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.

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.
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.

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.

		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.


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.

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

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.


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

20

-

6,500

Placerita Unit 2

SO1

Edison

Dec-09

16

4

6,500

S. Midway

Cogen 18

SO1

PG&E

Dec-09

12

4

6,700

Cogen 38

SO1

PG&E

Dec-09

37

-

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.

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.

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.

 

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."


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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