Berry Petroleum Company | Annual Report 2008

ITEM 7 — Management's Discussion and analysis of financial condition and results of operation

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

Developing our existing resource base
Investing our capital in a disciplined manner and maintaining a strong financial position
Calibrating our cost structure to the current commodity price environment
Acquiring additional assets with significant growth potential
Accumulating significant acreage positions near our producing operations

Notable Items in 2008.

Achieved record production which averaged 31,968 BOE/D, up 19% from 2007
Added 88 million BOE of proved reserves ending 2008 at 245.9 million BOE
Recorded cash from operating activities of $410 million and funded $398 million of capital expenditures
Closed on our E. Texas acquisition on July 15, 2008, adding approximately 32 MMcf to daily production
Placed 5,000 Bbl/d of $100 WTI floor collars for 2009 and 2010 to protect cash flow
Achieved net income of $134 million
Drilled 85 wells in the diatomite and increased average production to 1,840 Bbl/D, up 86% from 2007
Accomplished an 8 day drilling record on a Piceance mesa location and reduced average drilling days to 11
Drilled 72 gross (44 net) Piceance operated wells which increased net production to average 21 MMcf/D
Increased the borrowing base on our senior secured credit facility from $550 million to $1.25 billion with an increase in bank commitments to $1.21 billion
Completed relocation of our corporate headquarters from Bakersfield, California to Denver, Colorado
David D. Wolf joined the Company as Executive Vice President and Chief Financial Officer
Temporarily shut in 12,000 Bbl/D in December due to the bankruptcy of Big West Oil in California and recorded an allowance for doubtful accounts of $38.5 million for November and December California crude oil sales
Resumed California operations in late December, marketing California production to multiple refiners
Quickly responded to declining commodity price environment reducing rig count from twelve to two during the fourth quarter of 2008, and reducing our 2009 capital budget to $100 million

Notable Items and Expectations for 2009.

Expecting 2009 capital expenditures of $100 million to be fully funded from operating cash flow
Anticipating average production between 32,000 and 33,000 BOE/D
Entered into short-term agreements with multiple refiners to sell all of our California crude oil
Targeting a 20% reduction in both operating and capital costs for 2009
Amended the terms of our senior secured credit facility, increasing our maximum EBITDAX to debt ratio

Overview of the Fourth Quarter of 2008. We achieved average production of 35,583 BOE/D in the fourth quarter of 2008, up 1% from an average of 35,149 BOE/D in the third quarter of 2008. We had a net loss of $12.0 million, or $0.27 per diluted share. Net cash from operations was $78 million and capital expenditures during the quarter totaled $92 million. The net loss resulted primarily from a write-off of $38.5 million (pre-tax) of accounts receivable due from BWOC as a result of their bankruptcy filing. This write-off included November and 22 days of December production from the majority of our California properties. We have since contracted with other parties to receive our California production. Other notable charges taken in the fourth quarter of the year included pre-tax rig termination fees of $2.3 million, $4.2 million related to the disposal and impairment of certain drilling rigs and related equipment, and dry hole and impairment expenses of $0.7 million.

View to 2009. Our challenge for 2009 is to calibrate our cost structure to levels that are consistent with those experienced when commodity prices were at $30 Bbl to $50 Bbl. Each of our asset teams is actively pursuing cost reductions and we are targeting a 20% reduction in our non-steam operating costs and our capital costs per well when compared to 2008 levels. Our $100 million capital program is designed to fund high return projects in California and E. Texas and generate excess cash flow.

Capital expenditures. Our capital expenditures for 2008 totaled $398 million for development and were fully funded from our $410 million operating cash flow. We also funded $668 million in acquisitions through additional borrowing on our senior secured credit facility and capitalized $23 million of interest. This compares to our total capital expenditures in 2007 of $341 million, which consisted of $56 million of acquisitions and $285 million in development. We capitalized $18 million of interest in2007.

Excluding the acquisition of new properties, in 2009 we have a developmental capital program of approximately $100 million which we expect to fund fully out of operating cash flow. As we have operational control of all of our assets and we have limited drilling commitments, we have the ability to revise our capital program based on changes in commodity prices. We expect our capital program will allow us to hold production flat with 2008 levels with average production between 32,000 and 33,000 BOE/D.

Development, Exploitation and Exploration Activity. We drilled 452 gross (381 net) wells during 2008, realizing a gross success rate of 99 percent. As of December 31, 2008, we have two rigs drilling on our properties under long-term contracts.

Drilling Activity. The following table sets forth certain information regarding drilling activities for the year ended December 31, 2008:

	Gross Wells		Net Wells
S. Midway		68		67
N. Midway		103		102
S. Cal		25		25
Piceance		78		46
Uinta		51		50
DJ		107		71
Texas		20		20
Totals (1)		452		381

(1) Includes 6 gross wells (5 net wells) that were dry holes in 2008.

Net Oil and Gas Producing Properties at December 31, 2008.

Name, State	% Average Working Interest		Total Net Acres		Proved Reserves (BOE) in millions		Proved Developed Reserves (BOE) in millions		% of Total Proved Reserves			Proved Undeveloped Reserves (BOE) in millions		% of Total Proved Reserves			Average Depth of Producing Reservoir (feet)
S. Midway, CA		98		2,127		52.7		42.8		17	%		9.9		4	%		1,700
E. Texas		100		4,508		50.0		29.8		12			20.2		8			13,000
Piceance, CO		41		3,157		41.8		13.2		5			28.6		12			9,300
N. Midway, CA		100		1,597		38.9		16.2		7			22.7		9			1,500
Uinta, UT		98		36,635		23.3		10.9		5			12.4		5			6,000
DJ, CO		51		67,418		21.5		13.2		5			8.3		3			2,600
S. Cal, CA		100		1,598		17.7		8.7		4			9.0		4			1,200
Totals				117,040		245.9		134.8		55	%		111.1		45	%

Properties

We have 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. Our S. Midway, S. Cal and DJ asset teams are primarily focused on production and generate significant cash flow to fund the drilling inventory in our N. Midway, Piceance, E. Texas and Uinta projects.

S. Midway - We own and operate working interests in 38 properties, including 23 owned in fee. Production from this field relies on thermal EOR methods, primarily cyclic steaming to place steam effectively into the remaining oil column. This is our most mature thermally enhanced asset.

2008 - Capital was focused on adding 20 horizontal wells below existing horizontal wells and further development at Ethel D including drilling 32 producers and the initiation of a pilot steam flood.

2009 - Efforts will be focused on drilling 10 additional, deeper horizontal wells, evaluation of the Ethel D steam flood pilot and lowering operating costs through optimization of well servicing and steam placement.

N. Midway- We began the full scale development of our N. Midway diatomite asset in late 2006 and have drilled 190 wells on this property. The delineation drilling in 2008 increased our original oil in place estimates by 35% to 330 million barrels. We are targeting ultimate recovery between 23% and 40% similar to other diatomite developments in California.

2008 - Capital was focused on drilling approximately 85 diatomite wells, completing major infrastructure upgrades that will support future development, increasing steam injection and further refining our thermal recovery techniques. Production from our diatomite asset increased by 86% in 2008, averaging approximately 1,840 Bbl/D.

2009 - We plan to invest $37 million to drill an additional 44 diatomite wells and install additional steam generation facilities. Additionally, we are seeking operating and capital cost reductions through initiatives such as steam management to improve our steam oil ratio and improved project management to reduce overall well costs. Production is expected to increase over 50% averaging approximately 3,000 Bbl/D.

S. Cal - We acquired the Poso Creek properties in the San Joaquin Valley in early 2003 for approximately $3 million and have proceeded with a successful thermal EOR redevelopment. In the Placerita field in Los Angeles County, we own and operate working interests in thirteen properties, including nine leases and four fee properties. Production relies on thermal recovery methods, primarily steam flooding.

2008 - Capital was directed at a 28 well program at Poso Creek and further expansion of the steam flood including the installation of a fourth steam generator and expansion of our water processing facilities. Average production increased from 1,950 Bbl/D in 2007 to 3,100 Bbl/D in 2008. A fifth steam generator was purchased and installed allowing further steam flood expansion into 2009.

2009 - Production at Poso Creek will increase as the steam flood patterns we developed in 2008 continue to respond. We expect to focus our efforts in 2009 on improving steam-oil ratios and lowering operating expenses.

Piceance- In 2006, we made two separate acquisitions in Piceance in Colorado, targeting the Williams Fork section of the Mesaverde formation. We acquired a 50% working interest in 6,300 gross acres in the Garden Gulch property and a 5% non-operating working interest on 6,300 gross acres and a net operating working interest of 95% in 4,300 gross acres in the North Parachute Ranch property. We spent $312 million to acquire a majority working interest in several blocks of undeveloped acreage located in the Grand Valley field. We believe we have accumulated a sizable resource base with over 900 drilling locations which will allow us to add significant proved reserves over the next several years.

2008 - Production averaged 20,750 Mcf/D in 2008 in comparison to 10,200 Mcf/D in 2007. We operated a four rig drilling program for most of the year and drilled 54 gross (27 net) wells at Garden Gulch and 18 gross (17 net) wells at North Parachute. Significant progress was made during 2008 in reducing the days required to drill wells. During the last three months of drilling activity, the number of drilling days on our mesa wells averaged 10 days on Garden Gulch and 11 days in North Parachute, a 40% reduction in drilling times compared to early 2008.

2009 - Our focus in 2009 will be on reducing our drilling and completion cost structure along with evaluating reservoir parameters and completion practices to improve ultimate recoveries. We believe our focus on cost reduction and improvement of ultimate recovery will allow for attractive returns to continue the development of our over 900 well drilling inventory. We have an inventory of approximately 40 completions and recompletions that we will be evaluating for supplemental capital should commodity prices warrant.

Uinta -The Brundage Canyon leasehold in Duchesne County, northeastern Utah consists of approximately 30,000 undeveloped gross acres which include federal, tribal and private leases. We are targeting the Green River formation that produces both light oil and natural gas. Along with an industry partner, we also hold a 163,000 gross acre block in the Lake Canyon project, which is located immediately west of our Brundage Canyon producing properties. We will drill and operate the shallow wells, targeting light oil and natural gas in the Green River formation and retain up to a 75% working interest. Our partner will drill and operate deep wells that will target hydrocarbons in the Mesaverde and Wasatch formations. We will hold up to a 25% working interest in these deep wells. The Ute Tribe has the option to participate in each well and obtain a 25% working interest which would reduce our and our partner's participation.

2008 - Production averaged 6,142 BOE/D in 2008 compared to 5,743 BOE/D in 2007. We drilled 51 gross (50 net) wells in the Uinta project which included 39 wells at Brundage Canyon, 8 wells in the Ashley Forest and 4 Green River wells at Lake Canyon. The Ashley Forest results continue to be encouraging with the 2008 wells achieving recoveries similar to Brundage Canyon. Three of our Lake Canyon wells are waiting on completion which is scheduled for mid-2009.

2009 - In 2009 capital is primarily directed at facility upgrades, pursuing the remaining three Lake Canyon completions and the completion of the Ashley Forest Environmental Impact Study (EIS) which we anticipate in the first half of 2009.

DJ-In 2005, we made three acquisitions for approximately $111 million establishing a core area in the Niobrara gas producing assets in eastern Colorado, western Kansas, and southwestern Nebraska. In 2007, we divested of our Kansas and Nebraska positions and focused our development in Yuma County where we have approximately 110,000 net acres and over 1,100 producing wells. Our Yuma County Niobrara projects provide sustainable and steady cash flow resulting from low capital development costs, modest production declines and long-life reserves.

2008 - Production averaged 19,700 net Mcf/D in 2008 compared to 18,700 Mcf/D in 2007. In 2008 we drilled 107 Niobrara development wells (71 net) in Yuma County with a 100% success rate and expanded our gathering and compression infrastructure to facilitate our drilling program. Early in the year we acquired an additional 75 square miles of 3-D seismic data. Interpretation of the 2008 seismic program and re-evaluation of previous year's acquisitions continue to replenish our low risk repeatable drilling inventory and provide additions to our proved reserves.

2009 - The primary focus in 2009 will be to maximize production from our existing wells, increase operational efficiencies, and reduce lease operating expense. Our capital program will be directed toward lease acquisition and facility infrastructure upgrades.

E. Texas-On July 15, 2008, we acquired a 100% working interest in natural gas producing properties on 4,500 net acres in Limestone and Harrison counties in East Texas for approximately $650 million. In Limestone County, we are targeting seven productive sands including the Cotton Valley and Bossier sands at depths between 8,000 and 13,000 feet. In Harrison County, we are targeting five productive sands with average depths between 6,500 and 13,000 feet and have upside potential in the Haynesville and Bossier Shales. We assumed operations from the seller on November 1, 2008.

2008 - We executed a five rig program in 2008 and 19 wells have been drilled and put on production since closing (4 in Harrison and 15 in Limestone). We also drilled three wells which are awaiting completion during 2009.

2009 - We plan to run one rig during 2009 and will drill approximately five vertical wells in the Oakes field during the year and plan to begin drilling horizontal wells in the Haynesville Shale Darco field in the third quarter of 2009.

Obstacles and Risks to Accomplishment of Strategies and Goals.

See Item 1A Risk Factors for a detailed discussion of factors that affect our business, financial condition and results of operations.

Revenues Approximately 87% of our revenues are generated through the sale of oil and natural gas production under either negotiated contracts or spot gas purchase contracts at market prices. Approximately 8% of our revenues are derived from electricity sales from cogeneration facilities which supply approximately 32% of our steam requirement for use in our California thermal heavy oil operations. We have invested in these facilities for the purpose of lowering our steam costs which are significant in the production of heavy crude oil. The remaining 5% of our revenues are primarily derived from gas marketing sales which represent excess capacity on the Rockies Express pipeline which we used to market natural gas for our working interest partners.

Sales of oil and gas were up 49% in 2008 compared to 2007 and up 62% from 2006. This improvement was due to an overall increase in both oil and gas production levels and increased oil prices. Improvements in production volume reflect the successful results of capital investments. Oil and natural gas prices contributed roughly 73% of the revenue increase and the increase in production volumes contributed the other 27%. Approximately 64% of our oil and gas sales volumes in 2008 were crude oil, with 82% of the crude oil being heavy oil produced in California which was sold under a contract based on the higher of WTI minus a fixed differential or the average posted price plus a premium.

The following results are in millions (except per share data) for the years ended December 31:

	2008			2007		2006
Sales of oil	$	519		$	385	$	360
Sales of gas		179			82		70
Total sales of oil and gas	$	698		$	467	$	430
Sales of electricity		64			56		53
Gas marketing		36			-		-
Gain (loss) on sale of assets (1)		(1	)		54		1
Interest and other income, net		5			6		2
Total revenues and other income	$	802		$	583	$	486
Net income	$	134		$	130	$	108
Earnings per share (diluted)	$	2.94		$	2.89	$	2.41

(1) Includes 2007 sale of Montalvo, California assets

The following results are in millions (except per share data) for the three months ended:

December 31, 2007

December 31, 2006

September 30, 2007

Sales of oil

109

100

Sales of gas

Total sales of oil and

	December 31, 2008			December 31, 2007		September 30, 2008
Sales of oil	$	97		$	109	$	145
Sales of gas		43			24		63
Total sales of oil and gas	$	140		$	133	$	208
Sales of electricity		12			15		18
Gas marketing		8			-		13
Gain (loss) on sale of assets		(2	)		2		-
Interest and other income, net		2			3		2
Total revenues and other income	$	160		$	153	$	241
Net income (loss)	$	(12	)	$	32	$	53
Net income (loss) per share (diluted)	$	(.27	)	$	.71	$	1.17

gas

133

102

119

Sales of electricity

Gain on sale of assets

Interest and other income, net

Total revenues and other income

153

116

133

Net income

Net income per share (diluted)

.71

.43

.60

Oil Contracts. See Item 1 Business.

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

Operating data. The following table is for the years ended December 31:

		2008	%		2007	%		2006	%
Oil and Gas
Heavy Oil Production (Bbl/D)		16,633	52		16,170	60		15,972	63
Light Oil Production (Bbl/D)		3,697	12		3,583	13		3,707	15
Total Oil Production (Bbl/D)		20,330	64		19,753	73		19,679	78
Natural Gas Production (Mcf/D)		69,834	36		42,895	27		34,317	22
Total (BOE/D)		31,968	100		26,902	100		25,398	100
Percentage increase from prior year		19%			6%			10%

Per BOE:
Average sales price before hedging	$	70.22		$	49.72		$	48.38
Average sales price after hedging		59.81			47.50			46.67

Oil, per Bbl:
Average WTI price	$	99.75		$	72.41		$	66.25
Price sensitive royalties		(2.95	)		(5.03	)		(5.13	)
Gravity differential and other		(11.32	)		(9.53	)		(8.20	)
Crude oil hedges		(16.89	)		(4.61	)		(2.37	)
Correction to royalties payable		1.42			-			-
Average oil sales price after hedging	$	70.01		$	53.24		$	50.55

Natural gas price:
Average Henry Hub price per MMBtu	$	9.04		$	7.12		$	6.97
Conversion to Mcf		.45			.34			.33
Natural gas hedges		.14			.74			.09
Location, quality differentials and other		(2.62	)		(2.93	)		(1.82	)
Average gas sales price after hedging	$	7.01		$	5.27		$	5.57

Production increased 19% or 5,066 BOE/D for the year ended December 31, 2008 when compared to the year ended December 31, 2007. Our E. Texas acquisition which closed on July 15, 2008, contributed 2,384 BOE/D on an annualized basis. Our development activities during the year resulted in increases in the Piceance, Poso and diatomite of 1,796 BOE/D, 1,133 BOE/D and 851 BOE/D, respectively.

The following table is for the three months ended:

		December 31, 2008	%		December 31, 2007	%		September 30, 2008	%
Oil and Gas
Heavy Oil Production (Bbl/D)		15,999	45		16,595	59		17,264	49
Light Oil Production (Bbl/D)		3,659	10		3,395	12		3,898	11
Total Oil Production (Bbl/D)		19,658	55		19,990	71		21,162	60
Natural Gas Production (Mcf/D)		95,548	45		48,196	29		83,928	40
Total (BOE/D)		35,583	100		28,023	100		35,150	100

Per BOE:
Average sales price before hedging	$	38.45		$	60.38		$	80.22
Average sales price after hedging		42.93			52.32			64.98

Oil, per Bbl:
Average WTI price	$	59.08		$	90.50		$	118.22
Price sensitive royalties		(1.69	)		(6.68	)		(5.30	)
Gravity differential and other		(8.55	)		(9.92	)		(10.80	)
Crude oil hedges		4.69			(13.57	)		(26.12	)
Average oil sales price after hedging	$	53.53		$	60.33		$	76.00

Natural gas price:
Average Henry Hub price per MMBtu	$	6.95		$	7.39		$	10.24
Conversion to Mcf		.35			.35			.52
Natural gas hedges		.70			.91			.15
Location, quality differentials and other		(3.02	)		(3.21	)		(2.81	)
Average gas sales price after hedging	$	4.98		$	5.44		$	8.10

Electricity.We consume natural gas as fuel to operate our three cogeneration facilities which are intended to provide an efficient and secure long-term supply of steam necessary for the cost-effective production of heavy oil. We sell our electricity to utilities under standard offer contracts based on "avoided cost" or SRAC pricing approved by the CPUC and under which our revenues are currently linked to the cost of natural gas. Natural gas index prices are the primary determinant of our electricity sales price based on the current pricing formula under these contracts. The correlation between electricity sales and natural gas prices allows us to manage our cost of producing steam more effectively. Revenues were up and operating costs were up in the year ended 2008 from the year ended 2007 due to 18% higher electricity prices and 27% higher natural gas prices, respectively. Revenues were up and operating costs were down in the year ended 2007 from the year ended 2006 due to 2% higher electricity prices and 6% lower natural gas prices, respectively. We purchased approximately 27 MMBtu/D as fuel for use in our cogeneration facilities in both the year ended December 31, 2008 and the year ended December 31, 2007. In 2007 and 2008, our electricity operations improved partially from the lower cost of our firm transportation natural gas we purchased. We purchase and transport 12,000 average MMBtu/D on the Kern River Pipeline under our firm transportation contract and use this gas to produce conventional and cogeneration steam in the Midway-Sunset field. The differential between Rocky Mountain gas prices and Southern California Border prices increased during 2007 and 2008 compared to 2006 allowing us to purchase a portion of our gas at prices less than the Southern California Border price. As our electricity revenue is linked to Southern California Border prices, the fuel we purchased at lower Rocky Mountain prices was the primary contributor to the increase in our electricity margins in 2007 and 2008 compared to 2006.

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 SO contracts and revises the capacity prices paid under current SO1 contracts. The effective date of the SRAC Decision has not been determined nor has every element of the formula under the SRAC Decision been finalized. As such it is not possible to predict the economic impact on us of the SRAC Decision nor whether its terms will be applied retroactively and if so, for what period.

The following table is for the years ended December 31:

	2008		2007		2006
Electricity
Revenues (in millions)	$	63.5	$	55.6	$	52.9
Operating costs (in millions)	$	54.9	$	46.0	$	48.3
Decrease to total oil and gas operating expenses per barrel	$	.74	$	.98	$	.50
Electric power produced - MWh/D		2,063		2,133		2,074
Electric power sold - MWh/D		1,873		1,932		1,867
Average sales price/MWh (no hedging was in place)	$	92.98	$	78.62	$	77.13
Fuel gas cost/MMBtu (including transportation)	$	7.95	$	6.08	$	6.44

Royalties. A price-sensitive royalty burdens certain of our S. Midway properties which produced approximately 2,300 BOE/D in 2008. This royalty was 75% of the amount of the heavy oil posted price above a base price which was $16.11 in 2008. This royalty rate was reduced to 53% effective January 1, 2008 as long as we maintain a minimum steam injection level. We met the steam injection level in 2008 and expect to meet the requirement going forward. This base price escalates at 2% annually, thus the threshold price is $16.43 per barrel in 2009. Liabilities payable for these royalties were $22 million, $36 million and $36 million in the years ended December 31, 2008, 2007 and 2006, respectively.

In the first quarter of 2008, we determined there was an error in computing royalties payable in prior years, accumulating to $10.5 million as of December 31, 2007. We concluded the error was not material to any individual prior interim or annual period (or to the projected earnings for 2008) and, therefore, the error was corrected during the first quarter of 2008, with the effect of increasing our sales of oil and gas by $10.5 million and reducing our royalties payable.

Oil and Gas Operating, Production Taxes, G&A and Interest Expenses. We believe that the most informative way to analyze changes in recurring operating expenses from one period to another is on a per unit-of-production, or BOE, basis. The following table presents information about our operating expenses for each of the years ended December 31:

	Amount per BOE							Amount (in thousands)
	2008		2007		Change			2008		2007		Change
Operating costs - oil and gas production	$	17.10	$	14.38		19	%	$	200,098	$	141,218	42	%
Production taxes		2.56		1.75		46	%		29,898		17,215	74	%
DD&A - oil and gas production		11.81		9.54		24	%		138,237		93,691	48	%
G&A		4.73		4.09		16	%		55,353		40,210	38	%
Interest expense		2.24		1.76		27	%		26,209		17,287	52	%
Total	$	38.44	$	31.52		22	%	$	449,795	$	309,621	45	%

Our total operating costs, production taxes, G&A and interest expenses for 2008, stated on a unit-of-production basis, increased 22% over 2007. The changes were primarily related to the following items:

Operating costs: Our operating costs increased primarily due to higher contract services and labor costs, higher compression, gathering, and dehydration costs and higher steam costs resulting from higher volumes of injected steam. Of the $59 million increase in operating expense compared to 2007, approximately $31 million was due to higher steam costs and approximately $4 million was due to the addition of our E. Texas assets. On a per barrel basis, E. Texas operating costs approximate $1.00/Mcf and reduces our overall cost per barrel. The following table presents steam information:

	2008	2007	Change
Average volume of steam injected (Bbl/D)	99,908	87,990	14%
Fuel gas cost/MMBtu (including transportation)	7.95	$ 6.08	31%

Based on current plans, we are targeting average steam injection in 2009 of approximately 120,000 BSPD or a 20% increase compared to 2008.

Production taxes: Our production taxes have increased over the last year as the value of our oil and natural gas has increased. Severance taxes, which are prevalent in Utah and Colorado, are directly related to the field sales price of the commodity. In California, our production is burdened with ad valorem taxes on our total proved reserves. We expect production taxes to track oil and gas prices generally.
Depreciation, depletion and amortization: DD&A increased per BOE in 2008 by 24% from 2007. Over the past year this increase has resulted from an increase in capital spending in fields with higher drilling and leasehold acquisition costs, which is in line with our expectations. Additionally, DD&A may continue to trend higher as a certain portion of our interest cost related to our Piceance acquisitions is capitalized into the basis of the assets. We anticipate a portion will continue to be capitalized over the next several years until our probable reserves have been recategorized to proved reserves.
General and administrative: Approximately 65% of our G&A is related to compensation. The primary reason for the increase in G&A during 2008 was a 15% increase in employee headcount associated with our E. Texas acquisition and the development of our assets. In 2008 we moved our corporate headquarters from Bakersfield, California to Denver, Colorado and approximately $1.7 million was related to relocation of our employees and related expenses. Also included in G&A is $2.3 million in rig termination penalties that we incurred during the fourth quarter of 2008 and $0.6 million for costs we incurred to evaluate the formation of a master limited partnership.
Interest expense: Our outstanding borrowings, including our senior unsecured money market line of credit and senior subordinated notes, was $1.16 billion at December 31, 2008 compared to $459 million at December 31, 2007. Average borrowings in 2008 increased primarily due to our E. Texas acquisition. For the year ended December 31, 2008, $23 million of interest cost has been capitalized.

The following table presents information about our operating expenses for each of the years ended December 31:

	Amount per BOE							Amount (in thousands)
	2007		2006		Change			2007		2006		Change
Operating costs - oil and gas production	$	14.38	$	12.69		13	%	$	141,218	$	117,624	20	%
Production taxes		1.75		1.58		11	%		17,215		14,674	17	%
DD&A - oil and gas production		9.54		7.30		31	%		93,691		67,668	38	%
G&A		4.09		3.98		3	%		40,210		36,841	9	%
Interest expense		1.76		1.05		68	%		17,287		10,247	69	%
Total	$	31.52	$	26.60		18	%	$	309,621	$	247,054	25	%

Our total operating costs, production taxes, G&A and interest expenses for 2007, stated on a unit-of-production basis, increased 18% over 2006. The changes were primarily related to the following items:

Operating costs: Our operating costs increased primarily due to higher contract services and labor costs, higher compression, gathering, and dehydration costs and higher steam costs resulting from higher volumes of injected steam. The following table presents steam information:

	2007	2006	Change
Average volume of steam injected (Bbl/D)	87,990	81,246	8%
Fuel gas cost/MMBtu (including transportation)	$ 6.08	$ 6.44	(6%)

Production taxes: During 2007 our production taxes increased over 2006 as the value of our oil and natural gas had increased. Severance taxes, which are prevalent in Utah and Colorado, are directly related to the field sales price of the commodity. In California, our production is burdened with ad valorem taxes on our total proved reserves.
Depreciation, depletion and amortization: DD&A increased per BOE in 2007 by 31% from 2006 due to an increase in capital spending in fields with higher drilling and leasehold acquisition costs.
General and administrative: in 2007, approximately 70% of our G&A was related to compensation. The primary reason for the increase in G&A during 2007 was an 8% increase in employee headcount to accelerate the development of our assets and our competitive compensation practices to attract and retain our personnel.
Interest expense: Our outstanding borrowings, including our senior unsecured money market line of credit and senior subordinated notes, was $459 million at December 31, 2007 compared to $406 million at December 31, 2006. Average borrowings in 2007 increased primarily due to our final payment on our Piceance acquisition. For the year ended December 31, 2007, $18 million of interest cost was capitalized.

Estimated 2009 Oil and Gas Operating, G&A and Interest Expenses.We estimate our 2009 production volume will range between 32,000 BOE/D and 33,000 BOE/D. Based on WTI of $47.50 and NYMEX HH of $5.00 MMBtu, we expect our expenses to be within the following ranges:

	Amount per BOE
	Anticipated
	range in 2009		2008		2007
Operating costs-oil and gas production (1)	$	13.50 – 15.00	$	17.10	$	14.38
Production taxes (2)		1.50 – 2.00		2.56		1.75
DD&A		14.00 – 16.00		11.81		9.54
G&A		3.75 - 4.00		4.73		4.09
Interest expense		3.00 – 4.00		2.24		1.76
Total	$	35.75 – 41.00	$	38.44	$	31.52

(1) We expect operating costs to decrease in 2009 as compared to 2008 due to lower natural gas prices which are the primary driver of our cost to generate steam in California and our overall cost reduction efforts.
(2) We expect production taxes will be lower on a per BOE basis as our averaged realized price decreases due to lower commodity prices and a majority of these costs are based on a percentage of our revenue.

Dry hole, abandonment, impairment and exploration. In 2008 we had dry hole, abandonment and impairment charges of $12.3 million. We recorded $7.3 million for technical difficulties that were encountered on five wells in Piceance before reaching total depth. These holes were abandoned in favor of drilling to the same bottom hole location by drilling new wells. We incurred exploration costs of $2.4 million in 2008 compared to $0.7 million and $3.8 million in 2007 and 2006, respectively. These costs consist primarily of geological and geophysical costs in DJ. Due to the release of our rigs we performed an impairment test which resulted in $2.4 million of impairment costs resulting from the impairment of one rig. Additionally, we performed an impairment test of our oil and gas assets at December 31, 2008 in accordance with SFAS 144 and determined that no impairment was necessary.

In 2007 we had dry hole, abandonment and impairment charges of $13.7 million consisting primarily of a $4.6 million write down of a portion of our Tri-State acreage in connection with the then current and pending sale of these properties, a $3.3 million impairment of our Coyote Flats prospect to reflect its fair value in conjunction with the preparation of our year end reserve estimates, a $2.9 million write down of our Bakken properties sold in September 2007, and other dry hole charges of $2.2 million.

Bad debt expense. 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. Of the $38.7 million recorded in bad debt expense for the year ended December 31, 2008, $38.5 million relates to the allowance for bad debt taken for the bankruptcy of BWOC with the remainder due to the bankruptcy of SemCrude earlier in 2008. 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.

Income taxes. The Revenue Reconciliation Act of 1990 included a tax credit for certain costs associated with extracting high-cost, capital-intensive marginal oil or gas which utilizes certain methods, including cyclic steam and steam flood recovery methods for heavy oil. This credit is based on the average wellhead prices for the prior year. While we do not expect to generate EOR credit in 2009, we would expect to generate some EOR tax credit for 2010 if average U.S. wellhead oil prices in 2009 are within an approximate range of $44 to $50. As of December 31, 2008, we have approximately $24 million of federal and $17 million of state (California) EOR tax credit carryforwards available to reduce future cash income taxes. The EOR credits will begin to expire, if unused, in 2024 and 2015 for federal and California purposes, respectively.

We experienced an effective tax rate of 37%, 38% and 39% in 2008, 2007 and 2006, respectively. The rate is lower than our combined federal and state statutory tax rate of 40% primarily due to certain business incentives. We expect our effective tax rate to range between 37% and 38% in 2009, given the current commodity price environment. See Note 12 to the financial statements for further information.

Commodity derivatives. In March 2006, we took a charge for the change in fair market value of our natural gas derivatives put in place to protect our Piceance acquisition future cash flows. These gas derivatives did not qualify for hedge accounting under SFAS 133 because the price index in the derivative instrument did not correlate closely with the item being hedged. The pre-tax charge of $4.8 million represented the change in fair market value over the life of the contract, resulting from an increase in natural gas prices from the date of the derivative to March 31, 2006. In May 2006, we entered into basis swaps with natural gas volumes to match the volumes on our NYMEX Henry Hub collars that were placed on March 1, 2006. The combination of the derivative instruments entered into on March 1, 2006 (described above) and the basis swaps were designated as cash flow hedges in accordance with SFAS 133. Thus the unrealized net gain of $5.6 million included on the Statements of Income in 2006 under the caption "Commodity derivatives" is primarily the change in fair value of the derivative instrument caused by changes in forward price curves prior to designating these instruments as cash flow hedges.

On January 2, 2008 we entered into NYMEX swaps to protect our DJ cash flows. These natural gas derivatives were not correlated at inception, and therefore ineffective. On January 14, 2008, we entered into basis swaps and designated the combination of the basis swaps and NYMEX swaps as cash flow hedges. However, we took a charge of $357,000 to Commodity Derivatives in the first quarter of 2008 which reflected the ineffectiveness for the interim period.

Most of our oil hedges are based on the West Texas Intermediate (WTI) index and our California oil sales contract with BWOC is tied to WTI which has allowed us to qualify for hedge accounting and effectively hedge our production. Our interim sales contracts are primarily based on the field posting price and we are therefore subject to potential ineffectiveness. There is a high correlation between WTI and the field posting prices which allowed us to continue hedge accounting. Additionally, under the dollar offset method, we did not have any ineffectiveness under these contracts during 2008. However, depending on the change in value of our actual hedges compared to a hypothetical hedge based on field posting prices, we may have significant ineffectiveness on these contracts in the future based on changes in the field posted price compared to the changes in WTI.

Asset dispositions. We have significantly increased and strengthened our portfolio of assets since 2002 and expect to continue to make acquisitions. We anticipate that we will dispose of certain properties or assets over time. The assets most likely for disposition will be those that do not fit or complement our strategic growth plan, that are not contributing satisfactory economic returns given the profile of the assets, or that we believe the development potential will not be meaningful to us as a whole. We divested several assets in 2007. Proceeds from these sales contributed to the funding of our capital program. Net oil and gas properties and equipment classified as held for sale is zero at December 31, 2008 and $1.4 million as of December 31, 2007 in accordance with SFAS No. 144. See Note 3 to the financial statements.

Financial Condition, Liquidity and Capital Resources. Substantial capital is required to replace and grow reserves. We achieve reserve replacement and growth primarily through successful development and exploration drilling and the acquisition of properties. Fluctuations in commodity prices, production rates and operating expenses have been the primary reason for changes in our cash flow from operating activities.

Liquidity. In October 2006, we completed the sale of $200 million of ten year 8.25% senior subordinated notes and paid down our borrowings under our facility. In July 2008 we secured our credit facility with our assets and as of December 31, 2008 we had bank commitments of $1.21 billion with a borrowing base of $1.25 billion. As of December 31, 2008, we had total borrowings under the senior secured revolving credit facility and money market line of credit of $957 million and $200 million under our senior subordinated notes. Our available credit under our senior secured credit facility was $245 million at year-end 2008.

Our borrowing base is subject to semi-annual redeterminations in April and October of each year. The borrowing base is determined by each lender based on the value of our proved oil and gas reserves using price assumptions that vary by lender. Due to a decline in commodity prices, it is likely that our borrowing base will decrease in April 2009 which could substantially reduce our liquidity. Should the amount of our borrowing base decrease below the amount outstanding under the facility, we would be required to repay any such deficiency in two equal installments 90 and 180 days after the borrowing base redetermination. Hedges generally add significant value to our borrowing base as the prices banks use to value our assets are at a discount to futures prices. We have a minimal amount of our oil production hedged after 2010 and we will likely enter into additional hedge positions as needed to increase our borrowing base under the senior secured credit facility. In addition to amending our covenants to increase the amount of total leverage we may incur, the February 2009 amendment to our credit facility provides us with the flexibility to add various forms of debt that is junior to our senior secured credit facility and that is not subject to a borrowing base. We are evaluating such junior debt to further increase our liquidity.

Capital Expenditures and Cash Flows. We establish a capital budget for each calendar year based on our development opportunities and the expected cash flow from operations for that year. Acquisitions are typically debt financed. We may revise our capital budget during the year as a result of acquisitions and/or drilling outcomes or significant changes in cash flow. Excess cash generated from operations is expected to be applied toward debt reduction or other corporate purposes. As we operate all of our assets, we have the flexibility to modify our capital program based on changes in commodity prices. In 2009, we have a capital program of approximately $100 million and we expect to fully fund this program from operating cash flow which should approximate $175 million. Approximately 90% of our oil production is hedged for 2009 and thus our sensitivity to changes in oil prices is limited. A ten dollar change in oil prices impacts our operating cash flow by approximately $2 million in 2009. A one dollar change in natural gas prices impacts operating cash flow by approximately $6 million.

Dividends. Our regular annual dividend is currently $0.30 per share, or approximately $13.4 million annually, payable quarterly in March, June, September and December.

Working Capital. Cash flow from operations is dependent upon the price of crude oil and natural gas and our ability to increase production and manage costs. Combined crude oil and natural gas prices decreased in 2008 (see graphs on page 32) and we increased production by 19%.

Our working capital balance fluctuates as a result of the amount of borrowings and the timing of repayments under our credit arrangements. We use our long-term borrowings under our senior unsecured revolving credit facility primarily to fund property acquisitions. Generally, we use excess cash to pay down borrowings under our credit arrangement. As a result, we often have a working capital deficit or a relatively small amount of positive working capital. In 2009, we expect our working capital deficit to decrease by $50 to $65 million as our accounts payable is reduced to reflect a $100 million capital budget compared to a $400 million capital budget in 2009 and our price sensitive royalty in California which is paid annually in February of each year is reduced due to lower commodity prices.

In July 2008, we completed the purchase of 4,500 net acres in E. Texas for approximately $650 million which was funded from our senior secured credit facility.

In May 2007, we sold our non-core West Montalvo assets in Ventura County, California. The sale proceeds were approximately $61 million and we recognized a $52 million pretax gain on the sale, including post closing adjustments. Production from the property was approximately 700 BOE/D, which is less than 3% of average 2007 production and, as of December 31, 2006, the property had 7 million BOE of proved reserves, which is less than 5% of the 2006 year end total of 150 million BOE. Separately, during the second quarter of 2007 we paid the third and final installment of approximately $54 million for the North Parachute Ranch property located in Piceance.

The table below compares financial condition, liquidity and capital resources changes as of and for the years ended December 31 (in millions, except for production and average prices):

	2008			2007			Change
Average production (BOE/D)		31,968			26,902			19	%
Average oil and gas sales prices, per BOE after hedging	$	59.81		$	47.50			26	%
Net cash provided by operating activities	$	410		$	239			72	%
Working capital (deficit)	$	(72	)	$	(110	)		38	%
Sales of oil and gas	$	698		$	467			50	%
Total debt	$	1,157		$	459			152	%
Capital expenditures, including acquisitions and deposits on acquisitions	$	1,066		$	342			212	%
Dividends paid	$	13.4		$	13.3			1	%

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

Credit Facility. See Note 7 to the financial statements for more information.

Contractual Obligations.

Our contractual obligations as of December 31, 2008 are as follows (in thousands):

		Total		2009		2010		2011		2012		2013		Thereafter
Long-term debt and interest	$	1,471,383	$	82,211	$	56,558	$	56,558	$	56,558	$	969,998	$	249,500
Abandonment obligations		41,967		1,643		1,642		1,642		1,642		1,642		33,756
Operating lease obligations		18,328		2,373		2,390		2,436		2,446		2,493		6,190
Drilling and rig obligations		47,049		12,789		8,030		8,030		18,200		-		-
Firm natural gas transportation contracts		165,071		19,803		19,803		19,803		19,652		17,557		68,453
Total	$	1,743,798	$	118,819	$	88,423	$	88,469	$	98,498	$	991,690	$	357,899

Long-term debt and interest - Our credit facility borrowings and related interest of approximately 4.3% can be paid before its maturity date without significant penalty. Our bond notes and related interest of 8.25% mature in November 2016, but are not redeemable until November 1, 2011 and are not redeemable without any premium until November 1, 2014.

Operating leases- We lease corporate and field offices in California, Colorado and Texas. Rent expense with respect to our lease commitments for the years ended December 31, 2008, 2007 and 2006 was $1.7 million, $1.5 million and $1.0 million, respectively. In 2006, we purchased an airplane for business travel which was subsequently sold and contracted under a ten year operating lease beginning December 2006.

Drilling obligations - Starting in 2006, we began to participate in the drilling of over 16 gross wells on our Lake Canyon prospect over the four year contract. Our minimum obligation under our exploration and development agreement is $9.6 million, and as of December 31, 2008 the remaining obligation is $2.4 million. Also included above, under our June 2006 joint venture agreement in Piceance we are required to have 120 wells drilled by February 2011 to avoid penalties of $0.2 million per well or a maximum of $24 million. As of December 31, 2008 we have drilled 29 of these wells and anticipate resuming drilling in early 2010 to continue the progression towards meeting our commitment.

Drilling rig obligations - We are obligated in operating lease agreements for the use of two drilling rigs, one in California and one of which resulted from our July, 2008 E. Texas Acquisition (see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Properties).

Firm natural gas transportation - We have one firm transportation contract which provides us additional flexibility in securing our natural gas supply for California operations. This allows us to potentially benefit from lower natural gas prices in the Rocky Mountains compared to natural gas prices in California. We have eight long-term transportation contracts on five different pipelines to provide us with physical access to move gas from our producing areas to various markets.

Other Obligations. We adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no material adjustment to retained earnings. As of December 31, 2008, we had a gross liability for uncertain tax benefits of $12 million of which $10 million, if recognized, would affect the effective tax rate. We recognize potential accrued interest and penalties related to unrecognized tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. As of December 31, 2008, we had accrued approximately $1.2 million of interest related to our uncertain tax positions. Due to the uncertainty about the periods in which examinations will be completed and limited information related to current audits, we are not able to make reasonably reliable estimates of the periods in which cash settlements will occur with taxing authorities for the noncurrent liabilities.

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 notional 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 paraffinic crude oil can vary seasonally and this contract provides a stable outlet for the Company's crude oil.

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

A critical accounting policy is one that is important to the portrayal of our financial condition and results, and requires management to make difficult subjective and/or complex judgments. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. We believe the following accounting policies are critical policies.

Successful Efforts Method of Accounting. We account for our oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs, and the costs of carrying and retaining undeveloped properties, are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized as long as the additional exploratory work is under way or firmly planned. The application of the successful efforts method of accounting requires management's judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. The evaluation of oil and gas leasehold acquisition costs included in unproved properties requires management's judgment to estimate the fair value of such properties

Oil and Gas Reserves. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our oil and gas reserves are based on estimates prepared by independent engineering consultants. Reserve engineering is a subjective process that requires judgment in the evaluation of all available geological, geophysical, engineering and economic data. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices, may significantly impact estimated reserve quantities. Depreciation, depletion and amortization (DD&A) expense and impairment of proved properties are impacted by our estimation of proved reserves. These estimates are subject to change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased DD&A expense, increased impairment of proved properties and a lower standardized measure of discounted future net cash flows.

Carrying Value of Long-lived Assets. Downward revisions in our estimated reserve quantities, increases in future cost estimates or depressed crude oil or natural gas prices could cause us to reduce the carrying amounts of our properties. We perform an impairment analysis of our proved properties annually, or when current events or circumstances indicate that carrying amounts may not be recoverable, by comparing the future undiscounted net revenue to the net book carrying value of the assets. An analysis of the proved properties will also be performed whenever events or changes in circumstances indicate an asset's carrying value may not be recoverable from future net revenue. Assets are grouped at the field level and, if it is determined that the net book carrying value cannot be recovered by the estimated future undiscounted cash flow, they are written down to fair value. Cash flows used in the impairment analysis are determined based on our estimates of crude oil and natural gas reserves, future crude oil and natural gas prices and costs to extract these reserves. For our unproved properties, we perform an impairment analysis annually or whenever events or changes in circumstances indicate an asset's net book carrying value may not be recoverable. These evaluations involve a significant amount of judgment since the results are based on estimated future sales prices, costs to produce these products, estimates of oil and natural gas reserves to be recovered and the timing of development.

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

Income Taxes. We compute income taxes in accordance with SFAS No. 109, Accounting for Income Taxes as interpreted by FIN 48, Accounting for Uncertainty in Income Taxes. SFAS No. 109 requires an asset and liability approach which results in the recognition of deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each calendar year as well as the effects of tax rate changes, tax credits, and tax credit carryforwards. A valuation allowance is recognized if it is determined that deferred tax assets may not be fully utilized in future periods. We may generate EOR tax credits from the production of our heavy crude oil in California which may result in a deferred tax asset. We believe that these credits will be fully utilized in future years and consequently have not recorded any valuation allowance related to these credits. Due to uncertainties involved with tax matters, the future effective tax rate may vary significantly from the estimated current year effective tax rate. FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold an uncertain tax position is required to meet before tax benefits associated with such uncertain tax positions are recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 excludes income taxes from the scope of SFAS No. 5, Accounting for Contingencies. FIN 48 also requires that amounts recognized in the Balance Sheet related to uncertain tax positions be classified as a current or noncurrent liability, based upon the expected timing of the payment to a taxing authority.

Asset Retirement Obligations. We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and gas production operations. The computation of our asset retirement obligations (ARO) was prepared in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, which requires us to record the fair value of liabilities for retirement obligations of long-lived assets. Estimating the future ARO requires management to make estimates and judgments regarding timing, current estimates of plugging and abandonment costs, as well as to determine what constitutes adequate remediation. We develop estimates based on our historical costs and estimated costs where we do not have such historical data and use the present value of estimated cash flows related to our ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Changes in any of these assumptions can result in significant revisions to the estimated ARO. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment will be made to the related asset. Due to the subjectivity of assumptions and the relatively long life of our assets, the ultimate costs to retire our wells may vary significantly from previous estimates.

Environmental Remediation Liability. We review, on a quarterly basis, our estimates of costs of the cleanup of various sites including sites in which governmental agencies have designated us as a potentially responsible party. In accordance with SFAS No. 5, Accounting for Contingencies, when it is probable that obligations have been incurred and where a minimum cost or a reasonable estimate of the cost of remediation can be determined, the applicable amount is accrued. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is an estimation process that includes the subjective judgment of management. In many cases, management's judgment is based on the advice and opinions of legal counsel and other advisers, and the interpretation of laws and regulations, which can be interpreted differently by regulators or courts of law. Our experience and the experience of other companies in dealing with similar matters influence the decision of management as to how it intends to respond to a particular matter. A change in estimate could impact our oil and gas operating costs and the liability, if applicable, recorded on our Balance Sheet.

Accounting for Business Combinations. We have grown substantially through acquisitions and our business strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our business combinations using the purchase method, which is the only method permitted under SFAS 141. The accounting for business combinations is complicated and involves the use of significant judgment. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, stock or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets.

Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired may not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices, where available, appraisals, comparisons to transactions for similar assets and liabilities and the present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Each of the business combinations completed were of interests in oil and gas assets. We believe the consideration we paid to acquire these assets represents the fair value of the assets acquired and liabilities assumed at the time of acquisition. Consequently, we have not recognized any goodwill from any of our business combinations.

The E. Texas purchase price was based on the relative fair values, as determined by the valuation of proved reserves and related assets as of the acquisition date.

Stock-Based Compensation. We adopted SFAS No. 123(R) to account for our stock option plan beginning January 1, 2006. This standard requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. We previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation effective January 1, 2004. The modified prospective method was selected as described in SFAS 148, Accounting for Stock-Based Compensation—Transition and Disclosure. Under this method, we recognize stock option compensation expense as if we had applied the fair value method to account for unvested stock options from the original effective date. Stock option compensation expense is recognized from the date of grant to the vesting date. The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model that uses the following assumptions. Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding; the range results from certain groups of employees exhibiting different exercise behavior. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.

Electricity Cost Allocation. Our investment in our cogeneration facilities has been for the express purpose of lowering steam costs in our California heavy oil operations and securing operating control of the respective steam generation. Such cogeneration operations produce electricity and steam and use natural gas as fuel. We allocate steam costs to our oil and gas operating costs based on the conversion efficiency (of fuel to electricity and steam) of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to the utilities. Electricity used in oil and gas operations is allocated at cost. A portion of the capital costs of the cogeneration facilities is allocated to DD&A-oil and gas production.

Capitalized Interest. Interest incurred on funds borrowed to finance exploration and certain acquisition and development activities is capitalized. To qualify for interest capitalization, the costs incurred must relate to the acquisition of unproved reserves, drilling of wells to prove up the reserves and the installation of the necessary pipelines and facilities to make the property ready for production. Such capitalized interest is included in oil and gas properties, buildings and equipment. Capitalized interest is added into the depreciable base of our assets and is expensed on a units of production basis over the life of the respective project.

Recent Accounting Pronouncements. In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109, Accounting for Income Taxes. This interpretation requires that realization of an uncertain income tax position must be "more likely than not" (i.e. greater than 50% likelihood of receiving a benefit) before it can be recognized in the financial statements. Further, this interpretation prescribes the benefit to be recorded in the financial statements as the amount most likely to be realized assuming a review by tax authorities having all relevant information and applying current conventions. This interpretation also clarifies the financial statement classification of tax-related penalties and interest and sets forth new disclosures regarding unrecognized tax benefits. We adopted this interpretation in the first quarter of 2007. See Note 12.

In September 2006, SFAS No. 157, Fair Value Measurements was issued by the FASB. This statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. We adopted this Statement in 2008 and increased our disclosures accordingly. SFAS No. 157-2 addresses the same topic for nonfinancial assets and liabilities and will become effective for our fiscal year beginning January 1, 2009. We do not believe that the implementation of SFAS 157-2 will have a material impact on our financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity's election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the Balance Sheet. We adopted this statement January 1, 2008 and it did not have a material effect on our financial statements.

In April 2007, the FASB issued a FASB Staff Position to amend FASB Interpretation 39, Offsetting of Amounts Related to Certain Contracts. FIN 39-1 states that a reporting entity that is party to a master netting arrangement can offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with paragraph 10 of Interpretation 39. FIN 39-1 became effective for our fiscal year beginning January 1, 2008 and did not have any effect on our financial statements as we do not post collateral under our hedging agreements.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which improves the information that a reporting entity provides in its financial reports about a business combination and its effects. This Statement establishes principles and requirements for how the acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The Statement also recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. We may experience a financial statement impact depending on the nature and extent of any new business combinations entered into after the effective date of SFAS No. 141(R).

In September 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Positions (FSP) No. 133-1 and FIN 45-4 to amend FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a hybrid instrument. This FSP also amends FASB Interpretation No.45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to require an additional disclosure about the current status of the payment/performance risk of a guarantee. Further, this FSP clarifies the FASB's intent about the effective date of FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities. This FSP was adopted in 2008 and did not have a material effect on our financial statements and related disclosures.

In December 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS 160 was issued to establish accounting and reporting standards for the noncontrolling interest in a subsidiary (formerly called minority interests) and for the deconsolidation of a subsidiary. We do not expect the adoption of SFAS 160 to have a material effect on our financial statements and related disclosures. The effective date of this Statement is the same as that of the related Statement 141(R).

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities. Expanded disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement will require us to provide the additional disclosures described above.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America (the GAAP hierarchy). This Statement is effective 60 days following the SEC's approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles, which has not yet occurred. We do not expect the adoption of SFAS 162 to have a material effect on our financial statements or related disclosures.