Forward Looking Statements

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

PART I

ITEM 1 — Business

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

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

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

• Developing our existing resource base. We intend to increase both production and reserves annually. We are focused on the timely and prudent development of our large resource base through developmental and step-out drilling, down-spacing, well completions, remedial work and by application of enhanced oil recovery (EOR) methods, as applicable. We have large crude oil resources in place in the San Joaquin Valley basin, California, with diatomite being our largest, and a resource play in the Uinta basin, Utah (Lake Canyon). In 2006, we invested in a large undeveloped probable natural gas reserve position in the Piceance basin in Colorado, and are planning to continue significant drilling there over the next several years. We have a proven track record of developing reserves on a competitive basis and have increased annual production for over six years.
• Acquiring additional assets with significant growth potential. We will continue to evaluate oil and gas properties with proved reserves, probable reserves and/or sizeable acreage positions that we believe contain substantial hydrocarbons which can be developed at reasonable costs. In the last three years we have completed over $400 million of gas-oriented acquisitions in Colorado, establishing two core areas (the DJ and Piceance basins) of growth for us. We will continue to review asset acquisitions that meet our economic criteria with a primary focus on large repeatable development potential in the United States and concentrating on opportunities where we have strong technical expertise. Additionally, we seek to increase our net revenue interest in assets that we already operate.
• Utilizing joint ventures with respected partners to enter new basins. We believe that early entry into some basins offers the best potential for establishing low cost acreage positions in those basins. In areas where we do not have existing operations, we may seek to utilize the skills and knowledge of other industry participants upon entering these new basins so that we can reduce our risk and improve our ultimate success in the area.
• Accumulating significant acreage positions near our producing operations. We are interested in adding acreage positions near our existing producing operations to leverage our operating and technical expertise within the area and to build on established core operations. We believe this strategy can add value by utilizing our operational knowledge in a given area and by expanding our operations efficiently.
• Investing our capital in a disciplined manner and maintaining a strong financial position. The oil and gas business is capital intensive. Therefore we focus on utilizing our available capital on projects where we are likely to have success in increasing production and/or reserves at attractive returns. We believe that maintaining a strong financial position allows us to capitalize on investment opportunities and to be better prepared for a lower commodity price environment. We expect to continue to hedge oil and gas prices and to utilize long-term sales contracts with the objective of achieving the cash flow necessary for the development of our assets.

Business strengths.

• High quality asset portfolio with a long reserve life. Over the last several years we have diversified our asset base through acquisitions and now have approximately 40% of our production and proved reserves in the Rocky Mountain region with the balance in California. Our proved reserves consist of 69% crude oil and 31% natural gas. Our legacy California assets provides us with a steady stream of cash flow to re-invest into our significant drilling inventory and the appraisal of our prospects. Our wells are generally characterized by long production lives and predictable performance. At December 31, 2007 our implied reserve life was 16.5 years and our implied proved developed reserve life was 10.1 years.
• Track record of efficient proved reserve and production growth. For the three years ended December 31, 2007, our average annual reserve replacement rate was 316% at an average cost of $12.23 per barrel of oil equivalent (BOE). See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operation for further explanation of the reserve replacement rate. During the same period our proved reserves and production increased at an annualized compounded rate of 15% and 9%, respectively. We were able to deliver that growth predominantly through low-risk drilling. In 2007, we achieved an average gross drilling success rate of 98%. We believe we can continue to deliver strong growth through the drill bit by exploiting our large undeveloped leasehold position. We also plan to complement this drill bit growth through selective and focused acquisitions.
• Experienced management and operational teams. We operate our assets through six integrated teams organized around our six core areas of operations. These teams have clear objectives in production, reserves, finding and development costs, operating costs and are charged with value enhancement. In the last several years we have expanded and deepened our core team of technical staff and operating managers, who have broad industry experience, including experience in California heavy oil thermal recovery operations and Rocky Mountain tight gas sands development and completion. We continue to utilize technologies and steam practices that we believe will allow us to improve the ultimate recoveries of crude oil on our mature California properties. We also utilize 3-D seismic technology for evaluation of sub-surface geologic trends of our many prospects.
• Operational control and financial flexibility. We exercise operating control over approximately 98% of our proved reserve base. We generally prefer to retain operating control over our properties, allowing us to control operating costs more effectively, the timing of development activities and technological enhancements, the marketing of production and the allocation of our capital budget. In addition, the timing of most of our capital expenditures is discretionary, which allows us a significant degree of flexibility to adjust the size and timing of our capital budget. We finance our drilling budget primarily through our internally generated operating cash flows and we also have a $750 million senior unsecured revolving credit facility with a current borrowing base of $550 million.
• Established risk management policies. We actively manage our exposure to commodity price fluctuations by hedging a portion of our forecasted production. We use hedges to assist us in mitigating the effects of price declines and to secure operating cash flows in order to fund our capital expenditures program. Our long-term crude oil contracts with refiners and our long-term firm natural gas pipeline transportation agreements assist us in mitigating price differential volatility and in assuring product delivery to markets. Currently, the operation of our cogeneration facilities in California provides a partial hedge against increases in natural gas prices (which translates into higher steam costs) because of the high correlation between electricity and natural gas prices under our existing electricity sales contracts.

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

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

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

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

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

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

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

 

Crude Oil and Natural Gas Marketing.

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

 

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

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

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

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

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

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

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

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

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

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

 

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

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

Firm Transportation Summary.

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

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

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

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

 

Steaming Operations.

 

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

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

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

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

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

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

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

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

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

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

		2007				Estimated 2008
Natural gas produced:
DJ			18,500				18,500
Uinta (associated gas)			15,000				15,000
Piceance and other			11,000				21,000
Total natural gas volumes produced in operations			44,500				54,500
Natural gas consumed:
Cogeneration operations			27,000				27,000
Conventional boilers (1)			18,000				24,000
Total natural gas volumes consumed in operations			45,000				51,000
Less: Our estimate of approximate natural gas volumes consumed to produce electricity (2)			(24,000	)			(21,000	)
Total approximate natural gas volumes consumed to produce steam			21,000				30,000
Natural gas volumes hedged			15,000				18,000
Amount of natural gas volumes produced in excess of volumes consumed to produce steam and volumes hedged			8,500				6,500

 

Electricity.

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

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

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

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

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

Facility and Contract Summary.

Location and Facility

Type of Contract

Purchaser

Contract Expiration

Approximate Megawatts Available for Sale

Approximate Megawatts Consumed in Operations

Approximate Barrels of Steam Per Day

Placerita

Placerita Unit 1

SO2

Edison

Mar-09

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

 

Capital Expenditures Summary (Excluding Acquisitions). 

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

		2008				2007				2006
		(Budgeted) (1)
S. Midway Asset Team
New wells and workovers		$	27,948			$	13,174			$	15,904
Facilities - oil & gas			2,872				7,576				7,572
Facilities - cogeneration			-				-				415
General			-				150				411
			30,820				20,900				24,302
N. Midway Asset Team
New wells and workovers			43,143				12,949				28,707
Facilities - oil & gas			23,530				17,125				12,884
General			200				634				67
			66,873				30,708				41,658
S. Cal Asset Team
New wells and workovers			9,615				16,627				9,493
Facilities - oil & gas			7,328				17,549				6,234
Facilities - cogeneration			2,850				604				177
General			850				483				-
			20,643				35,263				15,904
Uinta Asset Team
New wells and workovers			48,060				52,700				104,397
Facilities			1,326				3,151				5,966
General			1,450				602				1,072
			50,836				56,453				111,434
Piceance Asset Team
New wells and workovers			93,900				103,921				36,654
Facilities			16,776				15,298				3,486
General			-				164				75
			110,676				119,383				40,215
DJ Asset Team
New wells and workovers			7,826				14,017				20,979
Facilities			3,497				2,736				7,883
General			1,691				1,519				427
			13,014				18,272				29,289
Other Fixed Assets			1,750				4,288				23,614		(2)
TOTAL		$	294,612			$	285,267			$	286,416

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

 

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

		2007				2006				2005
Net annual production: (1)
Oil (Mbbl)			7,210				7,182				7,081
Gas (MMcf)			15,657				12,526				7,919
Total equivalent barrels (MBOE) (2)			9,819				9,270				8,401
Average sales price:
Oil (per Bbl) before hedging		$	57.85			$	52.92			$	47.04
Oil (per Bbl) after hedging			53.24				50.55				40.83
Gas (per Mcf) before hedging			4.53				5.48				7.88
Gas (per Mcf) after hedging			5.27				5.57				7.73
Per BOE before hedging			49.72				48.38				47.01
Per BOE after hedging			47.50				46.67				41.62
Average operating cost - oil and gas production (per BOE)			14.38				12.69				11.79

 

Mbbl - Thousands of barrels

Mcf - Thousand cubic feet

MMcf - Million cubic feet

BOE - Barrels of oil equivalent

MBOE - Thousand barrels of oil equivalent

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

 

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

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

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

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

 

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

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

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

 

			2007
			Gross			Net
Total productive wells drilled:
Oil			230			227
Gas			186			90

 

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

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

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

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

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

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

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

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

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

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

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

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