The Company's contractual obligations as of December 31, 2003 are as follows (in thousands):

Contractual Obligations
2004

2005

2006

2007

2008

Thereafter

Total

Long-term debt $ - $ - $ 50,000 $ - $ - $ - $ 50,000
Operating lease obligations 528 562 487 107 107 90 1,881
Firm natural gas
transportation contract
3,066 3,066 3,066 3,066 3,066 13,280 28,610

Total $ 3,594 $ 3,628 $ 53,553 $ 3,173 $ 3,173 $ 13,370 $ 80,491

While the use of these hedging arrangements reduces the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. The Company's oil hedges are based on reported settlement prices on the NYMEX. The basis risk between NYMEX and the Company's California heavy crude oil is mitigated by the Company's crude oil sales contract under which the Company sells over 90% of its California production. Pricing in the existing agreement is based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed differential approximating $6.00 per barrel. This contract expires on December 31, 2005.

The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. With respect to the Company’s hedging activities, the Company utilizes multiple counterparties on its hedges and monitors each counterparty’s credit rating.

Table of Contents

Application of Critical Accounting Policies

The preparation of financial statements in conformity with generally accepted accounting principles requires Management to make estimates and assumptions for the reporting period and as of the financial statement date. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities and the reported amounts of revenues and expenses. Actual results could differ from those amounts.

A critical accounting policy is one that is important to the portrayal of the Company's financial condition and results, and requires Management to make difficult subjective and/or complex judgments. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. The Company believes the following accounting policies are critical ~~policies; accounting~~policies.

Successful Efforts Method of Accounting.The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves ~~environmental liabilities, income taxes~~have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and ~~asset retirement obligations.~~where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized as long as the additional exploratory work is under way or firmly planned.

Oil and Gas Reserves.Oil and gas reserves include proved reserves that 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. The Company's oil and gas reserves are based on estimates prepared by independent engineering ~~consultants~~consultants. Reserve engineering is a subjective process that requires judgment in the evaluation of all available geological, geophysical, engineering and economic data. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices may significantly impact estimated reserve quantities. Depreciation, depletion and amortization (DD&A) expense and impairment of proved properties are ~~used~~impacted by the Company's estimation of proved reserves. These estimates are subject to ~~calculate~~change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased DD&A expense, increased impairment of proved properties and ~~determine if any potential~~a lower standardized measure of discounted future net cash flows.

Carrying Value of Long-lived Assets.Downward revisions in the Company’s estimated reserve quantities, increases in future cost estimates or depressed crude oil or natural gas prices could cause the Company to reduce the carrying amounts on its properties. The Company performs an impairment ~~exists related~~analysis of its proved properties annually by comparing the future undiscounted net revenue per the annual reserve valuation prepared by the Company’s independent reserve engineers to the ~~recorded~~net book carrying value of the assets. An analysis of the proved properties will also be performed whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable from future net revenue. Assets are grouped at the field level and if it is determined that the net book carrying value cannot be recovered by the estimated future undiscounted cash flow, they are written down to fair value. For its unproved properties, the Company performs an impairment analysis annually or whenever events or changes in circumstances indicate an asset’s net book carrying value may not be recoverable. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil and natural gas reserves, future crude oil and natural gas prices and costs to extract these reserves.

Derivatives and Hedging.The Company follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 133,Accounting for Derivative Instruments and Hedging Activities. SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income. Under the provisions of SFAS 133, the Company may designate a derivative instrument as hedging the exposure to change in fair value of an asset or liability that is attributable to a particular risk (a fair value hedge) or as hedging the exposure to variability in expected future cash flows that are attributable to a particular risk (a cash flow hedge). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the derivative contract or by effectiveness assessments using statistical measurements. The Company's policy is to assess hedge effectiveness at the end of each calendar quarter.

Table of Contents

Income Taxes.The Company computes income taxes in accordance with SFAS No. 109,Accounting for Income Taxes. SFAS No. 109 requires an asset and liability approach which results in the recognition of deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the Company's financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, the Company's federal and state income tax returns are generally not filed before the financial statements are prepared, therefore the Company estimates the tax basis of its assets and liabilities at the end of each calendar year as well as the effects of tax rate changes, tax credits, and tax credit carryforwards. Adjustments related to differences between the estimates used and actual amounts reported are recorded in the period in which income tax returns are filed. These adjustments and changes in estimates of asset recovery could have an impact on results of operations. The Company generates enhanced oil recovery tax credits from the production of its heavy crude oil in California which results in a deferred tax asset. The Company believes that these credits will be fully utilized in future years and consequently has not recorded any valuation allowance related to these credits. Due to uncertainties involved with tax matters, the future effective tax rate may vary significantly from the estimated current year effective tax rate.

Asset Retirement Obligations.The Company has significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and gas ~~properties.~~production operations. The computation of the Company's asset retirement obligations (ARO) was prepared in accordance with SFAS No. 143,Accounting for Asset Retirement Obligations, which requires the Company to record the fair value of liabilities for retirement obligations of long-lived assets. The adoption of SFAS No. 143 in 2002 resulted in an immaterial difference in the liability that had been previously recorded by the Company. Estimating the future ARO requires Management to make estimates and judgments regarding timing, current estimates of plugging and abandonment costs, as well as what constitutes adequate remediation. The Company obtained estimates from third parties and used the present value of estimated cash flows related to its ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Changes in any of these assumptions can result in significant revisions to the estimated ARO. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment will be made to the related asset. Due to the subjectivity of assumptions and the relatively long life of the Company's assets, the costs to ultimately retire the Company's wells may vary significantly from previous estimates.

Environmental Remediation Liability.The Company reviews, on a quarterly basis, its estimates of costs of the cleanup of various sites including sites in which governmental agencies have designated the Company as a potentially responsible party. ~~When~~In accordance with SFAS No. 5,Accounting for Contingencies, when it is probable that obligations have been incurred and where a minimum cost or a reasonable estimate of the cost of remediation can be determined, the applicable amount is accrued. ~~Actual costs can differ from estimates due to changes in~~Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is an estimation process that includes the subjective judgment of Management. In many cases, Management's judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations, ~~discovery~~which can be interpreted differently by regulators or courts of law, the experience of the Company and ~~analysis of site conditions and changes~~other companies in ~~technology.~~

The Company makes certain estimates in determining its provision for income taxes. These estimates in determining taxable income, among other things, may include various tax planning strategies, the timing of deductionsdealing with similar matters and the ~~utilization~~decision of ~~tax attributes.~~

Management ~~is required~~on how it intends to ~~make judgments based on historical experience and future expectations on~~respond to a particular matter. A change in estimate could impact the ~~future abandonment cost of its~~Company's oil and gas ~~properties~~operating costs and ~~equipment. The Company reviews its estimate of~~ the ~~future obligation quarterly and accrues~~liability, if applicable, recorded on the ~~estimated obligation monthly based on SFAS No. 143, “Accounting for Asset Retirement Obligations”.~~Company's balance sheet.

Recent Accounting Developments

In December 2004, the ~~fourth quarter of 2002, the Company adopted the supplemental disclosure requirements~~Financial Accounting Standards Board (FASB) issued SFAS 123(R),Share-Based Payments, which is a revision of SFAS 123. SFAS 123(R) supersedes APB 25 and amends Statement of Accounting Standards No. ~~148, “Accounting for Stock-Based Compensation – Transition and Disclosure”, which amended~~95,Statement of Cash Flows. Generally, the approach in SFAS ~~No. 123, “Accounting for Stock-Based Compensation.” The Company continues~~123(R) will require all share-based payments to ~~record compensation related to~~employees, including grants of employee stock options, to be recognized based on their fair values. SFAS 123(R) must be adopted by the ~~intrinsic value method per APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 148 encourages companies to voluntarily elect to record~~Company no later than the ~~compensation based on market value either prospectively, as defined in SFAS No. 123, or retroactively or in a modified prospective method.~~third quarter of 2005. The Company ~~uses the Black-Scholes model to calculate~~voluntarily adopted SFAS 123 as of January 1, 2004 and ~~disclose the market value of its options granted. The Company~~ does not advocate nor does it believe that the Black-Scholes model can properly determine the val ue of a stock option, like Berry’s, that vest over a period of time and is not freely tradable upon grant. Therefore, the Company has delayed the potential transition to recording stock compensation based on fair market value until required by accounting standards in 2005.


	20

In November 2002 the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others ("FIN 45")." This Interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. In addition, the Interpretation clarifies the requirements related to the recognition of a liability by a guarantor at the inception of a guarantee for the obligations that the guarantor has undertaken in issuing the guarantee. The Company adopted the disclosure requirements of FIN 45 for the fiscal year ended December 31, 2002, and the recognition provisions on January 1, 2003. Adoption of this Interpretation did not have a material impact on the Company's Financial Statements.

~~In June 2002 the FASB issued~~expect SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring)." The Company has adopted, effective January 1, 2003, the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. SFAS No. 146 did not123(R) will have a material impact on the Company's financial ~~statements.~~position, net income or cash flows.

In ~~April 2003~~December 2004, the FASB issued FASB Staff Position (FSP) FAS 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004, This position clarifies how to apply SFAS No. ~~149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities.~~109 to the new law's tax deduction for income attributable to "domestic production activities." SFAS No. 149 amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying to conform it to language used in FIN 45, and amends certain other existing pronouncements. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and should be applied prospectively, with the exception of certain SFAS No. 133 implementation issues that were effective for all fiscal quarters prior to June 15, 2003. Any such implementation issues should continue to be applied in accordance with their respective effective dates. The ~~adoption of SFAS No. 149 did~~Company does not expect this statement will have a material impact on the Company's financial ~~statements.~~position, net income or cash flows.

~~During January 2003, the Financial Accounting Standards Board issued Interpretation No. 46, “Consolidation~~

Table of Variable Interest Entities” (“FIN 46”), which requires the consolidation of certain entities that are determined to be variable interest entities (“VIE’s”). An entity is considered to be a VIE when either (i) the entity lacks sufficient equity to carry on its principal operations, (ii) the equity owners of the entity cannot make decisions about the entity’s activities or (iii) the entity’s equity neither absorbs losses or benefits from gains. The Company has reviewed its financial arrangements and has not identified any material VIE’s that should be consolidated by the Company in accordance with FIN 46.Contents

In January 2005, the FASB issued SFAS No. 153,Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 28. This statement, which addresses the measurement of exchanges of nonmonetary assets, is effective prospectively for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of this statement is not expected to impact the Company's financial position, net income, or cash flows.

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.

~~Item 7A. Quantitative~~Other Factors Affecting the Company's Business and ~~Qualitative Disclosures About Market Risk~~Financial Results

Oil and gas prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on the Company's business.The Company's revenues, profitability and future growth depend substantially on reasonable prices for oil and gas. These prices also affect the amount of cash flow available for capital expenditures and the ability to borrow and raise additional capital. The amount the Company can borrow under its credit facility is subject to periodic asset redeterminations based in part on changing expectations of future crude oil and natural gas prices. Lower prices may also reduce the amount of oil and gas that can be economically produced.

Among the factors that can cause fluctuations are:

the domestic and foreign supply of oil and natural gas;

the price and availability of alternative fuels;

weather conditions;

the level of consumer demand;

the price of foreign imports;

world-wide economic conditions;

political conditions in oil and gas producing regions;

the change in the value of the U.S. dollar as global oil prices are priced in U. S. dollars; and

domestic and foreign governmental regulations.

The Company's heavy crude in California is less economic than lighter crude oil and natural gas. As of December 31, 2004, approximately 88% of the Company's proved reserves, or 97 million barrels, consisted of heavy oil. Heavy oil sells for less than light sweet crudes, over the past ten years, approximately $6.00 per barrel less. However, this differential widened during 2004, averaging $8.57 and has averaged over $14.00 during the first two months of 2005. Additionally, most of the Company's heavy oil production requires heat, in the form of steam, to mobilize the oil for production from the wellbore. Steam costs represent a significant portion of the Company's operating costs and are costs that the production of light crude oil or natural gas do not have. This thermal enhanced process and the related costs further reduce the Company's margins on its heavy crude oil. The Company consumes natural gas to generate steam and thus is at risk when natural gas prices rise without a corresponding rise in crude oil prices.

A widening of commodity differentials may adversely impact the Company’s revenues and per barrel economics. Both the Company’s produced crude oil and natural gas is subject to pricing in the local markets where the production occurs. It is customary that such product is priced based on local or regional supply and demand factors. California heavy crude sells at a substantial discount to WTI, the U.S. benchmark crude oil, primarily due to the additional cost to refine more gasoline or light product out of a barrel of heavy crude. The Company’s Utah light crude also is normally priced below WTI. Natural gas field prices are normally priced off of NYMEX traded prices or Henry Hub, the benchmark for U.S. natural gas. While the Company attempts to contract for the best possible price in each of its producing locations, there is no assurance that past price differentials will continue into the future. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the mid-stream or downstream sectors of the business, trade restrictions, governmental regulations, etc. The Company may be adversely impacted by a widening differential on the products it sells.

The future of the electricity market in California is uncertain. The Company utilizes cogeneration plants in California to generate lower cost steam compared to conventional steam generation methods. Electricity produced by the Company's cogeneration plants is sold to utilities and the steam costs are allocated to the Company’s oil and gas operations. While the Company has new five-year electricity sales contracts in place with the utilities beginning on January 1, 2005, legal and regulatory decisions, especially related to the pricing of electricity under the contracts, can adversely affect the economics of the Company’s cogeneration facilities and thereby, the cost of steam for use in the Company’s oil and gas operations. In addition, the utilities are seeking to overturn the CPUC order to offer such contracts.

Table of Contents

The Company may be subject to the risk of adding additional steam generation equipment if the electrical market deteriorates significantly.The Company may be subject to the risk of adding additional steam generation equipment if the electrical market deteriorates significantly. The Company is dependent on several cogeneration facilities that provide over half of its steam requirement. These facilities are dependent on reasonable electrical contracts to provide economic steam for use in the Company's operations. If, for any reason, the Company was unable to enter into an electrical contract or were to lose an existing contract, the Company may not be able to supply 100% of the steam requirements necessary to maximize production from its heavy oil assets. An additional investment in various steam sources may be necessary to replace such steam. The financial cost and timing of such investment may adversely affect the Company's production and cash provide by operating activities.

A shortage of natural gas in California could adversely affect the Company's business.The Company may be subject to the risks associated with a shortage of natural gas and/or the transportation of natural gas into California. The Company is highly dependent on sufficient volumes of natural gas that it uses for fuel in generating steam for use in its heavy oil operations in California. If the required volume of natural gas for use in its operations were to be unavailable or too highly priced to produce heavy oil economically, the Company's production could be adversely impacted.

The Company's use of oil and gas price hedging contracts involves credit risk and may limit future revenues from price increases and result in significant fluctuations in net income. The Company uses hedging transactions with respect to a portion of its oil and gas production to achieve more predictable cash flow and to reduce its exposure to a significant decline in the price of crude oil. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases. Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations.

The Company's future success depends on its ability to find, develop and acquire oil and gas reserves. To maintain production levels, the Company must locate and develop or acquire new oil and gas reserves to replace those depleted by production. Without successful exploration, exploitation or acquisition activities, the Company's reserves, production and revenues will decline. The Company may not be able to find and develop or acquire additional reserves at an acceptable cost. In addition, substantial capital is required to replace and grow reserves. If lower oil and gas prices or operating difficulties result in the Company's cash flow from operations being less than expected or limit its ability to borrow under credit arrangements, the Company may be unable to expend the capital necessary to locate and develop or acquire new oil and gas reserves.

Actual quantities of recoverable oil and gas reserves and future cash flows from those reserves most likely will vary from estimates.Estimating accumulations of oil and gas is complex. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions, some of which are mandated by the Securities and Exchange Commission (SEC), such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:

the quality and quantity of available data;

the interpretation of that data;

the accuracy of various mandated economic assumptions; and

the judgment of the persons preparing the estimate.

Actual quantities of recoverable oil and gas reserves, future production, oil and gas prices, revenues, taxes, development expenditures and operating expenses most likely will vary from estimates. Any significant variance could materially affect the quantities and present value of the Company's reserves. In addition, the Company may adjust estimates of proved reserves to reflect production history, results of development and exploration and prevailing oil and gas prices.

In accordance with SEC requirements, the Company bases the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

If oil and gas prices decrease, the Company may be required to take writedowns.The Company may be required to writedown the carrying value of its oil and gas properties when oil and gas prices are low, including basis differentials, or there are substantial downward adjustments to its estimated proved reserves, increases in estimates of development costs or deterioration in exploration or production results.

The Company ~~enters into various~~capitalizes costs to acquire, find and develop its oil and gas properties under the successful efforts accounting method. The net capitalized costs of the Company's oil and gas properties may not exceed the fair market value.

Table of Contents

If net capitalized costs of its oil and gas properties exceed fair value, the Company must charge the amount of the excess to earnings. The Company reviews the carrying value of its properties annually and at any time when events or circumstances indicate a review is necessary, based on prices in effect as of the end of the reporting period. The carrying value of oil and gas properties is computed on a field-by-field basis. Once incurred, a writedown of oil and gas properties is not reversible at a later date even if oil or gas prices increase.

The Company may be subject to risks in connection with acquisitions. The successful acquisition of producing properties requires an assessment of several factors, including:

reserves;

future oil and gas prices;

operating costs;

title to properties; and

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, the Company performs a review of the subject properties that it believes to be generally consistent with industry practices. A review will not necessarily reveal all existing or potential problems nor will it permit the Company to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. The Company often is not entitled to contractual indemnification for certain liabilities and acquires properties on an “as is” basis.

Competitive industry conditions may negatively affect our ability to conduct operations. Competition in the oil and gas industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage. Major and independent oil and gas companies actively bid for desirable oil and gas properties, as well as for the equipment and labor required to operate and develop their properties. Many of the Company's competitors have financial ~~contracts~~resources that are substantially greater, which may adversely affect the Company's ability to ~~hedge~~compete with these companies.

Drilling is a high-risk activity. The Company's future success will partly depend on the success of its ~~exposure~~drilling program. In addition to ~~commodity price~~the numerous operating risks described in more detail below, these activities involve the risk that no commercially productive oil or gas reservoirs will be discovered. In addition, the Company is often uncertain as to the future cost or timing of drilling, completing and producing wells. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

obtaining government and tribal required permits;

unexpected drilling conditions;

pressure or irregularities in formations;

equipment failures or accidents;

adverse weather conditions;

compliance with governmental or landowner requirements; and

shortages or delays in the availability of drilling rigs and the delivery of equipment.

The oil and gas business involves many operating risks that can cause substantial losses; insurance may not protect the Company against all of these risks. These risks include:

fires;

explosions;

blow-outs;

uncontrollable flows of oil, gas, formation water or drilling fluids;

natural disasters;

pipe or cement failures;

casing collapses;

embedded oilfield drilling and service tools;

abnormally pressured formations;

major equipment failures, including cogeneration facilities; and

environmental hazards such as oil spills, natural gas leaks, pipeline ruptures and discharges of toxic gases.

Table of Contents

If any of these events occur, the Company could incur substantial losses as a result of:

injury or loss of life;

severe damage or destruction of property, natural resources and equipment;

pollution and other environmental damage;

investigatory and clean-up responsibilities;

regulatory investigation and penalties;

suspension of operations; and

repairs to resume operations.

If the Company experiences any of these problems, its ability to conduct operations could be adversely affected.

The Company maintains insurance against some, but not all, of these potential risks and losses. The Company may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect the Company.

The Company is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.The Company's development, exploration, production and marketing operations are regulated extensively at the federal, state and local levels. In addition, a portion of the Company's leases in the Uinta Basin are, and some of the Company's future leases may be, regulated by Native American tribes. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, the Company could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of the Company's operations and subject it to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which the Company operates includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, the Company's activities are subject to the regulation by oil and natural gas-producing states and Native American tribes of conservation practices and protection of correlative rights. These regulations affect the Company's operations and limit the quantity of oil and natural gas the Company may produce and sell. A major risk inherent in the Company's drilling plans is the need to obtain drilling permits from state, local and Native American tribal authorities. Delays in obtaining regulatory approvals, drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on the Company's ability to explore on or develop its properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect the Company's profitability.

Other independent oil and gas companies’ limited access to capital may change the Company's development and exploration plans. Many independent oil and gas companies have limited access to the capital necessary to finance their activities. As a result, some of the other working interest owners of the Company's wells may be unwilling or unable to pay their share of the costs of projects as they become due. These problems could cause the Company to change, suspend or terminate drilling and development plans with respect to the affected project.

Commonly Used Oil and Gas Terms

Below are explanations of some commonly used terms in the oil and gas business.

API gravity -The industry standard method of expressing specific gravity of crude oils. Higher API gravities mean lower specific gravity and lighter oils.

Basis risk - The risk associated with ~~its~~the sales point price for oil or gas production varying from the reference (or settlement) price for a particular hedging transaction.

Bbl - - One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil ~~production, electricity production and net~~or condensate.

Bcf - - Billion cubic feet.

Bcfe - - Billion cubic feet equivalent, determined using the ratio of six Mcf gas to one Bbl of crude oil or condensate.

BOE - -Barrel of Oil equivalent.

BSPD - - Barrels of steam per day.

Table of Contents

Btu - - British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

California Public Utilities Commission (CPUC) - A California government agency which regulates privately owned electric, telecommunications, natural gas, ~~volumes purchased for its steaming operations. These contracts related~~water and transportation companies.

Cash-flow hedge -Derivative instruments used to mitigate the risk of variability in cash flows from crude oil and natural gas sales due to changes in market prices. These derivative instruments either fix the price a party receives for its production or, in the case of option contracts, set a minimum price or a price within a fixed range.

Cogeneration - - The simultaneous production of steam and electricity using a single fuel source (natural gas).

Completion - - The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

DD&A - -Depreciation, Depletion and Amortization

Developed acreage - The number of acres that are allocated or assignable to producing wells or wells capable of production.

Development well - A well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive, including a well drilled to find and produce probable reserves.

Dry hole or well - A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Enhanced Oil Recovery (EOR) -Efforts to improve the flow of oil from a reservoir that has already been produced by conventional means.

Exploitation - -Drilling wells in areas proven to be productive.

Exploration or exploratory well - A well drilled to find and produce oil or natural gas reserves that is not a development well.

Farm-out - -A transfer of all or part of the operating rights from the working interest owner to an asignee, who assumes all or some of the burden of development, in return for an interest in the property.

Federal Energy Regulatory Commission (FERC) - A government agency which regulates the transmission of oil and natural gas by pipeline and wholesale sales of electricity in interstate commerce.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

Gross acres or gross wells -The total acres or wells in which a working interest is owned.

Heavy oil - Oil with an API gravity below 20 degrees.

Henry Hub (HH) - The standard delivery point for natural gas traded on the New York Mercantile Exchange (Sabine Pipe Line Company's Henry Hub in Louisiana).

Infill drilling -Drilling wells between established producing wells on a lease; a drilling program to reduce the spacing between wells in order to increase production and/or recovery of in-place hydrocarbons from the lease.

Kilowatt (KW) - 1,000 watts, which are the standard measure of electrical power

MBbls - - One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf - - One thousand cubic feet.

Mcfe - - One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate.

Megawatt (MW) -One million watts.

MMS - - The Minerals Management Service of the United States Department of the Interior.

MMBbls - -One million barrels of crude oil or other liquid hydrocarbons.

MMcf - -One million cubic feet.

MMcfe - - One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate.

Net acres or net wells - The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NYMEX - - The New York Mercantile Exchange.

Productive well - A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Table of Contents

Proved developed producing reserves - Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

Proved developed reserves - Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved developed nonproducing reserves - Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved reserves - The estimated quantities of crude oil or natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves - Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Public Utility Regulatory Policies Act of 1978 (PURPA) - Federal regulation which provides incentives for the development of cogeneration facilities such as those owned by the Company.

Qualifying Facilities (QF) - A cogeneration facility which produces not only electricity, but also useful thermal energy for use in an industrial or commercial process for heating or cooling applications in certain proportions to the facility’s total energy output, and which meets certain energy efficiency standards.

Short Run Avoided Cost (SRAC) - An energy payment that reflects the utility’s avoided short-term variable cost to produce electricity.

Undeveloped acreage - Lease acreage on which wells have ~~historically~~not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

West Texas Intermediate (WTI) -The benchmark United States crude oil with an API gravity of approximately 40 degrees.

Working interest - The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover - - Operations on a producing well to restore or increase production.

Item 7A.

Quantitativeand Qualitative Disclosures About Market Risk

Price Risk Management.From time to time, the Company enters into crude oil and natural gas hedge contracts, the terms of which depend on various factors, including Management’s view of future crude oil and natural gas prices and the Company’s future financial commitments.This price hedging program is designed to moderate the effects of a severe crude oil price downturn and protect certain operating margins in the Company's California operations. Currently, the hedges are in the form of ~~zero-cost collars and~~ swaps, however, the Company ~~is considering~~may use a variety of hedge instruments ~~going forward.~~in the future. The Company generally attempts to hedge between 25% and 50% of its anticipated crude oil production and up to 30% of its anticipated net natural gas purchased each ~~year.~~year.Management regularly monitors the crude oil and natural gas markets and the Company’s financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging or other price protection is appropriate. 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.

Table of Contents


	21

As of December 31, 2004, the Company had hedge positions for 2005 of approximately 7,750 barrels per day of crude oil production at an average WTI price of approximately $40.75 and 7,500 MMBtu per day of natural gas consumption at an average SoCal price of approximately $5.25. At December 31, 2004 the Company had hedge positions for 2006 of 5,000 MMBtu per day through June 2006 at an average SoCal price of $4.85 and 1,000 MMBtu per day of natural gas production at a CIG price of $6.21. In 2004, the average differential between SoCal and Henry Hub (HH) was approximately $.60 per MMBtu and the differential between CIG and HH was approximately $1.00 per MMBtu. Based on NYMEX futures prices at December 31, ~~2003,~~2004, (WTI ~~$30.64; Henry Hub (HH) $5.21)~~$42.66; HH $6.32) the Company would expect ~~to make pre-tax~~ future cash payments or receipts, over the remaining term of its existing crude oil and natural gas hedges, ~~in place~~on a pre-tax basis, as follows:

				Impact of percent change in futures prices
	12/31/04			on earnings (in thousands)
	NYMEX Futures			-30%			-15%			+ 15%			+ 30%

Average WTI Price	$	42.66		$	29.86		$	36.26		$	49.05		$	55.45

Crude Oil gain/(loss)		(5,098	)		31,102			13,002			(23,199	)		(41,299	)

Average HH Price		6.32			4.43			5.38			7.27			8.22

Natural Gas gain/(loss)		2,625			(3,216	)		(295	)		5,545			8,466

Impact of percent change in futures prices
12/31/03
on earnings (in thousands)

NYMEX

Futures

-20%

-10%

+10%

+20%

Average WTI Price $ 30.64 $ 24.51 $ 27.57 $ 33.70 $ 36.77

Crude Oil gain/(loss) (8,400 ) 4,730 (1,710 ) (12,420 ) (16,160 )

Average HH Price 5.21 4.17 4.69 5.73 6.25

Natural Gas gain/(loss) 410 (3,720 ) (1,650 ) 2,470 4,530

The Company sells 100% of its electricity production, net of electricity used in its oil and gas operations, under SO contracts to major utilities. Three of the four SO contracts representing approximately 77% of the Company’s electricity for sale ~~originally~~ expired in one-year contracts on December 31, 2003. However, as ordered by CPUC, the utilities offered and the Company accepted one-year extensions on these contracts in January 2004 and ~~is evaluating its options beyond the revised termination dates. Among other things,~~as order by the CPUC ~~issued a decision~~ in ~~January~~late 2004, ~~that establishes rules whereby~~has entered into new five-year contracts with the ~~California utilities are required to offer Standard Offer contracts to certain qualified facilities, such as Berry, for a term of 5 years.~~utilities. However, the sales price under ~~this contract~~these contracts are subject to regulatory review and the pricing methodology may not be linked to natural gas ~~prices.~~prices in the future. The Company sells the remaining 20 MWh to a utility at $53.70 per MWh plus ~~cap acity~~capacity through a long-term sales ~~contract.~~contract that expires in June 2006.

Credit Risk.The Company attempts to minimize credit exposure to ~~counter parties~~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 December 31, 2004 and 2003 ~~and 2002~~ was ~~$50~~$28 million and ~~$15~~$50 million, respectively. Interest on amounts borrowed is charged at LIBOR plus 1.25% to 2.0%. Based on year-end ~~2003~~2004 borrowings, a 1% change in interest rates would not have a material impact on the Company’s financial statements.

Commodity Price Risk. During 2004, WTI prices per barrel reached a high of $55.17, a low of $32.48 and averaged $41.47 for the year compared to an average of $30.99 and $26.15 in 2003 and 2002, respectively. The price of crude oil is influenced by many factors both regionally and globally. Additionally, approximately 83% of the Company's current production is California heavy crude oil. California heavy crude oil has sold at a discount of approximately $6.00 to WTI over the past ten years. The basis risk between WTI and the Company's California heavy crude oil is mitigated by the Company's crude oil sales contract under which the Company sells over 90% of its California production. Pricing in the existing agreement is based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed differential approximating $6.00 per barrel. This contract expires on December 31, 2005.

During 2004 and through early 2005, the differential between California heavy crude oil and WTI widened to over $14.00 per barrel and averaged $8.57 in 2004. While the Company is confident that it will be able to secure a contract for its California heavy crude oil in future periods, it is unlikely that the Company will be able to obtain terms similar to the current contract. In 2004, the Company estimates that its revenues benefited from this contract by approximately $13 million, and at a current differential of approximately $14.00 per barrel, the Company estimates that its revenues in 2005 will benefit from the contract by approximately $45 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-K~~news release 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,~~to: the timing and extent of changes in commodity prices for oil, gas and ~~electricity,~~electricity; development, exploration, drilling and operating risks; a limited marketplace for electricity sales within California,counterparty ~~risk,~~risk; acquisition risks; competition, environmental ~~and weather~~ risks, litigation ~~uncertainties, drilling, development and operating risks, uncertainties about~~uncertainties; the ~~estimates of reserves, th e~~ availability of drilling rigs and other support services, legislative and/or judicial decisions and other government or Tribal regulations.

Table of Contents


Item 8.	22

FinancialStatements and Supplementary Data

~~Item 8. Financial Statements and Supplementary Data~~

BERRY PETROLEUM COMPANY

Index to Financial Statements and

Supplementary Data

	Page


Report of PricewaterhouseCoopers LLP, an Independent ~~Auditors~~Registered Public Accounting Firm	2441

Balance Sheets at December 31, ~~2003~~2004 and ~~2002~~2003	2542

Statements of Income for the
Years Ended December 31, 2004, 2003 ~~2002~~ and ~~2001~~2002	2643

Statements of Comprehensive Income for the
Years Ended December 31, 2004, 2003 ~~2002~~ and ~~2001~~2002	2643

Statements of Shareholders' Equity for the
Years Ended December 31, 2004, 2003 ~~2002~~ and ~~2001~~2002	2744

Statements of Cash Flows for the
Years Ended December 31, 2004, 2003 ~~2002~~ and ~~2001~~2002	2845

Notes to the Financial Statements	2946

Supplemental Information About Oil & Gas Producing Activities (unaudited)	41

~~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.~~64


	23

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 andrelated notes.

Table of Contents

REPORT OF INDEPENDENT ~~AUDITORS~~REGISTERED PUBLIC ACCOUNTING FIRM

To the ~~Shareholders and~~ Board of Directors and Shareholders

of Berry Petroleum Company:

We have completed an integrated audit of Berry Petroleum Company’s 2004 financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Financial statements

In our opinion, the accompanying balance sheets and the related statements of income, comprehensive income, cash flows and shareholders’ equity ~~and cash flows~~ present fairly, in all material respects, the financial position of Berry Petroleum Company at December 31, ~~2003~~2004 and ~~2002,~~2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2003in~~2004 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~~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~~the standards ~~generally accepted in~~of the ~~United States of America, which~~Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about ~~wheth er~~whether the financial statements are free of material misstatement. An audit of financial statements 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.

As discussed in Note 2 to the financial statements, effective January 1, 2004, the Company changed its method of accounting for stock-based compensation to conform to Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation.”

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in "Management’s Report on Internal Control Over Financial Reporting" appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control — Integrated Frameworkissued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

~~February 20, 2004~~March 30, 2005

Table of Contents


	24

BERRY PETROLEUM COMPANY

Balance Sheets

December 31, ~~2003~~2004 and ~~2002~~2003

(In Thousands, Except Share Information)

2003

2002

ASSETS

Current assets:

Cash and cash equivalents $ 10,658 $ 9,866
Short-term investments available for sale 663 660
Accounts receivable 23,506 15,582
Deferred income taxes 4,410 844
Prepaid expenses and other 2,049 1,753

Total current assets 41,286 28,705

Oil and gas properties (successful efforts basis),

buildings and equipment, net 295,151 228,475
Other assets 1,755 893

$ 338,192 $ 258,073

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:

Accounts payable $ 32,490 $ 19,189
Accrued liabilities 4,214 6,470
Income taxes payable 4,238 2,612
Fair value of derivatives 5,710 4,123

Total current liabilities 46,652 32,394

Long-term liabilities:

Deferred income taxes 38,168 33,866
Long-term debt 50,000 15,000
Abandonment obligation 7,311 4,596
Fair value of derivatives 343 159

95,822 53,621
Commitments and contingencies (Notes 10 and 11)

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;

20,904,372 shares issued and outstanding (20,852,695 in 2002) 209 209
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 49,798 49,052
Deferred stock option compensation (120 ) -
Accumulated other comprehensive loss (3,632 ) (2,569 )
Retained earnings 149,454 125,357

Total shareholders' equity 195,718 172,058

$ 338,192 $ 258,073

~~The accompanying notes are an integral part of these financial statements.~~


	25

~~BERRY PETROLEUM COMPANY~~

	2004			2003

ASSETS
Current assets:
Cash and cash equivalents	$	16,690		$	10,658
Short-term investments available for sale		659			663
Accounts receivable		34,621			23,506
Deferred income taxes		3,558			6,410
Fair value of derivatives		3,243			-
Prepaid expenses and other		2,230			2,049
Total current assets		61,001			43,286

Oil and gas properties (successful efforts basis),buildings and equipment, net		338,706			295,151
Deposits on potential property acquisitions		10,221			-
Other assets		2,176			1,940

	$	412,104		$	340,377

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	27,750		$	20,867
Revenue and royalties payable		23,945			11,623
Accrued liabilities		6,132			4,214
Income taxes payable		1,067			4,412
Fair value of derivatives		5,947			5,710
Total current liabilities		64,841			46,826

Long-term liabilities:
Deferred income taxes		47,963			38,559
Long-term debt		28,000			50,000
Abandonment obligation		8,214			7,311
Fair value of derivatives		-			343
		84,177			96,213
Commitments and contingencies (Notes 10 and 11)

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;21,060,420 shares issued and outstanding (20,904,372 in 2003)		210			209
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		60,676			56,475
Deferred stock-based compensation		-			(1,108	)
Accumulated other comprehensive loss		(987	)		(3,632	)
Retained earnings		203,178			145,385
Total shareholders' equity		263,086			197,338

	$	412,104		$	340,377

~~Statements of Income~~

~~Years ended December 31, 2003, 2002 and 2001~~

~~(In Thousands, Except Per Share Data)~~

2003

2002

2001

Revenues:

Sales of oil and gas $ 135,848 $ 102,026 $ 100,146
Sales of electricity 44,200 27,691 35,133
Interest and dividend income 236 536 2,150
Other income 580 1,116 328

180,864 131,369 137,757
Expenses:

Operating costs – oil and gas production 60,705 44,604 40,281
Operating costs – electricity generation 44,200 27,360 34,722
Depreciation, depletion & amortization 20,514 16,452 16,520
General and administrative 9,586 7,928 7,174
Interest 1,414 1,042 3,719
Dry hole, abandonment and impairment 4,195 - -
(Recovery) write-off of electricity receivable - (3,631 ) 6,645
Loss on termination of derivative contracts - - 1,458

140,614 93,755 110,519

Income before income taxes 40,250 37,614 27,238
Provision for income taxes 5,918 7,590 5,300

Net income $ 34,332 $ 30,024 $ 21,938

Basic net income per share $ 1.58 $ 1.38 $ 1.00

Diluted net income per share $ 1.56 $ 1.37 $ 0.99

Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share) 21,772 21,741 21,973

Effect of dilutive securities:

Stock options 204 156 113
Other 44 42 24

Weighted average number of shares of capital stock used to calculate diluted net income per share 22,020 21,939 22,110

Statements of Comprehensive Income
Years Ended December 31, 2003, 2002 and 2001
(In Thousands)

Net income $ 34,332 $ 30,024 $ 21,938
Unrealized gains (losses) on derivatives, net of income taxes

(3,632
)
(2,569
)
-
Reclassification of unrealized gains included in net income 2,569 -
(441
)

Comprehensive income $ 33,269 $ 27,455 $ 21,497

The accompanying notes are an integral part of these financial statements.


	26

Table of Contents

BERRY PETROLEUM COMPANY

Statements of ~~Shareholders’ Equity~~Income

Years ~~Ended~~ended December 31, 2004, 2003 ~~2002~~ and ~~2001~~2002

(In Thousands, Except Per Share Data)

Class A

Class B

Capital in Excess of Par Value

Deferred Stock Based Compen-sation

Retained Earnings

Accum-ulated Other Compre-hensive Income (Loss)

Share-holders’ Equity

Balances at January 1, 2001 $ 211 $ 9 $ 53,686 $ - $ 90,877 $ 441 $ 145,224

Stock options exercised - - 172 - - - 172
Deferred director fees – stock

compensation - - 156 - - - 156
Common stock repurchases (3 ) - (5,109 ) - - - (5,112 )
Cash dividends declared -

$.40 per share - - - - (8,784 ) - (8,784 )
Unrealized losses on derivatives - - - - - (441 ) (441 )
Net income - - - - 21,938 - 21,938

Balances at December 31, 2001 208 9 48,905 - 104,031 - 153,153

Stock options exercised 1 - 57 - - - 58
Deferred director fees – stock

compensation - - 190 - - - 190
Retirement of warrants - - (100 ) - - - (100 )
Cash dividends declared -

$.40 per share - - - - (8,698 ) - (8,698 )
Unrealized losses on derivatives - - - - - (2,569 ) (2,569 )
Net income - - - - 30,024 - 30,024

Balances at December 31, 2002 209 9 49,052 - 125,357 (2,569 ) 172,058

Stock options exercised - - 446 - - - 446
Deferred director fees – stock

compensation - - 169 - - - 169
Deferred stock option compensation - - 131 (131 ) - - -
Amortization of deferred stock option compensation - - - 11 - - 11
Cash dividends declared -

$.47 per share - - - - (10,235 ) - (10,235 )
Unrealized losses on derivatives - - - - - (1,063 ) (1,063 )
Net income - - - - 34,332 - 34,332

Balances at December 31, 2003 $ 209 $ 9 $ 49,798 $ (120 ) $ 149,454 $ (3,632 ) $ 195,718

	2004			2003			2002
Revenues:
Sales of oil and gas	$	226,876		$	135,848		$	102,026
Sales of electricity		47,644			44,200			27,691
Interest and dividend income		261			236			536
Other income		165			580			1,116
		274,946			180,864			131,369
Expenses:
Operating costs – oil and gas production		82,419			62,554			45,217
Operating costs – electricity generation		46,191			42,351			26,747
Depreciation, depletion & amortization - oil and gas		29,752			17,258			13,388
Depreciation, depletion & amortization - electricity generation		3,490			3,256			3,064
General and administrative		20,354			12,868			9,215
Interest		2,067			1,414			1,042
Loss on disposal of assets		410			-			-
Dry hole, abandonment and impairment		745			4,195			-
Recovery of electricity receivable		-			-			(3,631	)

		185,428			143,896			95,042

Income before income taxes		89,518			36,968			36,327
Provision for income taxes		20,331			4,605			7,117

Net income	$	69,187		$	32,363		$	29,210

Basic net income per share	$	3.16		$	1.49		$	1.34

Diluted net income per share	$	3.08		$	1.47		$	1.33

Weighted average number of shares of capital stock outstanding (used to calculate basic net income per share)		21,894			21,772			21,741

Effect of dilutive securities:
Stock options		523			215			115
Other		53			44			46

Weighted average number of shares of capital stock used to calculate diluted net income per share		22,470			22,031			21,902


Statements of Comprehensive Income
Years Ended December 31, 2004, 2003 and 2002
(In Thousands)

Net income	$	69,187		$	32,363		$	29,210
Unrealized gains (losses) on derivatives, net of incometaxes of ($521), ($709), and ($1,712)		(781	)		(3,632	)		(2,569	)
Reclassification of unrealized losses included in net incomenet of income taxes of $2,284, $1,712 and $0		3,426			2,569			-
Comprehensive income	$	71,832		$	31,300		$	26,641

The accompanying notes are an integral part of these financial statements.


	27

Table of Contents

BERRY PETROLEUM COMPANY

Statements of ~~Cash Flows~~Shareholders’ Equity

Years Ended December 31, 2004, 2003 ~~2002~~ and ~~2001~~2002

(In ~~Thousands)~~Thousands, Except Per Share Data)

	Class A		Class B		Par Value			Compensation			Earnings			Comprehensive Income (Loss)			Equity


Balances at January 1, 2002	$	208	$	9	$	50,730		$	(101	)	$	102,745		$	-		$	153,591

Accrued compensation costs		1		-		1,149			-			-			-			1,150
Deferred director fees – stockcompensation		-		-		190			-			-			-			190
Unearned stock-basedcompensation		-		-		245			(245	)		-			-			-
Retirement of warrants		-		-		(100	)		-			-			-			(100	)
Cash dividends declared -$.40 per share		-		-		-			-			(8,698	)		-			(8,698	)
Unrealized losses on derivatives		-		-		-			-			-			(2,569	)		(2,569	)
Net income		-		-		-			-			29,210			-			29,210

Balances at December 31, 2002		209		9		52,214			(346	)		123,257			(2,569	)		172,774

Accrued compensation costs		-		-		3,319			-			-			-			3,319
Deferred director fees – stockcompensation		-		-		169			-			-			-			169
Unearned stock-basedcompensation		-		-		773			(773	)		-			-			-
Amortization of deferred stockoption compensation		-		-		-			11			-			-			11
Cash dividends declared -$.47 per share		-		-		-			-			(10,235	)		-			(10,235	)
Unrealized losses on derivatives		-		-		-			-			-			(1,063	)		(1,063	)
Net income		-		-		-			-			32,363			-			32,363

Balances at December 31, 2003		209		9		56,475			(1,108	)		145,385			(3,632	)		197,338

Adoption of SFAS 123		-		-		(243	)		1,108			-			-			865
Stock-based compensationcosts		1		-		3,451			-			-			-			3,452
Deferred director fees – stockcompensation		-		-		993			-			-			-			993
Cash dividends declared -$.52 per share		-		-		-			-			(11,394	)		-			(11,394	)
Unrealized gain onderivatives		-		-		-			-			-			2,645			2,645
Net income		-		-		-			-			69,187			-			69,187

Balances at December 31, 2004	$	210	$	9	$	60,676		$	-		$	203,178		$	(987	)	$	263,086

2003

2002

2001

Cash flows from operating activities:

Net income $ 34,332 $ 30,024 $ 21,938
Depreciation, depletion and amortization 20,514 16,452 16,520
Dry hole, abandonment and impairment 3,756 - -
Deferred income taxes 1,371 3,842 (50 )
Other, net 400 (184 ) (505 )
Decrease (increase) in current assets other than cash,

cash equivalents and short-term investments (8,220 ) 1,854 11,241
Increase (decrease) in current liabilities other than notes payable 12,672 5,907 (13,711 )

Net cash provided by operating activities 64,825 57,895 35,433

Cash flows from investing activities:

Capital expenditures, excluding property acquisitions (41,555 ) (30,632 ) (14,895 )
Property acquisitions (48,579 ) (5,880 ) (2,273 )
Proceeds from sale of assets 1,890 - -
Purchase of short-term investments (3 ) (660 ) (1,183 )
Maturities of short-term investments - 594 1,171
Other, net 524 52 151

Net cash used in investing activities (87,723 ) (36,526 ) (17,029 )

Cash flows from financing activities:

Proceeds from issuance of long-term debt 40,000 5,000 45,000
Payment of long-term debt (5,000 ) (15,000 ) (45,000 )
Dividends paid (10,235 ) (8,698 ) (8,784 )
Share repurchase program - - (5,112 )
Other, net (1,075 ) (43 ) (1 )

Net cash provided by (used in) financing activities 23,690 (18,741 ) (13,897 )

Net increase in cash and cash equivalents 792 2,628 4,507
Cash and cash equivalents at beginning of year 9,866 7,238 2,731

Cash and cash equivalents at end of year $ 10,658 $ 9,866 $ 7,238

Supplemental disclosures of cash flow information:

Interest paid $ 2,125 $ 1,321 $ 3,532

Income taxes paid $ 2,510 $ 5,420 $ 5,635

Supplemental non-cash activity:

Decrease in fair value of derivatives:

Current (net of income taxes of $635 and $1,649) $ 952 $ 2,474 $ -
Non-current (net of income taxes of $74 and $63) 111 95 -

Net decrease to accumulated other comprehensive income $ 1,063 $ 2,569 $ -

The accompanying notes are an integral part of these financial statements.


	28

Table of Contents

BERRY PETROLEUM COMPANY

Statements of Cash Flows

Years Ended December 31, 2004, 2003 and 2002

(In Thousands)

	2004			2003			2002

Cash flows from operating activities:
Net income	$	69,187		$	32,363		$	29,210
Depreciation, depletion and amortization		33,242			20,514			16,452
Dry hole, abandonment and impairment		(569	)		3,756			-
Stock-based compensation expense		5,309			2,872			1,093
Deferred income taxes		10,815			1,496			3,883
Loss on disposal of assets		410			-			-
Other, net		384			400			(184	)
Decrease (increase) in current assets other than cash, cash equivalents and short-term investments		(11,310	)		(9,034	)		1,469
Increase (decrease) in current liabilities		17,145			12,458			5,972

Net cash provided by operating activities		124,613			64,825			57,895

Cash flows from investing activities:
Capital expenditures, excluding property acquisitions		(72,225	)		(41,555	)		(30,632	)
Property acquisitions		(2,845	)		(48,579	)		(5,880	)
Deposits on potential acquisitions		(10,221	)		-			-
Proceeds from sale of assets		101			1,890			-
Purchase of short-term investments		-			(3	)		(660	)
Maturities of short-term investments		3			-			594
Other, net		-			524			52

Net cash used in investing activities		(85,187	)		(87,723	)		(36,526	)

Cash flows from financing activities:
Proceeds from issuance of long-term debt		-			40,000			5,000
Payment of long-term debt		(22,000	)		(5,000	)		(15,000	)
Dividends paid		(11,394	)		(10,235	)		(8,698	)
Other, net		-			(1,075	)		(43	)

Net cash provided by (used in) financing activities		(33,394	)		23,690			(18,741	)

Net increase in cash and cash equivalents		6,032			792			2,628
Cash and cash equivalents at beginning of year		10,658			9,866			7,238

Cash and cash equivalents at end of year	$	16,690		$	10,658		$	9,866

Supplemental disclosures of cash flow information:
Interest paid	$	1,243		$	2,125		$	1,321
Income taxes paid	$	11,652		$	2,510		$	5,420

Supplemental non-cash activity:
Increase (decrease) in fair value of derivatives:
Current (net of income taxes of $1,202, ($635), and ($1,649))	$	1,804		$	(952	)	$	(2,474	)
Non-current (net of income taxes of $561, ($74), and ($63))		841			(111	)		(95	)
Net increase(decrease) to accumulated other comprehensive income	$	2,645		$	(1,063	)	$	(2,569	)

The accompanying notes are an integral part of these financial statements.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

1.~~General~~

1.	General

The Company is an independent energy company engaged in the production, development, acquisition, exploitation and exploration of crude oil and natural gas. The Company has ~~91%~~88% of its oil and gas reserves in California and 9%12% in the Rocky Mountain Region. Approximately ~~87%~~76% of the Company's production is in California, most of which is heavy crude oil, which is principally sold to a refiner. The Company has invested in cogeneration facilities which provide steam required for the extraction of heavy oil and which generates electricity for sale. Production of light crude oil and natural gas in the Rocky Mountain region accounts for approximately ~~13%~~24% of the Company’s production.

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 as of 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~~

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 and are carried at fair value. The Company utilizes specific identification in computing realized gains and losses on investments sold.

Accounts receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company does not have any off-balance-sheet credit exposure related to its customers. The Company assesses credit risk and allowance for doubtful accounts on a customer specific basis. As of December 31, 2004 and 2003, the Company did not have an allowance for doubtful accounts.

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 geologicalGeological and geophysical costs and the costs of carrying and retaining undeveloped properties are ~~charged to expense when~~expensed as incurred. ~~In certain cases, such as coalbed methane gas exploration plays, the drilling~~Exploratory well costs ~~may be~~are capitalized ~~until it is known~~pending further evaluation of whether ~~proved economic~~economically recoverable reserves have been ~~discovered. At that point, if unsuccessful, the~~found. If economically recoverable reserves are not found, exploratory well costs ~~will be~~are expensed as dry holes. All exploratory ~~dry hole costs.~~wells are evaluated for economic viability within one year of well completion and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized as long as the additional exploratory work is under way or firmly planned. The costs of development wells are capitalized whether productive or nonproductive.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

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.

2.	Summary of Significant Accounting Policies (cont'd)

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. 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. ~~Prior to 2002, the estimated costs of plugging~~Estimated residual salvage value is considered when determining depreciation, depletion and ~~abandoning wells and related facilities were accrued using the units-of-production method and were considered in determining DD&A expense. However, in~~amortization (DD&A) rates. In 2002 the Company adopted SFAS No. 143, ~~“Accounting~~Accounting for Asset Retirement ~~Obligations.” Unde r~~Obligations. Under this standard, the Company records the fair value of the future abandonment as capitalized abandonment costs in Oil and Gas Properties with an offsetting abandonment liability. The capitalized abandonment costs are amortized with other property costs using the units-of-production method. The Company increases the liability monthly by recording accretion expense using the Company’s credit adjusted interest rate. Accretion expense is included in ~~depreciation, depletion and amortization (DD&A)~~DD&A in the Company’s financial statements.


	29

~~BERRY PETROLEUM COMPANY~~

~~Notes to the Financial Statements~~

~~2. Summary of Significant Accounting Policies (cont'd)~~

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. Expenses for major renewals and betterments are capitalized.

Environmental Expenditures

The Company reviews, on a quarterly basis, its estimates of costs of the cleanup of various sites, including sites in which governmental agencies have designated the Company as a potentially responsible party. When it is probable that obligations have been incurred and where a minimum cost or a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. Any liabilities arising hereunder are not discounted.

Hedging

SFAS No. 133, ~~“Accounting~~Accounting for Derivative Instruments and Hedging Activities”, as amended, 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 is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. ~~Hedge~~The hedging relationship between the hedging instruments and hedged items, such as oil and gas, must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis. The Company measures 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 ~~o ptions~~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~~statements of ~~operations.~~income. Gains and losses on hedging instruments and adjustments of the carrying amounts of hedged items are included in revenues for hedges related to the Company's crude oil and natural gas sales and in operating expenses for hedges related to the Company's natural gas consumption. The resulting cash flows are reported as cash flows from operating activities. See Note 315 - ~~Fair Value of Financial Instruments.~~Hedging.

Cogeneration Operations

The ~~Company operates~~Company’s investment in its cogeneration facilities ~~to help minimize~~has been for the ~~cost~~express purpose of ~~producing~~lowering steam ~~which is a necessity~~costs in its ~~thermal~~heavy oil operations and ~~gas producing operations.~~securing operating control of the respective steam generation. Such cogeneration operations produce electricity ~~as a by-product from~~and steam. The Company allocates steam costs to its oil and gas operating costs based on the ~~production~~conversion efficiency of ~~steam. In each monthly accounting period, the cost of operating~~ the cogeneration facilities ~~up to the amount of the electricity sales, is considered operating~~plus certain direct 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. Also, electricity~~steam. Electricity revenue represents sales to ~~customers only. It does not include~~ the ~~value~~utilities. Electricity used in oil and gas operations is allocated at cost. Electricity consumption included in oil and gas operating costs for the years ended December 31, 2004, 2003 and 2002 was $5.0 million, $4.2 million and $2.3 million, respectively.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the ~~electricity utilized as power to run the Company’s field operations.~~Financial Statements

2.	Summary of Significant Accounting Policies (cont'd)

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 recognized when title passes to the customer, net of royalties, discounts and allowances, as applicable. Electricity and natural gas produced by the Company and used in the Company’s operations are not included in revenues. 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).

Shipping and Handling Costs

Shipping and handling costs, which consist primarily of natural gas transportation costs, are included in both "Operating costs - oil and gas production" or "Operating costs - electricity generation,” as applicable. Natural gas transportation costs included in these categories were $5.4 million, $4.0 million and $1.4 million, for 2004, 2003 and ~~$1.2 million for 2003,~~ 2002, ~~and 2001,~~ respectively.


	30

~~BERRY PETROLEUM COMPANY~~

~~Notes to the Financial Statements~~

~~2. Summary of Significant Accounting Policies (cont'd)~~Comprehensive Income (Loss)

Comprehensive income (loss) includes net earnings (loss) as well as unrealized gains and losses on derivative instruments, recorded net of tax.

Stock-Based Compensation

~~As allowed~~Effective January 1, 2004, the Company voluntarily adopted the fair value method of accounting for its stock option plan as prescribed by SFAS 123,Accounting for Stock-Based Compensation. The modified prospective method was selected as described in SFAS ~~No. 123, “Accounting~~148,Accounting for Stock-Based Compensation” - Transition and Disclosure. Under this method, the Company ~~continues~~recognizes stock option compensation expense as if it had applied the fair value method to ~~apply Accounting Principles Board Opinion (APB) No. 25, "Accounting~~account for unvested stock options from its original effective date. Stock ~~Issued to Employees,” and related interpretations in recording~~option compensation ~~related to its plan. Under SFAS 123, compensation~~expense is ~~determined at~~recognized from the date of grant ~~based on an estimated~~to the vesting date.

From January 1, 2004 to July 29, 2004 a portion of the Company's stock option compensation was calculated under variable accounting; however, the majority of stock option compensation was accounted for under the fair value ~~using an economic model, such as~~method. In accordance with variable plan accounting, the ~~Black-Scholes method. Under APB 25,~~Company recognized a corresponding liability determined by a mark-to-market valuation of the Company's stock at each financial reporting date. The Company revised certain stock option exercise provisions of the plan and, subsequent to July 29, 2004, variable plan accounting was no longer required.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

2.	Summary of Significant Accounting Policies (cont'd)

Had compensation ~~expense is~~cost for the Company’s stock based compensation plan (see Note 12) been based upon the ~~difference between the market price~~fair value at ~~date of grant and~~ the grant ~~price.~~dates for awards under the plan consistent with SFAS No. 123, the Company’s compensation cost, net of related tax effects, net income and earnings per share would have been recorded as the pro forma amounts indicated below (in thousands, except per share data):

	2003			2002

Net income, as reported	$	32,363		$	29,210
Plus compensation cost (net of tax), as reported		2,335			806
Less compensation cost (net of tax), pro forma		(1,323	)		(701	)
Net income, pro forma	$	33,375		$	29,315

Basic net income per share:
As reported	$	1.49		$	1.34
Pro forma		1.53			1.35

Diluted net income per share:
As reported	$	1.47		$	1.33
Pro forma		1.52			1.34

Under SFAS No. 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:

	2003		2002		2001		2003			2002

Yield	2.87	%	2.55	%	2.72	%		2.87	%		2.55	%
Expected option life – years	7.0		7.5		7.5			7.0			7.5
Volatility	27.87	%	33.45	%	38.71	%		27.87	%		33.45	%
Risk-free interest rate	3.86	%	4.09	%	4.65	%		3.86	%		4.09	%

Had compensation cost for the Company’s stock based compensation plan (see Note 12) been based upon the fair value at the grant dates for awards under the plan consistent with the method of SFAS No. 123, the Company’s compensation cost, net of related tax effects, net income and earnings per share would have been recorded as the pro forma amounts indicated below (in thousands, except per share data):

2003

2002

2001

Compensation cost, net of income taxes:

As reported $ 366 $ 33 $ 92
Pro forma 975 726 678

Net income:

As reported 34,332 30,024 21,938
Pro forma 33,723 29,331 21,352

Basic net income per share:

As reported 1.58 1.38 1.00
Pro forma 1.55 1.35 0.97

Diluted net income per share:

As reported 1.56 1.37 0.99
Pro forma 1.53 1.34 0.97

Income Taxes

Income taxes are provided based on the liability method of accounting. The provision for income taxes is based on reported pre-tax financial ~~accounting~~statement 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 bases 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.


	31

~~BERRY PETROLEUM COMPANY~~

~~Notes to the Financial Statements~~

~~2. Summary of Significant Accounting Policies (cont’d)~~

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 shares of capital stock outstanding (the denominator). The Company’s Class B stock is included in the denominator of basic and diluted net income. 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.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

2.	Summary of Significant Accounting Policies (cont'd)

Recent Accounting Developments

In December 2004, the ~~fourth quarter of 2002, the Company adopted the supplemental disclosure requirements~~Financial Accounting Standards Board (FASB) issued SFAS 123(R),Share-Based Payments, which is a revision of SFAS 123. SFAS 123(R) supersedes APB 25 and amends Statement of Accounting Standards No. ~~148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” which amended~~95,Statement of Cash Flows. Generally, the approach in SFAS ~~No. 123, “Accounting for Stock-Based Compensation.” The Company continues~~123(R) will require all share-based payments to ~~record compensation related to~~employees, including grants of employee stock options, to be recognized based on their fair values. SFAS 123(R) must be adopted by the ~~intrinsic value method per APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 148 encourages companies to voluntarily elect to record~~Company no later than the ~~compensation based on market value either prospectively, as defined in SFAS No. 123, or retroactively or in a modified prospective method.~~third quarter of 2005. The Company ~~uses the Black-Scholes model to calculate~~voluntarily adopted SFAS 123 as of January 1, 2004 and ~~disclose the market value of its options granted. The Company~~ does not advocate nor does it believe that the Black-Scholes model can properly determine the val ue of a stock option, like Berry’s, that vest over a period of time and is not freely tradable upon grant. Therefore, the Company has delayed the potential transition to recording stock compensation based on fair market value until required by accounting standards in 2005.

In November 2002 the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”).” This Interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. In addition, the Interpretation clarifies the requirements related to the recognition of a liability by a guarantor at the inception of a guarantee for the obligations that the guarantor has undertaken in issuing the guarantee. The Company adopted the disclosure requirements of FIN 45 for the fiscal year ended December 31, 2002, and the recognition provisions on January 1, 2003. Adoption of this Interpretation did notexpect SFAS 123(R) will have a material impact on the ~~Company’s Financial Statements.~~Company's financial position, net income or cash flows.

In ~~June 2002~~December 2004, the FASB issued FASB Staff Position (FSP) FAS 109-1,Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004, This position clarifies how to apply SFAS No. ~~146, “Accounting~~109 to the new law's tax deduction for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costsincome attributable to ~~Exit an Activity (Including Certain Costs Incurred in a Restructuring).”~~"domestic production activities." The Company has adopted, effective January 1, 2003, the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should in itially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. SFAS No. 146 diddoes not expect this statement will have a material impact on the ~~Company’s Financial Statements.~~Company's financial position, net income or cash flows.

In ~~April 2003~~January 2005, the FASB issued SFAS No. ~~149, “Amendment~~153,Exchanges of ~~Statement 133 on Derivative Instruments and Hedging Activities.” SFAS~~Nonmonetary Asset - an amendment of APB Opinion No. 149 amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets28. This statement, which addresses the ~~characteristic~~measurement of ~~a derivative, clarifies when a derivative contains a financing component, amends the definition~~exchanges of ~~an underlying to conform it to language used in FIN 45, and amends certain other existing pronouncements. SFAS No. 149~~nonmonetary assets, is effective prospectively for ~~contracts entered into or modified~~nonmonetary asset exchanges occurring in fiscal periods beginning after June ~~30, 2003, and should be applied prospectively, with the exception of certain SFAS No. 133 implementation issues that were effective for all fiscal quarters prior to June~~ 15, ~~2003. Any such implementation issues should continue to be applied in accordance with their respective effective dates.~~2005. The adoption of ~~SFAS No. 149~~this statement is not expected to impact the Company's financial position, net income, or cash flows.

Revisions to the classification of cogeneration costs

In connection with the preparation of the 2004 financial statements, the Company concluded that it was appropriate to revise its allocation of cogeneration costs to oil and gas operations. The revised allocation is based on the thermal efficiency (of fuel to electricity and steam) of the Company's cogeneration facilities. Accordingly, the Company has revised prior classifications of cogeneration facility operating costs for the years ended December 31, 2003 and 2002 as follows (in thousands):

	2003			2002
Operating costs - oil and gas
As previously reported	$	60,705		$	44,604
As revised		62,554			45,217
Difference	$	1,849		$	613

Operating costs - electricity generation
As previously reported	$	44,200		$	27,360
As revised		42,351			26,747
Difference	$	(1,849	)	$	(613	)

DD&A - oil and gas
As previously reported	$	20,514		$	16,452
As revised		17,258			13,388
Difference	$	(3,256	)	$	(3,064	)

DD&A - electricity generation
As previously reported	$	-		$	-
As revised		3,256			3,064
Difference	$	3,256		$	3,064

The change in classification did not ~~have a material impact on the Company’s financial statements.~~affect previously reported total revenues, total operating expenses, net income or net cash provided by operating activities.


	32

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

~~2. Summary of Significant Accounting Policies (cont’d)~~

During January 2003, the Financial Accounting Standards Board issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”), which requires the consolidation of certain entities that are determined to be variable interest entities (“VIE’s”). An entity is considered to be a VIE when either (i) the entity lacks sufficient equity to carry on its principal operations, (ii) the equity owners of the entity cannot make decisions about the entity’s activities or (iii) the entity’s equity neither absorbs losses or benefits from gains. The Company has reviewed its financial arrangements and has not identified any material VIE’s that should be consolidated by the Company in accordance with FIN 46.

~~Reclassifications~~

~~Certain reclassifications have been made to the 2002 and 2001 financial statements to conform with the 2003 presentation.~~

~~3. Fair Value of Financial Instruments~~

3.	Fair Value of Financial Instruments

Cash equivalents consist principally of commercial paper investments. Cash equivalents of ~~$10.6~~$16.7 million and ~~$9.8~~$10.7 million at December 31, ~~2003~~2004 and ~~2002,~~2003, respectively, are stated at cost, which approximates market.

The Company’s short-term investments available for sale at December 31, ~~2003~~2004 and ~~2002~~2003 consist of United States treasury notes that mature in less than one year and are carried at fair value. For the three years ended December 31, ~~2003,~~2004, realized and unrealized gains and losses were insignificant to the financial statements. A United States treasury note with a market value of ~~$.6~~$.7 million is pledged as collateral to the California State Lands Commission as a performance bond on the Company’s Montalvo properties. The carrying value of the Company’s long-term debt approximates its fair value since it is carried at current interest rates.

In 2001, the Company established an oil price hedge on 3,000 barrels per day for a one-year period beginning on June 1; and a natural gas price hedge on 5,000 MMBtu/D for a three-year period beginning on August 1. Both of these hedges were with Enron as the counterparty. On December 10, 2001, after Enron filed for bankruptcy, the Company elected to terminate all contracts with Enron and agreed with Enron as to the value of the contracts as of the termination date. Based on this agreed value, the Company recorded a pre-tax charge of $1.5 million in the fourth quarter of 2001 and recorded a liability of $1.3 million, which was remitted upon the approval of the termination agreement in the Enron bankruptcy proceedings. The Company had a signed International Swap Dealer’s Association master agreement with Enron, which allowed for the netting of any receivables and liabilities aris ing thereunder.

To protect the Company’s revenues from potential price declines, the Company periodically enters into hedge contracts covering up to 50% of production. As a result of hedging activities, the Company’s revenue was reduced by $11.8 million, $3.8 million, and $0 in 2003, 2002 and 2001, respectively, which was reported in “Sales of oil and gas” in the Company’s financial statements.

4.	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. ~~Primarily due to~~

Because of the Company’s ability to deliver significant volumes of crude oil over a multi-year period, the Company was able to secure a ~~three-year~~thirty-nine month sales agreement, beginning in ~~April 2000,~~late 2002, with a major California refiner whereby the Company ~~sold in excess~~sells over 90% of ~~80% of~~ its California production under a negotiated pricing mechanism. This contract ~~was renegotiated during 2002 and extended through~~expires on December 31, 2005. ~~Over 90% of the Company’s current California production is subject to this new contract.~~ Pricing in ~~the new~~this agreement is based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed ~~differential.~~differential near $6.00 per barrel. Both ~~m ethods~~methods are calculated using a monthly determination. In addition to providing a premium above field postings, the agreement effectively eliminates the Company’s exposure to the risk of widening ~~WTI-heavy~~WTI to California heavy crude price ~~differentials.~~


	33

~~BERRY PETROLEUM COMPANY~~

~~Notes~~differentials and allows the Company to ~~the Financial Statements~~

4. ~~Concentration of Credit Risks (Cont’d)~~effectively hedge its production based on WTI pricing.

For the three years ended December 31, ~~2003,~~2004, the Company has experienced no credit losses on the sale of oil, gas and natural gas liquids. However, the Company did experience a loss of $6.6 million on its electricity sales in ~~2001. The Company assigned all of its rights, title~~2001 and ~~interest~~ in its $12.1 million past due receivables from Pacific Gas and Electric Company to an unrelated party for $9.3 million, resulting in a pre-tax loss of $2.8 million. In addition, at December 31, 2001, the Company was owed $13.5 million from Southern California Edison (Edison) for past due electricity sales. The Company wrote off $3.6 million of this balance in March 2001. In March 2002, the Company ~~was paid the total amount due from Edison plus interest resulting in pre-tax income of $4.2 million recorded in the first quarter of 2002.~~recovered $3.6 million.

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, ~~2003,~~2004, the Company has not incurred losses related to these investments. With respect to the Company’s hedging activities, the Company utilizes more than one counterparty on its hedges and monitors each counterparty’s credit rating.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

4.	Concentration of Credit Risks

The following summarizes the accounts receivable balances at December 31, ~~2003~~2004 and ~~2002~~2003 and sales activity with significant customers for each of the years ended December 31, 2004, 2003 ~~2002~~ and ~~2001~~2002 (in thousands). The Company does not believe that the loss of any one customer would impact the marketability of its oil, gas, natural gas liquids or electricity sold. However, the Company can make no assurances regarding the pricing of any new sales agreement.

					Sales
	Accounts Receivable				For the Year Ended December 31,										Sales
											Accounts Receivable				For the Year Ended December 31,
Customer		December 31, 2003		December 31, 2002		2003		2002		2001	December 31, 2004		December 31, 2003		2004		2003		2002

Oil & Gas Sales:
A	$	12,887	$	10,714	$	142,422	$	94,870	$	83,336	$	18,391	$	12,887	$	202,966	$	142,422	$	94,870
B		-		621		680		5,463		4,858		5,465		2,256		58,807		5,566		-
C		-		-		-		10,188		14,962		670		625		9,138		6,524		-
D		2,256		-		5,566		-		-		-		-		-		680		5,463
E		625		-		6,524		-		-		-		-		-		-		10,188
											$	24,526	$	15,768	$	270,911	$	155,192	$	110,521
	$	15,768	$	11,335	$	155,192	$	110,521	$	103,156

Electricity Sales:
F	$	2,970	$	-	$	24,616	$	-	$	6,859	$	3,402	$	2,156	$	21,755	$	20,334	$	15,199
G		2,156		1,795		20,334		15,199		21,257		2,764		2,970		26,524		24,616		-
H		-		1,573		265		12,317		6,279		-		-		-		265		12,317
											$	6,166	$	5,126	$	48,279	$	45,215	$	27,516
	$	5,126	$	3,368	$	45,215	$	27,516	$	34,395

Sales amounts will not agree to the Statements of Income due primarily to the effects of hedging and ~~a revenue sharing royalty~~price sensitive royalties paid on a portion of the Company’s ~~Midway-Sunset~~ crude oil sales, which isare netted in “Sales of oil and gas” on the Statements of Income.


	34

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

5.~~Oil and Gas Properties, Buildings and Equipment~~

5.	Oil and Gas Properties, Buildings and Equipment

Oil and gas properties, buildings and equipment consist of the following at December 31 (in thousands):

2003

2002

Oil and gas:

Proved properties:

Producing properties, including intangible drilling costs $ 238,303 $ 180,942
Lease and well equipment⁽¹⁾
191,664 160,264

429,967 341,206
Unproved properties

Properties, including intangible drilling costs 2,925 6,725
Lease and well equipment 10 653

2,935 7,378

432,902 348,584
Less accumulated depreciation, depletion and amortization 139,514 121,695

293,388 226,889

Commercial and other:

Land 333 173
Buildings and improvements 3,703 3,838
Machinery and equipment 4,266 3,922

8,302 7,933
Less accumulated depreciation 6,539 6,347

1,763 1,586

$ 295,151 $ 228,475

⁽¹⁾~~Includes cogeneration facility costs.~~

	2004		2003
Oil and gas:
Proved properties:
Producing properties, including intangible drilling costs	$	260,566	$	237,677
Lease and well equipment⁽¹⁾		238,778		191,092
		499,344		428,769
Unproved properties
Properties, including intangible drilling costs		5,569		3,710
Lease and well equipment		2,498		582
		8,067		4,292
		507,411		433,061

Less accumulated depreciation, depletion and amortization		170,606		139,514

		336,805		293,547
Commercial and other:
Land		297		174
Buildings and improvements		3,703		3,703
Machinery and equipment		4,835		4,266
		8,835		8,143
Less accumulated depreciation		6,934		6,539

		1,901		1,604

	$	338,706	$	295,151
(1)Includes cogeneration facility costs.

The following sets forth costs incurred for oil and gas property acquisition, development and exploration activities, whether capitalized or expensed (in thousands):

	2004		2003		2002
Property acquisitions
Proved properties	$	440	$	49,326	$	186
Unproved properties		2,405		853		5,694
Development⁽¹⁾		66,664		42,391		29,133
Exploration		5,506		788		1,684

	$	75,015	$	93,358	$	36,697

2003

2002

2001

Property acquisitions

Proved properties $ 50,822 $ 186 $ 2,273
Unproved properties 379 5,694 -
Development⁽¹⁾
41,369 29,133 15,875
Exploration 788 1,684 -

$ 93,358 $ 36,697 $ 18,148

(1)Development costs include $.7 million, $.9 million ~~$.5 million~~ and ~~$1.0~~$.5 million that were charged to expense during 2004, 2003 and 2002, respectively.

In July 2004, the Company purchased with Bill Barrett Corporation approximately 169,000 gross acres in the Lake Canyon prospect in Utah, of which 124,500 gross (62,250 net) acres are leased from the Ute Tribe and ~~2001, respectively.~~44,500 gross (22,250 net) acres are fee lands. Total cost to Berry was approximately $2.0 million. The Company will drill and operate shallow wells which target light oil in the Green River formation and retain up to a 75% working interest. The Company’s partner will drill and operate deeper wells and the Company will retain up to a 25% working interest. The Ute Tribe has the option to participate in all wells and retain up to a 25% working interest.The Company's minimum obligation under its exploration and development agreement is $10.5 million.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

5.	Oil and Gas Properties, Buildings and Equipment (Cont'd)

In 2003, the Company purchased leases totaling 45,380 gross (43,500 net) acres in the Brundage Canyon field in Utah for approximately $45 million and the McVan property totaling 560 acres in the Poso Creek field in Kern County, California for approximately $2.6 million. ~~Approximately 14 million equivalent barrels of proved reserves were added by 2003 acquisitions and property development.~~ The Company capitalized approximately $2.6 million in future abandonment obligations related to the 2003 acquisitions.

In 2002, the Company acquired approximately 262,000 net acres for the potential development of CBM ~~natural gas~~ production in Kansas and Illinois for approximately $6 ~~million. The~~million.The Company has written off two pilot projects and impaired the acreage for a total pre-tax write off of $4.2 million in 2003 and recovered part of the cost through the sale of approximately 43,000 acres in Kansas in 2003 for $1.7 million at minimal gain to the Company. No reserves were recorded at year-end associated with the CBM related acreage. ~~However,~~

Results of operations from oil and gas producing	2004			2003			2002
and exploration activities (in thousands):

Sales to unaffiliated parties	$	226,876		$	135,848		$	102,026
Production costs		(82,419	)		(62,554	)		(45,217	)
Depreciation, depletion and amortization		(29,752	)		(17,258	)		(13,388	)
Dry hole, abandonment and impairment		(745	)		(4,195	)		-
		113,960			51,841			43,421
Income tax expenses		(32,875	)		(8,426	)		(8,341	)

Results of operations from producing and exploration activities	$	81,085		$	43,415		$	35,080

The following table reflects the ~~Company added 4.2 MMBOE~~net changes in capitalized exploratory well costs during the years ended 2004, 2003 and 2002 (in thousands):

	2004		2003		2002

Beginning balance at January 1	$	511	$	1,684	$	-
Additions to capitalized exploratory well costs pending the determination of proved reserves		3,420		1,081		1,684
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		-		-		-
Capitalized exploratory well costs charged to expense		479		2,254		-
Ending balance at December 31	$	3,452	$	511	$	1,684

The following table provides an aging of ~~proved reserves through its 2002 development expenditures, principally~~capitalized exploratory well costs based on ~~its California properties.~~the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period of greater than one year since the completion of drilling (in thousands):

	2004		2003		2002
Capitalized exploratory well costs that have beencapitalized for a period of one year or less	$	2,941	$	511	$	1,684
Capitalized exploratory well costs that have beencapitalized for a period greater than one year		511		-		-
Balance at December 31	$	3,452	$	511	$	1,684

Number of projects that have exploratory well costs thathave been capitalized for a period of greater than one year		1		-		-

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements


5.	35

Oil and Gas Properties, Buildings and Equipment (Cont'd)

~~BERRY PETROLEUM COMPANY~~

~~Notes~~Included in the amount of exploratory well costs that have been capitalized for a period of greater than one year since completion of drilling are costs of $.5 million that have been capitalized since 2003. These costs are related to the ~~Financial Statements~~Company's diatomite project in the Midway-Sunset field. The Company continues to evaluate this pilot and test its diatomite steam flood and cyclic steam project and anticipates that the determination of commerciality will be complete in 2006.

5.~~Oil and Gas Properties, Buildings and Equipment (Cont’d)~~

6.	Debt Obligations

In 2001, the Company acquired a 15.8% non-operated working interest in CBM natural gas properties in Wyoming for $2.2 million and a producing property adjacent to Berry's core Midway-Sunset properties for $.1 million. In 2001, approximately 1.1 million equivalent barrels of proved reserves were added by these acquisitions and property development.

Results of operations from oil and gas producing
and exploration activities (in thousands): 2003

2002

2001

Sales to unaffiliated parties $ 135,848 $ 102,026 $ 100,146
Production costs (60,705 ) (44,604 ) (40,281 )
Depreciation, depletion and amortization (20,215 ) (16,124 ) (16,175 )
Dry hole, abandonment and impairment (4,195 ) - -

50,733 41,298 43,690
Income tax expenses (8,246 ) (7,933 ) (10,740 )

Results of operations from producing and

exploration activities $ 42,487 $ 33,365 $ 32,950

	2004		2003
Long-term debt for the years ended December 31 (in thousands):

Revolving bank facility	$	28,000	$	50,000

~~6. Debt Obligations~~

2003

2002

Long-term debt for the years ended December 31 (in thousands):

Revolving bank facility $ 50,000 $ 15,000

On July 10, 2003, the Company entered into a new Credit Agreement (the Agreement) with a banking syndicate, replacing an existing credit agreement which was due to expire in January 2004. The Agreement is a revolving credit facility for up to $200 million with ten banks. At December 31, ~~2003~~2004 and ~~2002,~~2003, the Company had ~~$50~~$28 million and ~~$15~~$50 million, respectively, outstanding under the ~~Agreement and the predecessor agreement.~~Agreement. In addition to the ~~$50~~$28 million in borrowings under the Agreement, the Company has ~~$.3~~$.5 million of outstanding Letters of Credit and the remaining credit available under the Agreement is, therefore, ~~$149.7~~$172 million at December 31, ~~2003.~~2004. 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 ~~redeterminatio n~~redetermination each year. The agreement matures on July 10, 2006. Interest on amounts borrowed is charged at LIBOR plus a margin of 1.25% to 2.00%, or the higher of the lead bank’s prime rate or the federal funds rate plus 50 basis points plus a margin of 0.0% to 0.75%, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. The Company pays a commitment fee of 30 to 50 basis points on the unused portion, which is also based on the ratio of credit outstanding to the borrowing base.

The weighted average interest rate on outstanding borrowings at December 31, ~~2003~~2004 was ~~2.58%~~3.37%. The Agreement contains restrictive covenants which, among other things, requires the Company to maintain a certain tangible net worth and minimum EBITDA, as defined. The Company was in compliance with all such covenants as of December 31, ~~2003.~~2004.

7.~~Shareholders' Equity~~

7.	Shareholders' Equity

Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the ~~“Capital~~"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.

The Company's Common Stock activity follows:

	Number of Shares
	Class A			Class B
December 31, 2001		20,833,094			898,892
Option exercises		19,717			-
Shares cancelled		(98	)		-
Shares repurchased and retired		(18	)		-
December 31, 2002		20,852,695			898,892
Option exercises		51,683			-
Shares repurchased and retired		(6	)		-
December 31, 2003		20,904,372			898,892
Option exercises		155,269			-
Shares issued under Director deferred compensation plan		797			-
Shares repurchased and retired		(18	)		-
December 31, 2004		21,060,420			898,892

Table of Contents

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 ~~ou tstanding~~outstanding shares of Common Stock, either event occurring without the prior consent of the Company.


	36

~~BERRY PETROLEUM COMPANY~~

~~Notes to the Financial Statements~~

7.~~Shareholders' Equity (Cont’d)~~

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 replaced the previous Shareholder Rights Agreement approved in December 1989 which expired on December 8, 1999.~~

In August 2001, the Board of Directors authorized the Company to repurchase $20 million of Common Stock in the open market. As of December 31, 2001, the Company had repurchased 308,075 shares for approximately $5.1 million. All shares repurchased were retired. No additional shares were repurchased in 2002 or 2003.

The Company issued 155,269, 51,683 ~~19,717,~~ and ~~6,529~~19,717, shares in 2004, 2003 ~~2002,~~ and ~~2001,~~2002, respectively, through its stock option plan.

~~The~~In 2004, the Company paid a special dividend of $.06 per share on September 29, 2004 and increased its regular quarterly dividend by 9%, from $.11 to $.12 per share beginning with the September 2004 dividend. In 2003, the Company paid a special dividend of $.04 per share on May 2, 2003 and increased its regular quarterly dividend by 10%, from $.10 to $.11 per share beginning with the June 2003 dividend.

As of December 31, ~~2003,~~2004, 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. Annual dividend payments are limited by covenants in the Company's credit facility to the greater of $13 million or 75% of net income.

8.	Asset Retirement Obligations

8. ~~Asset Retirement Obligations~~

In 2002, the Company implemented SFAS No. 143 ~~“Accounting~~, Accounting for Asset Retirement ~~Obligations”~~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~~Financial Accounting and Reporting by Oil and Gas Producing ~~Companies.”~~Companies. Under SFAS ~~No.~~ 143, the following table summarizes the change in ~~our~~ abandonment obligation for the year ended December 31, ~~2003~~2004 (in thousands):

		2003		2004			2003


Beginning abandonment obligation December 31, 2002	$	4,596
Beginning balance at January 1				$	7,311		$	4,596
Liabilities incurred		2,623			769			2,623
Liabilities settled		(439	)		(570	)		(439	)
Accretion expense		531			704			531


Ending abandonment obligation December 31, 2003	$	7,311

Ending balance at December 31				$	8,214		$	7,311

9.Table of Contents

~~Income Taxes~~BERRY PETROLEUM COMPANY

Notes to the Financial Statements

9.	Income Taxes

The ~~Provision~~provision for income taxes consists of the following (in thousands):

2003

2002

2001

Current:

Federal $ 3,652 $ 2,700 $ 3,108
State 907 1,032 1,119

4,559 3,732 4,227

Deferred:

Federal 1,841 4,258 1,755
State (482 ) (400 ) (682 )

1,359 3,858 1,073

Total $ 5,918 $ 7,590 $ 5,300


	37

	2004			2003			2002

Current:
Federal	$	7,073		$	2,490		$	2,340
State		2,443			619			894
		9,516			3,109			3,234
Deferred:
Federal		11,959			2,027			4,286
State		(1,144	)		(531	)		(403	)
		10,815			1,496			3,883
Total	$	20,331		$	4,605		$	7,117

~~BERRY PETROLEUM COMPANY~~

~~Notes to the Financial Statements~~

9.~~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 non-current 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):

	2004			2003

Deferred tax asset:
Federal benefit of state taxes	$	1,308		$	318
Credit carryforwards		26,478			23,440
Stock option costs		1,700			2,185
Derivatives		658			2,421
Other, net		1,610			1,488
		31,754			29,852
Deferred tax liability:
Depreciation and depletion		(76,311	)		(61,425	)
Other, net		152			(253	)

		(76,159	)		(61,678	)

Net deferred tax liability	$	(44,405	)	$	(31,826	)

2003

2002

2001

Deferred tax asset:

Federal benefit of state taxes $ 318 $ 350 $ 392
Credit/deduction carryforwards 23,440 15,454 11,599
Derivatives 2,421 1,712 -
Other, net 1,488 (1,187 ) 579

27,667 16,329 12,570

Deferred tax liability:

Depreciation and depletion (61,425 ) (49,458 ) (43,608 )
Other, net 138 173 210

(61,287 ) (49,285 ) (43,398 )

Net deferred tax liability $ (33,620 ) $ (32,956 ) $ (30,828 )

At December 31, 2004, the Company's net deferred tax assets and liabilities were recorded as a current asset of $3.6 million and a long-term liability of $48.0 million. At December 31, 2003, the Company's net deferred tax assets and liabilities were recorded as a current asset of $6.4 million, a non-current asset of $.4 million and a long-term liability of $38.6 million.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

9.	Income Taxes (Cont'd)

Reconciliation of the statutory federal income tax rate to the effective income tax rate ~~follows.~~follows:

	2004			2003			2002

Tax computed at statutory federal rate		35	%		35	%		35	%

State income taxes, net of federal benefit		1			1			1
Tax credits		(9	)		(24	)		(15	)
Recognition of tax basis of properties		(5	)		-			-
Other		1			-			(1	)

Effective tax rate		23	%		12	%		20	%

2003

2002

2001

Tax computed at statutory federal rate 35 % 35 % 35 %

State income taxes, net of federal benefit 1 1 1
Tax credits (21 ) (15 ) (16 )
Other - (1 ) (1 )

Effective tax rate 15 % 20 % 19 %

The Company has approximately ~~$20~~$24 million of federal and ~~$11~~$14 million of state (California) EOR tax credit carryforwards available to reduce future income taxes. The EOR credits will begin to expire, if unused, in ~~2020~~2022 and ~~2014~~2015 for federal and California, respectively.

~~10.Commitments~~

10.

Commitments

Operating Leases –- Office Space

The Company leases corporate and field offices in California and the Rocky Mountain region. Rent expense with respect to the Company's lease commitments for the years ended December 31, 2004, 2003 and 2002 was $.6 million, $.5 million, and $.3 million, respectively. The total minimum rental payments, on a combined basis, for these leases are as follows (in thousands):

Year ending December 31,

2004 $ 528
2005 562
2006 487
2007 107
2008 107
2009 90

Total $ 1,881


	38

Year ending December 31,

2005	$	621
2006		538
2007		138
2008		108
2009		18

Total	$	1,423

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

~~10.Commitments (Cont’d)~~

10.

Commitments (Cont'd)

Firm Transportation-Natural Gas Purchases

The Company entered into a 12,000 MMBtu/D ten-year firm transportation agreement on the Kern River pipeline with gas deliveries commencing in May 2003. This firm transportation provides the Company additional flexibility in securing its natural gas supply and allows the Company to potentially benefit from ~~discounted~~lower natural gas prices in the ~~Rockies.~~Rockies compared to natural gas prices in California. As of December 31, ~~2003,~~2004, this take-or-pay commitment ~~was approximately $29 million~~ over the remaining term of the ~~contract.~~contract is as follows (in thousands):

Year ending December 31,

2005	$	2,814
2006		2,814
2007		2,814
2008		2,814
2009		2,814
Thereafter		9,368
Total	$	23,438

~~11.~~

~~Contingencies~~Drilling Commitment

The Company ~~has accrued~~intends to participate in the drilling of over 30 gross wells on its Lake Canyon prospect over the next five years. The Company's minimum obligation under its exploration and development agreement is $10.5 million.

11.

Contingencies

The Company accrues environmental liabilities for all sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, where it is probable that a loss will be incurred and the minimum cost or amount of loss can be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be higher than the liability currently accrued. Amounts currently accrued are not significant to the ~~consolidated~~ financial position of the Company and Management believes, based upon current site assessments, that the ultimate resolution of these matters will not require substantial additional accruals. The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of Management, the resolution of these matters will not have a material effect on the Company’s financial position, results of operations or liquidity.

~~12.Stock Option Plan~~

12.

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 and December 2001 (the 1994 Plan or Plan) and approved by the shareholders in May 1998 and May 2002, respectively. The 1994 Plan ~~provides~~provided for the granting of stock options to purchase up to an aggregate of 3,000,000 shares of Common Stock. All options, with the exception of the formula grants to non-employee Directors, ~~will be~~were granted at the discretion of the Compensation Committee of the Board of Directors. The term of each option ~~may~~did not exceed ten years from the date the ~~option is~~options were granted. The 1994 Plan expired on December 2, 2004. The Board has approved a new equity incentive plan for submittal to the Shareholders in May 2005.

The options vest 25% per year for four years. The 1994 Plan also ~~allows~~allowed for option grants to the ~~Board of~~Company's non-employee Directors under a formula plan whereby ~~all non-employee Directors receive~~each such Director received 5,000 options annually on December 2^ndat the fair value on the date of grant. The options granted to the ~~non-employee~~ Directors vest immediately.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

12.

Stock Option Plan (Cont'd)

Effective January 1, 2004, the Company voluntarily adopted the fair value method of accounting for its stock option plan as prescribed by SFAS 123,Accounting for Stock-Based Compensation. The modified prospective method was selected as described in SFAS 148,Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, the Company recognizes stock option compensation expense as if it had applied the fair value method to account for unvested stock options from its original effective date. Compensation expense under the fair value method for the year ended December 31, 2004 was $1.5 million. Additionally, the Company recorded $4.4 million, $3.9 million and $1.3 million for the years ended December 31, 2004, 2003 and 2002, respectively, in compensation expense under the variable method of accounting prior to the modification of certain exercise provisions of the Company's stock option plan on July 29, 2004.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model that uses the assumptions noted in the following table. Expected volatilities are based on the historical volatility of the Company's stock. The Company uses historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding; the range given below results from certain groups of employees exhibiting different exercise behavior. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.

		2004
Expected volatility		25%
Weighted-average volatility		25%
Expected dividends		1.27% - 2.45%
Expected term (in years)		4 - 7
Risk-free rate		3.4% - 4.4%

The following is a summary of stock-based compensation activity for the years 2004, 2003 ~~2002~~ and ~~2001.~~2002.

	2004			2003			2002
	Options			Options			Options

Balance outstanding, January 1		1,701,925			1,604,575			1,474,962
Granted		567,750			411,500			241,200
Exercised		(581,550	)		(294,150	)		(95,837	)
Canceled/expired		(122,500	)		(20,000	)		(15,750	)
Balance outstanding, December 31		1,565,625			1,701,925			1,604,575

Balance exercisable at December 31		688,275			1,037,275			1,153,000

Available for future grant		-			615,600			1,007,100

Weighted average remaining contractuallife (years)		8			7			7
Weighted average fair value peroption granted during the year basedon the Black-Scholes pricing model	$	10.10		$	5.11		$	5.25

2003

2002

2001

Options

Options

Options

Balance outstanding, January 1 1,604,575 1,474,962 1,407,837
Granted 411,500 241,200 239,500
Exercised (294,150 ) (95,837 ) (65,125 )
Canceled/expired (20,000 ) (15,750 ) (107,250 )

Balance outstanding, December 31 1,701,925 1,604,575 1,474,962

Balance exercisable at December 31 1,037,275 1,153,000 1,010,712

Available for future grant 615,600 1,007,100 232,550

Exercise price-range $ 15.10 $ 16.56 $ 14.40
to 20.30 to 18.05 to 16.96
Weighted average remaining contractuallife (years) 7 7 7
Weighted average fair value peroption granted during the year basedon the Black-Scholes pricing model $ 5.11 $ 5.25 $ 5.87


	39

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

~~12.Stock Option Plan (Cont’d)~~

12.

Stock Option Plan (Cont'd)

The following table summarizes information related to stock options outstanding and exercisable as of December 31, 2004

			Weighted
		Weighted	Average		Weighted
Range of		Average	Remaining		Average
Exercise	Options	Exercise	Contractual	Options	Exercise
Prices	Outstanding	Price	Life	Exercisable	Price
$10.63 - $22.50	997,875	$ 16.76	6.9	648,275	$ 16.01
$22.51 - $34.00	103,500	28.79	9.5	-	-
$34.01 - $45.50	464,250	43.23	9.9	40,000	43.54
$10.63 - $45.50	1,565,625	$ 25.41	8.0	688,275	$ 17.61

Weighted average option exercise price information for the years 2004, 2003 ~~2002~~ and ~~2001~~2002 as follows.

	2004		2003		2002
Outstanding at January 1	$	16.50	$	15.17	$	14.80
Granted during the year		40.60		19.31		16.14
Exercised during the year		15.73		13.15		11.87
Cancelled/expired during the year		18.02		16.55		15.92
Outstanding at December 31		25.41		16.50		15.17
Exercisable at December 31		17.61		15.62		14.81

2003

2002

2001

Outstanding at January 1 $ 15.17 $ 14.80 $ 14.58
Granted during the year 19.31 16.14 16.16
Exercised during the year 13.15 11.87 13.12
Cancelled/expired during the year 16.55 15.92 16.01
Outstanding at December 31 16.50 15.17 14.80
Exercisable at December 31 15.62 14.81 14.55

~~13.Retirement Plan~~The total intrinsic value of options exercised during the years ended December 31, 2004, 2003 and 2002, was $7.2 million, $1.6 million and $.5 million, respectively. At December 31, 2004, the intrinsic value of options outstanding was $34.9 million and the intrinsic value of exercisable options was $20.7 million.

As of December 31, 2004, there was $7 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the Plan. This cost is expected to be recognized over a weighted-average period of 3.4 years.

13.

401(k) Plan

The Company sponsors a ~~401(k)~~ defined contribution thrift plan under section 401(k) of the internal revenue code to assist all eligible 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 $.8 million, $.5 million ~~in 2003, $.4 million in 2002,~~ and $.4 million in ~~2001.~~2004, 2003 and 2002, respectively. On average, approximately 96% of eligible employees participate in the plan.

Table of Contents

~~14.~~BERRY PETROLEUM COMPANY

~~Quarterly~~Notes to the Financial ~~Data (unaudited)~~Statements

14.

Director Deferred Compensation Plan

In 1998, the Company established a non-employee director deferred stock and compensation plan to permit eligible Directors, in recognition of their contributions to the Company, to receive fees as compensation and defer recognition of their compensation in whole or in part to a Stock Unit Account or an Interest Account. When the eligible Director ceases to be a Director, the distribution from the Stock Unit Account shall be made in shares using an established market value date and the distribution from the Interest Account shall be made in cash. The aggregate number of shares which may be issued to eligible Directors under the plan shall not exceed 250,000, subject to adjustment for corporate transactions that change the amount of outstanding stock. The plan may be amended at any time, not more than once every six months, by the Compensation Committee or the Board of Directors and shall terminate, unless extended, on May 31, 2008.

Amounts allocated to the Stock Unit Account have the right to receive an amount equal to the dividend per share declared by the Company on the applicable dividend payment date and this “dividend equivalent” shall be treated as reinvested in additional number of units and credited to their account using an established market value date. Amounts allocated to the Interest Account are credited with interest at an established interest rate.

Shares deferred in accordance with the plan as of December 31, 2004, 2003 and 2002 were 56,204, 50,388 and 39,459, respectively.

15.

Hedging

From time to time, the Company enters into crude oil and natural gas hedge contracts, the terms of which depend on various factors, including Management’s view of future crude oil and natural gas prices and the Company’s future financial commitments. This hedging program is designed to moderate the effects of a severe crude oil price downturn and protect certain operating margins in the Company's California operations. Currently, the hedges are in the form of swaps, however, the Company may use a variety of hedge instruments in the future. The Company generally attempts to hedge between 25% and 50% of its anticipated crude oil production and up to 30% of its anticipated net natural gas purchased each year.Management regularly monitors the crude oil and natural gas markets and the Company’s financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging or other price protection is appropriate. All of these hedges have historically been deemed to be cash flow hedges with the mark-to-market valuations provided by external sources, based on prices that are actually quoted.

As a result of hedging activities, the Company's revenue was reduced by $24.9 million, $11.8 million and $3.8 million in 2004, 2003, and 2002, respectively, which was reported in "Sales of oil and gas" in the Company's financial statements. These hedging activities resulted in a net reduction in revenue per BOE to the Company of $3.31 in 2004, $1.96 in 2003, and $.72 in 2002. As of December 31, 2004, contracts had settlement dates through the third quarter of 2006.

At December 31, 2004, Accumulated Other Comprehensive Loss consisted of $1.6 million ($1.0 million net of tax) of unrealized losses from the Company's crude oil and natural gas swaps. Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2004 are expected to be reclassified to earnings during 2005 and 2006.

With respect to the Company's hedging activities, the Company utilizes more than one Conterparty on its hedges and monitors each counterparty's credit rating.

Table of Contents

BERRY PETROLEUM COMPANY

Notes to the Financial Statements

16.

Quarterly Financial Data (unaudited)

The following is a tabulation of unaudited quarterly operating results for ~~2003~~2004 and ~~2002~~2003 (in thousands, except per share data):.

2003
Operating Revenues

Gross
Profit

Net Income

Basic Net Income Per Share

Diluted Net Income Per Share

First Quarter $ 46,766 $ 16,790 $ 9,177 $ 0.42 $ 0.42
Second Quarter 39,372 9,187 6,510 0.30 0.30
Third Quarter 44,108 11,842 8,035 0.37 0.36
Fourth Quarter 49,802 17,110 10,610 0.49 0.48

$ 180,048 $ 54,929 $ 34,332 $ 1.58 $ 1.56

2002

First Quarter $ 26,807 $ 8,014 $ 8,620 $ 0.40 $ 0.40
Second Quarter 31,765 10,482 6,827 0.31 0.31
Third Quarter 34,933 12,599 7,587 0.35 0.35
Fourth Quarter 36,212 10,534 6,990 0.32 0.32

$ 129,717 $ 41,629 $ 30,024 $ 1.38 $ 1.37


	40

							Basic Net		Diluted Net
	Operating		Gross		Net		Income		Income
2004	Revenues		Profit		Income		Per Share		Per Share

First Quarter	$	57,139	$	19,976	$	10,364	$	0.48	$	0.47
Second Quarter		64,046		25,057		15,278		0.70		0.68
Third Quarter		72,904		31,130		18,229		0.83		0.82
Fourth Quarter(1)		80,431		36,505		25,316		1.15		1.13
	$	274,520	$	112,668	$	69,187	$	3.16	$	3.08

2003

First Quarter	$	46,766	$	16,790	$	10,275	$	0.47	$	0.47
Second Quarter		39,372		9,187		4,905		0.23		0.22
Third Quarter		44,108		11,842		7,827		0.36		0.35
Fourth Quarter		49,802		17,110		9,356		0.43		0.42
	$	180,048	$	54,929	$	32,363	$	1.49	$	1.47

(1) During the fourth quarter, the Company recorded a net tax benefit of approximately $2.3 million, primarily due to the recognition of deferred tax assets related to certain properties and other tax items.

17.

Subsequent Events (unaudited)

In January 2005, the Company completed its acquisition of certain assets in the Niobrara fields in northeastern Colorado for approximately $105 million utilizing the Company’s existing credit facility. The properties consist of approximately 127,000 gross (69,500 net) acres and the Company, will have a working interest of approximately 52%. The Company's 52% share of current production is approximately 9 MMcf of natural gas per day with estimated proved reserves of 87 Bcf. The acquisition also includes approximately 200 miles of a natural gas pipeline gathering system and gas compression facilities for delivery into interstate gas lines. Subsequent to this acquisition and as of March 1, 2005 the Company's total debt outstanding was $144 million.

In January 2005, the Company entered into an agreement to purchase, for approximately $5 million, a working interest in approximately 390,000 gross (172,250 net) prospective acres, located in eastern Colorado, western Kansas and southwestern Nebraska, from Bill Barrett Corporation.The joint venture will apply seismic technologies to explore and, if successful, develop the Niobrara formation for biogenic gas, which lies at less than 2,000 feet, and will apply seismic technologies to evaluate oil potential in the Pennsylvanian formations at depths of 4,000 to 4,800 feet.The Company believes the potential of the Tri-State area can be exploited by using new drilling techniques, with 3-D seismic technology to assess structural complexity, and estimate potentially recoverable oil and gas and determine drilling locations. Drilling on the prospect commenced in early 2005.

At December 31, 2004, the Company was in the process of drilling one exploratory well on its Midway-Sunset property and one exploratory well on its Coyote Flats prospect. These two wells were determined non-commercial in February 2005. Costs of $.5 million which were incurred as of December 31, 2004 were charged to expense and are reflected on the Company's income statement under "Dry-hole, abandonment and impairment." The remaining costs of approximately $2.5 million will be charged to expense during the first quarter of 2005.

Table of Contents

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, 2004, 2003 ~~2002~~ and ~~2001.~~2002. 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, 2004, 2003 ~~2002~~ and ~~2001,~~2002, and changes in such quantities during each of the years then ended were as follows (in thousands):

	2003						2002						2001

	Oil		Gas				Oil		Gas				Oil		Gas				2004									2003									2002
	Mbbls		Mmcf		BOE		Mbbls		Mmcf		BOE		Mbbls		Mmcf		BOE		Oil			Gas						Oil			Gas						Oil			Gas
																			Mbbls			Mmcf			BOE			Mbbls			Mmcf			BOE			Mbbls			Mmcf			BOE
Proved developed and
Undeveloped reserves:
Beginning of year	100,744		5,850		101,719		101,701		6,926		102,855		106,664		4,184		107,361			106,640			19,680			109,920			100,744			5,850			101,719			101,701			6,926			102,855
Revision of previous estimates	(82	)	293		(33	)	(30	)	(307	)	(81	)	33		153		58			2,974			8,246			4,348			(82	)		293			(33	)		(30	)		(307	)		(81	)
Improved recovery	1,271		-		1,271		752		-		752		-		-		-			2,021			-			2,021			1,271			-			1,271			752			-			752
Extensions and discoveries	1,853		2,005		2,187		3,444		-		3,444		-		-		-			2,736			714			2,855			1,853			2,005			2,187			3,444			-			3,444
Property sales																				(127	)		(77	)		(140	)		-			-			-			-			-			-
Production	(5,827	)	(1,277	)	(6,040	)	(5,123	)	(769	)	(5,251	)	(4,996	)	(288	)	(5,044	)		(7,043	)		(2,839	)		(7,516	)		(5,827	)		(1,277	)		(6,040	)		(5,123	)		(769	)		(5,251	)
Purchase of reserves in place	8,681		12,809		10,816		-		-		-		-		2,877		480			132			-			132			8,681			12,809			10,816			-			-			-

Royalties converted to working interest (1)																				(1,784	)		-			(1,784	)		-			-			-			-			-			-

End of year	106,640		19,680		109,920		100,744		5,850		101,719		101,701		6,926		102,855			105,549			25,724			109,836			106,640			19,680			109,920			100,744			5,850			101,719


Proved developed reserves:
Beginning of year	72,889		3,252		73,431		79,317		3,518		79,903		81,132		1,635		81,405			78,145			12,207			80,180			72,889			3,252			73,431			79,317			3,518			79,903


End of year	78,145		12,207		80,180		72,889		3,252		73,431		79,317		3,518		79,903			78,207			20,048			81,549			78,145			12,207			80,180			72,889			3,252			73,431


	41

(1) In December 2004 certain royalty owners exercised their right to convert their royalty interest into a working interest on the Company's Formax property in the Midway-Sunset field. This resulted in a reduction to the Company of 1.8 million barrels of reserves and represents approximately 450 BOE/day at year end production levels. The Company has no other similar conversion rights by any other current royalty owners.

Table of Contents

	DELAWARE		77-0079387
	(State of incorporation or organization)		(I.R.S. Employer Identification Number)

	~~Name of each exchange~~
Title of each class		Name of each exchangeon which registered
	Class A Common Stock, $.01 par value		New York Stock Exchange
	(including associated stock purchase rights)

		Page
Item 1.
~~Items 1 and 2.~~	Business ~~and Properties~~	3
	General	3
	Crude Oil and Natural Gas Marketing	4
	~~Steaming Operations~~	6
	~~Electricity Generation~~	7
	~~Electricity Sales Contracts~~	7
	~~Environmental and Other Regulations~~ Steaming Operations	8
	~~Competition~~ Electricity Generation	98
	~~Employees~~ Electricity Sales Contracts	98
	~~Oil~~ Environmental and ~~Gas Properties~~Other Regulations	910
	~~Enhanced Oil Recovery Tax Credits~~ Competition	12
	~~Oil and Gas Reserves~~ Employees	12
	~~Production~~ Oil and Gas Properties	12
	~~Acreage and Wells~~ Enhanced Oil Recovery Tax Credits	1315
	~~Drilling Activity~~ Oil and Gas Reserves	1316
	~~Title and Insurance~~ Production	1316
	Acreage and Wells	16
	Drilling Activity	17
	Title and Insurance	17
Item 2.	Properties	18
Item 3.	Legal Proceedings	1418
Item 4.	Submission of Matters to a Vote of Security Holders	1418
	Executive Officers of the Registrant	1418


Item 5.	Market for the Registrant's Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities	1519
Item 6.	Selected Financial Data	1621
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	1722
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	2138
Item 8.	Financial Statements and Supplementary Data	2340
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	4367
Item 9A	Controls and Procedures	4367
Item 9B	Other Information	68


Item 10.	Directors and Executive Officers of the Registrant	4368
Item 11.	Executive Compensation	4368
Item 12.	Security Ownership of Certain Beneficial Owners and Management	4368
Item 13.	Certain Relationships and Related Transactions	4368
Item 14.	Principal Accounting Fees and Services	4368


Item 15.	Exhibits, Financial Statement Schedules ~~and Reports on Form 8-K~~	4469

	3·

Rockies & Mid-Continent production - In 2005, the Company will continue the development of the Brundage Canyon producing property on 80-acre spacing, test the potential of 40-acre infill drilling and appraise the northern and southern limits of the field. On the recently acquired Niobrara gas assets, the Company plans to drill approximately 60 wells as part of its ongoing development program and the initiation of the 40-acre infill program from the existing 80-acre development.

Crude Oil and Natural Gas Hedges
(Based on NYMEX Pricing)

				Floor				Ceiling
	Barrels
Term		Per Day		Sell Put		Buy Put		Sell Call		Buy Call

Crude Oil Hedges

01/01/2004 – 03/31/2004		2,500	$	18.25	$	22.10	$	25.40	$	30.10

01/01/2004 – 03/31/2004		2,500	$	18.25	$	22.10	$	25.45	$	30.10

04/01/2004 – 12/31/2004		1,000	$	19.00	$	22.00	$	25.50	$	29.40

04/01/2004 – 12/31/2004		1,000	$	19.50	$	23.00	$	26.00	$	29.75

04/01/2004 – 12/31/2004		1,000	$	19.50	$	23.00	$	26.00	$	29.50

04/01/2004 – 12/31/2004		1,000	$	19.50	$	23.00	$	26.25	$	29.85

01/01/2004 – 04/30/2004		1,000	$	-	$	25.00	$	25.00	$	-

01/01/2004 – 12/31/2004		1,500	$	-	$	29.25	$	29.25	$	-

01/01/2004 – 12/31/2004		1,500	$	-	$	29.00	$	29.00	$	-


Natural Gas Hedges		MMBtu
		Per Day

01/01/2004 – 06/30/2006		2,500	$	-	$	4.85	$	4.85	$	-

01/01/2004 – 06/30/2006		2,500	$	-	$	4.85	$	4.85	$	-

Location and Facility	Type of Contract	Purchaser	Contract Expiration	Approximate Megawatts Available for Sale	Approximate Megawatts Consumed in Operations	Approximate Barrels of Steam Per Day

Placerita
Placerita Unit 1	SO2	Edison	Mar-09	20	-	6,600
Placerita Unit 2	SO1	Edison	Dec-09	16	4	6,700

South Midway-Sunset
Cogen 18	SO1	PG&E	Dec-09	12	4	6,600
Cogen 38	SO1	PG&E	Dec-09	37	-	18,000

	Developed Acres				Undeveloped Acres				Total
	Gross		Net		Gross		Net		Gross		Net

California		8,167		8,167		7,038		7,038		15,205		15,205
Utah (1)		9,520		9,360		82,363		58,352		91,883		67,712
Wyoming		3,800		750		4,266		2,250		8,066		3,000
Illinois		-		-		58,318		54,601		58,318		54,601
Kansas		-		-		168,960		163,046		168,960		163,046
Other		80		19		-		-		80		19

		21,567		18,296		320,945		285,287		342,512		303,583

		2003						2002

		Price Range				Dividends		Price Range				Dividends	2004						2003
		High		Low		Per Share		High		Low		Per Share	Price Range				Dividends		Price Range				Dividends
													High		Low		Per Share		High		Low		Per Share
First Quarter	$	17.01	$	14.65	$	0.10	$	16.90	$	13.25	$	0.10	$	27.30	$	18.25	$	0.11	$	17.01	$	14.65	$	0.10
Second Quarter		18.38		14.40		0.15		17.58		15.45		0.10		31.07		25.09		0.11		18.38		14.40		0.15
Third Quarter		19.17		16.96		0.11		18.25		14.52		0.10		38.44		27.73		0.18		19.17		16.96		0.11
Fourth Quarter		20.95		17.90		0.11		17.50		15.60		0.10		50.58		35.16		0.12		20.95		17.90		0.11

	Number of securities to be
	issued upon exercise of	Weighted average exercise	Number of securities
	outstanding options, warrants	price of outstanding options,	remaining available for future
	and rights (1)(3)	warrants and rights	issuance (2)(3)
Plan category	(a)	(b)	(c)

Equity compensation plansapproved by security holders	1,565,625	$25.41	-

Equity compensation plans not approved by security holders	-	-	-
Total	1,565,625	$25.41	-

	2004			2003 (1)			2002(1)			2001(1)			2000(1)
Audited Financial Information
Statement of Income Data:
Sales of oil and gas	$	226,876		$	135,848		$	102,026		$	100,146		$	118,801
Sales of electricity		47,644			44,200			27,691			35,133			51,420
Operating costs – oil and gas production		82,419			62,554			45,217			38,114			48,594
Operating costs – electricity generation		46,191			42,351			26,747			36,890			45,464
General and administrative expenses (G&A)		20,354			12,868			9,215			8,718			6,782
Depreciation, depletion & amortization
(DD&A) - oil and gas production		29,752			17,258			13,388			13,225			11,374
DD&A - electricity generation		3,490			3,256			3,064			3,295			2,656
Net income		69,187			32,363			29,210			20,985			37,766
Basic net income per share		3.16			1.49			1.34			0.96			1.71
Diluted net income per share		3.08			1.47			1.33			0.95			1.71
Weighted average number of shares outstanding (basic)		21,894			21,772			21,741			21,973			22,029
Weighted average number of shares outstanding (diluted)		22,470			22,031			21,902			22,162			22,145
Balance Sheet Data:
Working capital	$	(3,840	)	$	(3,540	)	$	(2,892	)	$	6,314		$	(963	)
Total assets		412,104			340,377			259,325			238,779			238,572
Long-term debt		28,000			50,000			15,000			25,000			25,000
Shareholders' equity		263,086			197,338			172,774			153,590			145,220
Cash dividends per share		0.52			0.47			0.40			0.40			0.40
Operating Data:
Cash flow from operations		124,613			64,825			57,895			35,433			65,934
Capital expenditures (excluding acquisitions)		72,225			41,555			30,632			14,895			25,253
Property/facility acquisitions		2,845			48,579			5,880			2,273			3,182

Unaudited Operating Data
Oil and gas producing operations (per BOE):
Average sales price before hedging	$	33.64		$	24.48		$	20.11		$	19.63		$	23.01
Average sales price after hedging		30.32			22.52			19.39			19.79			21.72
Average operating costs - oil and gas production		10.96			10.37			8.61			7.64			9.29
G&A		2.71			2.13			1.75			1.73			1.24
DD&A - oil and gas production		3.96			2.86			2.55			3.28			2.57

Production(MBOE)		7,517			6,040			5,251			5,044			5,467
Production(MWh)		776			767			748			483			764
Proved Reserves Information:
Total BOE		109,836			109,920			101,719			102,855			107,361
Standardized measure⁽²⁾	$	686,748		$	528,220		$	449,857		$	278,453		$	501,694
Present value (PV10) of estimated future netcash flow before income taxes		876,502			683,124			599,826			358,653			719,882
Year-end average BOE price for PV10 purposes		29.87			25.89			24.91			14.13			21.13
Other:
Return on average shareholders' equity		31.06	%		17.50	%		17.90	%		14.00	%		28.80	%
Return on average total assets		18.60	%		10.80	%		11.70	%		8.80	%		16.90	%

	16·

timing of its future drilling, development and abandonment activities;


~~BOE/D = Barrels of oil equivalent per day~~
~~MWh/D = Megawatt hours per day~~
~~MMBtu = Million British Thermal Units~~

		2004		2003		2002

		(Budgeted) (1)
CALIFORNIA
Midway-Sunset Field
New wells	$	6,885	$	10,710	$	10,224
Remedials/workovers		2,045		1,718		1,981
Facilities - oil & gas		2,385		3,136		1,340
Facilities - cogeneration⁽²⁾		150		231		898
General		1,682		187		-

		13,147		15,982		14,443

Placerita
New wells	��	322		6,509		5,278
Remedials/workovers		1,233		154		174
Facilities - oil & gas		1,590		916		2,480
Facilities - cogeneration⁽²⁾		150		370		4,382

		3,295		7,949		12,314

Montalvo
Remedials/workovers		1,180		928		909
Facilities		425		94		179

		1,605		1,022		1,088

McVan
New Wells		150		-		-
Remedials/workovers		650		2		-
Facilities		540		666		-

		1,340		668		-


Total California		19,387		25,621		27,845


ROCKIES AND MID-CONTINENT
Brundage Canyon

	2005		2004		2003
	(Budgeted) (1)
CALIFORNIA
Midway-Sunset Field
New wells	$	11,012	$	11,376	$	10,710
Remedials/workovers		420		1,415		1,718
Facilities - oil & gas		6,850		4,045		3,136
Facilities - cogeneration		3,435		1,055		231
General		2,001		2,144		187
		23,718		20,035		15,982

Other California Fields
New wells		5,295		426		6,509
Remedials/workovers		4,463		1,589		1,084
Facilities - oil & gas		2,470		3,416		1,676
Facilities - cogeneration		250		555		370
		12,478		5,986		9,639

Total California		36,196		26,021		25,621

ROCKIES AND MID-CONTINENT
Uinta Basin
New wells		47,914		39,467		14,298
Remedials/workovers		2,050		4,597		234
Facilities		4,332		1,979		146
		54,296		46,043		14,678
DJ Basin
New wells/workovers		5,660		-		-
Land and seismic		3,573		-		-
		9,233		-		-

Other		3,593		161		1,256

Total Rocky Mountain and
Mid-Continent		67,122		46,204		15,934

Other		3,682		-		-


Totals	$	107,000	$	72,225	$	41,555

	2004				2003				2002
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells drilled:
Productive		5		5		-		-		-		-
Dry⁽¹⁾		-		-		-		-		11		11
Development wells drilled:⁽²⁾
Productive		123		111		121		119		81		76
Dry⁽¹⁾		-		-		1		1		-		-
Total wells drilled:
Productive		128		116		121		119		81		76
Dry⁽¹⁾		-		-		1		1		11		11

	Amount per BOE							Amount (in thousands)
					%							%
	2004		2003		Change			2004		2003		Change

Operating costs	$	10.96	$	10.36		6	%	$	82,419	$	62,554		32	%
DD&A		3.96		2.86		38	%		29,752		17,258		72	%
G&A		2.71		2.13		27	%		20,354		12,868		58	%
Interest expense		0.27		0.23		17	%		2,067		1,414		46	%
Total	$	17.90	$	15.58		15	%	$	134,592	$	94,094		43	%

The Company's contractual obligations as of December 31, 2004 are as follows (in thousands):

			Less than		1-3		3-5		More than
Contractual Obligations	Total		1 year		years		years		5 years

Long-term debt	$	28,000	$	-	$	28,000	$	-	$	-
Abandonment obligations		8,214		304		871		1,064		5,975
Operating lease obligations		1,423		621		676		126		-
Drilling obligation		10,525		925		4,250		5,350		-
Firm natural gas
transportation contract		23,438		2,814		5,628		5,628		9,368
Total	$	71,600	$	4,664	$	39,425	$	12,168	$	15,343

					Impact of percent change in futures prices
		12/31/03		on earnings (in thousands)
		NYMEX
		Futures			-20%			-10%			+10%			+20%

Average WTI Price	$	30.64		$	24.51		$	27.57		$	33.70		$	36.77

Crude Oil gain/(loss)		(8,400	)		4,730			(1,710	)		(12,420	)		(16,160	)

Average HH Price		5.21			4.17			4.69			5.73			6.25

Natural Gas gain/(loss)		410			(3,720	)		(1,650	)		2,470			4,530

Statements of Comprehensive Income
Years Ended December 31, 2003, 2002 and 2001
(In Thousands)

Net income	$	34,332		$	30,024		$	21,938
Unrealized gains (losses) on derivatives, net of income taxes		(3,632	)		(2,569	)		-
Reclassification of unrealized gains included in net income		2,569			-			(441	)

Comprehensive income	$	33,269		$	27,455		$	21,497

2003		Operating Revenues		Gross Profit		Net Income		Basic Net Income Per Share		Diluted Net Income Per Share

First Quarter	$	46,766	$	16,790	$	9,177	$	0.42	$	0.42
Second Quarter		39,372		9,187		6,510		0.30		0.30
Third Quarter		44,108		11,842		8,035		0.37		0.36
Fourth Quarter		49,802		17,110		10,610		0.49		0.48

	$	180,048	$	54,929	$	34,332	$	1.58	$	1.56

2002

First Quarter	$	26,807	$	8,014	$	8,620	$	0.40	$	0.40
Second Quarter		31,765		10,482		6,827		0.31		0.31
Third Quarter		34,933		12,599		7,587		0.35		0.35
Fourth Quarter		36,212		10,534		6,990		0.32		0.32

	$	129,717	$	41,629	$	30,024	$	1.38	$	1.37

~~C. Exhibits~~

Exhibit No.	Description of Exhibit

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)
3.5	Bylaws, as amended, dated February 24, 2005
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, 2001, 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 (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)
10.410.3	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)
10.510.4	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)
~~10.7~~10.5*	Credit Agreement, dated as of July 10, 2003, by and between the Registrant and Wells Fargo Bank, N.A. and other financial ~~institutions.~~institutions (filed as Exhibit 10.7 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003, File No. 1-9735)
10.810.6	Amended and Restated 1994 Stock Option Plan (filed as Exhibit 4.1 to the Registrant’s Registration Statement on Form S-8 filed on August 20, 2002, File No. 333-98379)
10.910.7*	Crude oil purchase contract, dated as of August 1, 2002, by and between the Registrant and Equiva Trading Company (filed as Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-9735).

~~Exhibits (cont'd)~~

Exhibit No.	Description of Exhibit

10.10*10.8	Amended and Restated Non-Employee Director Deferred Stock and Compensation Plan
10.9*	Purchase and sale agreement between the Registrant and Williams Production Company (filed as Exhibit ~~10.10~~10.11 to the ~~Registrant’s~~Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2002,~~2003, File No. 1-9735).
~~10.11~~10.10*	Employment Contract dated as of June 16, 2004 by and between the Registrant and Robert F. Heinemann (filed as Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 1-9735)
10.11*	Salary Continuation Agreement dated as of June 16, 2004 by and between the Registrant and Robert F. Heinemann (filed as Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 1-9735)
10.12*	Purchase and sale agreement between the Registrant and ~~Willliams Production~~J-W Operating Company (filed as Exhibit 99.2 to the Registrant's Current Report on Form 8-K/A filed on February 15, 2005, File No. 1-9735)
23.1	Consent of PricewaterhouseCoopers LLP, Independent Registered Accounting Firm
23.2	Consent of DeGolyer and MacNaughton
31.1	Certification of Chief Executive Officer pursuant to SEC Rule 13(a)-14(a)
31.2	Certification of Chief Financial Officer pursuant to SEC Rule 13(a)-14(a)
32.1	Certification of Chief Executive Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32.2	Certification of Chief Financial Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
99.1	~~Undertaking for Form S-8 Registration Statements~~
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)~~
99.399.2	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
** Pursuant to 17CFR240.24b-2, confidential information has been omitted and has been filed separately with the Securities and Exchange Commission, pursuant to a Confidential Treatment Request filed with the Commission.

~~JERRY V. HOFFMAN~~/s/ Robert F. Heinemann	/s/ Ralph J. Goehring	/s/ Donald A. Dale
ROBERT F. HEINEMANN	RALPH J. GOEHRING	DONALD A. DALE
~~Chairman of the Board, Director,~~President Chief Executive Officer	~~Senior~~Executive Vice President and	Controller
~~President~~ and ~~Chief~~Director	Chief Financial Officer	(Principal Accounting Officer)
~~Executive Officer~~	(Principal Financial Officer)

Name	Office	Date

/s/ ~~Jerry V. Hoffman~~Martin H. Young, Jr.	Chairman of the Board, Director ~~Presidentand~~	March ~~5, 2004~~30, 2005
~~Jerry V. Hoffman~~Martin H. Young, Jr.

/s/ Robert F. Heinemann	President, Chief Executive Officer	March 30, 2005
Robert F. Heinemann	and Director

/s/ William F. Berry	Director	March ~~5, 2004~~30, 2005
William F. Berry

/s/ Ralph B. Busch, III	Director	March ~~5, 2004~~30, 2005
Ralph B. Busch, III

/s/ William E. Bush, Jr.	Director	March ~~5, 2004~~30, 2005
William E. Bush, Jr.

/s/ Stephen L. Cropper	Director	March ~~5, 2004~~30, 2005
Stephen L. Cropper

/s/ J. Herbert Gaul, Jr.	Director	March ~~5, 2004~~30, 2005
J. Herbert Gaul, Jr.

/s/ John A. Hagg	Director	March ~~5, 2004~~30, 2005
John A. Hagg

~~/s/ Robert F. Heinemann~~	~~Director~~	~~March 5, 2004~~
~~Robert F. Heinemann~~

/s/ Thomas J. Jamieson	Director	March ~~5, 2004~~30, 2005
Thomas J. Jamieson

~~/s/ Martin H. Young, Jr.~~	~~Director~~	~~March 5, 2004~~
~~Martin H. Young, Jr.~~