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 September 30, 2003 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 93309-0640 (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 ( ) Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES (X) NO ( ) The number of shares of each of the registrant's classes of capital stock outstanding as of September 30, 2003, was 20,885,522 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. BERRY PETROLEUM COMPANY September 30, 2003 INDEX Page No. PART I. FINANCIAL INFORMATION Item 1. Financial Statements Condensed Balance Sheets at September 30, 2003 and December 31, 2002 3 Condensed Income Statements for the Three Month Periods Ended September 30, 2003 and 2002 4 Condensed Income Statements for the Nine Month Periods Ended September 30, 2003 and 2002 5 Condensed Statements of Comprehensive Income for the Nine Month Periods Ended September 30, 2003 and 2002 5 Condensed Statements of Cash Flows for the Nine Month Periods Ended September 30, 2003 and 2002 6 Notes to Condensed Financial Statements 7 Item 2. Management's Discussion and Analysis Of Financial Condition and Results of Operations 10 Item 3. Quantitative and Qualitative Disclosures About Market Risk 14 PART II. OTHER INFORMATION Item 4. Controls and Procedures 15 EXHIBIT INDEX Item 6. Exhibits and Reports on Form 8-K 15 SIGNATURES 16 EX-31.1 Certification of CEO pursuant to Section 302 17 EX-31.2 Certification of CFO pursuant to Section 302 18 EX-32.1 Certification of CEO pursuant to Section 906 19 EX-32.2 Certification of CFO pursuant to Section 906 20 2 BERRY PETROLEUM COMPANY Part I. Financial Information Item 1. Financial Statements Condensed Balance Sheets (In Thousands, Except Share Information) Sept 30, December 2003 31, 2002 (Unaudited) ASSETS Current Assets: Cash and cash equivalents $ 10,568 $ 9,866 Short-term investments available for sale 661 660 Accounts receivable 19,951 15,582 Prepaid expenses and other 4,994 2,597 -------- -------- Total current assets 36,174 28,705 Oil and gas properties (successful efforts basis), buildings and equipment, net 283,038 228,475 Other assets 2,228 893 -------- -------- $ 321,440 $ 258,073 ======== ======== LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable $ 23,061 $ 19,189 Accrued liabilities 4,155 6,470 Federal and state income taxes payable 2,785 2,612 Fair value of derivatives 4,014 4,123 -------- -------- Total current liabilities 34,015 32,394 Long-term liabilities: Deferred income taxes 37,367 33,866 Long-term debt 55,000 15,000 Abandonment obligations 6,356 4,596 Fair value of derivatives 1,285 159 -------- -------- Total long-term liabilities 100,008 53,621 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; 20,885,522 shares issued and outstanding at September 30, 2003 209 209 (20,852,695 at December 31, 2002) Class B Stock, 1,500,000 shares authorized; 898,892 shares issued and outstanding 9 9 (liquidation preference of $899) Capital in excess of par value 49,135 49,052 Accumulated other comprehensive loss (3,179) (2,569) Retained earnings 141,243 125,357 -------- -------- Total shareholders' equity 187,417 172,058 -------- -------- $ 321,440 $ 258,073 ======== ======== 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 September 30, 2003 and 2002 (In Thousands, Except Per Share Information) (Unaudited) 2003 2002 Revenues: Sales of oil and gas $ 33,466 $ 28,044 Sales of electricity 11,120 7,172 Interest and other income, net 350 71 -------- -------- 44,936 35,287 Expenses: -------- -------- Operating costs - oil and gas production 16,533 11,402 Operating costs - electricity generation 11,120 7,172 Depreciation, depletion and amortization 5,167 4,126 General and administrative 2,002 2,277 Interest 368 179 -------- -------- 35,190 25,156 -------- -------- Income before income taxes 9,746 10,131 Provision for income taxes 1,711 2,544 -------- -------- Net income $ 8,035 $ 7,587 ======== ======== Basic net income per share $ .37 $ .35 ======== ======== Diluted net income per share $ .36 $ .35 ======== ======== Cash dividends per share $ .11 $ .10 ======== ======== Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share) 21,776 21,746 Effect of dilutive securities: Stock options 242 166 Other 47 33 -------- -------- Weighted average number of shares of capital stock used to calculate diluted net income per share 22,065 21,945 ======== ======== 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 Nine Month Periods Ended September 30, 2003 and 2002 (In Thousands, Except Per Share Information) (Unaudited) 2003 2002 Revenues: Sales of oil and gas $ 97,286 $ 73,289 Sales of electricity 34,385 20,963 Interest and other income, net 597 1,616 -------- -------- 132,268 95,868 Expenses: -------- -------- Operating costs - oil and gas production 45,343 30,381 Operating costs - electricity generation 34,385 20,631 Depreciation, depletion and amortization 14,350 12,396 General and administrative 6,663 6,171 Recovery of electricity receivables - (3,631) Dry hole and abandonment 2,487 - Interest 845 863 -------- -------- 104,073 66,811 -------- -------- Income before income taxes 28,195 29,057 Provision for income taxes 4,473 6,023 -------- -------- Net income $ 23,722 $ 23,034 ======== ======== Basic net income per share $ 1.09 $ 1.06 ======== ======== Diluted net income per share $ 1.08 $ 1.05 ======== ======== Cash dividends per share $ .36 $ .30 ======== ======== Weighted average number of shares of capital stock outstanding used to calculate basic net income per share 21,766 21,738 Effect of dilutive securities: Stock options 107 149 Other 44 40 -------- -------- Weighted average number of shares of capital stock used to calculate diluted net income per share 21,917 21,927 ======== ======== Condensed Statements of Comprehensive Income Nine Month Periods Ended September 30, 2003 and 2002 (in Thousands) (Unaudited) 2003 2002 Net income $ 23,722 $ 23,034 Unrealized losses on derivatives, (net of income taxes of $407 and $1,968 respectively) (610) (2,953) -------- -------- $ 23,112 $ 20,081 ======== ======== 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 Nine Month Periods Ended September 30, 2003 and 2002 (In Thousands) (Unaudited) 2003 2002 Cash flows from operating activities: Net income $ 23,722 $ 23,034 Depreciation, depletion and amortization 14,350 12,396 Dry hole and abandonment 2,517 (474) Deferred income tax liability 3,501 1,414 Other, net (291) 216 -------- -------- Net working capital provided by operating activities 43,799 36,586 Decrease (increase) in accounts receivable, prepaid expenses and other (6,808) 2,801 Increase in current liabilities 2,998 2,567 -------- -------- Net cash provided by operating activities 39,989 41,954 Cash flows from investing activities: Capital expenditures (24,620) (22,527) Property acquisitions (47,519) - Proceeds from sale of assets 1,735 - Other, net 29 (44) -------- -------- Net cash used in investing activities (70,375) (22,571) Cash flows from financing activities: Proceeds (payment) of long-term debt 40,000 (12,000) Dividends paid (7,836) (6,522) Other, net (1,076) (238) -------- -------- Net cash provided by (used in) financing activities 31,088 (18,760) -------- -------- Increase in cash and cash equivalents 702 623 Cash and cash equivalents at beginning of year 9,866 7,238 -------- -------- Cash and cash equivalents at end of period $ 10,568 $ 7,861 ======== ======== Supplemental non-cash activity: Decrease (increase) in fair value of derivatives: Current (net of income taxes of $(44) and $1,857 in 2003 and 2002, respectively) $ (65) $ 2,786 Non-current (net of income taxes of $450 and $111 in 2003 and 2002, respectively) 675 167 -------- -------- Net decrease to accumulated other comprehensive income $ 610 $ 2,953 ======== ======== The accompanying notes are an integral part of these financial statements. 6 BERRY PETROLEUM COMPANY Part I. Financial Information Item 1. Financial Statements Notes to Condensed Financial Statements September 30, 2003 (Unaudited) 1. All adjustments which are, in the opinion of management, necessary for a fair presentation of the Company's financial position at September 30, 2003 and December 31, 2002 and results of operations for the three and nine month periods ended September 30, 2003 and 2002 and cash flows for the nine month periods ended September 30, 2003 and 2002 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, 2002 financial statements. The December 31, 2002 Form 10- K and the March 31, 2003 and June 30, 2003 Form 10-Q's 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 August 2003, the Company completed the sale of its approximately 43,000 leased acres in Jackson County, Kansas for approximately $1.7 million, while retaining an overriding royalty interest in the property. The Company recovered its cost in the property. 4. As allowed in Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation," as amended, 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 plan. Under SFAS No. 123, as amended, compensation cost would be recognized for the fair value of the employee's option rights. Had compensation cost for the Company's stock based compensation plan been based upon the fair value at the grant dates for awards under the plan consistent with the method of SFAS No. 123, as amended, using the Black-Scholes Method, the Company's compensation cost, net of related tax effects, net income and earnings per share would have been recorded as the proforma amounts indicated below for the three and nine months ended September 30, 2003 and 2002 (in thousands, except per share data): 7 BERRY PETROLEUM COMPANY Part I. Financial Information Item 1. Financial Statements Notes to Condensed Financial Statements 4. (cont'd) Three Months Nine Months Ended Sept 30 Ended Sept 30 2003 2002 2003 2002 Compensation cost, net of income taxes As reported $ 95 $ 7 $ 203 $ 33 Pro forma 191 205 557 567 Net income: As reported 8,035 7,587 23,722 23,034 Pro forma 7,939 7,389 23,368 22,500 Basic net income per share: As reported .37 .35 1.09 1.06 Pro forma .36 .34 1.07 1.04 Diluted net income per share: As reported .36 .35 1.08 1.05 Pro forma .36 .34 1.07 1.03 5. In August 2003, the Company completed the acquisition from Williams Production RMT Company of its oil and gas properties located in Brundage Canyon, Utah in the Uinta Basin for approximately $44.6 million. The purchase price was adjusted downward from the $48.6 million value at April 1, 2003 due to the net operating income generated from the properties between April 1st and August 28, 2003, the date of closing. The properties, located in northeastern Utah, consist of approximately 43,500 net acres, and are producing approximately 2,100 BOE/day of light crude oil and natural gas as of October 31, 2003. The Company estimated the proved reserves at 8.6 million BOE (75% light oil and 25% natural gas) as of April 1, 2003. 8 6. In 2002, the Company implemented SFAS No. 143, "Accounting for Asset Retirement Obligations" for recording future site restoration costs related to its oil and gas properties. Prior to its implementation, the Company had recorded the future obligation per SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." Under SFAS No. 143, the following table summarizes the changes in our abandonment obligation for the nine months ended September 30, 2003: Nine Months Ended Sept. 30, 2003 Beginning abandonment obligation Dec. 31, 2002 $ 4,597 Liabilities incurred 1,599 Liabilities settled (202) Accretion expense 362 ________ Ending abandonment obligation Sept. 30, 2003 $ 6,356 ======== 7. The FASB is currently evaluating the application of certain provisions of SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," to companies in the extractive industries, including oil and gas companies. The FASB is considering whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other oil and gas property costs, and provide specific footnote disclosures. At the present time, the Company continues to include these intangible assets in its oil and gas properties. 9 BERRY PETROLEUM COMPANY Part I. Financial Information Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations Net income for the third quarter of 2003 was $8 million, or $.37 per share (basic), on revenues of $44.9 million, up 5% and 23%, from $7.6 million, or $.35 per share (basic), on revenues of $35.3 million in the third quarter of 2002 and $6.5 million, or $.30 per share (basic), on revenues of $40.1 million in the second quarter of 2003. Net income for the first nine months of 2003 was $23.7 million, or $1.09 per share (basic), on revenues of $132.3 million, up 3% from $23 million, or $1.06 per share (basic), on revenues of $95.9 million for the same period in 2002. Results for the first nine months of 2003 include a pre-tax write- off of $2.5 million, representing the cost of a pilot project and associated leasehold acquisition costs in Waubansee County, Kansas. Pre- tax income for the first nine months of 2002 include the recovery of $3.6 million of the $6.6 million in electricity receivables which was written off in the first quarter of 2001. Three Months Ended Nine Months Ended Sept 30, June 30, Sept 30 Sept 30, Sept 30, 2003 2003 2002 2003 2002 Oil and gas: Net Production - BOE per day 16,482 15,397 14,464 15,874 14,110 Per BOE: Realized sales price(1) $22.07 $21.07 $21.03 $22.45 $19.02 Operating costs (2) 10.21 10.63 8.06 9.88 7.35 Production taxes .69 .52 .51 .58 .54 ----- ----- ----- ----- ----- Total operating costs 10.90 11.15 8.57 10.46 7.89 Depreciation/Depletion(DD&A) 3.41 3.38 3.10 3.31 3.22 General & administrative expenses (G&A) 1.32 1.72 1.71 1.54 1.60 Interest expense .24 .19 .13 .19 .22 Electricity: Production - Mwh per day 2,127 2,036 2,088 2,100 2,025 Sales - Mwh per day 1,937 1,847 1,918 1,912 1,852 Average sales price - $/Mwh 60.12 62.59 37.59 65.38 38.54 Natural gas cost - $/MMBtu 4.75 5.04 3.02 5.06 2.83 (1) Includes realized hedge losses of $1.90, $1.42 and $1.19 for the three months ended September 30, 2003, June 30, 2003 and September 30, 2002 and losses of $1.98 and $.58 for the nine months ended September 30, 2003 and 2002, respectively. (2) Includes monthly expenses in excess of monthly revenues from cogeneration operations of $2.34, $2.79 and $1.69 for the three months ended September 30, 2003, June 30, 2003 and September 30, 2002, respectively and $2.28 and $1.26 for the nine months ended September 30, 2003 and 2002, respectively. Operating income from oil and gas operations for the third quarter of 2003 was $11.8 million, down 6% from $12.6 million in the third quarter of 2002, but up 28% from $9.2 million in the second quarter of 2003. Operating income for the first nine months of 2003 was $35.3 million, up 15% from $30.8 million for the same period in 2002. 10 Oil and gas production (BOE/day) in the third quarter of 2003 was a record 16,482, up 14% and 7%, respectively from 14,464 in the third quarter of 2002 and 15,397 in the second quarter of 2003. Production for the first nine months of 2003 was 15,874, also a Company record, up 13% from 14,110 for the same period of 2002. The increase was attributed primarily to the Company's 2003 drilling program and the addition of the Brundage Canyon property in the latter part of the third quarter. On October 31, 2003, Brundage Canyon was producing approximately 2,100 BOE/day and contributed 700 BOE/day in the third quarter and 236 BOE/day to the Company's 2003 year- to-date totals. Many of the wells drilled this year on the Company's California properties have just recently completed their initial steam cycle and are contributing to further increases in production. Total Company production for the fourth quarter of 2003 is expected to approximate 19,000 BOE/day and the average for 2003 is expected to exceed 16,600 BOE/day, a 15% increase over 2002. The Company has targeted an average production gain for 2004 over 2003 of approximately 20% (without additional acquisitions) to an average in excess of 20,000 BOE/day. The average realized sales price per BOE for the Company's crude oil and natural gas was approximately $22.07 in the third quarter of 2003, up from $21.03 and $21.07 received in the third quarter of 2002 and the second quarter of 2003, respectively. The Company primarily is at risk to reductions in operating income as a result of declines in crude oil and electricity prices and increases in natural gas prices. To assist in mitigating these risks, the Company periodically enters into various types of commodity hedges. See "Item 3. Quantitative and Qualitative Disclosure About Market Risk" for more information on market risk and existing hedges for the Company at September 30, 2003. In January 2003, Standard Offer contract terms were reinstated on the power produced from one of two turbines at the Company's cogeneration facility located in the Placerita oilfield in Los Angeles County and on both the 38 megawatt and 18 megawatt facilities located on the Company's Midway-Sunset properties in Kern County, California. Under the terms of these agreements, the Company received an average of $54.32 per Mwh in the third quarter of 2003 and $61.59 per Mwh for the first nine months of 2003. The primary benefit of these contracts is that the Company's price received for electricity produced is based on the cost of natural gas. Therefore, these contracts contribute to reducing the Company's exposure to higher operating costs based on higher natural gas costs. The Company consumes approximately 37,000 MMBtu of natural gas per day for use in generating steam and of this total, approximately 72% is consumed in the Company's cogeneration operations. These contracts are scheduled to expire in the fourth quarter of 2003. Management has requested that these contracts be extended into 2004. However, if they are not extended, the Company has a contract in place with a power marketer whereby it can sell its electricity into the California open market. However, these sales may not be linked to the cost of natural gas. Operating costs from oil and gas operations in the third quarter of 2003, were $16.5 million, up from $11.4 million in the third quarter of 2002, and up from $15.6 million in the second quarter of 2003. On a per BOE basis, operating costs were $10.90 in the third quarter 2003, up from $8.57 in the third quarter of 2002, but down from $11.15 in the second quarter of 2003 due primarily to increased production levels. Steam costs for the third quarter of 2003 remained very high compared to the same quarter in 2002. The price of natural gas, the largest component of the cost of generating steam, averaged $4.75 per MMBtu in the third quarter of 2003 compared to $3.02 per MMBtu in the third quarter of 11 2002. The Company has continued to increase steam injection volumes on its core heavy oil producing assets with average steam injection of 66,000 barrels of steam per day (BSPD) for the third quarter of 2003, up from 62,000 BSPD in the third quarter of 2002. The Company expects operating costs to average from $10.00 to $10.25 per BOE for the full year of 2003 and to average slightly less than $10.00 per BOE in 2004, assuming natural gas prices remain at current levels. DD&A for the third quarter was $5.2 million, or $3.41 per BOE, up from $4.1 million, or $3.10 per BOE, in the third quarter of 2002 and $4.7 million, or $3.38 per BOE, in the second quarter of 2003. The Company expects average DD&A per BOE in 2003 to be from $3.40 to $3.50 per BOE and to rise to an average of $4.40 to $4.70 per BOE for 2004. The increase in the third quarter of 2003 and projected increase in 2004 are due primarily to the acquisition of the Brundage Canyon properties. G&A expenses for the third quarter of 2003 were $2.0 million, or $1.32 per BOE, down from $2.3 million, or $1.71 per BOE, in the third quarter of 2002 and $2.4 million, or $1.72 per BOE, in the second quarter of 2003. On a per BOE basis, G&A expenses have trended lower primarily due to higher production levels. Most of the decrease from the third quarter of 2002 was due to the allocation of various acquisition related costs to successful acquisition projects. For the first nine months of 2003, G&A expenses were $6.7 million, or $1.54 per BOE, up from $6.2 million, or $1.60 per BOE, in the same period of 2002. Management expects G&A expenses for all of 2003 to be approximately $1.50 per BOE and for 2004 to average from $1.30 to $1.45 per BOE. The Company completed the sale of approximately 43,000 leased acres in Jackson County, Kansas in August 2003 for approximately $1.7 million. The Company recovered its cost in the property while retaining an overriding royalty interest. The Company has approximately 165,000 leased acres in Waubansee and Osage County, Kansas. The Company is evaluating locations for test wells in Osage County and anticipates drilling these wells in 2004. The Company also has a 55,000 acreage position in Illinois and continues to evaluate its pilot with results expected in 2004. The Company's effective tax rate of 17% in the third quarter was 2003 and 16% in the first nine months of 2003 compared to 25% and 21% in the same three and nine month 2002 periods, respectively. The Company continues to invest in qualifying enhanced oil recovery (EOR) projects and anticipates that it will continue to earn EOR tax credits. This is the primary reason that the Company's effective tax rate is below the statutory tax rate. Liquidity and Capital Resources Working capital at September 30, 2003 was $2.2 million, up from ($3.7) million at December 31, 2002. Net cash provided by operations was $40.0 million for the first nine months of 2003, down slightly from $42.0 million for the first nine months of 2002. Cash was used for capital expenditures of $24.6 million, dividends of $7.8 million and net property acquisitions totaling $47.5 million. 12 The Company has completed a substantial portion of its 2003 drilling program on its California assets. As of October 26, 2003, 82 wells of a planned 96 well drilling program have been drilled and completed. In addition, the Company has drilled 11 new wells in Utah and plans to drill an additional 15 wells this year. The Company also budgeted 41 workovers on its California properties and had completed 35 of these projects as of October 26, 2003. These activities and planned facilities improvements will bring the total 2003 development budget to approximately $47.1 million. The Company successfully completed a new $200 million unsecured three year bank credit facility in July 2003. The facility replaced the previous $150 million unsecured facility which was due to mature in January 2004. The new facility recognizes the Company's strong financial position and should provide significant low-cost capital for the Company to meet its growth objectives. In August 2003, the Company drew upon this facility to finance $40 million of the net $44.6 million purchase price for the Brundage Canyon, Utah assets. As of September 30, 2003, the Company has $145 million available under the facility as the outstanding long-term debt is $55 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. 13 BERRY PETROLEUM COMPANY Part I. Financial Information Item 3. Quantitative and Qualitative Disclosures About Market Risk The Company enters into various financial contracts to hedge its exposure to commodity price risk associated with its crude oil production, electricity production and net natural gas volumes purchased for its steaming operations. These contracts related to crude oil and natural gas, have historically been in the form of zero-cost collars and swaps. The Company generally attempts to hedge between 25% and 50% of its anticipated crude oil production each year and up to 30% of its anticipated net natural gas purchased each year. All of these hedges have historically been deemed to be cash flow hedges with the mark-to-market valuations of the collars provided by external sources, based on prices that are actually quoted. Based on the Nymex futures crude oil prices at September 30, 2003, the Company would expect to make future cash payments of $5.2 million over the remaining term of its crude oil hedges in place. If the futures prices decreased 10%, the expected future cash payment under the hedges would decrease to approximately $.7 million. If the futures prices increased 10%, the expected future cash payments under the hedges would increase to approximately $9.9 million. However, at these prices, the Company has reached the ceiling for the majority of its hedge instruments. Therefore, if the futures prices increased by 20%, the additional amount the Company would expect to pay under these hedges would increase by less than $1 million. In addition to its crude oil hedges, the Company has a revenue sharing agreement on approximately 21% of its production. For every $1 increase or decrease in oil price, the annual effect of this agreement on companywide oil revenue is approximately $1.1 million. On the Company's natural gas hedge instruments at September 30, 2003, the Company would expect to make future cash payments of approximately $.4 million based on the futures natural gas prices. If the futures prices increased by 10%, the Company would expect to receive approximately $2.0 million under the hedge instruments. If the futures prices decreased by 10%, the Company would expect to pay approximately $2.8 million under these hedge instruments. The Company sells approximately 80% of its electricity production, net of electricity used in its oil and gas operations, under standard offer contracts to major utilities. These contracts are scheduled to expire on or before December 31, 2003. However, the Company has requested that these contracts be extended into 2004. However, if they are not extended, the Company has a contract in place with a power marketer whereby it can sell its electricity into the open California market. However, the sales price under this contract may not be linked to natural gas prices. The Company sells the remaining 19 Mwh to a utility at $53.70/Mwh plus capacity through a long-term sales contract. The Company attempts to minimize credit exposure to counter parties through monitoring procedures and diversification. 14 Item 4. Controls and Procedures The Company's Chief Executive Officer and its Chief Financial Officer have evaluated the Company's disclosure controls and procedures as of the end of the fiscal quarter covered by this report pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934 and have concluded that there are no significant changes in the Company's internal controls or in other factors that could significantly affect these controls. BERRY PETROLEUM COMPANY Part II. Other Information Item 6. Exhibits and Reports on Form 8-K (a) Exhibits Exhibit No. Description 31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. * 31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. * 32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * 32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * * Filed herewith (b) Reports on Form 8-K On July 15, 2003, the Company filed a Form 8-K reporting an Item 9 - Regulation FD Disclosure to furnish the Securities and Exchange Commission a copy of the Company's press release announcing the completion of a new $200 million unsecured credit facility. On July 22, 2003, the Company filed a Form 8-K reporting an Item 9 - Regulation FD Disclosure to furnish the Securities and Exchange Commission a copy of the Company's press release announcing entering into a definitive agreement to sell its interest in 43,000 acres of non-producing coal bed methane acreage in eastern Kansas. On August 6, 2003, the Company filed a Form 8-K reporting an Item 9 - Regulation FD Disclosure to furnish the Securities and Exchange Commission a copy of the Company's press release announcing the second quarter results for 2003. On August 28, 2003, the Company filed a Form 8-K reporting an Item 9 - Regulation FD Disclosure to furnish the Securities and Exchange Commission a copy of the Company's press release announcing the closing of the Company's purchase of the $48.6 million Unita Basin property from Williams Production RMT Company. 15 BERRY PETROLEUM COMPANY Part II. Other Information (b) Reports on Form 8-K (Cont'd) On August 28, 2003, the Company filed a Form 8-K reporting an Item 9 - Regulation FD Disclosure to furnish the Securities and Exchange Commission a copy of the Company's press release announcing the completion of the sale of its interest in 43,000 acres of non-producing coalbed methane acreage in eastern Kansas. 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/ Donald A. Dale Donald A. Dale Controller (Principal Accounting Officer) Date: November 6, 2003 16
CERTIFICATION OF CHIEF EXECUTIVE OFFICER I, Jerry V. Hoffman, certify that: 1. I have reviewed this report on Form 10-Q of Berry Petroleum Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant is made known to us by others within the registrant, particularly during the period in which this report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls over financial reporting. Date: November 6, 2003 /s/ Jerry V. Hoffman Jerry V. Hoffman Chairman, President and Chief Executive Officer Exhibit 31.1
CERTIFICATION OF CHIEF FINANCIAL OFFICER I, Ralph J. Goehring, certify that: 1. I have reviewed this report on Form 10-Q of Berry Petroleum Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant is made known to us by others within the registrant, particularly during the period in which this report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls over financial reporting Date: November 6, 2003 /s/ Ralph J. Goehring Ralph J. Goehring Senior Vice President and Chief Financial Officer Exhibit 31.2
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I, Jerry V. Hoffman, as Chairman, President and Chief Executive Officer of Berry Petroleum Company (the "Company"), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Quarterly Report on Form 10-Q of the Company for the period ended September 30, 2003 (the "Report") which this certification accompanies, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Jerry V. Hoffman Jerry V. Hoffman Chairman, President and Chief Executive Officer November 6, 2003 Exhibit 32.1
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I, Ralph J. Goehring, Senior Vice President and Chief Financial Officer of Berry Petroleum Company (the "Company"), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Quarterly Report on Form 10-Q of the Company for the period ended September 30, 2003 (the "Report") which this certification accompanies, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Ralph J. Goehring Ralph J. Goehring Senior Vice President and Chief Financial Officer November 6, 2003 Exhibit 32.2