The following discussion and analysis should be read in conjunction with the “Selected Financial Data" and the accompanying financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward looking statements that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially because of a number of risks and uncertainties. Some of these risks and uncertainties are detailed in Part I, Item 1A – “Risk Factors," and elsewhere in this Form 10-K.

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:

• Maximize production from our base oil assets
• Grow oil production from our inventory of organic development projects
• Increase natural gas production that will meet the growing demand for steam generation
• Invest our capital in a disciplined manner and maintain a strong financial position
• Acquire additional resources with an emphasis on crude oil

Notable Items in 2009.

• Achieved total production averaging 30,034 BOE/D, of which 66% is crude oil production, with $135 million of capital investment
• Added 21.5 million BOE of proved reserves, ending 2009 at 235 million BOE
• Drilled 51 wells in the diatomite, increasing production 68% over 2008 levels to average 3,100 BOE/D in 2009
• Acquired property and initiated a steam flood pilot near McKittrick, California with development potential similar to our Poso Creek asset
• Acquired deep rights on our E. Texas Darco property providing an additional 13 Haynesville horizontal locations
• Implemented a new completion method in the Piceance basin, improving well results compared to our historical field average
• Issued $450 million of 10.25% senior unsecured notes due in 2014
• Closed on the sale of our DJ basin assets with proceeds of $154 million
• Completed the sale of our E. Texas midstream assets for $18 million

Notable Items and Expectations for 2010.

• Expecting 2010 capital expenditures between $250 million and $290 million to be fully funded from operating cash flow
• Anticipating average production between 32,250 and 33,000 BOE/D, a 7% to 10% increase over 2009
• Expecting diatomite production to exit 2010 at 5,000 BOE/D
• Entered into an agreement to acquire 6,900 net acres and 11 MMBOE of proved reserves, primarily in the Wolfberry trend in W. Texas for approximately $126 million
• Entered into an agreement to purchase an additional 3,200 acres and 2 MMBOE of proved reserves in the Wolfberry trend for $14 million
• Issued 8 million shares for net proceeds of $224 million to fund the Wolfberry acquisition and reduce debt
• Increased liquidity to over $650 million

Overview of the Fourth Quarter of 2009. We had net income from continuing operations of $13 million, or $0.28 per diluted share, and cash provided from operations of $64 million in the fourth quarter of 2009. Net income from continuing operations includes $3.6 million related to an unrealized gain on ineffective hedges and impairment charges of $4.2 million related to the write-down of a rig and the write-down of expired leases. Also included in the fourth quarter of 2009 are adjustments to correct the prior accounting for our royalties in the amount of $2.7 million, net of tax, which resulted in decreasing our sales of oil and gas and increasing our royalties payable. We drilled 41 gross wells, and capital expenditures, excluding property acquisitions, totaled $40 million. We achieved average production of 29,149 BOE/D in the fourth quarter of 2009, up 3% from the third quarter of 2009.

Revenue and Production.

Revenues. Approximately 88% 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 6% of our revenues are derived from electricity sales from cogeneration facilities which supply approximately 28% 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 6% of our revenues are primarily derived from gas marketing sales which represent our excess capacity on the Rockies Express pipeline which we used to market natural gas for our working interest partners.       Sales of oil and gas decreased 22% in 2009 compared to 2008. The decrease in oil and natural gas prices resulted in a 24% decrease in sales of oil and natural gas. The decrease was offset by an increase in production volumes. Approximately 66% of our oil and gas sales volumes in 2009 were crude oil, with 56% of the crude oil being heavy oil produced in California which was sold under various contracts with prices tied to the San Joaquin posted price.

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

		2009				2008				2007
Sales of oil		$	420			$	519			$	385
Sales of gas			87				130				48
Total sales of oil and gas		$	507			$	649			$	433
Sales of electricity			36				64				56
Gas marketing			23				36				-
Gain on derivatives			6				-				-
Gain (loss) on sale of assets (1)			1				(1	)			54
Interest and other income, net			2				3				4
Total revenues and other income		$	575			$	751			$	547
Net income from continuing operations		$	60			$	122			$	127
Diluted earnings per share from continuing operations		$	1.30			$	2.66			$	2.81

      (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, 2009				December 31, 2008				September 30, 2009
Sales of oil		$	109			$	97				$	109
Sales of gas			24				38					18
Total sales of oil and gas		$	133			$	135				$	127
Sales of electricity			10				12					9
Gas marketing			5				8					5
Gain (loss) on sale of assets			-				(2		)			1
Interest and other income, net			-				1					1
Total revenues and other income		$	148			$	154				$	143
Net income (loss) from continuing operations		$	13			$	(11	)	)		$	18
Diluted earnings (loss) per share from continuing operations		$	0.28			$	(0.24		)		$	0.40

The following table is for the years ended December 31:

			2009	%		2008	%		2007	%
Oil and Gas
Heavy Oil Production (Bbl/D)			16,842	56		16,633	52		16,170	60
Light Oil Production (Bbl/D)			2,846	10		3,697	12		3,583	13
Total Oil Production (Bbl/D)			19,688	66		20,330	64		19,753	73
Natural Gas Production (Mcf/D)			62,074	34		69,834	36		42,895	27
Total Production (BOE/D)			30,034	100		31,968	100		26,902	100
Less DJ basin production			765			3,295			3,123
Production – Continuing operations (BOE/D)			29,269			28,673			23,779
Oil and gas, per BOE, for continuing operations:
Average sales price before hedging		$	41.23		$	73.64		$	52.30
Average sales price after hedging			46.59			62.03			49.80
Oil, per Bbl for continuing operations:
Average WTI price		$	62.09		$	99.75		$	72.41
Price sensitive royalties			(2.04	)		(2.95	)		(5.03	)
Gravity differential and other			(9.08	)		(11.32	)		(9.53	)
Crude oil hedges reported with Sales of oil and gas			7.47			(16.89	)		(4.61	)
Crude oil hedges reported with Gain on derivatives	(a)		(0.92	)		-			-
Correction to royalties payable	(b)		(0.24	)		1.42			-
Average oil sales price after hedging		$	57.28		$	70.01		$	53.24
Natural gas price for continuing operations:
Average Henry Hub price per MMBtu		$	4.00		$	9.04		$	7.12
Conversion to Mcf			0.20			0.46			.36
Natural gas hedges reported with Sales of oil and gas			0.53			0.20			1.31
Natural gas hedges reported with Gain on derivatives	(a)		(0.04	)		-			-
Location, quality differentials and other			(0.60	)		(2.59	)		(3.31	)
Average gas sales price after hedging		$	4.09		$	7.11		$	5.48

(a)Includes cash settlements on hedges for which the Company has not elected hedge accounting that are recorded in “Gain (Loss) on hedges.

(b) Included in 2009 is a correction to one of our royalties in the amount of $1.9 million, which resulted in decreasing our sales of oil and gas and increasing our royalties payable.

      Production from continuing operations increased 2%, or 596 BOE/D, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase is the result of additional development activities during the year in the diatomite and the benefit of a full year of E. Texas production in 2009. These increases were offset by decreases in the Uinta basin, the S. Midway field and the Piceance basin where there was very little capital activity during the year.

      Production from continuing operations increased 21%, or 4,894 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 2008 resulted in production 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, 2009	%		December 31, 2008	%		September 30, 2009	%
Oil and Gas
Heavy Oil Production (Bbl/D)			17,280	60		15,999	45		16,780	59
Light Oil Production (Bbl/D)			2,719	9		3,659	10		2,530	9
Total Oil Production (Bbl/D)			19,999	69		19,658	55		19,310	68
Natural Gas Production (Mcf/D)			54,899	31		95,548	45		54,637	32
Total production (BOE/D)			29,149	100		35,583	100		28,417	100
Less DJ basin production			-			3,415			-
Production – Continuing operations (BOE/D)			29,149			32,168			28,417
Oil and gas, per BOE, for continuing operations :
Average sales price before hedging		$	50.76		$	40.61		$	45.41
Average sales price after hedging			47.08			45.56			46.39
Oil, per Bbl:
Average WTI price		$	76.13		$	59.08		$	68.24
Price sensitive royalties			(2.64	)		(1.69	)		(2.36	)
Gravity differential and other			(9.63	)		(8.55	)		(8.78	)
Crude oil hedges reported with Sales of oil and gas			(3.96	)		-			2.28
Crude oil hedges reported with Gain on derivatives	(a)		(2.16	)		4.69			(1.41	)
Correction to royalties payable	(b)		(1.78	)		-			-
Average oil sales price after hedging		$	55.96		$	53.53		$	57.97
Natural gas price for continuing operations:
Average Henry Hub price per MMBtu		$	4.17		$	6.95		$	3.39
Conversion to Mcf			0.21			.35			0.17
Natural gas hedges reported with Sales of oil and gas			0.40			-			0.27
Natural gas hedges reported with Gain on derivatives	(a)		(0.11	)		.89			(0.07	)
Location, quality differentials and other			(0.12	)		(2.67	)		(0.28	)
Average gas sales price after hedging		$	4.55		$	5.52		$	3.48

(a) Includes cash settlements on hedges for which the Company has not elected hedge accounting that are recorded in “Gain (Loss) on hedges."

(b) Included in the fourth quarter of 2009 is a correction to one of our royalties in the amount of $3.3 million, which resulted in decreasing our sales of oil and gas and increasing our royalties payable.

Production from continuing operations decreased 9%, or 3,019 BOE/D, for the fourth quarter of 2009 compared to the fourth quarter of 2008, primarily due to production decreases in the Uinta basin and the Piceance basin where there was very little capital activity during 2009.

      Production from continuing operations increased 3%, or 732 BOE/D, for the fourth quarter of 2009 compared to the third quarter of 2009 primarily due to development activities during the fourth quarter of 2009 that resulted in an increase in the diatomite.

Electricity. Electricity revenues and operating costs decreased in the year ended 2009 compared to the year ended 2008 as a result of 34% lower electricity prices and 56% lower natural gas prices. Electricity revenues and operating costs increased in the year ended 2008 compared to the year ended 2007 due to 18% higher electricity prices and 27% higher natural gas prices. We purchased approximately 27 MMBtu/D as fuel for use in our cogeneration facilities for the year ended December 31, 2009 and the year ended December 31, 2008. In 2009 and 2008, our electricity operations improved partially from the lower cost of the 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 decreased during 2009 compared to 2008 and in 2008 compared to 2007.

The following table is for the years ended December 31:

		2009				2008				2007
Electricity
Revenues (in millions)		$	36.1			$	63.5			$	55.6
Operating costs (in millions)		$	31.4			$	54.9			$	46.0
Decrease to total oil and gas operating expenses per barrel		$	0.43			$	0.74			$	0.98
Electric power produced - MWh/D			2,098				2,063				2,133
Electric power sold - MWh/D			1,907				1,873				1,932
Average sales price/MWh (no hedging was in place)		$	60.99			$	92.98			$	78.62
Fuel gas cost/MMBtu (including transportation)		$	3.75			$	7.95			$	6.08

Royalties. A price-sensitive royalty burdens certain of our S. Midway properties which produced approximately 2,100 BOE/D in 2009. This royalty was 75% of the amount of the heavy oil posted price above a base price which was $16.43 in 2009. 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 2009 and expect to meet the requirement going forward. This base price escalates at 2% annually, thus the threshold price is $16.76 per barrel in 2010. Liabilities payable for these royalties were $15 million, $22 million and $36 million in the years ended December 31, 2009, 2008 and 2007, respectively.

      Included in the fourth quarter of 2009 are adjustments to correct the prior accounting for our royalties in the amount of $3.3 million, which resulted in decreasing our sales of oil and gas and increasing our royalties payable. Management concluded the impact was immaterial to the current and prior periods.

      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 and Other Expenses.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008:

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

	Amount per BOE								Amount (in thousands)
	2009			2008		Change			2009			2008			Change
Operating costs - oil and gas production	$	14.66		$	17.99		(19)	%	$	156,612		$	188,758		(17)	%
Production taxes		1.70			2.56		(34)	%		18,144			26,876		(32)	%
DD&A - oil and gas production		13.10			11.97		9	%		139,919			125,595		11	%
G&A		4.61			5.17		(11)	%		49,237			54,279		(9)	%
Interest expense		4.67			2.28		105	%		49,923			23,942		109	%
Total	$	38.74		$	39.97		(3)	%	$	413,835		$	419,450		(1)	%

• Operating costs: Steam costs are the primary variable component of our operating costs and fluctuate based on the amount of steam we inject and the price of fuel used to generate steam. The following table presents steam information:

	2009	2008	Change
Average volume of steam injected (Bbl/D)	109,153	99,908	9%
Fuel gas cost/MMBtu (including transportation)	3.75	7.95	(53)%
Approximate net fuel gas volume consumed in steam generation (MMBtu/D)	30,462	26,826	14%

Operating costs decreased $32.1 million, or 17%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The decrease is primarily the result of a 53% decrease in fuel gas cost which is directly correlated to a decrease in natural gas prices.

• Production taxes: Production taxes have decreased over the last year as the value of our oil and natural gas has decreased. Severance taxes in Utah, Colorado and Texas 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 natural gas prices generally.
• Depreciation, depletion and amortization: DD&A increased per BOE in 2009 by 9% from 2008 due to an increase in the contribution of our development properties with higher drilling and leasehold acquisition costs and the integration of our E. Texas assets which have higher finding and development costs than our legacy assets.
• General and administrative: Approximately 65% of our G&A is related to compensation. The primary reason for the decrease in G&A during 2009 was a 20% decrease in employee headcount primarily associated with the sale of our DJ assets, offset by a liability of $2.1 million that was established during the second quarter of 2009 for a regulatory compliance matter. 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 in 2008 was $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 total outstanding borrowings were approximately $1.0 billion at December 31, 2009 compared to $1.2 billion at December 31, 2008. The increase in interest expense between periods is due to the amortization of additional debt issuance costs and amortization of the net discount, which were incurred in June 2009 and August 2009 in connection with the issuance of our 10.25% senior notes due in 2014 as well as a higher interest rate on the 10.25% senior notes issued compared to the interest rate on the credit facility.
• Debt extinguishment costs: During the years ended December 31, 2009 and 2008, we recorded debt extinguishment costs of $10.8 million and $0, respectively. These costs related to credit facility borrowing base changes, issuance of senior unsecured notes, and pay off of our second lien term loan.
• Dry hole, abandonment, impairment and exploration: In 2009 we had dry hole, abandonment and impairment charges of $5.2 million primarily due to a $4.2 million impairment charge related to the write-down of a rig to its fair market value (see Note 2 Fair Value Measurement). We incurred exploration costs in 2009 of $0.2 million compared to $0.6 million in 2008. These costs consist primarily of geological and geophysical costs.
• In 2008 we had dry hole, abandonment, impairment and exploration charges of $10.5 million consisting primarily of $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. 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. We incurred exploration costs of $0.6 million in both 2008 and 2007. These costs consist primarily of geological and geophysical costs.
• Bad debt expense. We recorded $0 and $38.7 million of bad debt expense for the years ended December 31, 2009 and 2008, respectively. The $38.7 million recorded in bad debt expense for the year ended December 31, 2008 was related to the bankruptcy of BWOC.
• Income Tax Expense. The effective tax rate for the year ended December 31, 2009 and 2008 was 32% and 36% , respectively. The change in the effective tax rate between periods is due to reduced state rates and the reduction in our liability related to uncertain tax positions. Our estimated annual effective tax rate varies from the 35% federal statutory rate due to the effects of state income taxes and estimated permanent differences. See Note 8 to the financial statements.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007:

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	$	17.99		$	15.09		19	%	$	188,758		$	130,940		44	%
Production taxes		2.56			1.69		51	%		26,876			14,651		83	%
DD&A - oil and gas production		11.97			9.55		25	%		125,595			82,861		52	%
G&A		5.17			4.57		13	%		54,279			39,663		37	%
Interest expense		2.28			1.74		31	%		23,942			15,069		59	%
Total	$	39.97		$	32.64		22	%	$	419,450		$	283,184		48	%

      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 $58 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%



• Production taxes: 2008 production taxes increased over 2007 as the value of our oil and natural gas 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 2008 by 25% from 2007 due to an increase in capital spending in fields with higher drilling and leasehold acquisition costs.
• General and administrative: In 2008, approximately 65% of our G&A was 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 incurred during the fourth quarter of 2008. $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, were $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 was capitalized.
• Dry hole, abandonment, impairment and exploration: In 2008 we had dry hole, abandonment and impairment charges of $10.5 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 $0.6 million in 2008 compared to $0.6 million in 2007 . These costs consist primarily of geological and geophysical costs. 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 and determined that no impairment was necessary.
  
  In 2007 we had dry hole, abandonment, impairment and exploration charges of $8.4 million consisting primarily of 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.

Hedging. See Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 3 to the financial statements.

Estimated 2010 Oil and Gas Operating, G&A and Interest Expenses. We estimate our 2010 production volume will range between 32,250 BOE/D and 33,000 BOE/D. Based on WTI of $60.00 and NYMEX HH of $5.00 MMBtu, we expect our expenses to be within the following ranges:

		Amount per BOE
		Anticipated
		range in 2010			2009			2008
Operating costs-oil and gas production (1)		$	17.00 – 20.00		$	14.66		$	17.99
Production taxes (2)			1.75 – 2.25			1.70			2.56
DD&A			12.00 – 14.00			13.10			11.97
G&A			4.00 – 4.50			4.61			5.17
Interest expense			4.00 – 5.00			4.67			2.28
Total		$	38.75 – 45.75		$	38.74		$	39.97

(1) We expect operating costs to increase in 2010 as compared to 2009 due to higher natural gas prices which are the primary driver of our cost to generate steam in California, offset in part by our overall cost reduction efforts.

(2) We expect production taxes will be higher on a per BOE basis as our average realized price increases due to higher commodity prices and a majority of these costs are based on a percentage of our revenue.

Financial Condition, Liquidity and Capital Resources.

      Our exploration, development, and acquisition activities require us to make significant operating and capital expenditures. Historically, we have used cash flow from operations and our bank credit facilities as our primary sources of liquidity. We have also used the private and public markets as other sources of financing and, as market conditions have permitted, we have engaged in asset monetization transactions.

      Changes in the market prices for oil and natural gas directly impact our level of cash flow generated from operations. We employ a hedging strategy in an attempt to minimize the adverse effects of wide fluctuations in the commodity prices on our cash flow. As of December 31, 2009 we have approximately 75% and 40% of our expected 2010 and 2011 oil production hedged in the form of swaps and collars and we have approximately 30% and 10% of our 2010 and 2011 expected natural gas production hedged in the form of swaps and collars. This level of hedging will provide a measure of certainty of the cash flow that we will receive for a portion of our production in 2010 and 2011. In the future, we may determine to increase or decrease our hedging positions. Most of our derivatives counterparties were commercial banks that are parties to our credit facilities, or their affiliates. See Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk" below for further details concerning our hedging activities.

      We have a $1.5 billion senior secured revolving credit facility with a current borrowing base of $938 million and $562 million of available borrowing capacity. At December 31, 2009, we had $372 million in borrowings and $4 million in letters of credit outstanding under the credit facility. Our borrowing base is subject to semi-annual redeterminations in April and October of each year. The borrowing base is determined by the lenders (a syndicate of banks), taking into consideration the estimated value of our proved oil and gas reserves based on pricing models determined by the lenders.

      In May 2009, we issued $325 million principal amount of 10.25% senior notes due 2014 and in August 2009 we issued an additional $125 million principal amount of our 10.25% senior notes due 2014.

      See Note 7 to the financial statements for more information regarding our senior secured revolving credit facility, our 10.25% senior notes due 2014 and our 8.25% senior subordinated notes due 2016.

      In January 2010, we completed the sale of 8 million shares of Class A common stock at a public offering at a price of $29.25 per share. The net proceeds of $224 million will be used to fund the Wolfberry acquisition and for general corporate purposes. Pending application of the proceeds for such purposes, we reduced outstanding borrowings under our senior secured revolving credit facility. Subsequent to these transactions the amount available under our credit facility will be approximately $660 million.

      Our ability to access the debt and equity capital markets on economical terms is affected by general economic conditions, the financial markets, the credit ratings assigned to our debt by independent credit rating agencies, our operational and financial performance, the value and performance of equity and debt securities, prevailing commodity prices, and other macroeconomic factors outside of our control.

      We have also engaged in asset dispositions to generate additional cash to fund expenditures and further enhance our financial flexibility. In April 2009, we sold our DJ basin assets and related hedges for $154 million before customary closing adjustments and in July 2009, we completed the sale of our E. Texas gas gathering system for $18.4 million in cash.

Historical Cash Flows

      Cash flows provided by operating activities are primarily affected by the price of crude oil and natural gas, production volumes, and changes in working capital. The decrease in net cash provided by operating activities of $197 million in 2009 compared to 2008 is primarily due to lower realized commodity sales prices in 2009 compared to 2008. The increase in net cash provided by operating activities of $171 million in 2008 compared to 2007 is primarily due to higher realized commodity sales prices and higher production volumes in 2008 compared to 2007.

      Cash flows used by investing activities are primarily comprised of acquisition, exploration and development of oil and gas properties net of dispositions of oil and gas properties. The decrease in net cash used in investing activities of $1.0 billion in 2009 compared to 2008 is due to the 2008 E. Texas acquisition, a decrease in development expenditures in 2009 and the 2009 sale of our DJ basin assets and related hedges. The increase in net cash used in investing activities of $800 million in 2008 compared to 2007 is due to the 2008 E. Texas acquisition and an increase in development expenditures in 2008 compared to 2007.

      Net cash used in financing activities in 2009 included the repayment of the senior secured revolving credit facility and the money market line of credit of $574 million, debt issuance costs of $24 million and dividends paid of $14 million, offset by the issuance of $450 million of 10.25% senior notes due 2014 for net proceeds of $424 million and proceeds from the sale of our E. Texas gathering system of $18 million. Net cash provided by financing activities in 2008 included net borrowings under the senior secured revolving credit facility and money market line of credit of $698 million, offset by dividends paid of $13 million and debt issuance costs of $11 million. Net cash provided by financing activities in 2007 included net borrowings under the senior secured revolving credit facility and money market line of credit of $53 million, offset by dividends paid of $13 million.

Capital Expenditures

      Our capital expenditures for 2009 totaled $135 million for development and were fully funded from our $213 million operating cash flow. We also funded $13 million in acquisitions through borrowing on our senior secured credit facility and capitalized $30 million of interest. This compares to our total capital expenditures for 2008 of $398 million for development, which were fully funded from our $410 million operating cash flow. We also funded $668 million in acquisitions in 2008 through additional borrowing on our senior secured credit facility and capitalized $23 million of interest.

      Excluding the acquisition of new properties, for 2010 we have established a commodity sensitive capital program that will range between $250 million and $290 million, which we expect to fund fully out of operating cash flow. We expect our 2010 capital program will allow us to increase production from 2009 levels to average 2010 production between 32,250 BOE/D and 33,000 BOE/D.

      We believe that our cash flow provided by operating activities and funds available under our credit facilities will be sufficient to fund our operating and capital expenditures budget and our short-term contractual operations during 2010. However, if our revenue and cash flow decrease in the future as a result of further deterioration in economic conditions or an adverse change in commodity prices, we may have to reduce our spending levels. As we have operational control of all of our assets and we have limited drilling commitments, we believe that we have the financial flexibility to adjust our spending levels, if necessary, to meet our financial obligations.

Contractual Obligations.

      Our contractual obligations as of December 31, 2009 are as follows (in millions):

		Total		2010		2011		2012		2013		2014		Thereafter
Long-term debt and interest	$	1,359.7	$	71.9	$	71.9	$	437.3	$	62.6	$	485.7	$	230.3
Abandonment obligations		43.5		2.8		2.8		2.9		2.9		2.8		29.3
Operating lease obligations		16.0		2.4		2.4		2.5		2.5		2.5		3.7
Drilling and rig obligations		52.1		13.9		27.7		2.1		2.1		6.3		-
Firm natural gas transportation contracts		136.8		19.7		19.7		17.9		15.7		14.8		49.0
Total	$	1,608.1	$	110.7	$	124.5	$	462.7	$	85.8	$	512.1	$	312.3

Long-term debt and interest – Borrowing under our senior secured revolving credit facility and related interest may be paid before the facility’s maturity date without significant penalty. Our 8.25% senior subordinated notes and related interest 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, 2009, 2008 and 2007 was $2.1 million, $1.7 million and $1.5 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 - We amended and restated our Utah Lake Canyon project in December 2009 and have a 14 gross well drilling commitment over the amended term (December 2009 to December 2014). Our minimum obligation under our exploration and development agreement is $14.7 million as of December 31, 2009. Also included in the table above are contractual obligations on our Piceance assets in Colorado. We must spud 120 wells by February 2011 to avoid penalties of $0.2 million per well. We expect to meet all obligations but our ability to meet this commitment depends on the capital resources available to us to fund our activities to develop these assets on the schedule required to avoid penalties or loss of related leases.

Drilling rig obligations - We are obligated in operating lease agreements for the use of four drilling rigs, one in California, one in Utah, one in the Piceance basin and one in E. Texas.

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 are a party to a crude oil sales contract through June 30, 2013 with a refiner for the purchase of a minimum of 5,000 Bbl/D of our Uinta light crude oil. Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI. While the contractual differentials under this contract may be less favorable at times than the posted differential, demand for the Company’s 40 degree black wax (light) crude oil can vary seasonally and this contract provides a stable outlet for the Company’s crude oil. Gross oil production from our Uinta properties averaged approximately 2,700 Bbl/D in 2009. Please see “Item 1A. Risk Factors–We may not be able to deliver minimum crude oil volumes required by our sales contract."

      In addition, Berry has signed two precedent agreements with El Paso Corporation for an average of 35,000 MMBtu/D of firm transportation on the proposed Ruby Pipeline from Opal, Wyoming to Malin, Oregon. While it is not certain that this new line will be constructed, the expectation is that the project will proceed and be in service by 2011. A component of these agreements is currently in dispute and may result in a termination of our contracts for capacity on this pipeline in which case we will make alternative arrangements for the transportation and marketing of our production. We do not believe the termination of these contracts will result in monetary damages. Please see “Item 1A. Risk Factors– If third-party pipelines interconnected to our natural gas wells and gathering facilities become partially or fully unavailable to transport our natural gas, our results of operations and financial condition could be adversely affected."

      As of December 31, 2009, the Company had a gross liability for uncertain tax benefits of $6.1 million and an additional $0.7 million of interest related to its uncertain tax positions. At this time, the Company is unable to make a reasonably reliable estimate of the timing of payments in individual years due to uncertainties in the timing of tax audit outcomes; therefore, such amounts are not included in the above contractual obligation table.

Critical Accounting Policies and Estimates.

      The preparation of financial statements in conformity with generally accepted accounting principles requires management to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as disclosure of contingent assets and liabilities at the date of our financial statements Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies is detailed in Note 1 to our financial statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management.

      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, which are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Our oil and gas reserves are based on estimates prepared by independent engineering consultants. Reserve engineering is a 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 is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. 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. Changes in reserve estimates are applied on a prospective basis. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher costs fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

Impairment of Oil and Gas Properties. 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 periodically enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility. We also enter into derivative contracts to mitigate the risk of interest rate fluctuations. The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of income because changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value and any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, whether or not the forecasted hedged transaction will occur, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements changes as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. Effective January 1, 2010, we have elected to de-designate all of our commodity and interest rate contracts that had previously been designated as cash flow hedges as of December 31, 2009 and have elected to discontinue hedge accounting prospectively. At December 31, 2009, Accumulated other comprehensive loss (AOCL) consisted of $97 million ($60 million after tax) of unrealized losses, representing the mark-to-market value of the Company’s cash flow hedges as of the balance sheet date, less any ineffectiveness recognized. As a result of discontinuing hedge accounting on January 1, 2010, such mark-to-market values at December 31, 2009 are frozen in AOCL as of the de-designation date and will be reclassified into earnings in future periods as the original hedged transactions affect earnings. The Company expects to reclassify into earnings from AOCL the frozen value related to de-designated commodity hedges during the next three years.

Income Taxes and Uncertain Tax Positions. Income taxes are provided for the tax effects of transactions reported in the financial statements and consists of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statements and income tax reporting. We routinely assess the realizability of our deferred tax assets and a valuation allowance is recognized if it is determined that deferred tax assets may not be fully utilized in future periods. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). There can be no assurance that facts and circumstances will not materially change and require us to establish deferred tax asset valuation allowances in a future period. We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. We recognize certain tax positions that meet a more-likely-than not recognition threshold. If we ultimately determine that the payment of these liabilities will be unnecessary, we will reverse the liability and recognize a tax benefit during the period in which we determine the liability no longer applies.

Asset Retirement Obligations. Our asset retirement obligations (AROs) consist primarily of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of the ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted-risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capital cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas field.

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. 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 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. The accounting for business combinations is complex and involves the use of significant judgment. Under the acquisition method of accounting, assets and liabilities of an acquired business are recognized at fair value. 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.

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.

Recent Accounting Standards Updates.

In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-06 “Improving Disclosures about Fair Value Measurements." The ASU amends previously issued authoritative guidance and requires new disclosures and clarifies existing disclosures and is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the rollforward activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. As this requires only additional disclosures, the guidance will have no impact on our financial position or results of operations.

 

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