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     The Company achieved another production record in the third quarter of 2004. Production (BOE/day) for the quarter averaged 20,825, up 26% from 16,482 in the third quarter of 2003 and 3% from 20,315 in the second quarter of 2004. The increase from the third quarter of 2003 was due primarily to production from our Brundage Canyon field which was purchased in late August 2003. Production from that field, which averaged less than 1,000 BOE/day for the third quarter of 2003, averaged 4,950 BOE/day in the third quarter of 2004. The Company drilled 42 wells in the Brundage Canyon field during the nine months ended September 30, 2004. A total of 55 wells are planned for the property in 2004.

Production (BOE/day) from the Company's California properties averaged 15,689, 15,971 and 15,522 for the third quarter of 2004, the second quarter of 2004 and the third quarter of 2003, respectively. The Company has plans to drill approximately 20 new wells and work over approximately 24 wells in the fourth quarter of 2004, which is expected to improve California production to approximately 16,000 BOE/day. Additionally, the Company has launched three new enhanced (thermal) recovery projects in California (Poso Creek field, Ethel D property and a diatomite pilot) which all show promise to increase production in future periods. On a Companywide basis, management believes the Company will achieve its average production target of 20,500 BOE/day in 2004.

While preliminary, the Company is targeting production growth from existing assets of approximately 10% to average in excess of 22,500 BOE/day in 2005. This expectation is based on crude oil prices exceeding WTI $35 per barrel and maintaining a historic natural gas to oil pricing ratio of six to one. The Company is anticipating a capital budget for 2005 of at least $80 million with the majority of funds allocated for Rocky Mountain activity.

     World crude oil prices reached an all time high during the third quarter of 2004, with Nymex WTI prices averaging $43.89 per barrel. In the third quarter, the Company's average price received per BOE was $32.28, up 13% from $28.55 in the second quarter of 2004 and 46% from $22.07 per BOE in the third quarter of 2003. The difference of $11.61 between the price received by the Company and Nymex WTI average price for the quarter is derived from 1) the quality differential between WTI crude oil and the heavier crude oils produced by the Company, which was a reduction of approximately $5.39 per BOE, 2) hedge losses on produced and sold quantities in the quarter had an impact of $3.32 per BOE, and 3) a price based royalty paid on production from a California property that lowered the price by $2.90 per BOE. The average differential per barrel between Nymex WTI and the average posting for the Company's 13 degree heavy crude oil in California, which averaged $5.72 in 2003, has expanded to an average of $8.68 in the third quarter of 2004, and was $11.38 on September 30, 2004. The Company believes that this widening differential is due to the WTI price being well above $40 per barrel and a general increase in supply of heavier crude oil on a worldwide basis.

The Company has a sales contract in California under which it sells 97% of its California production with a price mechanism equating to WTI less approximately $6.00 per barrel. This contract expires December 31, 2005 and while the Company believes there is a sufficient market for its crude oil, it can make no assurances as to the terms it can negotiate within a new sales contract. The Company anticipates crude oil prices to remain strong for the foreseeable future. However, since crude oil prices are impacted by world supply and demand and other factors, actual prices may vary significantly from current levels. Please refer to Part 1, Item 3 of this report for more detail concerning the

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Company's current hedge strategy and the impact of these agreements on current and future revenues. For the nine months ended September 30, 2004, the Company's average price received, net of hedges, was $28.81, up 28% from $22.45 received in the same period of 2003.

     Sales of oil and gas of $61.6 million in the third quarter of 2004 was up 84% from $33.5 million generated in the third quarter of 2003. On a year-to-date basis, sales of oil and gas increased 64% to $159.5 million in the 2004 nine-month period from $97.3 million in the first nine months of 2003. In 2004, approximately 93% of the Company's oil and gas sales is crude oil, with 79% being heavy crude oil produced in California.

     The Company has continued its practice of hedging a portion of its production to protect cash flows from a severe crude oil price decline. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for information related to these agreements and their impact on future revenues. The Company nets its oil hedging realized gains or losses into its revenues from the sales of oil and gas. For the third quarter of 2004, the effect of these agreements was to reduce the net realized price per barrel of crude oil by $3.32 compared to a reduction of $2.28 in the second quarter of 2004 and $1.90 in the third quarter of 2003.

     The Company sells approximately 79 MW of the 88 MW of electricity it generates from its cogeneration facilities. The Company consumes 9 MW, or 10%, of its generation in its field operations. The Company estimates that this consumption practice reduces California oil and gas operating costs by $.20 per BOE. Approximately 59 MW is sold to utilities under Standard Offer (SO) contracts that are scheduled to terminate on December 31, 2004. In January 2004, the California Public Utilities Commission (CPUC) issued a decision that orders the utilities to continue to purchase energy and capacity from Qualified Facilities (QFs), such as Berry, under 5-year SO contracts. The CPUC has not yet determined the price that will be paid under these SO contracts. The Company is currently reviewing draft agreements to accomplish this CPUC order, and expects to sign final agreements in the fourth quarter of 2004. The remaining 20 MW of electricity continues to be sold to a utility under a long-term SO contract that is scheduled to terminate in March 2009. The outlook for electricity volume appears to be relatively stable in 2005. However, revenues will be impacted by volatile fuel (natural gas) costs.

     Oil and gas operating expenses per BOE for the third quarter of 2004 were $11.54, up 6% from $10.90 in the third quarter of 2003 and, up 11% from $10.38 in the second quarter of 2004. The primary factor contributing to higher operating costs is steam cost, which increased as a result of a 10% increase in injection volumes into California heavy oil properties during the third quarter of 2004 compared to injection volumes in both the third quarter of 2003 and the second quarter of 2004. Overall, the Company injected approximately 6.7 million barrels of steam during the third quarter of 2004. In addition to higher injection volumes, the operating costs increased in the third quarter of 2004 from the third quarter of 2003 because the cost of natural gas used as fuel in the Company's steam generating operations increased 11% between the two periods. Oil and gas operating expenses for the third quarter of 2004 were $22.1 million, up from $16.5 million, in the third quarter of 2003 and, up from $19.2 million in the second quarter of 2004, which is consistent with production growth.

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For the nine months ended September 30, 2004, operating costs per BOE were $10.69, up 2% from $10.46 for the first nine months of 2003. Contributing to the increase in costs per BOE was an 8%, or 1.3 million increase in steam injection volume (in barrels) to 18.6 million in the 2004 nine month period. The cost of natural gas used in steam operations was fairly flat in the two nine-month periods averaging slightly over $5.00 per Mmbtu. Although the Company incurred higher operating costs of $59.3 million for the nine months ended September 30, 2004, up from $45.3 million for the first nine months of 2003, the cost per BOE remained fairly flat because the operating cost per BOE at the Brundage Canyon properties is lower than California since steam is not required in the Utah operations. The Company anticipates that operating costs will average between $10.50 and $11.25 per BOE during the full year of 2004 based on increasing natural gas prices. The Company is targeting operating costs per BOE in 2005 of between $11.00 and $12.00, which is higher than 2004 due to anticipated higher steam volumes and higher average prices for natural gas used to produce steam.

     DD&A per BOE for the third quarter of 2004 was $4.34, down by 6% from $4.60 in the second quarter of 2004, however, up 27% from $3.41 in the third quarter of 2003. DD&A per BOE for the first nine months of 2004 was $4.33, up 31% from $3.31 in the first nine months of 2003. The decrease in DD&A per BOE in the third quarter of 2004 compared to the second quarter of 2004 is due to a revision in the reserve estimates for Brundage Canyon that lowered the DD&A rate per BOE as a result of drilling production volumes exceeding previous expectations considered in prior DD&A rates. Consistent with expectations, the DD&A per BOE between the third quarter of 2004 and third quarter of 2003 is trending higher and is expected to continue to increase over the next few years due to the Utah acquisitions, continued development of its Utah and California properties and the shorter reserve life of the Utah assets compared to the California assets. DD&A for the third quarter of 2004 was $8.3 million, up from $5.2 million in the third quarter of 2003 and DD&A for the first nine months of 2004 was $24.0 million, up from $14.4 million in the first nine months of 2003. DD&A increase in total dollars is consistent with the Company's production growth. The Company anticipates its DD&A to approximate $32 million or range from an average of between $4.10 and $4.50 per BOE for all of 2004. For 2005, the Company expects DD&A to approximate $4.40 to $4.70 per BOE, or $36 million to $38 million.

     G&A per BOE for the third quarter of 2004 was $2.21, or $4.2 million, down 7% from $2.38, or $4.4 million in the second quarter of 2004 and up 43% from $1.55, or $2.4 million in the third quarter of 2003. For the first nine months of 2004, G&A per BOE was $2.74, or $15.2 million compared to $1.81, or $7.9 million in the first nine months of 2003. Stock option compensation was $5.0 million for the nine months ended September 30, 2004, up $3.5 million from $1.5 million incurred in the first nine months of 2003. G&A expenses also increased in 2004 due to $.8 million in costs associated with the change in the chief executive officer of the Company in the second quarter of 2004, increases in payroll costs of $1.9 million resulting from additional staffing to accommodate Company growth, a change in the treatment of stock compensation, higher accounting and legal fees related to Sarbanes-Oxley compliance and higher oil and gas property evaluation expenses. The Company anticipates G&A costs for all of 2004 to be between $18.0 and $19.0 million and average between $2.40 and $2.55 per BOE. The Company expects its G&A costs to be much lower in 2005 than 2004, primarily due to lower charges related to its stock option accounting. The Company anticipates its G&A costs for 2005 will approximate $1.55 to $1.75 per BOE, or $13 million to $14 million.

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     The Company experienced an effective tax rate of 31% for the third quarter of 2004, up from 17% for the same period last year. The significant improvement in pre-tax income had the effect of lowering in percentage terms the benefit of enhanced oil recovery (EOR) credit. For the nine months ending September 30, 2004, the Company's effective tax rate was 27%, up from 15% in the same period last year. This increase is also directly related to improved earnings. The Company's investment in qualifying EOR projects in California allows for an effective rate well below the statutory rate of 40%. Based on current oil prices, the Company anticipates an effective tax rate for 2004 of between 24% and 28%. With the likelihood that WTI will average over $42 per barrel in 2004, the Company believes the EOR tax credit will be reduced in 2005 due to the phase-out under its pricing mechanism. Thus, the Company expects to earn less EOR credit in 2005. Generally, the Company expects that its effective tax rate will trend higher as it dedicates an increasing percentage of it capital investments to non-EOR projects. The American Jobs Creation Act, signed by the President on October 22, 2004, is expected to reduce the Company's effective tax rate by approximately one percentage point. Given the above and the outlook for crude oil pricing next year, the Company expects its effective tax rate to average between 34% and 38%.

Net cash provided by operating activities was $78.5 million in the first nine months of 2004, up $38.5 million or 96% from $40.0 million in the first nine months of 2003. The increase in cash provided is the direct result of increases in crude oil prices and higher production levels in the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003. Sales of oil and gas increased $62.2 million during the period ended September 30, 2004 compared to the same period in 2003 due to a 28% increase in crude oil prices, net of hedges, and a 28% increase in production between the respective periods. Cash flows from operations were affected by an $11.5 million increase in current liabilities, primarily due to a higher level of operating activities in the 2004 nine month period. Cash flows from operations were also impacted by a $10.2 million increase in receivables due primarily to higher crude oil prices and production levels during the nine months ended September 30, 2004.

     Excluding 2004 acquisitions, the Company's revised capital budget for 2004 is approximately $70 million, up 32% from its initial capital budget of approximately $53 million. The Company expects to drill a total of approximately 120 wells, perform approximately 90 workovers and complete various facility improvements. The Company intends to fund 100% of its capital program out of internally generated cash flow. During the first 9 months of 2004, cash was used to fund $51.9 million in capital expenditures, which included drilling 93 new wells and completing 76 workovers. Of these totals, 51 new wells were drilled and 41 workovers were performed in California and 42 new wells were drilled and 35 workovers were performed on the Brundage Canyon property.

In August 2004, the Company increased its annual dividend by 9% to $.12 per share per quarter ($.48 per share per annum) and announced a special dividend of $.06 per share. The Company paid dividends of $4.1 million during the third quarter of 2004, which is included in dividends paid of $8.8 million in the first nine months of 2004.
     

In the third quarter of 2004, the Company paid down $17 million of long-term debt. As of September 30, 2004, the Company had $167 million available under its $200 million unsecured credit facility. Cash provided by operating activities

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will be targeted to acquisitions, additional development and debt reduction. As of September 30, 2004, the Company had not closed on the acreage in Lake Canyon. The Company will pay approximately $2 million for this acreage and related costs in the fourth quarter of 2004. The Company estimates its share of the drilling cost associated with its 34 well drilling commitment with the Ute Indian Tribe and Ute Distribution Corporation through December 31, 2009 is approximately $21 million. This estimate is subject to changes in drilling and completion costs. The Company anticipates that it will participate in the first deep test well on this acreage which is targeted to spud in January 2005. The Company is also planning to drill at least two shallow wells on this acreage in the first quarter of 2005.

                            Forward Looking Statements

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 natural gas volumes purchased for its steaming operations. These contracts have historically been in the form of zero-cost collars and swaps. The Company typically hedged 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. Going forward, the Company anticipates that it will implement its hedges in the form of swaps with a target of approximately 50% of its production to capture the benefit of favorable crude pricing. The Company may, at times, exceed the 50% target, but in no circumstances foresees exceeding 75% of its production. All of these hedges have historically been deemed to be cash flow hedges with the mark-to-market valuations of the collars and swaps provided by external sources, based on prices that are actually quoted. The Company reviews the effectiveness of these hedges on a regular basis. The Company may not have the benefit of a sales contract that links heavy crude oil prices to Nymex WTI crude prices after 2005, thus, any hedges placed on volumes in 2006 or beyond may not be deemed to be cash flow hedges. Therefore, the accounting treatment under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, may require mark-to-market valuations which would impact the income statement before the cash settlement of the hedge.

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     Based on NYMEX futures prices as of September 30, 2004, the Company would expect to make pre-tax future cash receipts (cash payments) over the remaining term of its crude oil (through December 31, 2005) and natural gas (through June 30, 2006) hedges in place as follows:

The Company sells approximately 79 MW of the 88 MW of electricity it generates from its cogeneration facilities. The Company consumes 9 MW, or 10%, of its generation in its field operations. The Company estimates that this consumption practice reduces California oil and gas operating costs by $.20 per BOE. Approximately 59 MW is sold to utilities under Standard Offer (SO) contracts that are scheduled to terminate on December 31, 2004. In January 2004, the California Public Utilities Commission (CPUC) issued a decision that orders the utilities to continue to purchase energy and capacity from Qualified Facilities (QFs), such as Berry, under 5-year SO contracts. The CPUC has not yet determined the price that will be paid under these SO contracts. The Company is currently reviewing draft agreements to accomplish this CPUC order, and expects to sign final agreements in the fourth quarter of 2004. The remaining 20 MW of electricity continues to be sold to a utility under a long-term SO contract that is scheduled to terminate in March 2009. The outlook for electricity volume appears to be relatively stable in 2005. However, revenues will be impacted by volatile fuel (natural gas) costs.

     The Company attempts to minimize credit exposure to counterparties through monitoring procedures and diversification. The Company's exposure to changes in interest rates results primarily from long-term debt. Total debt outstanding at September 30, 2004 and December 31, 2003 was $33 million and $50 million, respectively. Interest on amounts borrowed is charged at LIBOR plus 1.25% to 2.0%. Based on these borrowings, a 1% change in interest rates would not have a material impact on the Company's condensed financial statements.

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BERRY PETROLEUM COMPANY
Part I. Financial Information
Item 4. Controls and Procedures

     Based on an evaluation by the Company's management as of the end of the period covered by this Quarterly Report on Form 10-Q, subject to and except for the discussion below, the Company's Chief Executive Officer and Chief Financial Officer have concluded that the Company's disclosure controls and procedures, as defined by regulations of the Securities Exchange Act of 1934 as amended (the "Exchange Act"), are effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission's rules and forms.

     In July, 2004, the Company became aware of a material weakness relating to the Company's internal controls and procedures over its financial reporting for stock based compensation relating to its stock option plan. As a result, the Company performed a review of the method of stock option exercises by employees and directors since the plan's inception in 1994. Based on this review, the Company determined that variable plan accounting was required to comply with generally accepted accounting principles in the United States. In response to this matter, the Company, during the third quarter 2004, revised its procedures related to stock option exercising to remove the option holder's election to surrender options in payment of any portion of taxes above the minimum statutory withholding. Furthermore, the Company, during the third quarter 2004, has remediated the ineffective internal controls through the implementation of enhanced controls to assure that financial reporting is in compliance with generally accepted accounting principles in the United States.

     The Company has identified no changes in the internal control over financial reporting that occurred during the fiscal quarter ended September 30, 2004, and that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting, except as described above.

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     On July 19, 2004 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 acquisition of additional Uinta Basin acreage and a joint exploration and development program.

     On July 26, 2004 the Company filed a Form 8-K reporting an Item 12 - Disclosure of results of operations and financial condition to furnish the Securities and Exchange Commission a copy of the Company's Press Release announcing a rescheduling of the release of the Company's financial results for the three months ended June 30, 2004 and the revision of accounting treatment for stock options.
  

     On August 9, 2004, the Company filed a Form 8-K reporting an Item 9 - Regulation FD Disclosure and Item 12 - Disclosure of results of operations and financial condition to furnish the Securities and Exchange Commission a copy of the Company's Press Release announcing financial results for the three and six months ended June 30, 2004.

     On August 31, 2004, the Company filed a Form 8-K reporting an Item 7.01 - Regulation FD announcing the increase in the annual dividend and capital budget.

     Exhibit No.               Description

31.1   Rule 13a-14(a) Certification of Chief Executive Officer

31.2   Rule 13a-14(a) Certification of Chief Financial Officer

32.1   Rule 1350 Certification of Chief Executive Officer

32.2   Rule 1350 Certification of Chief Financial Officer

 

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                                    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:  October 26, 2004