Edgar Filing: BERRY PETROLEUM CO

Total productive wells drilled:

form10-k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2007

Commission file number 1-9735

BERRY PETROLEUM COMPANY

(Exact name of registrant as specified in its charter)

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

5201 Truxtun Avenue, Suite 300

Bakersfield, California 93309

(Address of principal executive offices, including zip code)

Registrant's telephone number, including area code: (661) 616-3900

Securities registered pursuant to Section 12(b) of the Act:

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

YES x NO o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

YES o NO x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filerx Accelerated filero Non-accelerated filero Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO x

As of June 29, 2007, the aggregate market value of the voting and non-voting common stock held by non-affiliates was $1,376,613,441. As of February 1, 2008, the registrant had 42,585,553 shares of Class A Common Stock outstanding. The registrant also had 1,797,784 shares of Class B Stock outstanding on February 1, 2008 all of which are held by an affiliate of the registrant.

DOCUMENTS INCORPORATED BY REFERENCE

Part III is incorporated by reference from the registrant's definitive Proxy Statement for its Annual Meeting of Shareholders to be filed, pursuant to Regulation 14A, no later than 120 days after the close of the registrant's fiscal year.

Berry Petroleum Company - 2007 Form 10-K

BERRY PETROLEUM COMPANY

TABLE OF CONTENTS

PART I

		Page
Item 1.	Business		3
	General		3
	Crude Oil and Natural Gas Marketing		5
	Steaming Operations		8
	Electricity		9
	Competition		10
	Employees		10
	Capital Expenditures Summary		11
	Production		12
	Acreage and Wells		12
	Drilling Activity		13
	Environmental and Other Regulations		13
Item 1A.	Risk Factors		14
Item 1B.	Unresolved Staff Comments		22
Item 2.	Properties		22
Item 3.	Legal Proceedings		22
Item 4.	Submission of Matters to a Vote of Security Holders		22
	Executive Officers		22

PART II


Item 5.	Market for the Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	23
Item 6.	Selected Financial Data	26
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operation	27
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 8.	Financial Statements and Supplementary Data	47
	Balance Sheets	49
	Statements of Income	50
	Statements of Shareholders' Equity	51
	Statements of Cash Flows	52
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
Item 9A.	Controls and Procedures	72
Item 9B.	Other Information	73

PART III


Item 10.	Directors and Executive Officers and Corporate Governance	73
Item 11.	Executive Compensation	73
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	74
Item 13.	Certain Relationships and Related Transactions, and Director Independence	74
Item 14.	Principal Accounting Fees and Services	74

PART IV


Item 15.	Exhibits, Financial Statement Schedules			74

Berry Petroleum Company - 2007 Form 10-K

Forward Looking Statements

“Safe harbor under the Private Securities Litigation Reform Act of 1995:” Any statements in this Form 10-K that are not historical facts are forward-looking statements that involve risks and uncertainties. Words or forms of words such as “will,” “might,” “intend,” “continue,” “target,” “expect,” “achieve,” “strategy,” “future,” “may,” “could,” “goal,”, “forecast,” “anticipate,” or other comparable words or phrases, or the negative of those words, and other words of similar meaning, indicate forward-looking statements and important factors which could affect actual results. Forward-looking statements are made based on management’s current expectations and beliefs concerning future developments and their potential effects upon Berry Petroleum Company. These items are discussed at length on page 14 in Part I, Item 1A in this Form 10-K filed with the Securities and Exchange Commission, under the heading “Risk Factors.”

PART I

Item 1. Business

General. We are an independent energy company engaged in the production, development, acquisition, exploitation of and exploration for, crude oil and natural gas. While we were incorporated in Delaware in 1985 and have been a publicly traded company since 1987, we can trace our roots in California oil production back to 1909. In 2003, we purchased and began operating properties in the Rocky Mountains. Our corporate headquarters are in Bakersfield, California and we have a regional office in Denver, Colorado. Information contained in this report on Form 10-K reflects our business during the year ended December 31, 2007 unless noted otherwise.

Our website, located at http://www.bry.com, can be used to access recent news releases and Securities and Exchange Commission (SEC) filings, crude oil price postings, our Annual Report, Proxy Statement, Board committee charters, Corporate Governance Guidelines, code of business conduct and ethics, the code of ethics for senior financial officers, and other items of interest. SEC filings, including supplemental schedules and exhibits, can also be accessed free of charge through the SEC website at http://www.sec.gov.

Corporate strategy. Our objective is to increase shareholder value through consistent growth in our production and reserves, both through the drill bit and acquisitions. We strive to operate our properties in an efficient manner to maximize the cash flow and earnings of our assets. The strategies to accomplish these goals include:

Developing our existing resource base. We intend to increase both production and reserves annually. We are focused on the timely and prudent development of our large resource base through developmental and step-out drilling, down-spacing, well completions, remedial work and by application of enhanced oil recovery (EOR) methods, as applicable. We have large crude oil resources in place in the San Joaquin Valley basin, California, with diatomite being our largest, and a resource play in the Uinta basin, Utah (Lake Canyon). In 2006, we invested in a large undeveloped probable natural gas reserve position in the Piceance basin in Colorado, and are planning to continue significant drilling there over the next several years. We have a proven track record of developing reserves on a competitive basis and have increased annual production for over six years.

Acquiring additional assets with significant growth potential. We will continue to evaluate oil and gas properties with proved reserves, probable reserves and/or sizeable acreage positions that we believe contain substantial hydrocarbons which can be developed at reasonable costs. In the last three years we have completed over $400 million of gas-oriented acquisitions in Colorado, establishing two core areas (the DJ and Piceance basins) of growth for us. We will continue to review asset acquisitions that meet our economic criteria with a primary focus on large repeatable development potential in the United States and concentrating on opportunities where we have strong technical expertise. Additionally, we seek to increase our net revenue interest in assets that we already operate.

Utilizing joint ventures with respected partners to enter new basins. We believe that early entry into some basins offers the best potential for establishing low cost acreage positions in those basins. In areas where we do not have existing operations, we may seek to utilize the skills and knowledge of other industry participants upon entering these new basins so that we can reduce our risk and improve our ultimate success in the area.

Accumulating significant acreage positions near our producing operations. We are interested in adding acreage positions near our existing producing operations to leverage our operating and technical expertise within the area and to build on established core operations. We believe this strategy can add value by utilizing our operational knowledge in a given area and by expanding our operations efficiently.

Investing our capital in a disciplined manner and maintaining a strong financial position. The oil and gas business is capital intensive. Therefore we focus on utilizing our available capital on projects where we are likely to have success in increasing production and/or reserves at attractive returns. We believe that maintaining a strong financial position allows us to capitalize on investment opportunities and to be better prepared for a lower commodity price environment. We expect to continue to hedge oil and gas prices and to utilize long-term sales contracts with the objective of achieving the cash flow necessary for the development of our assets.

Berry Petroleum Company - 2007 Form 10-K

Business strengths.

High quality asset portfolio with a long reserve life. Over the last several years we have diversified our asset base through acquisitions and now have approximately 40% of our production and proved reserves in the Rocky Mountain region with the balance in California. Our proved reserves consist of 69% crude oil and 31% natural gas. Our legacy California assets provides us with a steady stream of cash flow to re-invest into our significant drilling inventory and the appraisal of our prospects. Our wells are generally characterized by long production lives and predictable performance. At December 31, 2007 our implied reserve life was 16.5 years and our implied proved developed reserve life was 10.1 years.

Track record of efficient proved reserve and production growth. For the three years ended December 31, 2007, our average annual reserve replacement rate was 316% at an average cost of $12.23 per barrel of oil equivalent (BOE). See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operation for further explanation of the reserve replacement rate. During the same period our proved reserves and production increased at an annualized compounded rate of 15% and 9%, respectively. We were able to deliver that growth predominantly through low-risk drilling. In 2007, we achieved an average gross drilling success rate of 98%. We believe we can continue to deliver strong growth through the drill bit by exploiting our large undeveloped leasehold position. We also plan to complement this drill bit growth through selective and focused acquisitions.

Experienced management and operational teams. We operate our assets through six integrated teams organized around our six core areas of operations. These teams have clear objectives in production, reserves, finding and development costs, operating costs and are charged with value enhancement. In the last several years we have expanded and deepened our core team of technical staff and operating managers, who have broad industry experience, including experience in California heavy oil thermal recovery operations and Rocky Mountain tight gas sands development and completion. We continue to utilize technologies and steam practices that we believe will allow us to improve the ultimate recoveries of crude oil on our mature California properties. We also utilize 3-D seismic technology for evaluation of sub-surface geologic trends of our many prospects.

Operational control and financial flexibility. We exercise operating control over approximately 98% of our proved reserve base. We generally prefer to retain operating control over our properties, allowing us to control operating costs more effectively, the timing of development activities and technological enhancements, the marketing of production and the allocation of our capital budget. In addition, the timing of most of our capital expenditures is discretionary, which allows us a significant degree of flexibility to adjust the size and timing of our capital budget. We finance our drilling budget primarily through our internally generated operating cash flows and we also have a $750 million senior unsecured revolving credit facility with a current borrowing base of $550 million.

Established risk management policies. We actively manage our exposure to commodity price fluctuations by hedging a portion of our forecasted production. We use hedges to assist us in mitigating the effects of price declines and to secure operating cash flows in order to fund our capital expenditures program. Our long-term crude oil contracts with refiners and our long-term firm natural gas pipeline transportation agreements assist us in mitigating price differential volatility and in assuring product delivery to markets. Currently, the operation of our cogeneration facilities in California provides a partial hedge against increases in natural gas prices (which translates into higher steam costs) because of the high correlation between electricity and natural gas prices under our existing electricity sales contracts.

Proved Reserves and Revenues. As of December 31, 2007, our estimated proved reserves were 169 million BOE, of which 60% are heavy crude oil, 9% light crude oil and 31% natural gas. We have a geographically diverse asset base with 60% of our reserves located in California, and 40% in the Rocky Mountains. Of our proved reserves 61% were proved developed, while proved undeveloped reserves make up 39% of our proved total. The projected future capital to develop these proved undeveloped reserves is $677 million at an estimated cost of approximately $10.21 per BOE. Approximately 62% of the capital to develop these reserves is expected to be expended in the next five years. Production in 2007 was 9.8 million BOE, up 6% from production of 9.3 million BOE in 2006.

Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics with a ratio of proved reserves to production (based on the year ended December 31, 2007) of approximately 16.5 years as compared to 15.3 years at year end 2006.

Berry Petroleum Company - 2007 Form 10-K

We have organized our operations into six asset teams as follows: South Midway-Sunset (S. Midway), North Midway-Sunset including diatomite (N. Midway), Southern California including Poso Creek and Placerita (S. Cal), Piceance, Uinta and DJ. The following table sets forth the estimated quantities of proved reserves and production attributable to our asset teams as of December 31, 2007. We operate 98% of these assets:

State	Name	Type	Average Daily Production (BOE/D)		% of Daily Production			Proved Reserves (BOE) in millions		% of Proved Reserves			Oil & Gas Revenues before hedging (in millions)		% of Oil & Gas Revenues before hedging
CA	S. Midway	Heavy oil		9,616		36	%		52.4		31	%	$	189.0		39	%
UT	Uinta	Light oil/Natural gas		5,743		21			23.4		14			91.6		19
CA	S. Cal	Heavy oil		4,265		16			26.3		16			101.8		21
CO	DJ	Natural gas		3,123		12			21.1		12			34.2		7
CA	N. Midway	Heavy oil		2,068		8			22.8		13			50.4		10
CO	Piceance	Natural gas		1,715		6			23.1		14			16.4		3
	Other (1)	Heavy oil/Natural gas		372		1			.1		-			5.8		1
Totals				26,902		100	%		169.2		100	%	$	489.2		100	%

(1) Primarily relates to properties sold during 2007.

We continue to engage DeGolyer and MacNaughton (D&M) to appraise the extent and value of our proved oil and gas reserves and the future net revenues to be derived from our properties for the year ended December 31, 2007. D&M is an independent oil and gas consulting firm located in Dallas, Texas. In preparing their reports, D&M reviewed and examined geologic, economic, engineering and other data considered applicable to properly determine our reserves. They also examined the reasonableness of certain economic assumptions regarding forecasted operating and development costs and recovery rates in light of the economic environment on December 31, 2007. See Supplemental Information About Oil & Gas Producing Activities (Unaudited) for our oil and gas reserve disclosures.

Acquisitions. See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Operations. In California, we operate all of our principal oil and gas producing properties. The S. Midway, N. Midway and S. Cal assets contain predominantly heavy crude oil which requires heat, supplied in the form of steam, which is injected into the oil producing formations to reduce the oil viscosity, thereby allowing the oil to flow to the wellbore for production. We utilize cyclic steam and/or steam flood recovery methods on all assets. Field operations related to oil production include the initial recovery of the crude oil and its transport through treating facilities into storage tanks. After the treating process is completed, which includes removal of water and solids by mechanical, thermal and chemical processes, the crude oil is metered through automatic custody transfer units or gauged before sale and subsequently transferred into crude oil pipelines owned by other companies or transported via truck.

In the Rocky Mountains, crude oil produced from the Uinta properties is transported by truck. Natural gas produced from the Uinta, DJ and Piceance basin properties is transported to one of several main pipelines. We have seven firm transportation contracts on four different pipelines to provide transport for our Rocky Mountain natural gas production. See table on page 7.

Crude Oil and Natural Gas Marketing.

Economy. Global and California crude oil demand continues to remain strong although pricing is volatile. Product prices continued to exhibit an overall-strengthening trend through December 2007. Oil is a globally priced commodity and is priced according to the supply and demand of crude oil and its products. The weakness of the U.S. dollar in 2007 has contributed to a rise in the price of crude oil denominated in U.S. dollars. This price action is a contributor to the volatility of the commodity. Other dominant factors in the pricing of our crude oil include the condition of the global economy and political tension in or near oil producing regions. The range of West Texas Intermediate (WTI) crude prices for 2007, based upon NYMEX settlements, was a low of $50.48 and a high of $98.18. We expect that crude prices will continue to be volatile in 2008.

Berry Petroleum Company - 2007 Form 10-K

	2007		2006		2005
Average NYMEX settlement price for WTI	$	72.41	$	66.25	$	56.70
Average posted price for Berry’s:
Utah 40 degree black wax (light) crude oil		59.28		56.34		53.03
California 13 degree API heavy crude oil		61.64		54.38		44.36
Average crude price differential between WTI and Berry’s:
Utah light 40 degree black wax (light) crude oil		13.13		9.91		3.67
California 13 degree API heavy crude oil		10.77		11.87		12.34

The above posting prices and differentials are not necessarily amounts paid or received by us due to the contracts discussed below. The crude oil price differential between WTI and California’s heavy crude has remained relatively stable in 2007 and 2006. On December 31, 2007 the differential was $12.44 and ranged from a low of $9.11 to a high of $12.47 per barrel during the year. Crude oil price differentials between WTI and Utah’s 40 degree black wax (light) crude oil were fairly consistent during 2007. On December 31, 2007 the differential was $14.50 and ranged from a low of $12.41 to a high of $14.50 per barrel during the year.

Oil Contracts. We market our crude oil production to competing buyers which may be an independent or a major oil refining company.

California - We have the ability to deliver significant volumes of crude oil over a multi-year period. On November 21, 2005, we entered into a new crude oil sales contract with an independent refiner for substantially all of our California production for deliveries beginning February 1, 2006 and ending January 31, 2010. After the initial term of the contract, we have a one-year renewal at our option. The per barrel price, calculated on a monthly basis and blended across the various producing locations, is the higher of 1) the WTI NYMEX crude oil price less a fixed differential approximating $8.10, or 2) heavy oil field postings plus a premium of approximately $1.35. The agreement effectively eliminates our exposure to the risk of a widening WTI to California heavy crude price differential over the four year contract term and allows us to effectively hedge our production based on WTI pricing. This contract allowed us to improve our California revenues by $15 million and $21 million over the posted price in 2007 and 2006, respectively.

Prior to November 2005, we secured a three-year sales agreement, beginning in late 2002, with a major oil company whereby we sold over 90% of our California production under a negotiated pricing mechanism. This contract ended on January 31, 2006. Pricing in this agreement was based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed differential near $6.00 per barrel.

Utah - During 2007, our Utah light crude oil was sold under multiple contracts with different purchasers for varying pricing terms, and in some cases our realized price was further reduced by transportation charges. As operator we deliver all produced volumes pursuant to these contracts, although our working interest partners or royalty owners may take their respective volumes in kind and market their own volumes. We experienced increasing difficulty in locating additional buyers of our crude oil production from this region in the latter part of 2006. Our Utah crude oil is a paraffinic crude and can be processed efficiently by only a limited number of refineries. Increased production of crude oil in the region, the ability of refiners to process other higher sulfur crudes as a result of capital upgrades, as well as the increasing availability of Canadian crude oil, put downward pressure on the sales price of our crude oil.

On February 27, 2007, we entered into a multi-staged crude oil sales contract with a refiner for our Uinta basin light crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D on July 1, 2007. Upon completion of its refinery expansion in Salt Lake City, which is expected in the first half of 2008, the refiner will increase its total purchased volumes to 5,000 Bbl/D through June 30, 2013. Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI, which was near the posted price at the contract’s starting date. As global and regional prices of crude oil have risen in 2007, we are receiving crude oil prices below the posted price, although this posted price is thinly traded and does not necessarily indicate the actual price at which a seller can market their crude oil. While our price differentials have widened as the crude oil price increased, we are able to sell 100% of our crude oil to a refiner and avoid any field shut down due to the inability of placing the crude. The margins on our Uinta crude allow us to reinvest in drilling the field and to retain and increase the overall value of the field. As of January 1, 2008 this contract is our only sales contract for our Uinta oil.

From October 1, 2003 through April 30, 2006 we were able to sell our Utah crude oil at approximately $2.00 per barrel below WTI, and from May 1, 2006 through September 30, 2006, we were selling the majority of our Utah crude at approximately $9.00 per barrel below WTI. Due to this lower pricing, and based on sales of 3,500 Bbl/D, our revenues were lower by approximately $9.2 million in 2006 as compared to 2005.

Berry Petroleum Company - 2007 Form 10-K

Natural Gas Marketing. We market our produced natural gas from Colorado and Utah. Generally, natural gas is sold at monthly index related prices plus an adjustment for transportation. Certain volumes are sold at a daily spot related price. Approximately two-thirds of the pricing of our natural gas is tied to the Panhandle Eastern Pipeline (PEPL) index and the remaining volume to the Colorado Interstate Gas (CIG) Index; both indices are lower than NYMEX Henry Hub prices.

	2007		2006		2005
Annual average closing price per MMBtu for:
NYMEX Henry Hub (HH) prompt month natural gas contract last day	$	6.86	$	7.23	$	8.62
Rocky Mountain Questar first-of-month indices (Uinta sales)		3.69		5.36		6.73
Rocky Mountain CIG first-of-month indices (DJ and Piceance sales)		3.97		5.63		6.95
Mid-Continent PEPL first-of-month indices (CO, KS, UT & WY sales)		5.99		6.02		7.29
Average natural gas price per MMBtu differential between NYMEX HH and:
Questar		3.17		1.87		1.89
CIG		2.89		1.60		1.67
PEPL		.87		1.21		1.33

Gas Basis Differential. Natural gas prices in the Rockies continue to be volatile due to various factors, including takeaway pipeline capacity, supply volumes, and regional demand issues. The basis differential between HH and CIG has narrowed, as anticipated, upon the startup of the Rockies Express pipeline in early 2008. We have contracted a total of 35,000 MMBtu/D on this pipeline under two separate transactions to provide firm transport for our Piceance basin gas production. The CIG basis differential per MMBtu, based upon first-of-month values, averaged $2.89 below HH and ranged from $.51 to $5.31 below HH in 2007. Although related to CIG, the actual basin price varies. Gas from the Piceance basin traded slightly below the CIG price while Uinta basin gas sold for approximately $.40 below CIG pricing. DJ Basin gas is priced using one of two indices. Approximately two-thirds of our volumes from our DJ natural gas properties is tied to the PEPL index for pricing and the remaining volumes to CIG pricing. For that portion of the production with firm transportation on either the Cheyenne Plains Pipeline or the KMIGT pipeline, pricing is based upon the PEPL index which averaged approximately $.87 below the HH index before the cost of transportation is considered. The remainder of the DJ Basin gas is sold slightly above the CIG index price.

We have physical access to interstate gas pipelines to move gas to or from market. To assure delivery of gas, we have entered into long-term gas transportation contracts as follows:

Firm Transportation Summary.

Name	From	To	Quantity (Avg. MMBtu/D)		Term		December 31, 2007 base cost per MMBtu			Remaining contractual obligation (in thousands)
Kern River Pipeline	Opal, WY	Kern County, CA	12,000		5/2003 to 4/2013	$	0.643		$	15,012
Rockies Express Pipeline	Meeker, CO	Clarington, OH	25,000		2/2008 to 2/2018		1.098	(1)		101,941
Rockies Express Pipeline	Meeker, CO	Clarington, OH	10,000		1/2008 to 1/2018		1.064	(1)		39,205
Questar Pipeline	Brundage Canyon, UT	Salt Lake City, UT	2,500		9/2003 to 4/2012		0.174			687
Questar Pipeline	Brundage Canyon, UT	Salt Lake City, UT	2,859		9/2003 to 4/2012		0.174			787
Questar Pipeline	Brundage Canyon, UT	Goshen, UT	5,000		9/2003 to 4/2012		0.257			2,033
KMIGT	Yuma County, CO	Grant, KS	2,500		1/2005 to 10/2013		0.227			1,209
Cheyenne Plains Gas Pipeline	Yuma County, CO	Kiowa County, KS	11,000	(2)	1/2007 to 12/2016		0.342			12,369
Total			70,859						$	173,243

(1) Base cost per MMBtu is a weighted average cost.

(2) Quantity varies by year, but averages 11,000 per day over the ten year term.

Royalties. See Item 7A Quantitative and Qualitative Disclosures about Market Risk.

Hedging. See Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 15 to the financial statements.

Concentration of Credit Risk. See Note 4 to the financial statements.

Berry Petroleum Company - 2007 Form 10-K

Steaming Operations.

Cogeneration Steam Supply. As of December 31, 2007, approximately 60% of our proved reserves, or 101.6 million barrels, consisted of heavy crude oil produced from depths of less than 2,000 feet. In pursuing our goal of being a cost-efficient heavy oil producer in California, we have consistently focused on minimizing our steam cost. We believe one of the main methods to keep steam costs low is through the ownership and efficient operation of three cogeneration facilities located on our properties. Two of these cogeneration facilities, a 38 megawatt (MW) and an 18 MW facility, are located in S. Midway. We also own a 42 MW cogeneration facility which is located in the Placerita field. Cogeneration, also called combined heat and power (CHP), extracts energy from the exhaust of a turbine that would otherwise be wasted, to produce steam. This increases the efficiency of the combined process and consumes less fuel than would be required to produce the steam and electricity separately. The reduction in fuel use also results in a corresponding reduction of greenhouse gas (GHG) emissions.

Conventional Steam Generation. In addition to these cogeneration plants, we own 23 fully permitted conventional boilers. The quantity of boilers operated at any point in time is dependent on 1) the steam volume required for us to achieve our targeted production and 2) the price of natural gas compared to the realized price of crude oil sold.

Total barrels of steam per day (BSPD) capacity as of December 31, 2007 is as follows:


Steam generation capacity of conventional boilers			67,700
Steam generation capacity of cogeneration plants			38,000
Additional steam purchased under contract with a third party			2,000
Total steam capacity			107,700

The average volume of steam injected for the years ended December 31, 2007 and 2006 was 87,990 and 81,246 BSPD, respectively.

Ownership of these varied steam generation facilities and sources allows for maximum operational control over the steam supply, location, and to some extent, control over the aggregated cost of steam generation. Our steam supply and flexibility are crucial for the maximization of California thermally enhanced heavy oil production, cost control and ultimate reserve oil recovery.

In 2007, we have added additional steam capacity for our development projects at N. Midway, primarily diatomite, and Poso Creek to achieve maximum production from these properties. In 2008, we plan to add one additional 5,000 BSPD generator at Poso Creek and three additional 5,000 BSPD generators on our diatomite producing properties.

We operated most of our conventional steam generators in 2007 to achieve our goal of increasing heavy oil production. Approximately 62% of the volume of natural gas purchased to generate steam and electricity is based upon SoCal Border indices. We pay distribution/transportation charges for the delivery of gas to our various locations where we consume gas for steam generation purposes. However, in some cases this transportation cost is embedded in the price of gas. Approximately 26% of supply volume is purchased in Wyoming and moved to the Midway-Sunset field using our firm transportation capacity on the Kern River Pipeline. This gas is purchased based upon the Rocky Mountain Northwest Pipeline (NWPL) index. The remaining 12% of supply volume is purchased based upon the PG&E Citygate index and used in our Poso Creek steaming operations.

	2007		2006		2005
Average SoCal Border Monthly Index Price per MMBtu	$	6.38	$	6.29	$	7.37
Average Rocky Mountain NWPL Monthly Index Price per MMBtu		3.95		5.66		6.96
Average PG&E Citygate Monthly Index Price per MMBtu		6.86		6.70		7.72

Berry Petroleum Company - 2007 Form 10-K

We historically have been a net purchaser of natural gas, and thus our net income was negatively impacted when natural gas prices rose higher than its oil equivalent. In 2005, on a gas balance basis, we achieved parity due to our eastern Colorado (DJ) gas acquisition. Subsequent to 2005, we have been a net seller of gas and will benefit operationally when gas prices are higher. We are a net seller of gas with a balance between natural gas consumed and produced. The following table shows our average 2007 and estimated average 2008 amount of production in excess of consumption and hedged volumes (in average MMBtu/D):

	2007			Estimated 2008
Natural gas produced:
DJ		18,500			18,500
Uinta (associated gas)		15,000			15,000
Piceance and other		11,000			21,000
Total natural gas volumes produced in operations		44,500			54,500

Natural gas consumed:
Cogeneration operations		27,000			27,000
Conventional boilers (1)		18,000			24,000
Total natural gas volumes consumed in operations		45,000			51,000
Less: Our estimate of approximate natural gas volumes consumed to produce electricity (2)		(24,000	)		(21,000	)
Total approximate natural gas volumes consumed to produce steam		21,000			30,000

Natural gas volumes hedged		15,000			18,000

Amount of natural gas volumes produced in excess of volumes consumed to produce steam and volumes hedged		8,500			6,500

(1) In 2008, we will have additional conventional capacity at Poso Creek and diatomite to increase our production from these fields.

(2) We estimate this volume based on electricity revenues divided by the gas purchase price, including transportation, per MMBtu for the respective period.

Electricity.

Generation. The total annual average electrical generation of our three cogeneration facilities is approximately 93 MW, of which we consume approximately 9 MW for use in our operations. Each facility is centrally located on certain of our oil producing properties. Thus the steam generated by the facility is capable of being delivered to numerous wells that require steam for the EOR process. Our investment in our cogeneration facilities has been for the express purpose of lowering the steam costs in our heavy oil operations and securing operating control of the respective steam generation. Expenses of operating the cogeneration plants are analyzed regularly to determine whether they are advantageous versus conventional steam boilers. Cogeneration costs are allocated between electricity generation and oil and gas operations based on the conversion efficiency (of fuel to electricity and steam) of each cogeneration facility and certain direct costs to produce steam. Cogeneration costs allocated to electricity will vary based on, among other factors, the thermal efficiency of our cogeneration plants, the price of natural gas used for fuel in generating electricity and steam, and the terms of our power contracts. Although we account for cogeneration costs as described above, economically we view any profit or loss from the generation of electricity as a decrease or increase, respectively, to our total cost of producing heavy oil in California. DD&A related to our cogeneration facilities is allocated between electricity operations and oil and gas operations using a similar allocation method.

Sales Contracts. Historically, we have sold electricity produced by our cogeneration facilities, each of which is a Qualifying Facility (QF) under the Public Utilities Regulatory Policy Act of 1978, as amended (PURPA), to two California public utilities; Southern California Edison Company (Edison) and PG&E, under long-term contracts approved by the California Public Utilities Commission (CPUC). These contracts are referred to as standard offer (SO) contracts under which we are paid an energy payment that reflects the utility’s Short Run Avoided Cost (SRAC) of energy plus a capacity payment that reflects a recovery of capital expenditures that would otherwise have been made by the utility. During most periods natural gas is the marginal fuel for California utilities, so this formula provides a hedge against our cost of gas to produce electricity and steam in our cogeneration facilities. On September 20, 2007, the CPUC issued a decision (SRAC Decision) that changes prospectively the way SRAC energy prices will be determined for existing and new SO contracts and revises the capacity prices paid under current SO1 contracts. The decision also requires California utilities to offer new contracts for energy and as-available capacity (similar to an SO1) and new contracts for energy and firm capacity (similar to an SO2) for a term of up to ten years. The new pricing methodology provides for a gradual transition of SRAC energy prices to market prices for electricity. Based on our preliminary analysis, we do not believe that the proposed pricing changes will materially affect us in 2008.

Berry Petroleum Company - 2007 Form 10-K

In December 2004, we executed a five-year SO1 contract with Edison for the Placerita Unit 2 facility, and five-year SO1 contracts with PG&E for the Cogen 18 and Cogen 38 facilities, each effective January 1, 2005. Pursuant to these contracts, we are paid the purchasing utility’s SRAC energy price and a capacity payment that is subject to adjustment from time to time by the CPUC. Edison and PG&E challenged, in the California Court of Appeals, the legality of the CPUC decision that ordered the utilities to enter into these five-year SO1 contracts, and similar one-year SO1 contracts that were ordered for 2004. The Court ruled that the CPUC had the right to order the utilities to execute these contracts. The Court also ruled that the CPUC was obligated to review the prices paid under the contracts and to adjust the prices retroactively to the extent it was later determined that such prices did not comply with the requirements of PURPA. To date, the CPUC has taken no final action based on this court ruling. We are currently analyzing whether to exercise our right under the SRAC Decision to replace each of these three SO1 contracts prior to its scheduled termination with one of the new SO contracts ordered by the SRAC Decision.

Based on the current pricing mechanism for our electricity under the contracts, we expect that our electricity revenues will be in the $50 million to $60 million range for 2008.

During the California energy crisis in 2000 and 2001, we had two Power Purchase Agreements with Edison and two with PG&E. Under these contracts, we were paid under an SRAC formula which included pricing gas off of the Southern California Border Spot Average. In various CPUC and court documents, this price point is often referred to as Topock. The Topock compressor site is located just inside the California border at Needles, California. On March 27, 2001, the CPUC issued a decision making certain changes in the then SRAC formula, the most significant of which was changing the pricing point from the Southern California Border to Malin (in northern California), which resulted in a significant reduction in the price we were to be paid by Edison and PG&E. The extreme disruption that this caused in the cogeneration industry caused Edison to enter into settlement agreements with us and other similarly situated gas fired QFs by which Edison nevertheless agreed to pay using the Southern California Border pricing point from March 27th forward. The CPUC approved the settlements. In various ongoing proceedings, the utilities argued the revised SRAC formula should be retroactively applied to the period from December 2000 to March 27, 2001. The CPUC has indicated in the past it did not believe retroactive adjustment should be made. On February 7, 2008, the CPUC Administrative Law Judge (ALJ) issued an order indicating that the ALJ intended to deal with a pending remand on this issue and ordered the utilities to report the number and identity of QF's still subject to this unresolved issue. We expect we may be one of those QF's. The ALJ also invited interested parties to propose solutions to the pending remand dispute. We intend to vigorously oppose any retroactive application of the March 27, 2001 decision and believe that any resolution of such dispute should be immaterial to us.

Facility and Contract Summary.

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

6,500

Placerita Unit 2

SO1

Edison

Dec-09

6,500

S. Midway

Cogen 18

SO1

PG&E

Dec-09

6,700

Cogen 38

SO1

PG&E

Dec-09

18,000

Competition. The oil and gas industry is highly competitive. As an independent producer we have little control over the price we receive for our crude oil and natural gas. As such, higher costs, fees and taxes assessed at the producer level cannot necessarily be passed on to our customers. In acquisition activities, competition is intense as integrated and independent companies and individual producers are active bidders for desirable oil and gas properties and prospective acreage. Although many of these competitors have greater financial and other resources than we have, we believe we are in a position to compete effectively due to our business strengths (identified on page 4).

Employees. On December 31, 2007, we had 263 full-time employees, up from 243 full-time employees on December 31, 2006.

Berry Petroleum Company - 2007 Form 10-K

Capital Expenditures Summary (Excluding Acquisitions).

The following is a summary of the developmental capital expenditures incurred during 2007 and 2006 and budgeted capital expenditures for 2008 (in thousands):

	2008		2007		2006
	(Budgeted) (1)

S. Midway Asset Team
New wells and workovers	$	27,948	$	13,174	$	15,904
Facilities - oil & gas		2,872		7,576		7,572
Facilities - cogeneration		-		-		415
General		-		150		411
		30,820		20,900		24,302
N. Midway Asset Team
New wells and workovers		43,143		12,949		28,707
Facilities - oil & gas		23,530		17,125		12,884
General		200		634		67
		66,873		30,708		41,658
S. Cal Asset Team
New wells and workovers		9,615		16,627		9,493
Facilities - oil & gas		7,328		17,549		6,234
Facilities - cogeneration		2,850		604		177
General		850		483		-
		20,643		35,263		15,904
Uinta Asset Team
New wells and workovers		48,060		52,700		104,397
Facilities		1,326		3,151		5,966
General		1,450		602		1,072
		50,836		56,453		111,434
Piceance Asset Team
New wells and workovers		93,900		103,921		36,654
Facilities		16,776		15,298		3,486
General		-		164		75
		110,676		119,383		40,215
DJ Asset Team
New wells and workovers		7,826		14,017		20,979
Facilities		3,497		2,736		7,883
General		1,691		1,519		427
		13,014		18,272		29,289

Other Fixed Assets		1,750		4,288		23,614	(2)

TOTAL	$	294,612	$	285,267	$	286,416

(1) Budgeted capital expenditures may be adjusted for numerous reasons including, but not limited to, oil and natural gas price levels and equipment availability, working capital needs, permit and regulatory issues. See Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operation.

(2) Other Fixed Assets in 2006 were primarily made up of two drilling rig purchases.

Berry Petroleum Company - 2007 Form 10-K

Production. The following table sets forth certain information regarding production for the years ended December 31, as indicated:

	2007		2006		2005
Net annual production: (1)
Oil (Mbbl)		7,210		7,182		7,081
Gas (MMcf)		15,657		12,526		7,919
Total equivalent barrels (MBOE) (2)		9,819		9,270		8,401

Average sales price:
Oil (per Bbl) before hedging	$	57.85	$	52.92	$	47.04
Oil (per Bbl) after hedging		53.24		50.55		40.83
Gas (per Mcf) before hedging		4.53		5.48		7.88
Gas (per Mcf) after hedging		5.27		5.57		7.73
Per BOE before hedging		49.72		48.38		47.01
Per BOE after hedging		47.50		46.67		41.62
Average operating cost - oil and gas production (per BOE)		14.38		12.69		11.79

Mbbl - Thousands of barrels

Mcf - Thousand cubic feet

MMcf - Million cubic feet

BOE - Barrels of oil equivalent

MBOE - Thousand barrels of oil equivalent

(1) Net production represents that owned by us and produced to our interests.

(2) Equivalent oil and gas information is at a ratio of 6 thousand cubic feet (Mcf) of natural gas to 1 barrel (Bbl) of oil. A barrel of oil is equivalent to 42 U.S. gallons

Acreage and Wells. As of December 31, 2007, our properties accounted for the following developed and undeveloped acres:

	Developed Acres		Undeveloped Acres		Total
	Gross	Net	Gross	Net	Gross	Net
California	5,512	5,512	521	521	6,033	6,033
Colorado	89,383	70,610	157,099	75,384	246,482	145,994
Illinois	-	-	746	63	746	63
Kansas	-	-	138,632	104,190	138,632	104,190
Utah (1) (2)	39,280	36,635	183,176	77,780	222,456	114,415
Wyoming	3,520	539	1,746	276	5,266	815
Other	80	19	-	-	80	19
	137,775	113,315	481,920	258,214	619,695	371,529

(1) Includes 1,600 gross developed and 42,983 gross undeveloped acres at Lake Canyon. We have an interest in 75% of the shallow rights and 25% of the deep rights, which is reduced when the Tribe participates.

(2) Does not include 125,000 gross (70,000 net) acres and 125,000 gross (23,000 net) acres at Lake Canyon (shallow) and Lake Canyon (deep), respectively, which we can earn upon fulfilling specific drilling obligations over a four year contract period beginning in 2006.

Gross acres represent acres in which we have a working interest; net acres represent our aggregate working interests in the gross acres.

As of December 31, 2007, we have 3,872 gross productive wells (3,183 net). Gross wells represent the total number of wells in which we have a working interest. Net wells represent the number of gross wells multiplied by the percentages of the working interests owned by us. One or more completions in the same bore hole are counted as one well. Any well in which one of the multiple completions is an oil completion is classified as an oil well.

Berry Petroleum Company - 2007 Form 10-K

Drilling Activity. The following table sets forth certain information regarding our drilling activities for the periods indicated:

	2007		2006		2005
	Gross	Net	Gross	Net	Gross	Net
Exploratory wells drilled (1):
Productive	5	3	7	3	13	6
Dry (2)	-	-	5	1	1	1
Development wells drilled:
Productive	411	314	532	356	213	176
Dry (2)	7	5	7	5	7	5
Total wells drilled:
Productive	416	317	539	359	226	182
Dry (2)	7	5	12	6	8	6

(1) 2005 does not include one gross well drilled by our industry partner that was being evaluated at December 31, 2005.

(2) A dry well is a well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Dry hole, abandonment and impairment. See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Company Owned Drilling Rigs. During 2005 and 2006, we purchased three drilling rigs, all of which are operational. Owning these rigs has allowed us to successfully meet a portion of our drilling needs in the Uinta and Piceance basins. As the rig market and our rig requirements change, we evaluate the necessity to continue to own these rigs and may dispose of one or all of such rigs over time. See Note 10 to the financial statements.

Other. At year end, we had two subsidiaries accounted for under the equity method (see Note 1 to the financial statements). We had no special purpose entities and no off-balance sheet debt. See discussion of our related party transaction at Note 17 to the financial statements.

Environmental and Other Regulations. We are committed to responsible management of the environment and prudent health and safety policies, as these areas relate to our operations. We strive to achieve the long-term goal of sustainable development within the framework of sound environmental, health and safety practices and standards. We strive to make environmental, health and safety protection an integral part of all business activities, from the acquisition and management of our resources to the decommissioning and reclamation of our wells and facilities.

We have programs in place to identify and manage known risks, to train employees in the proper performance of their duties and to incorporate viable new technologies into our operations. The costs incurred to ensure compliance with environmental, health and safety laws and other regulations are normal operating expenses and are not material to our operating costs. There can be no assurances, however, that changes in, or additions to, laws and regulations regarding the protection of the environment will not have an impact in the future. We maintain insurance coverage that we believe is customary in the industry although we are not fully insured against all environmental or other risks.

Environmental regulation. Our oil and gas exploration, production and related operations are subject to numerous and frequently changing federal, state, tribal and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Environmental laws and regulations may require the acquisition of certain permits prior to or in connection with drilling activities or other operations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment including releases in connection with drilling and production, restrict or prohibit drilling activities or other operations that could impact wetlands, endangered or threatened species or other protected areas or natural resources, require remedial action to mitigate pollution from ongoing or former operations, such as cleanup of environmental contamination, pit cleanups and plugging of abandoned wells, and impose substantial liabilities for pollution resulting from our operations. See Item 1A Risk Factors—"We are subject to complex federal, state, regional, local and other laws and regulations that could give rise to substantial liabilities from environmental contamination or otherwise adversely affect our cost, manner or feasibility of doing business."

Berry Petroleum Company - 2007 Form 10-K

Regulation of oil and gas. The oil and gas industry, including our operations, is extensively regulated by numerous federal, state and local authorities, and with respect to tribal lands, Native American tribes.

These types of regulations include requiring permits for the drilling of wells, the posting of drilling bonds and the reports concerning operations. Regulations may also govern the location of wells, the method of drilling and casing wells, the rates of production or "allowables," the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the notifying of surface owners and other third parties. Certain laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. We are also subject to various laws and regulations pertaining to Native American tribal surface ownership, to Native American oil and gas leases and other exploration agreements, fees, taxes, or other burdens, obligations and issues unique to oil and gas ownership and operations within Native American reservations.

Federal energy regulation. The enactment of PURPA, as amended, and the adoption of regulations thereunder by the Federal Energy Regulatory Commission (FERC) provided incentives for the development of cogeneration facilities such as ours. A domestic electricity generating project must be a QF under FERC regulations in order to benefit from certain rate and regulatory incentives provided by PURPA.

PURPA provides two primary benefits to QFs. First, QFs generally are relieved of compliance with extensive federal and state regulations that control the financial structure of an electricity generating plant and the prices and terms on which electricity may be sold by the plant. Second, FERC's regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs at a price based on the purchasing utility's avoided cost, and that the utility sell back-up power to the QF on a non-discriminatory basis. The term "avoided cost" is defined as the incremental cost to an electric utility of electric energy or capacity, or both, which, but for the purchase from QFs, such utility would generate for itself or purchase from another source. The Energy Policy Act of 2005 amends PURPA to allow a utility to petition FERC to be relieved of its obligation to enter into any new contracts with QFs if FERC determines that a competitive wholesale electricity market is available to QFs in the service territory. Such a determination has not been made for our service areas in California. This amendment does not affect any of our current SO contracts. FERC issued an order on October 20, 2006 implementing this amendment to PURPA and on December 20, 2006 issued a subsequent order granting limited rehearing of the October 20, 2006 order. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates lower than the utilities' avoided costs.

State energy regulation. The CPUC has broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in California and to promulgate regulation for implementation of PURPA. Since a power sales agreement becomes a part of a utility's cost structure (generally reflected in its retail rates), power sales agreements with independent electricity producers, such as we, are potentially under the regulatory purview of the CPUC and in particular the process by which the utility has entered into the power sales agreements. While we are not subject to regulation by the CPUC, the CPUC's implementation of PURPA is important to us.

Item 1A. Risk Factors

Other Factors Affecting the Company's Business and 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 our business, results of operations and financial condition. Our revenues, profitability and future growth and reserve calculations depend substantially on reasonable prices for oil and gas. These prices also affect the amount of our cash flow available for capital expenditures, working capital and payments on our debt and our ability to borrow and raise additional capital. The amount we can borrow under our senior unsecured revolving credit facility (see Note 6 to the financial statements) 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 we can produce economically. The oil and natural gas markets fluctuate widely, and we cannot predict future oil and natural gas prices. Oil prices have recently been at historically high levels and natural gas prices have been at high levels over the past several years when compared to prior periods. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

·	regional, domestic and foreign supply and perceptions of supply of and demand for oil and natural gas;

·	level of consumer demand;

·	weather conditions;

·	overall domestic and global political and economic conditions, including those in the Middle East and South America;

·	actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

·	the impact of increasing liquefied natural gas, or LNG, deliveries to the United States;

Berry Petroleum Company - 2007 Form 10-K

·	technological advances affecting energy consumption and supply;

·	domestic and foreign governmental regulations and taxation;

·	the impact of energy conservation efforts;

·	the capacity, cost and availability of oil and natural gas pipelines and other transportation facilities, and the proximity of these facilities to our wells; and

·	the price and availability of alternative fuels.

Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

·	reduce the amount of cash flow available to make capital expenditures or make acquisitions;

·	reduce the number of our drilling locations;

·	negatively impact the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically; and

·	limit our ability to borrow money or raise additional capital.

We have multiple hedges placed on our oil and gas production. See Item 7A Quantitative and Qualitative Disclosures About Market Risk.

Our heavy crude in California may be less economic than lighter crude oil and natural gas. As of December 31, 2007, approximately 60% of our proved reserves, or 101.6 million barrels, consisted of heavy oil. Light crude oil represented 9% and natural gas represented 31% of our oil and gas reserves. Heavy crude oil sells for a discount to light crude oil, as more complex refining equipment is required to convert heavy oil into high value products. We currently sell our heavy crude oil in California under a long-term contract for approximately $8.10 below WTI, the U.S. benchmark crude oil pricing. Regional pricing can influence commodity prices. Additionally, most of our crude oil in California is produced using the enhanced oil recovery process of steam injection. This process is more costly than primary and secondary recovery methods.

A widening of commodity differentials may adversely impact our revenues and our economics. Our crude oil and natural gas are priced in the local markets where the production occurs based on local or regional supply and demand factors. The prices that we receive for our crude oil and natural gas production are generally lower than the relevant benchmark prices, such as NYMEX, that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict natural gas and crude oil differentials.

Price differentials may widen in 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 industry, trade restrictions and governmental regulations. We may be adversely impacted by a widening differential on the products we sell. Our oil and natural gas hedges are based on WTI or natural gas index prices, so we may be subject to basis risk if the differential on the products we sell widens from those benchmarks and we do not have a contract tied to those benchmarks. Additionally, insufficient pipeline capacity or trucking capability and the lack of demand in any given operating area may cause the differential to widen in that area compared to other oil and natural gas producing areas. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our financial condition.

Market conditions or operational impediments may hinder our access to crude oil and natural gas markets or delay our production. Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities, trucking capability and refineries owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipelines, gathering system capacity, processing facilities or refineries. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market. See firm transportation summary schedule at Item 1 Business.

Factors that can cause price volatility for crude oil and natural gas include:

·	availability of gathering systems with sufficient capacity to handle local production;

·	seasonal fluctuations in local demand for production;

·	local and national natural gas storage capacity;

·	interstate pipeline capacity;

·	availability and cost of natural gas transportation facilities; and

·	availability and capacity of refineries.

Berry Petroleum Company - 2007 Form 10-K

We may not be able to deliver minimum crude oil volumes required by our sales contract. Production volumes from our Uinta properties over the next six years are uncertain and there is no assurance that we will be able to consistently meet the minimum contractual requirement. Upon completion of the refiner’s refinery expansion in Salt Lake City, which is expected in the first half of 2008, the refiner will increase its total purchased volumes to 5,000 Bbl/D through June 30, 2013. During the term of the contract, the minimum number of delivered barrels (“base daily volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion of the refinery upgrade. In the event that we cannot produce the necessary volume, we may need to purchase crude to meet our contract requirements.

We may be subject to the risk of adding additional steam generation equipment if the electrical market deteriorates significantly. We are dependent on several cogeneration facilities that, combined, provide approximately 35% of our steam capacity. These facilities are dependent on reasonable power contracts for the sale of electricity. If, for any reason, including if utilities that purchase electricity from us are no longer required by regulation to enter into power contracts with us, we were unable to enter into new or replacement contracts or were to lose any existing contract, we may not be able to supply 100% of the steam requirements necessary to maximize production from our heavy oil assets. An additional investment in various steam sources may be necessary to replace such steam, and there may be risks and delays in being able to install conventional steam equipment due to permitting requirements and availability of equipment. The financial cost and timing of such new investment may adversely affect our production, capital outlays and cash provided by operating activities. We have power contracts which expire in 2009 covering our electricity generation.

The future of the electricity market in California is uncertain. We utilize cogeneration plants in California to generate lower cost steam compared to conventional steam generation methods. Electricity produced by our cogeneration plants is sold to utilities and the steam costs are allocated to our oil and gas operations. While we have electricity sales contracts in place with the utilities that are currently scheduled to terminate in 2009, legal and regulatory decisions (especially related to the pricing of electricity under the contracts), can adversely affect the economics of our cogeneration facilities and as a result the cost of steam for use in our oil and gas operations.

A shortage of natural gas in California could adversely affect our business. We may be subject to the risks associated with a shortage of natural gas and/or the transportation of natural gas into and within California. We are highly dependent on sufficient volumes of natural gas necessary to use for fuel in generating steam in our heavy oil operations in California. If the required volume of natural gas for use in our operations were to be unavailable or too highly priced to produce heavy oil economically, our production could be adversely impacted. We have firm transportation to move 12,000 MMBtu/D on the Kern River Pipeline from the Rocky Mountains to Kern County, CA, which accounts for approximately one-quarter of our current requirement.

Our use of oil and gas price and interest rate hedging contracts involves credit risk and may limit future revenues from price increases or reduced expenses from lower interest rates, as well as result in significant fluctuations in net income and shareholders' equity. We use hedging transactions with respect to a portion of our oil and gas production with the objective of achieving a more predictable cash flow, and reducing our exposure to a significant decline in the price of crude oil and natural gas. We also utilize interest rate hedges to fix the rate on a portion of our variable rate indebtedness, as only a portion of our total indebtedness has a fixed rate and we are therefore exposed to fluctuations in interest rates. While the use of hedging transactions limits the downside risk of price declines or rising interest rates, as applicable, their use may also limit future revenues from price increases or reduced expenses from lower interest rates, as applicable. Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations.

Berry Petroleum Company - 2007 Form 10-K

Our future success depends on our ability to find, develop and acquire oil and gas reserves. To maintain production levels, we must locate and develop or acquire new oil and gas reserves to replace those depleted by production. Without successful exploration, exploitation or acquisition activities, our reserves, production and revenues will decline. We may not be able to find, develop or to 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 our cash flow from operations being less than expected or limit our ability to borrow under credit arrangements, we may be unable to expend the capital necessary to locate and to develop or acquire new oil and gas reserves.

Actual quantities of recoverable oil and gas reserves and future cash flows from those reserves, future production, oil and gas prices, revenues, taxes, development expenditures and operating expenses most likely will vary from estimates. It is not possible to measure underground accumulations of oil or natural gas in an exact way. Estimating accumulations of oil and gas is a complex process that relies on subjective 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, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, some of which are mandated by the SEC. The accuracy of a reserve estimate is a function of:

·	quality and quantity of available data;

·	interpretation of that data; and

·	accuracy of various mandated economic assumptions.

Any significant variance could materially affect the quantities and present value of our reserves. In addition, we 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, we base 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.

Future commodity price declines and/or increased capital costs may result in a write-down of our asset carrying values which could adversely affect our results of operations and limit our ability to borrow funds. Declines in oil and natural gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments.

We capitalize costs to acquire, find and develop our oil and gas properties under the successful efforts accounting method. If net capitalized costs of our oil and gas properties exceed fair value, we must charge the amount of the excess to earnings. We review the carrying value of our properties annually and at any time when events or circumstances indicate a review is necessary, based on estimated prices 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. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facility.

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 of proved undeveloped acreage. Major and independent oil and gas companies actively bid for desirable oil and gas properties, as well as for the equipment, supplies, labor and services required to operate and develop their properties. Some of these resources may be limited and have higher prices due to current strong demand. Many of our competitors have financial resources that are substantially greater than ours, which may adversely affect our ability to compete within the industry.

Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. These larger companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

Berry Petroleum Company - 2007 Form 10-K

Drilling is a high-risk activity. Our future success will partly depend on the success of our drilling program. In addition to the numerous operating risks described in more detail below, these drilling activities involve the risk that no commercially productive oil or gas reservoirs will be discovered. Also, we are 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 and/or services, including experienced labor.

The oil and gas business involves many operating risks that can cause substantial losses; insurance will not protect us 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.

If any of these events occur, we 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 we experience any of these problems, our ability to conduct operations could be adversely affected. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us. In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. For instance, we do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. While we intend to obtain and maintain insurance coverage we deem appropriate for these risks, there can be no assurance that our operations will not expose us to liabilities exceeding such insurance coverage or to liabilities not covered by insurance.

We are subject to complex federal, state, regional, local and other laws and regulations that could give rise to substantial liabilities from environmental contamination or otherwise adversely affect our cost, manner or feasibility of doing business. All facets of our operations are regulated extensively at the federal, state, regional and local levels. In addition, a portion of our leases in the Uinta basin are, and some of our future leases may be, regulated by Native American tribes. Environmental laws and regulations impose limitations on our discharge of pollutants into the environment, establish standards for our management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose on us obligations to investigate and remediate contamination in certain circumstances. We also must satisfy, in some cases, federal and state requirements for providing environmental assessments, environmental impact studies and/or plans of development before we commence exploration and production activities. Environmental and other requirements applicable to our operations generally have become more stringent in recent years, and compliance with those requirements more expensive. Frequently changing environmental and other governmental laws and regulations have increased our costs to plan, design, drill, install, operate and abandon oil and natural gas wells and other facilities, and may impose substantial liabilities if we fail to comply with such

Berry Petroleum Company - 2007 Form 10-K

regulations or for any contamination resulting from our operations. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Furthermore, our business, results from operations and financial condition may be adversely affected by any failure to comply with, or future changes to, these laws and regulations.

In addition, we could also be liable for the investigation or remediation of contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage. Such liabilities may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate, and may arise even where the contamination does not result from any noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share. We have incurred expenses and penalties in connection with remediation of contamination in the past, and we may do so in the future. From time to time we have experienced accidental spills, leaks and other discharges of contaminants at some of our properties, as have other similarly situated oil and gas companies. Some of the properties that we have acquired, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible. Some of our operations are in environmentally sensitive areas that may provide habitat for endangered or threatened species, and other protected areas, and our operations in such areas must satisfy additional regulatory requirements. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed certain drilling projects and/or access to prospective lands and have filed litigation to attempt to stop such projects, including decisions by the Bureau of Land Management regarding several leases in Utah that we have been awarded.

Our activities are also subject to the regulation by oil and natural gas-producing states and one Native American tribe of conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from federal, state, local and Native American tribal authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions that are more expensive than we have anticipated could have a negative effect on our ability to explore or develop our 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 our profitability.

Recent and future environmental regulations, including additional federal and state restrictions on greenhouse gas emissions that may be passed in response to climate change concerns, may increase our operating costs and also reduce the demand for the oil and natural gas we produce. On September 27, 2006, California’s governor signed into law the “California Global Warming Solutions Act of 2006” Assembly Bill (AB) 32, which establishes a statewide cap on GHG that will reduce the state’s GHG emissions to 1990 levels by 2020. The California Air Resources Board (“ARB”) has been designated as the lead agency to establish and adopt regulations to implement AB 32 by January 1, 2012. Other state agencies are involved in this effort. ARB is working on mandatory reporting regulations and early action measures to reduce GHG emissions prior to the 2012 date. A number of our personnel are involved in monitoring the establishment of these regulations through industry trade groups and other organizations in which we are a member. Similar laws and regulations may be adopted by other states in which we operate or by the federal government. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, such as carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. It is not possible, at this time, to estimate accurately how regulations to be adopted by ARB or that may be adopted by others to address GHG emissions would impact our business.

Furthermore, we benefit from federal energy laws and regulations that relieve our cogeneration plants, all of which are QFs, from compliance with extensive federal and state regulations that control the financial structure of electricity generating plants, as well as the prices and terms on which electricity may be sold by those plants. These federal energy regulations also require that electric utilities purchase electricity generated by our cogeneration plants at a price based on the purchasing utility's avoided cost, and that the utility sell back-up power to us on a non-discriminatory basis. The term "avoided cost" is defined as the incremental cost to an electric utility of electric energy or capacity, or both, which, but for the purchase from QFs, such utility would generate for itself or purchase from another source. The Energy Policy Act of 2005 amends PURPA to allow a utility to petition FERC to be relieved of its obligation to enter into any new contracts with QFs if the FERC determines that a competitive wholesale electricity market is available to QFs in its service territory. FERC issued an order on October 20, 2006 implementing this amendment to PURPA and on December 20, 2006 issued a subsequent order granting limited rehearing of the October 20, 2006 order. Any contracts in effect at the time of such determination would not be affected. Such a determination has not been made for our service areas in California; however, one of the California utilities has indicated that an application for relief will be filed upon the implementation of certain changes to the California electricity markets. Those market changes are not expected to occur until late in 2008. While the granting of an application for relief by FERC would not affect any of our current SO contracts, it could limit the availability of future contracts pursuant to PURPA. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates different than the utilities' avoided costs.

Berry Petroleum Company - 2007 Form 10-K

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. Our natural gas gathering operations are generally exempt from FERC regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still affects our gathering operations. FERC has recently proposed to require major non-interstate pipelines, including natural gas gathering pipelines (to comply with certain Internet posting requirements) with the goal of promoting transparency in the interstate natural gas market. The proposed rule would exclude from the posting requirement non-interstate pipelines flowing annually ten million MMBtus or less of gas, lying entirely upstream of a processing plant or delivering more than 95% of their gas directly to end users. FERC has not yet issued a final rule on that proposed rulemaking. We may experience an increase in costs if the rule is adopted as proposed.

Other FERC regulations may indirectly impact our gathering and natural gas production and sales operations. FERC’s policies and practices across the range of its natural gas regulatory activities (including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion) may affect access to natural gas transportation. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is subject to change based on future determinations by FERC, the courts, or Congress. Accordingly the classification and regulation of some of our natural gas gathering facilities may be subject to change based on future determinations by FERC, the courts, or Congress.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, or EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation.

State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at the state level because in recent years FERC has permitted interstate pipeline transmission companies to transfer their gathering facilities to unregulated affiliates. Our gathering operations could be adversely affected in the future should they become subject to the application of state or federal regulation of rates and services. These operations may also be, or become subject to, safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from natural gas wells. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect our business.

Property acquisitions are a component of our growth strategy, and our failure to complete future acquisitions successfully could reduce our earnings and slow our growth. Our business strategy has emphasized growth through strategic acquisitions, but we may not be able to continue to identify properties for acquisition or we may not be able to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If we are unable to achieve strategic acquisitions, our growth may be impaired, thus impacting earnings, cash from operations and reserves.

Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities. Our recent growth is due in part to acquisitions of properties with additional development potential and properties with minimal production at acquisition but significant growth potential, and we expect acquisitions will continue to contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include: recoverable reserves, exploration potential, future oil and natural gas prices, operating costs, production taxes and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not allow us to become sufficiently familiar with the properties, and we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited.

Berry Petroleum Company - 2007 Form 10-K

We generally are not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities, on acquisitions. Often, we acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties. If material breaches are discovered by us prior to closing, we could require adjustments to the purchase price or if the claims are significant, we or the seller may have a right to terminate the agreement. We could also fail to discover breaches or defects prior to closing and incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, for which we would have limited or no contractual remedies or insurance coverage.

There are risks in acquiring producing properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of management attention, and costs of increased scope, geographic diversity and complexity of our operations. Increasing our reserve base through acquisitions is an important part of our business strategy. Any acquisition involves potential risks, including, among other things:

·	the validity of our assumptions about reserves, future production, the future prices of oil and natural gas, revenues and costs, including synergies;

·	an inability to integrate successfully the properties and businesses we acquire;

·	a decrease in our liquidity to the extent we use a significant portion of our available cash or borrowing capacity to finance acquisitions;

·	a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

·	the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

·	the diversion of management’s attention from other business concerns;

·	an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

·	unforeseen difficulties encountered in operating in new geographic areas; and

·	customer or key employee losses at the acquired businesses.

Our decision to acquire a property or business will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential problems. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

If third-party pipelines interconnected to our natural gas wells and gathering facilities become partially or fully unavailable to transport our natural gas, our results of operations and financial condition could be adversely affected.We depend upon third party pipelines that provide delivery options from our wells and gathering facilities. Since we do not own or operate these pipelines, their continuing operation in their current manner is not within our control. If any of these third-party pipelines become partially or fully unavailable to transport our natural gas, or if the gas quality specifications for their pipelines change so as to restrict our ability to deliver natural gas to those pipelines, our revenues and cash available for distribution could be adversely affected.

The loss of key personnel could adversely affect our business. We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business, and we do not maintain key man insurance on the lives of any of these persons. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.

We have limited control over the activities on properties that we do not operate. Although we operate most of the properties in which we have an interest, other companies operate some of the properties. We have limited ability to influence or control the operation or future development of these nonoperated properties or the amount of capital expenditures that we are required to fund their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns or lead to unexpected future costs.

Berry Petroleum Company - 2007 Form 10-K

We may not adhere to our proposed drilling schedule. Our final determination of whether to drill any scheduled or budgeted wells will depend on a number of factors, including:

·	results of our exploration efforts and the acquisition, review and analysis of our seismic data, if any;

·	availability of sufficient capital resources to us and any other participants for the drilling of the prospects;

·	approval of the prospects by other participants after additional data has been compiled;

·	economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability and prices of drilling rigs and crews; and

·	availability of leases, license options, farm-outs, other rights to explore and permits on reasonable terms for the prospects.

Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame, or at all. In addition, our drilling schedule may vary from our expectations because of future uncertainties, rig availability and access to our drilling locations utilizing available roads. As of December 31, 2007, we own three drilling rigs, two of which are drilling on our properties, and have additional contract commitments on another three drilling rigs. See contractual obligations in Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operation.

We may incur losses as a result of title deficiencies. We acquire from third parties, or directly from the mineral fee owners, working and revenue interests in the oil and natural gas leaseholds and estates upon which we will perform our exploration activities. The existence of a material title deficiency can reduce the value or render a property worthless thus adversely affecting the results of our operations and financial condition. Title insurance covering mineral leaseholds is not always available and when available is not always obtained. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and/or undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. In cases involving title problems, the amount paid for affected oil and natural gas leases or estates can be generally lost, and a prospect can become undrillable.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information required by Item 2 Properties is included under Item 1 Business.

Item 3. Legal Proceedings

While we are, from time to time, a party to certain lawsuits in the ordinary course of business, we do not believe any of such existing lawsuits will have a material adverse effect on our operations, financial condition, or liquidity.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the most recently ended fiscal quarter.

Executive Officers. Listed below are the names, ages (as of December 31, 2007) and positions of our executive officers and their business experience during at least the past five years. All our officers are reappointed in May of each year at an organizational meeting of the Board of Directors. There are no family relationships between any of the executive officers and members of the Board of Directors.

ROBERT F. HEINEMANN, 54, has been President and Chief Executive Officer since June 2004. Mr. Heinemann was Chairman of the Board and interim President and Chief Executive Officer from April 2004 to June 2004. From December 2003 to March 2004, Mr. Heinemann acted as the director designated to serve as the presiding director at executive sessions of the Board in the absences of the Chairman and as liaison between the independent directors and the CEO. Mr. Heinemann joined the Board in March of 2003. From 2000 until 2002, Mr. Heinemann served as the Senior Vice President and Chief Technology Officer of Halliburton Company and as the Chairman of the Halliburton Technology Advisory Committee. He was previously with Mobil Oil Corporation (Mobil) where he served in a variety of positions for Mobil and its various affiliate companies in the energy and technical fields from 1981 to 1999, with his last responsibilities as Vice President of Mobil Technology Company and General Manager of the Mobil Exploration and Producing Technical Center.

Berry Petroleum Company - 2007 Form 10-K

RALPH J. GOEHRING, 51, has been Executive Vice President and Chief Financial Officer since June 2004. Mr. Goehring served as Senior Vice President from April 1997 to June 2004, has been Chief Financial Officer since March 1992, and was Manager of Taxation from September 1987 until March 1992. In December 2007, Mr. Goehring announced his intention to retire from his role and duties of Chief Financial Officer in mid 2008. Mr. Goehring’s employment with Berry is expected to conclude by the end of 2008. Mr. Goehring is also an Assistant Secretary.

MICHAEL DUGINSKI, 41, has been Executive Vice President and Chief Operating Officer since September 2007. Mr. Duginski served as Executive Vice President of Corporate Development and California from October 2005 to August 2007; he acted as Senior Vice President of Corporate Development from June 2004 through October 2005 and as Vice President of Corporate Development from February 2002 through June 2004. Mr. Duginski, a mechanical engineer, was previously employed by Texaco, Inc. from 1988 to 2002 where his positions included Director of New Business Development, Production Manager and Gas and Power Operations Manager. Mr. Duginski is also an Assistant Secretary.

DAN ANDERSON, 45, has been Vice President of Rocky Mountains Production since October 2005. Mr. Anderson was Rocky Mountains Manager of Engineering from August 2003 through October 2005. Previously, Mr. Anderson served as a Senior Staff Petroleum Engineer with Williams Production RMT from August 2001 through August 2003. He also was a Senior Staff Engineer with Barrett Resources from October 2000 through August 2001.

WALTER B. AYERS, 64, has acted as Vice President of Human Resources since May 2006. Mr. Ayers was previously a private consultant to the energy industry from January 2002 until his employment with us. Mr. Ayers served as a Manager of Human Resources for Mobil Oil Corporation from June 1965 until December 2000.

GEORGE T. CRAWFORD, 47, has been Vice President of California Production since October 2005. Mr. Crawford served as Vice President of Production from December 2000 through October 2005 and as Manager of Production from January 1999 to December 2000. Mr. Crawford, a petroleum engineer, previously served as the Production Engineering Supervisor for Atlantic Richfield Corp. (ARCO) from 1989 to 1998, with numerous engineering and operational assignments, including Production Engineering Supervisor, Planning and Evaluation Consultant and Operations Superintendent.

BRUCE S. KELSO, 52, has been Vice President of Rocky Mountains Exploration since October 2005. Mr. Kelso served as Rocky Mountains Exploration Manager from August 2003 through October 2005. Mr. Kelso, a petroleum geologist, previously acted as a Senior Staff Geologist assigned to Rocky Mountain assets with Williams Production RMT, from January 2002 through August 2003. He previously held the position of Vice President of Exploration and Development at Redstone Resources, Inc. from 2000 to 2001.

SHAWN M. CANADAY, 32, has held the position of Controller since March 2007. Mr. Canaday served as Treasurer from December 2004 to February 2007 and as Senior Financial Analyst from November 2003 until December 2004. Mr. Canaday has worked in the oil and gas industry since 1998 in various finance functions at Chevron and in public accounting. Mr. Canaday is also an Assistant Secretary.

KENNETH A. OLSON, 52, has been Corporate Secretary since December 1985 and was Treasurer from August 1988 until December 2004.

STEVEN B. WILSON, 44, has been Treasurer since March 2007. Mr. Wilson was Controller or Assistant Controller from November 2003 to February 2007. Before joining us in November 2003, he served as the vice president of finance and administration for Accela, Inc., a software development company, for three years. Prior to that, he held finance functions in select companies and in public accounting. Mr. Wilson is also an Assistant Secretary.

PART II

Item 5. Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock," are each entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $.50 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder.

In November 1999, we adopted a Shareholder Rights Agreement and declared a dividend distribution of one such Right for each outstanding share of Capital Stock on December 8, 1999. Each share of Capital Stock issued after December 8, 1999 includes one Right. The Rights expire on December 8, 2009. See Note 7 to the financial statements.

Berry Petroleum Company - 2007 Form 10-K

Our Class A Common Stock is listed on the New York Stock Exchange (NYSE) under the symbol BRY. The Class B Stock is not publicly traded. The market data and dividends for 2007 and 2006 are shown below:

	2007						2006
	Price Range				Dividends		Price Range				Dividends
	High		Low		Per Share		High		Low		Per Share
First Quarter	$	31.54	$	27.63	$	.075	$	39.98	$	28.60	$	.065
Second Quarter		41.08		30.41		.075		39.00		27.27		.065
Third Quarter		41.06		31.03		.075		35.77		26.07		.095
Fourth Quarter		49.39		39.30		.075		33.69		25.71		.075
Total Dividends Paid					$	.300					$	.300

		February 1, 2008			December 31, 2007			December 31, 2006
Berry’s Common Stock closing price per share as reported on NYSE Composite Transaction Reporting System		$	39.18		$	44.45		$	31.01

The number of holders of record of our Common Stock was 547 as of February 1, 2008. There was one Class B Shareholder of record as of February 1, 2008.

Dividends. Our regular annual dividend is currently $.30 per share, payable quarterly in March, June, September and December. We paid a special dividend of $.02 per share on September 29, 2006 and increased our regular quarterly dividend by 15%, from $.065 to $.075 per share beginning with the September 2006 dividend.

Since our formation in 1985 through December 31, 2007, we have paid dividends on our Common Stock for 73 consecutive quarters and previous to that for eight consecutive semi-annual periods. We intend to continue the payment of dividends, although future dividend payments will depend upon our level of earnings, operating cash flow, capital commitments, financial covenants and other relevant factors. Dividend payments are limited by covenants in our 1) credit facility to the greater of $20 million or 75% of net income, and 2) bond indenture of up to $20 million annually irrespective of our coverage ratio or net income if we have exhausted our restricted payments basket, and up to $10 million in the event we are in a non-payment default.

Equity Compensation Plan Information.

	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
Plan category	and rights	warrants and rights	issuance
Equity compensation plans approved by security holders	3,034,189	$ 24.33	988,798

Equity compensation plans not approved by security holders	none	none	none

Issuer Purchases of Equity Securities.

In June 2005, we announced that our Board of Directors authorized a share repurchase program for up to an aggregate of $50 million of our outstanding Class A Common Stock. From June 2005 through December 31, 2007, we repurchased 818,000 shares in the open market for approximately $25 million. Our repurchase plan expired and no shares were repurchased in 2007.

Berry Petroleum Company - 2007 Form 10-K

Performance Graph

This graph shall not be deemed “filed” for purposes of Section 18 of the Securities and Exchange Act of 1934 (the “Exchange Act”) or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933 or the Exchange Act, regardless of any general incorporation language in such filing.

Total returns assume $100 invested on December 31, 2002 in shares of Berry Petroleum Company, the Russell 2000, the Standard & Poors 500 Index (S&P 500) and a Peer Group, assuming reinvestment of dividends for each measurement period. The information shown is historical and is not necessarily indicative of future performance. The 15 companies which make up the Peer Group are as follows: Bill Barrett Corp., Cabot Oil & Gas Corp., Cimarex Energy Co., Comstock Resources Inc., Denbury Resources Inc., Encore Acquisition Co., Forest Oil Corp., Petrohawk Energy Corp., Plains Exploration & Production Co., Quicksilver Resources Inc., Range Resources Corp., St. Mary Land & Exploration Co., Stone Energy Corp., Swift Energy Co. and Whiting Petroleum Corp.




	12/02	12/03	12/04	12/05	12/06	12/07

Berry Petroleum Company	100.00	122.01	292.22	353.92	387.58	560.32
S&P 500	100.00	128.68	142.69	149.70	173.34	182.87
Russell 2000	100.00	147.25	174.24	182.18	215.64	212.26
Peer Group	100.00	133.23	201.44	299.34	302.82	439.43

Berry Petroleum Company - 2007 Form 10-K

Item 6. Selected Financial Data

The following table sets forth certain financial information and is qualified in its entirety by reference to the historical financial statements and notes thereto included in Item 8 Financial Statements and Supplementary Data. The Statements of Income and Balance Sheet data included in this table for each of the five years in the period ended December 31, 2007 were derived from the audited financial statements and the accompanying notes to those financial statements (in thousands, except per share, per BOE and % data).

	2007			2006			2005			2004			2003
Audited Financial Information
Sales of oil and gas	$	467,400		$	430,497		$	349,691		$	226,876		$	135,848
Sales of electricity		55,619			52,932			55,230			47,644			44,200
Gain on sale of assets		54,173			97			130			410			570
Operating costs - oil and gas production		141,218			117,624			99,066			73,838			57,830
Operating costs - electricity generation		45,980			48,281			55,086			46,191			42,351
Production taxes		17,215			14,674			11,506			6,431			3,097
General and administrative expenses (G&A)		40,210			36,841			21,396			22,504			14,495
Depreciation, depletion & amortization (DD&A)
Oil and gas production		93,691			67,668			38,150			29,752			17,258
Electricity generation		3,568			3,343			3,260			3,490			3,256
Net income		129,928			107,943			112,356			69,187			32,363
Basic net income per share		2.95			2.46			2.55			1.58			.74
Diluted net income per share	$	2.89		$	2.41		$	2.50		$	1.54		$	.73
Weighted average number of shares outstanding (basic)		44,075			43,948			44,082			43,788			43,544
Weighted average number of shares outstanding (diluted)		44,906			44,774			44,980			44,940			44,062
Working capital (deficit)	$	(110,350	)	$	(116,594	)	$	(54,757	)	$	(3,840	)	$	(3,540	)
Total assets		1,452,106			1,198,997			635,051			412,104			340,377
Long-term debt		445,000			390,000			75,000			28,000			50,000
Shareholders' equity		459,974			427,700			334,210			263,086			197,338
Cash dividends per share		.30			.30			.30			.26			.24
Cash flow from operations		248,279			243,229			187,780			124,613			64,825
Exploration and development of oil and gas properties		281,702			265,110			118,718			71,556			41,061
Property/facility acquisitions		56,247			257,840			112,249			2,845			48,579
Additions to vehicles, drilling rigs and other fixed assets	$	3,565		$	21,306		$	11,762		$	669		$	494
Unaudited Operating Data
Oil and gas producing operations (per BOE):
Average sales price before hedging	$	49.72		$	48.38		$	47.01		$	33.64		$	24.48
Average sales price after hedging		47.50			46.67			41.62			30.32			22.52
Average operating costs - oil and gas production		14.38			12.69			11.79			10.09			9.57
Production taxes		1.75			1.58			1.37			.86			.51
G&A		4.09			3.98			2.55			2.99			2.40
DD&A - oil and gas production	$	9.54		$	7.30		$	4.54		$	3.96		$	2.86
Production (MBOE)		9,819			9,270			8,401			7,517			6,040
Production (MMWh)		779			757			741			776			767
Total proved reserves (BOE)		169,179			150,262			126,285			109,836			109,920
Standardized measure (1)	$	2,419,506		$	1,182,268		$	1,251,380		$	686,748		$	528,220
Year end average BOE price for PV10 purposes	$	66.27		$	41.23		$	48.21		$	29.87		$	25.89
Return on average shareholders' equity		29.18	%		28.33	%		37.63	%		31.06	%		17.50	%
Return on average capital employed		16.01	%		18.21	%		32.74	%		26.29	%		15.44	%

(1) See Supplemental Information About Oil & Gas Producing Activities.

Berry Petroleum Company - 2007 Form 10-K

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation

Overview. We seek to increase shareholder value through consistent growth in our production and reserves, both through the drill bit and acquisitions. We strive to operate our properties in an efficient manner to maximize the cash flow and earnings of our assets. The strategies to accomplish these goals include:

·	Developing our existing resource base

·	Acquiring additional assets with significant growth potential

·	Utilizing joint ventures with respected partners to enter new basins

·	Accumulating significant acreage positions near our producing operations

·	Investing our capital in a disciplined manner and maintaining a strong financial position

Notable Items in 2007.

·	Achieved record production which averaged 26,902 BOE/D, up 6% from 2006

·	Achieved record cash from operating activities of $248 million, up 2% from 2006

·	Achieved record net income of $130 million, up 20% from 2006

·	Added 35.4 million BOE of proved reserves before production ending 2007 at a record 169.2 million BOE

·	Achieved a reserve replacement rate of 293%

·	Expended $341 million of capital expenditures, of which $285 million was for development and $56 million for acquisitions

·	Modified steam injection and new well fracturing techniques at N. Midway diatomite, increasing production from existing wells and decreasing the steam oil ratio to six to one

·	Started drilling the next 50 well expansion on our N. Midway diatomite asset

·	Accomplished a 15 day drilling record on a mesa location and significantly reduced the overall number of days and drilling costs in Piceance

·	Completed 47 gross (27 net) Piceance basin operated wells which increased net production to average 10,200 MMcf/D for the full year and 14,600 MMcf/D in the fourth quarter

·	Achieved a record production average of 2,400 Bbl/D at Poso Creek by drilling an additional 70 wells

·	Drilled 18 horizontal wells at deeper depths at S. Midway to reduce the natural decline and identify additional resource opportunities

·	Entered into a long-term crude oil sales contract for our Uinta basin, Utah production

·	Entered into a long-term firm transportation contract on the Rockies Express pipeline for our Colorado natural gas production

·	Sold Montalvo, California assets with proceeds of approximately $61 million

Notable Items and Expectations for 2008.

·	Targeting over 10% net average production growth to achieve between 29,500 and 30,500 BOE/D

·	Targeting an increase in 2008 year end proved reserves to between 180 to 190 MMBOE

·	Expecting a 2008 capital expenditure program of $295 million to be funded wholly from operating cash flow

·	Drilling approximately 120 wells at N. Midway diatomite and targeting production to increase to 2,200 Bbl/D average for the year for an increase of 122%

·	Executing a 60 gross (35 net) well drilling program at the Piceance and expecting production to average 21.6 MMcf/D in 2008

·	Drilling 28 wells at Poso Creek targeting an average annual production of 3,270 Bbl/D with an average year end exit rate of over 3,500 Bbl/D

·	Continuing our appraisal of the Lake Canyon resource potential in the Uinta basin by drilling four Green River wells, three exploratory wells, and participate in deep Wasatch wells

Overview of the Fourth Quarter of 2007. We achieved record average production of 28,023 BOE/D in the fourth quarter of 2007, up 4% from an average of 26,873 BOE/D in the third quarter of 2007. We had net income of $32.3 million, or $.71 per diluted share and net cash from operations was $63.7 million. In December, we entered into a second long-term (ten year) firm transportation contract for our Colorado natural gas production. This contract is for 25,000 MMBtu/D on the REX pipeline and provides us assurance of significant deliverability of our increasing gas production in the Piceance basin. We recognized a $2.9 million pretax gain on the sale of stock (see Note 17 to the financial statements) and we had a pretax impairment charge of $3.3 million associated with our Coyote Flats, Utah asset.

Berry Petroleum Company - 2007 Form 10-K

View to 2008. Our challenge for 2008 is to grow our business through improved execution in a rapidly changing price and high cost environment while adding significant reserves through the drill bit. We have an extensive inventory of development drilling in several basins, and expect our program to be the most influenced by production and reserve growth on our diatomite asset and our properties in the Piceance basin. Our goal is to achieve at least a 10% increase in production and a 10% increase in reserves at a very competitive finding and development cost. Our $295 million capital program is designed to achieve these targets while being funded entirely out of our cash flow from operations. We expect no increase in debt in 2008 unless we are successful in acquiring assets and/or WTI pricing averages below $75 per barrel. We will continue to evaluate acquisition opportunities that fit our growth strategy. Our previously announced plans to proceed with a master limited partnership for certain of our assets is currently on hold due to the unfavorable capital market conditions. We will continue to monitor the economic conditions relevant to a successful offering.

Capital expenditures. Our capital expenditures for 2007 totaled $341 million consisting of $285 million for development and other assets and $56 million for acquisitions. We also capitalized $18 million of interest. We funded these items from $248 million of operating cash flow, $72 million from asset sale proceeds and the balance from additional borrowings. This compares to our total capital expenditures in 2006 of $544 million, which consisted of $258 million of acquisitions, $286 million in development and other assets. Also, we capitalized $9 million of interest in 2006.

Excluding the acquisition of new properties, in 2008 we have a developmental capital program of approximately $295 million which we expect to fund wholly out of operating cash flow and based on WTI pricing to average over $75 per barrel. We are proceeding with this program, but may revise our plans due to lower commodity price expectations, equipment availability, permitting or other factors.

Our 2008 capital program allows us to continue high activity levels and as a result, we are targeting 2008 production to average between 29,500 BOE/D to 30,500 BOE/D. In 2008, we expect production to be approximately 60% heavy oil, 10% light oil and 30% natural gas. We have secured the necessary equipment and are currently meeting permit requirements to achieve the 2008 program.

Development, Exploitation and Exploration Activity. We drilled 442 gross (339 net) wells during 2007, realizing a gross success rate of 98 percent. As of December 31, 2007, we have four rigs drilling on our properties under long-term contracts and have one additional rig that began operating in early 2008.

Drilling Activity. The following table sets forth certain information regarding drilling activities for the year ended December 31, 2007:

Gross Wells