second quarter of 2002, the first quarter of 2002 and the second quarter of 2001, respectively. For the first six months of 2002 and 2001, respectively, these expenses represent $1.03 and $1.64. Operating income from oil and gas operations for the three and six months ended June 30, 2002 was $10.5 million and $18.2 million, respectively, down 18% and 35% from $12.8 million earned in the second quarter of 2001 and $28.1 million earned in the first six months of 2001, respectively. 8 The largest contributor to the decline in operating income in the second quarter of 2002 from the second quarter of 2001 was a $2.2 million decline in oil and gas sales which occurred for two reasons; first, the average realized sales price/BOE declined 5% to $19.99 in the 2002 three month period from $21.14 in the same 2001 quarter, and second, the Company recorded an unrealized hedging gain of $1.1 million in the second quarter of 2001 compared to a $.7 million realized loss in 2002. Similarly, operating income declined for the six months ended June 30, 2002 from the first six months of 2001 due to an 18% decline in the average realized sales price per BOE to $17.96 in the 2002 period and because of the unrealized hedging gain recorded in June 2001. Oil and gas production (BOE per day) in the second quarter was 14,060, up from 13,611 in the second quarter of 2001 and 13,799 in the first quarter of 2002. However, production has averaged 13,930 for the first six months of 2002, down from 14,445 for the six months ended June 30, 2001. The Company has not as yet been able to attain the production levels experienced before the suspension of steaming in 2001 due to the California energy crisis. Currently, steam injection is approximately 65,000 barrels per day and management believes that the new wells drilled and the existing well workovers completed under the 2002 capital development program, combined with the application of cyclic and sequential steaming techniques, will improve production rates and the Company expects to exit 2002 with a production level of approximately 16,000 BOE per day. Due to an increase in steam costs resulting from higher steam injection volumes, higher natural gas prices and lower electricity prices, the Company experienced an increase in operating cost/BOE to $8.51 in the second quarter of 2002 from $6.52 in the first quarter of 2002. Until June 2002, the Company sold approximately 37 Mwh of electricity under fixed rate contracts and 43 Mwh in the open market. Effective June 2002, one fixed rate contract expired and, therefore, an additional approximate 17 Mwh is now sold in the open market with 20 Mwh remaining under a long-term fixed rate contract. The average price received for electricity sales in the open market for the three and six months ended June 30, 2002 was $22.59/Mwh and $22.57/Mwh, respectively, while the cost of natural gas to run the cogeneration plants during these same three and six month periods averaged $2.73/Mmbtu and $2.97/Mmbtu, respectively. This combination resulted in a weak "spark spread" (the difference between the price realized from the sale of electricity and the cost paid for natural gas used as fuel in the cogeneration operations) in the second quarter of 2002. The loss/BOE from the cogeneration operations reflected in the Company's steam costs increased to $1.73 in the second quarter of 2002 from $.31 in the first quarter of 2002. The electrical marketplace in California continues to be unpredictable due in part to the State of California's significant power purchase commitments (with possible excess power at times), continued rulemaking and a very limited open market for creditworthy buyers and sellers. The Company continues to seek a long-term agreement for the sale at reasonable prices of the approximately 60 Mwh presently sold on the open market, but until that occurs, the Company may utilize more financial hedges to reduce the volatility of the resulting steam costs. DD&A was $4.3 million, or $3.34/BOE, in the second quarter, up from $3.9 million, or $3.15/BOE, in the second quarter of 2001 and $4.0 million, or $3.21/BOE, in the first quarter of 2002. The increase from the second quarter of 2001 was due primarily to capital development projects completed in the latter half of 2001 and the first half of 2002. The Company anticipates that its DD&A per BOE will fluctuate between $3.00 and $3.50 over the next several quarters. 9 G&A of $2.0 million for the second quarter of 2002 was equivalent to the second quarter of 2001 and up slightly from $1.9 million in the first quarter of 2002. Lower legal costs in the second quarter of 2002 compared to the second quarter of 2001 were offset primarily by higher costs for consulting, property evaluations and office rent. The Company experienced an effective tax rate of 26% in the second quarter and 18% for the first six months of 2002 compared to 29% and 26% in the same 2001 periods, respectively. The higher effective rate in the second quarter of 2002 compared to the rate for the first three months of 2002 of 11% was due primarily to the increase in oil prices and production. The Company anticipates that its effective tax rate will remain well below the combined federal and state statutory rate due to the Company's significant investment in numerous enhanced oil recovery projects in 2002. As part of the Company's risk management program, the Company's goal is to protect itself from large swings in commodity prices, i.e., sharp declines in crude oil and electricity realized sales prices and the cost of purchased natural gas used in its operations. The Company has entered into certain hedge transactions during 2002 to reduce the volatility of its cash flows related to these commodity prices. In March 2002, the Company entered into a series of put and call option contracts with two counterparties, effectively creating a zero-cost collar on 5,000 barrels per day, representing approximately 35% of the Company's current total oil production. Both hedges were effective April 1, 2002 for a period of one year. The Company's goal when entering into these types of arrangements is to protect its operations from sharp declines in oil prices while giving up only a portion of potential increases in realized oil prices. In July 2002, two bracketed zero-cost collars were executed for the period April 2003 through March 2004 which hedges 5,000 barrels per day for an additional year. Since the sales price received by the Company for the sale of its crude oil was slightly higher than the top end of the collar during the second quarter of 2002, the Company incurred after-tax hedging losses of approximately $.4 million in the second quarter related to these hedge contracts and recorded an after- tax charge to "accumulated other comprehensive income" of $1.6 million with an offset to the caption "fair value of derivatives" in current liabilities at June 30, 2002. In January 2002, the Company entered into an energy conversion arrangement with an electricity customer for February, March, May and June 2002. Under the terms of the agreement, the Company sold approximately 25 Mwh of electricity to a customer in exchange for a sufficient volume of gas to produce this electricity and the Company's payment of an additional fee. This arrangement minimized the Company's risk to fluctuating natural gas and electricity prices related to these volumes and provided steam at a cost less than $1/Bbl to the Company's heavy oil producing operations. In July 2002, the Company entered into a series of swap transactions which established a fixed price mechanism for 30 Mwh of offpeak electricity averaging slightly higher than $20.00/Mwh from August 2002 through May 2003. The Company also entered into transactions for 25 Mwh of onpeak power for August and September. The Company may enter into additional commodity hedging transactions if management believes it is prudent to do so. The Company is aware of counterparty risk and anticipates entering into such hedges only with well established and well financed counterparties. However, the Company can make no assurances as to the ultimate financial performance of any of its counterparties. 10 Liquidity and Capital Resources Working capital at June 30, 2002 was $2.8 million, down from $50.4 million at June 30, 2001, and $5.4 million at March 31, 2002. Working capital was maintained at an unusually high level in the second quarter of 2001 to deal effectively with the financial consequences of the California energy crisis. Net cash provided by operations was $25.4 million for the first six months of 2002, up substantially from a $.2 million use of funds for the first six months of 2001. Cash flow from operations was negatively affected by the non-payment of $26.6 million in electricity sales from two major California utilities in the first quarter of 2001. The Company subsequently collected approximately $23.8 million of these sales. Cash was used in the first half of 2002 to reduce long-term debt by $10.0 million and pay capital expenditures of $11.7 million, dividends of $4.3 million and an annual revenue sharing royalty on 2001 production of $3.9 million. The Company's capital budget for 2002 is currently $27.3 million. The plan includes the drilling of 88 new wells, of which 15 will be horizontal. As of July 26, 2002, the Company had drilled 19 new vertical producing wells, 8 horizontal wells and 3 service wells (i.e., steam injectors or water disposal wells). In addition, the Company completed 33 workovers of existing wells. The planned major refurbishment of one of the two turbines at the 42 Mwh cogeneration plant was completed in the first quarter of 2002 at a cost of $1.8 million. Also, the Company spent $1.9 million in other miscellaneous improvements to the Company's producing properties in the first half of 2002. The Company has a borrowing base under its credit facility of $150 million, of which $15 million is outstanding and approximately $7 million is committed for various Letters of Credit, thus the current additional amount available solely under this facility is approximately $128 million. 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-Q 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, a limited marketplace for electricity sales within California, counterparty risk, competition, environmental risks, litigation uncertainties, drilling, development and operating risks, the availability of drilling rigs and other support services, legislative and/or judicial decisions and other government regulations. 11 BERRY PETROLEUM COMPANY Part II. Other Information Item 4. Submission of Matters to a Vote of Security Holders At the annual meeting, which was held at the Company's corporate offices on May 16, 2002, eleven incumbent directors were re-elected and an amendment to the Company's stock option plan was approved. The results of voting as reported by the inspector of elections are noted below: 1. There were 21,731,888 shares of the Company's capital stock issued, outstanding and entitled to vote as of the record date, March 11, 2002. 2. There were present at the meeting, in person or by proxy, the holders of 20,023,024 shares, representing 92.14% of the total number of shares outstanding and entitled to vote at the meeting, such percentage representing a quorum. PROPOSAL ONE: Election of Directors PERCENT OF NOMINEE QUORUM WITHHOLD FOR VOTES VOTES CAST AUTHORITY William F. Berry 18,447,938 92.13% 1,575,086 Ralph B. Busch, III 18,416,038 91.97% 1,606,986 William E. Bush, Jr. 18,446,938 92.13% 1,576,086 Stephen L. Cropper 18,093,138 90.36% 1,929,886 J. Herbert Gaul, Jr. 18,472,538 92.26% 1,550,486 John A. Hagg 18,441,338 92.10% 1,581,686 Robert F. Heinemann 18,060,436 90.20% 1,962,588 Jerry V. Hoffman 18,473,035 92.26% 1,549,989 Thomas J. Jamieson 18,441,236 92.10% 1,581,788 Roger G. Martin 18,472,738 92.26% 1,550,286 Martin H. Young, Jr. 18,472,938 92.26% 1,550,086 Percentages are based on the shares represented and voting at the meeting in person or by proxy. PROPOSAL TWO: Approve the Second Amendment to the Company's Restated and Amended 1994 Stock Option Plan. SHARES PERCENT OF PERCENT OF QUORUM SHARES VOTES CAST OUTSTANDING Votes For 16,508,800 82.45% 75.97% Votes Against 1,463,723 7.31% 6.74% Votes Abstain 2,050,499 10.24% 9.43% Broker Non-Vote 2 .00% .00% Total Votes 20,023,024 100.00% 92.14% 12 BERRY PETROLEUM COMPANY Part II. Other Information Item 6. Exhibits and Reports on Form 8-K None SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. BERRY PETROLEUM COMPANY /s/ Jerry V. Hoffman Jerry V. Hoffman Chairman, President and Chief Executive Officer /s/ Ralph J. Goehring Ralph J. Goehring Senior Vice President and Chief Financial Officer (Principal Financial Officer) /s/ Donald A. Dale Donald A. Dale Controller (Principal Accounting Officer) Date: July 30, 2002 13