Edgar Filing: BERRY PETROLEUM CO

form10k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2008

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)

1999 Broadway

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

Registrant's telephone number, including area code:

(303) 999- 4400

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, $0.01 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 £ NO T

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 £ NO T

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 T NO £

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. £

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 filerT

Accelerated filer£

Non-accelerated filer£

Smaller reporting company£

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

As of June 30, 2008, the aggregate market value of the voting and non-voting common stock held by non-affiliates was $2,173,457,341. As of February 2, 2009, the registrant had 42,782,521 shares of Class A Common Stock outstanding. The registrant also had 1,797,784 shares of Class B Stock outstanding on February 2, 2009 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

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	15
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	23
	Executive Officers	23

PART II

Item 5.	Market for the Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	27
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 8.	Financial Statements and Supplementary Data	48
	Balance Sheets	50
	Statements of Income	51
	Statements of Shareholders' Equity	52
	Statements of Cash Flows	53
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	77
Item 9A.	Controls and Procedures	77
Item 9B.	Other Information	78

PART III

Item 10.	Directors and Executive Officers and Corporate Governance	78
Item 11.	Executive Compensation	78
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	79
Item 13.	Certain Relationships and Related Transactions, and Director Independence	79
Item 14.	Principal Accounting Fees and Services	79

PART IV

Item 15.	Exhibits, Financial Statement Schedules	80

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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. In 2008, we purchased and began operating properties in East Texas (E. Texas). Also in 2008, we relocated our corporate headquarters to Denver, Colorado and we have regional offices in Bakersfield, California and Plano, Texas. Information contained in this report on Form 10-K reflects our business during the year ended December 31, 2008 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, hedging summaries, 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. Information on our website is not incorporated into this report. 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 the value of our business 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 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, and optimization technologies, as applicable. We also have large potential hydrocarbon resources in place in the San Joaquin Valley, California (diatomite); Piceance, Colorado; Uinta, Utah (Lake Canyon); and Cotton Valley Trend in E. Texas. We have a proven track record of developing reserves and establishing new businesses in the Rocky Mountain and E. Texas regions.

Investing our capital in a disciplined manner and maintaining a strong financial position. 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 will allow us to capitalize on investment opportunities in all commodity cycles. Our capital programs are developed to be fully funded through internally generated cash flows while our acquisitions have been primarily funded through debt. We hedge a significant portion of our production and utilize long-term sales contracts whenever possible to maintain a strong financial position and provide the cash flow necessary for the development of our assets.

Acquiring additional assets with significant growth potential. We will continue to evaluate oil and gas properties with proved reserves, probable reserves and/or acreage positions that we believe contain substantial hydrocarbons which can be developed at reasonable costs. In July 2008 we completed the acquisition of natural gas producing properties in E. Texas for approximately $650 million. We will continue to review asset acquisitions that meet our economic criteria with a primary focus on large repeatable development potential in these regions.

Accumulating significant acreage positions near our producing operations. We have been successful in adding significant acreage positions in our producing areas. This strategy allows us to leverage our operating and technical expertise within the area and build on established core operations.

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Business strengths.

Balanced high quality asset portfolio with a long reserve life. Since 2002, we have grown our asset base and diversified our California heavy oil through a number of acquisitions in the Rocky Mountain and East Texas regions that have significant growth potential. Our diverse asset base provides us with the flexibility to reallocate capital among our assets depending on fluctuations in natural gas and oil prices as well as area economics. Our production based asset teams are focused around S.Midway-Sunset, Southern California and DJ assets. Our resource based asset teams are focused around diatomite, Piceance, Uinta and our newly acquired E. Texas assets. Our base of legacy California assets provides us with a steady stream of cash flow to fund our significant drilling inventory and the appraisal of our prospects. Our wells are generally characterized by long production lives and predictable performance.

Low-risk multi-year drilling inventory in established resource plays. Most of our drilling locations are located in proven resource plays that possess low geologic risk leading to predictable drilling results. Our historical drilling success rate for the three years ended December 31, 2008 has averaged 98%.

Experienced management and operational teams. Our core team of technical staff and operating managers have broad industry experience, including experience in heavy oil thermal recovery operations and 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.

Track record of efficient proved reserve and production growth. For the three years ended December 31, 2008, our proved reserves and production increased at an annualized compounded rate of 25% and 12%, respectively. We apply our operational expertise to improve the efficiency and profitability of our drilling projects. For example, in the Piceance we have decreased our well drilling time from 40 days in 2006 to under 10 days in 2008, while at the same time increasing our initial production rates from 1,250 Mcfe/d to 1,350 Mcfe/d. We believe we can continue to deliver strong and efficient growth through the drill bit by exploiting our drilling inventory. We also plan to complement this drill bit growth through selective and focused acquisitions.

Operational control and financial flexibility. We exercise operating control over approximately 99% of our proved reserve base. We generally prefer to retain operating control over our properties, allowing us to more effectively control operating costs, timing of development activities and technological enhancements, marketing of production, and 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 of our capital budget. We finance our drilling budget primarily through our internally generated operating cash flows.

Long Lived Proved Reserves. 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, 2008) of approximately 19 years as compared to 16.5 years at year end 2007. Our estimated proved reserves as of December 31, 2008 were 246 million BOE, of which 45% are heavy crude oil, 6% light crude oil and 49% natural gas. We have a geographically diverse asset base with 45% of our proved reserves located in California, 35% in the Rocky Mountains and 20% in East Texas. Of our proved reserves 55% were proved developed, while proved undeveloped reserves make up 45%of our proved total. The projected future capital to develop these proved undeveloped reserves is $950 million at an estimated cost of approximately $8.55 per BOE. Approximately 61% of the capital to develop these reserves is expected to be expended in the next five years.

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We have organized our operations into seven 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, DJ and E. Texas. The following table sets forth the estimated quantities of proved reserves and production attributable to our asset teams as of December 31, 2008.

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		8,798		28	%		52.7		22	%	$	278		34	%
UT	Uinta	Light oil/Natural gas		6,142		19			23.3		9			136		17
CA	S. Cal	Heavy oil		5,117		16			17.7		7			173		21
CO	Piceance	Natural gas		3,511		11			41.8		17			53		6
CO	DJ	Natural gas		3,295		10			21.5		9			49		6
CA	N. Midway	Heavy oil		2,714		9			38.9		16			91		11
TX	E. Texas	Natural gas		2,384		7			50.0		20			40		5
	Other	Heavy oil/Natural gas		7		-			-		-			-		-
Totals				31,968		100	%		245.9		100	%	$	820		100	%

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, 2008. D&M is an independent oil and gas consulting firm. 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, 2008. 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 Operations.

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 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. In E. Texas, natural gas produced from the Darco and Oakes properties is transported intra-state on the Enbridge system to various market points.

Crude Oil and Natural Gas Marketing.

Economy. Global and regional demand for crude oil and natural gas declined in the latter part of 2008 as part of the overall economic recession. Oil is a globally priced commodity and is priced according to the supply and demand of crude oil and its products. The range of NYMEX light sweet crude prices for 2008, based upon settlements, was a low of $33.87 and a high of $145.29.

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	2008		2007		2006
Average NYMEX settlement price for WTI	$	99.75	$	72.41	$	66.25
Average posted price for:
Utah 40 degree API black wax (light) crude oil		84.99		59.28		56.34
California 13 degree API heavy crude oil		86.51		61.64		54.38
Average crude price differential between WTI and:
Utah light 40 degree API black wax (light) crude oil		14.76		13.13		9.91
California 13 degree API heavy crude oil		13.24		10.77		11.87

The above posting prices and differentials do not necessarily reflect the amounts paid or received by us due to the contracts discussed below. In California the differential on December 31, 2008 was $14.05 and ranged from a low of $12.31 to a high of $14.96 per barrel during the year. On December 31, 2008 the differential was $16.25 and ranged from a low of $13.75 to a high of $16.25 per barrel during the year.

Oil Contracts. We market our crude oil production to competing buyers which may be independent or major oil refiners or third party marketers.

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 crude oil sales contract with Big West of California (BWOC), 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.

In December 2008, Flying J, Inc., and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary BWOC filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Also in December 2008, BWOC informed the Company that it was unable to receive the Company’s production. We have entered into various short-term agreements with other companies to sell our California oil production. Pricing and volumes under these agreements vary with prices ranging from just above the posted price for San Joaquin heavy oil to the posted price less a discount. Beginning January 2009, our California crude oil daily production was, on average, near levels achieved prior to BWOC’s Chapter 11 filing. BWOC is evaluating several options, including a sale of the Bakersfield, California refinery. We recorded $38.5 million of bad debt expense in 2008 for the bankruptcy of BWOC. Of the $38.5 million due from BWOC, $12.4 million represents December crude oil sales by the Company and represents an administrative claim under the bankruptcy proceedings and $26.1 million represents November crude oil sales which would have the same priority as other general unsecured claims. BWOC will also be liable to us for damages under this contract for any amounts received by us under our short-term contracts which are less than what we would have otherwise received from BWOC had they been able to accept our production. We have guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, in the event that our claim is not fully collectible from BWOC. While we believe that we may recover some or all of the amounts due from BWOC, the data received from the bankruptcy proceedings to date has not provided us with adequate data from which to make a conclusion that any amounts will be collected nor as to whether BWOC will assume or reject our contract.

Utah - On February 27, 2007, we entered into a multi-staged crude oil sales contract through June 30, 2013 with a refiner for the purchase of our Uinta light crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D on July 1, 2007. After partial completion of its refinery expansion in Salt Lake City in March 2008, the refiner increased its total purchase volumes to 5,000 Bbl/D. Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI, and ranges between $10 and $15 at WTI prices between $40 and $60. While the contractual differentials under this contract may be less favorable at times than the posted differential, demand for the Company’s 40 degree black wax (light) crude oil can vary seasonally and this contract provides a stable outlet for the Company’s crude oil.

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Natural Gas Marketing. We market our produced natural gas from Colorado, Utah and Texas. 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 Rocky Mountain natural gas production is tied to the Panhandle Eastern Pipeline (PEPL) index and the remaining volume to the Colorado Interstate Gas (CIG) Index. E. Texas gas is priced using a formula containing the Houston Ship Channel, Texas Eastern-East Texas, and NGPL TX-OK indices.

	2008		2007		2006
Annual average closing price per MMBtu for:
NYMEX Henry Hub (HH) prompt month natural gas contract last day	$	9.03	$	6.86	$	7.23
Rocky Mountain Questar first-of-month indices (Uinta sales)		6.15		3.69		5.36
Rocky Mountain CIG first-of-month indices (DJ, WY and Piceance sales)		6.24		3.97		5.63
Mid-Continent PEPL first-of-month indices (DJ and Piceance sales)		7.08		5.99		6.02
Texas Eastern- East Texas		8.46		n/a		n/a
Average natural gas price per MMBtu differential between NYMEX HH and:
Questar		2.88		3.17		1.87
CIG		2.79		2.89		1.60
PEPL		1.95		.87		1.21
Texas Eastern- East Texas		.57		n/a		n/a

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 narrowed, as anticipated, upon the startup of the Rockies Express pipeline in early 2008. However, the differential started to widen again during the second quarter of 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 gas production. The CIG basis differential per MMBtu, based upon first-of-month values, averaged $2.81 below HH and ranged from $0.93 to $6.62 below HH in 2008. Although related to CIG, the actual price varies. Gas from Piceance traded slightly below the CIG price while Uinta gas sold for approximately $0.15 below CIG pricing. DJ gas is priced using one of two indices. During 2008, approximately two-thirds of our volumes from our DJ natural gas properties was tied to the PEPL index for pricing and the remaining volumes to CIG pricing. Beginning in 2009, we have increased firm transportation on the Cheyenne Plains Pipeline which brings our PEPL priced gas to about three-quarters of our production. 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 $1.96 below the HH index before the cost of transportation is considered. The remainder of DJ gas is sold slightly above the CIG index price. For E. Texas, the Texas Eastern - East Texas index averaged $0.58 below HH and ranged from $0.34 to $0.94 below HH in 2008.

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.

Pipeline	From	To	Quantity (Avg. MMBtu/D)			Term	December 31, 2008 demand charge per MMBtu			Remaining contractual obligation (in thousands)
Kern River Pipeline	Opal, WY	Kern County, CA		12,000		5/2003 to 4/2013	$	0.6407		$	12,160
Rockies Express Pipeline	Meeker, CO	Clarington, OH		25,000		2/2008 to 2/2018		1.1153	(1)		93,288
Rockies Express Pipeline	Meeker, CO	Clarington, OH		10,000		1/2008 to 1/2018		1.07694	(1)		36,032
Questar Pipeline	Brundage Canyon, UT	Salt Lake City, UT		2,500		9/2003 to 4/2012		0.174			529
Questar Pipeline	Brundage Canyon, UT	Salt Lake City, UT		2,859		9/2003 to 9/2012		0.174			681
Questar Pipeline	Brundage Canyon, UT	Goshen, UT		5,000		9/2003 to 10/2022		0.257			6,488
KMIGT	Yuma County, CO	Grant, KS		2,500		1/2005 to 10/2013		0.227			1,001
Cheyenne Plains Gas Pipeline	Yuma County, CO	Kiowa County, KS		12,000	(2)	1/2007 to 12/2016		0.34			14,892
Total				71,859						$	165,071

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

(2)	Volume increase to 15,000 MMBtu/D starting January 1, 2009 for remaining life of contract.

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Berry has signed a binding precedent agreement with El Paso Corporation for an average of 35,000 MMBtu/D of firm transportation on the proposed Ruby Pipeline from Opal, WY to Malin, OR. While it is not certain that this new line will be constructed, the expectation is that the project will proceed and be in service in 2011. As part of this agreement and in order to access the Ruby pipeline, we also secured firm transportation from Piceance to Opal.

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

Hedging. See Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 18 to the financial statements.

Concentration of Credit Risks. See Note 5 to the financial statements.

Steaming Operations.

Cogeneration Steam Supply. As of December 31, 2008, approximately 45% of our proved reserves, or 109 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.

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, 2008 is as follows:

Steam generation capacity of conventional boilers			87,070
Steam generation capacity of cogeneration plants			42,789
Additional steam purchased under contract with a third party			2,100
Total steam capacity			131,959

The average volume of steam injected for the years ended December 31, 2008 and 2007 was 99,908 BSPD and 87,990 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 2008, we added additional steam capacity for our development projects at N. Midway, primarily diatomite, and Poso Creek to achieve maximum production from these properties. In 2009, 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 2008 to achieve our goal of increasing heavy oil production. Approximately 75% of the volume of natural gas purchased to generate steam and electricity is based upon California 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 25% of supply volume is purchased in the Rockies 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.

	2008		2007		2006
Average SoCal Border Monthly Index Price per MMBtu	$	7.92	$	6.38	$	6.29
Average Rocky Mountain NWPL Monthly Index Price per MMBtu		6.25		3.95		5.66
Average PG&E Citygate Monthly Index Price per MMBtu		8.63		6.86		6.70

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Prior to 2005, we were a net purchaser of natural gas, and thus our net income was negatively impacted when natural gas prices increased. In 2005, our production and consumption became balanced due to our eastern Colorado (DJ) gas acquisition. Subsequent to 2005, we have been a net seller of gas and benefit operationally when gas prices increase. However, our consumption of natural gas provides a form of natural hedge as our revenues received from natural gas sales are partially offset by operating cost increases in California when natural gas prices rise. The following table shows our average 2008 and estimated average 2009 amount of production in excess of consumption and hedged volumes (in average MMBtu/D):

	2008			Estimated 2009
Approximate Natural gas volumes produced in operations		69,800			75,000
Approximate Natural gas consumed:
Cogeneration operations		26,700			26,900
Conventional boilers (1)		20,400			22,600
Total natural gas volumes consumed in operations		47,100			49,500
Less: Our estimate of approximate natural gas volumes consumed to produce electricity (2)		(20,300	)		(20,500	)
Total approximate natural gas volumes consumed to produce steam		26,800			29,000

Natural gas volumes hedged		18,250			20,400

Amount of natural gas volumes produced in excess of volumes consumed to produce steam and volumes hedged		24,750			25,600

(1)	In 2009, 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 the historical allocation of fuel costs to electricity.

Electricity.

Generation. The total annual average electrical generation of our three cogeneration facilities is approximately 83 MW, of which we consume approximately 8 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 the way SRAC energy prices will be determined for existing and new Standard Offer (SO) contracts and revises the capacity prices paid under current SO1 contracts. At this time, there is no certainty as to the final formula of the SRAC Decision nor the effective date of the SRAC Decision nor whether its terms will be applied retroactively and if so, for what period.

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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, as they did in the SRAC decision. 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. However, given the proceedings described above on the SRAC Decision, it is possible that some resolution of this element of retroactivity may be resolved concurrently, although there is no pending ruling. Our SO2 contract for the Placerita Unit 1 Facility is scheduled to terminate on March 31, 2009 and we are negotiating an interim contract that will become effective on April 1, 2009. The payment provisions of this interim contract are expected to be similar to the payment provisions ordered in the SRAC Decision. The Company intends to enter into new standard contracts with Edison and PG&E for all three facilities as soon as the ongoing challenges are resolved and the CPUC has approved the terms of the new standard contracts.

Based on the current pricing mechanism for our electricity under the contracts, we expect that our electricity revenues will be in the $40 million to $60 million range for 2009.

At the time of the California energy crisis in 2000 and 2001, we had two electricity sales agreements with Edison and two with PG&E. Under these contracts, we were paid under an SRAC formula that priced gas off of Topock. On March 27, 2001, the CPUC issued a decision making certain changes in the SRAC formula applicable at that time, the most significant of which was changing the pricing point to Malin, which resulted in a significant reduction in the price we were to be paid by Edison and PG&E. We thereafter entered into a settlement agreement with Edison by which Edison nevertheless agreed to pay using Topock from March 27th forward. The CPUC approved the settlement. However, 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 were identified as an affected QF by PG&E but not by Edison. The ALJ also invited interested parties to propose solutions to the pending remand dispute. As no resolution was proposed, on January 26, 2009, the ALJ issued a ruling in this matter in which he proposed a settlement in lieu of continued litigation over this issue. A briefing schedule has been established as to his proposed settlement and out of that briefing will come some determination of whether litigation will continue.

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, 2008, we had 303 full-time employees, up from 263 full-time employees on December 31, 2007.

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Capital Expenditures Summary (Excluding Acquisitions).

The following is a summary of the developmental capital expenditures incurred during 2008 and 2007 and budgeted capital expenditures for 2009 (in thousands):

	2009		2008		2007
	(Budgeted) (1)

S. Midway Asset Team
New wells and workovers	$	4,600	$	32,508	$	13,174
Facilities - oil & gas		2,800		652		7,576
Facilities - cogeneration		-		828		-
General		-		-		150
		7,400		33,988		20,900
N. Midway Asset Team
New wells and workovers		12,400		32,477		12,949
Facilities - oil & gas		22,400		33,991		17,125
General		2,100				634
		36,900		66,468		30,708
S. Cal Asset Team
New wells and workovers		-		12,215		16,627
Facilities - oil & gas		3,500		9,356		17,549
Facilities - cogeneration		500		2,889		604
General		1,150		-		483
		5,150		24,460		35,263
Uinta Asset Team
New wells and workovers		-		56,491		52,700
Facilities		1,900		2,369		3,151
General		-		-		602
		1,900		58,860		56,453
Piceance Asset Team
New wells and workovers		5,150		123,982		103,921
Facilities		6,900		4,517		15,298
General		50		1,195		164
		12,100		129,694		119,383
DJ Asset Team
New wells and workovers		-		14,518		14,017
Facilities		500		2,600		2,736
General		600		190		1,519
		1,100		17,308		18,272

E. Texas Asset Team
New wells and workovers		34,200		65,412		-
Facilities		700		335		-
		34,900		65,747		-

Other Fixed Assets		550		1,076		4,288

TOTAL	$	100,000	$	397,601	$	285,267

(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.

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

	2008		2007		2006
Net annual production: (1)
Oil (Mbbl)		7,441		7,210		7,182
Gas (MMcf)		25,559		15,657		12,526
Total equivalent barrels (MBOE) (2)		11,700		9,819		9,270

Average sales price:
Oil (per Bbl) before hedging	$	86.90	$	57.85	$	52.92
Oil (per Bbl) after hedging		70.01		53.24		50.55
Gas (per Mcf) before hedging		6.87		4.53		5.48
Gas (per Mcf) after hedging		7.01		5.27		5.57
Per BOE before hedging		70.22		49.72		48.38
Per BOE after hedging		59.81		47.50		46.67
Average operating cost - oil and gas production (per BOE)		17.10		14.38		12.69

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, 2008, our properties accounted for the following developed and undeveloped acres:

	Developed Acres				Undeveloped Acres				Total
	Gross		Net		Gross		Net		Gross		Net
California		5,322		5,322		653		653		5,975		5,975
Colorado		89,110		70,575		105,714		59,691		194,824		130,266
Kansas		-		-		62,810		61,856		62,810		61,856
Texas		4,794		4,523		-		-		4,794		4,523
Utah (1)		39,280		36,635		183,176		77,779		222,456		114,414
Wyoming		3,520		539		1,746		276		5,266		815
Other		40		3		-		-		40		3
		142,066		117,597		354,099		200,255		496,165		317,852

(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 Ute Tribe participates.

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, 2008, we have 4,093 gross productive wells (3,316 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.

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

	2008				2007				2006
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells drilled:
Productive		3		2		5		3		7		3
Dry (1)		-		-		-		-		5		1
Development wells drilled:
Productive		443		374		411		314		532		356
Dry (1)		6		5		7		5		7		5
Total wells drilled:
Productive		446		376		416		317		539		359
Dry (1)		6		5		7		5		12		6

(1)	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.

	2008
	Gross		Net
Total productive wells drilled:
Oil		248		245
Gas		198		131

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

Company owned drilling rigs. During 2005 and 2006, we purchased three drilling rigs. Owning these rigs allowed us to successfully meet a portion of our drilling needs in Uinta and Piceance. Two of these rigs are leased to a drilling rig operator on a short-term basis and are not currently drilling on the Company's properties and one rig is idle. As the rig market and our rig requirements change, we continue to evaluate the ownership of these rigs and $4.2 million related to the disposal and impairment of certain drilling rigs and related equipment,was recorded in 2008. See Note 13 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 20 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."

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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 us, 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.

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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 the price received for our oil and gas production. 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. 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. 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

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,

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;

increase the likelihood of refinery default;

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.

Our level of indebtedness may limit our financial flexibility. As of December 31, 2008 our total debt was $1.16 billion which is comprised of $200 million outstanding on our 8.25% senior subordinated notes due 2016 and $957 million drawn under our credit facilities.

Our level of indebtedness affects our operations in several ways, including the following:

•

a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

•

we may be at a competitive disadvantage as compared to similar companies that have less debt;

•

the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

•

additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants; and

•

changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings may increase the interest rate and fees we pay on our revolving bank credit facility.

A higher level of indebtedness increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

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The borrowing base under our credit facility may be insufficient to fund our outstanding debt. The amount we are able to borrow under our senior secured credit facility is determined based on the value of our proved oil and gas reserves and is based on oil and natural gas price assumptions which vary by individual lender. Our borrowing base is subject to redetermination twice each year in April and October with the option for one additional redetermination each year. Should there be a deficiency in the amount of our borrowing base in comparison to our outstanding debt under the facility we would be required to repay any such deficiency in two equal installments, 90 and 180 days after the redetermination.

Our heavy crude in California may be less economic than lighter crude oil and natural gas. As of December 31, 2008, approximately 45% of our proved reserves, or 109 million barrels, consisted of heavy oil. Light crude oil represented 6% and natural gas represented 49% 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. Additionally, most of our crude oil in California is produced using the enhanced oil recovery process of steam injection. This process is generally more costly than primary and secondary recovery methods.

Purchasers of our crude oil and natural gas may become insolvent. We have significant concentrations of credit risk with the purchasers of our crude oil and natural gas. We have had a long-term contract to sell all of our heavy crude oil in California for approximately $8.10 below WTI, the U.S. benchmark crude oil pricing, with Big West of California (BWOC). On December 22, 2008, Flying J, Inc. and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary BWOC each filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Also in December 2008, BWOC informed the Company that it was unable to receive the Company’s production. We have entered into various currently short-term agreements with other companies to sell our California oil production. Pricing and volumes under these agreements vary with prices ranging from just above the posted price for San Joaquin heavy oil to the posted price less a discount. BWOC is evaluating several options, including a sale of the Bakersfield, California refinery. We recorded $38.5 million of bad debt expense in 2008 for the bankruptcy of BWOC. Of the $38.5 million due from BWOC, $12.4 million represents December crude oil sales by the Company and represents an administrative claim under the bankruptcy proceedings and $26.1 million represents November crude oil sales which would have the same priority as other general unsecured claims. BWOC will also be liable to us for damages under this contract. While we also have guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, the information received from the bankruptcy proceedings to date has not provided us with adequate data from which to make a conclusion that any amounts will be collected nor whether BWOC will assume or reject our agreement.

Additionally, all of our crude oil in Utah is sold under a long-term contract to a single refiner. Under the standard credit terms with our refiners, we may not know that a refiner will be unable to make payment to us until 50 days of our production has been delivered to them. If our purchasers become insolvent, we may not be able to collect any of the amounts owed to us.

We may be unable to meet our drilling obligations. We have drilling obligations in both the Piceance assets in Colorado and our Lake Canyon asset in Utah. In the Piceance basin, we must drill 91 additional wells by February 2011 to avoid penalties of $0.2 million per well and loss of related leases. In Lake Canyon, we must drill an additional 7 wells by November 2009 to avoid the loss of related leases. Our ability to meet these commitments depends on the capital resources available to us to fund our drilling activities and the commodity price environment which affects the economics of these projects.

Our financial counterparties may be unable to satisfy their obligations. We rely on financial institutions to fund their obligations under our senior secured credit facility and make payments to us under our hedging agreements. If one or more of our financial counterparties becomes insolvent, they may not be able to meet their commitment to fund future borrowings under our credit facility which would reduce our liquidity. Additionally, at current commodity prices, a significant portion of our cash flow over the next two years will come from payments from our counterparties on our commodity hedging contracts. If our counterparties are not able to make these payments, our cash flow will be reduced.

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 may not be able to accurately predict natural gas and crude oil differentials.

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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.

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 five years are uncertain and there is no assurance that we will be able to consistently meet the minimum contractual requirement. After partial completion of its refinery expansion in Salt Lake City in March 2008, the refiner increased its total purchased volumes to 5,000 Bbl/D. During the term of the contract, the minimum number of delivered barrels (“base daily volume”) is 5,000 Bbl/D. In the event that we cannot produce the necessary volume, we may need to purchase crude to meet our contract requirements. Current gross oil production from our Uinta properties is approximately 3,800 Bbl/D.

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 32% 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. All of our power contracts 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. All of our electricity sales contracts in place with the utilities are currently scheduled to terminate in 2009 and while we intend to enter into future contacts with the utilities all of the terms of such contracts are not known. Additionally legal and regulatory decisions (especially related to the pricing of electricity under the contracts such as the SRAC Decision and the pending issues as to effective dates on retroactivity), can by reducing our electricity revenues 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 15,000 MMBtu/D on the Kern River Pipeline from the Rocky Mountains to Kern County, CA, which accounts for approximately one-third 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.

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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. While we did not have any impairment charges in 2008, it is possible that declining commodity prices could prompt an impairment in the future. 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.

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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.

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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 Uinta 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 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 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 greenhouse gases (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.

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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.

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.

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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 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.

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.

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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, 2008) 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, 55, 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.

DAVID D. WOLF, 38, has been Executive Vice President and Chief Financial Officer since August 2008. Mr. Wolf was previously employed by JPMorgan from 1995 to 2008 where he served as a Managing Director in JPMorgan's Oil and Gas Group.

MICHAEL DUGINSKI, 42, 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, 46, 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, a petroleum engineer, 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. He previously held various engineering and management positions with Santa Fe Snyder Corporation and Conoco, Inc. from 1985 to 2000.

WALTER B. AYERS, 65, 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.

SHAWN M. CANADAY, 33, has held the position of Vice President and Controller since June 2008 and was Interim Chief Financial Officer from June 2008 until August 2008. Mr. Canaday served as Controller from February 2007 to June 2008, 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.

GEORGE T. CRAWFORD, 48, 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, 53, 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.

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KENNETH A. OLSON, 53, has been Corporate Secretary since December 1985 and was Treasurer from August 1988 until December 2004.

STEVEN B. WILSON, 45, 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 $0.50 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 8 to the financial statements.

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 2008 and 2007 are shown below:

	2008						2007
	Price Range				Dividends		Price Range				Dividends
	High		Low		Per Share		High		Low		Per Share
First Quarter	$	47.20	$	33.41	$	.075	$	31.54	$	27.63	$	.075
Second Quarter		62.15		45.73		.075		41.08		30.41		.075
Third Quarter		61.72		30.99		.075		41.06		31.03		.075
Fourth Quarter		37.76		6.02		.075		49.39		39.30		.075
Total Dividends Paid					$	.300					$	.300

		February 2, 2009				December 31, 2008				December 31, 2007
Berry’s Common Stock closing price per share as reported on NYSE Composite Transaction Reporting System		$	7.36			$	7.56			$	44.45

The number of holders of record of our Common Stock was 544 as of February 2, 2009. There was one Class B Shareholder of record as of February 2, 2009.

Dividends. Our regular annual dividend is currently $0.30 per share, payable quarterly in March, June, September and December. We increased our regular quarterly dividend by 15%, from $0.065 to $0.075 per share beginning with the September 2006 dividend.

Since our formation in 1985 through December 31, 2008, we have paid dividends on our Common Stock for 77 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.

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Equity Compensation Plan Information.

Plan category

Number of securities to be issued upon exercise of outstanding options, warrants and rights

Weighted average exercise price of outstanding options, warrants and rights

Number of securities remaining available for future issuance

Equity compensation plans approved by security holders

3,389,097

25.16

412,025

Equity compensation plans not approved by security holders

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, 2006 we repurchased 818,000 shares in the open market for approximately $25 million. Our repurchase plan expired in 2006 and no shares were repurchased in 2007 or 2008.

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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, 2003 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.

*$100 invested on 12/31/03 in stock & index-including reinvestment of dividends.

Fiscal year ending December 31.

	12/03	12/04	12/05	12/06	12/07	12/08

Berry Petroleum Company	100.00	239.51	290.08	317.66	459.24	79.18
S&P 500	100.00	110.88	116.33	134.70	142.10	89.53
Russell 2000	100.00	118.33	123.72	146.44	144.15	95.44
Peer Group	100.00	151.19	224.68	227.29	329.83	175.45

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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, 2008 were derived from the audited financial statements and the accompanying notes to those financial statements (in thousands, except per share, per BOE and % data).

	2008			2007			2006			2005			2004
Audited Financial Information
Sales of oil and gas	$	697,977		$	467,400		$	430,497		$	349,691		$	226,876
Sales of electricity		63,525			55,619			52,932			55,230			47,644
Gas marketing sales		35,750			-			-			-			-
Gain (loss) on sale of assets (1)		(1,297	)		54,173			97			130			410
Operating costs - oil and gas production		200,098			141,218			117,624			99,066			73,838
Operating costs - electricity generation		54,891			45,980			48,281			55,086			46,191
Gas marketing expense		32,072			-			-			-			-
Production taxes		29,898			17,215			14,674			11,506			6,431
General and administrative expenses (G&A)		55,353			40,210			36,841			21,396			22,504
Depreciation, depletion & amortization (DD&A)
Oil and gas production		138,237			93,691			67,668			38,150			29,752
Electricity generation		2,812			3,568			3,343			3,260			3,490
Net income		133,529			129,928			107,943			112,356			69,187
Basic net income per share		3.00			2.95			2.46			2.55			1.58
Diluted net income per share	$	2.94		$	2.89		$	2.41		$	2.50		$	1.54
Weighted average number of shares outstanding (basic)		44,485			44,075			43,948			44,082			43,788
Weighted average number of shares outstanding (diluted)		45,395			44,906			44,774			44,980			44,940
Working capital (deficit)	$	(71,545	)	$	(110,350	)	$	(116,594	)	$	(54,757	)	$	(3,840	)
Total assets		2,542,383			1,452,106			1,198,997			635,051			412,104
Long-term debt		1,131,800			445,000			390,000			75,000			28,000
Shareholders' equity		827,544			459,974			427,700			334,210			263,086
Cash dividends per share		.30			.30			.30			.30			.26
Cash flow from operations		409,569			238,879