BERRY PETROLEUM CO - 10-Q Quarterly Report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES (X) NO ( )

The number of shares of each of the registrant’s classes of capital stock outstanding as of March 31, 2005, was 21,164,726 shares of Class A Common Stock ($.01 par value) and 898,892 shares of Class B Stock ($.01 par value). All of the Class B Stock is held by a shareholder who owns in excess of 5% of the outstanding stock of the registrant.

	March 31,			December 31,
	2005			2004
	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	18,150		$	16,690
Short-term investments available for sale		659			659
Accounts receivable		45,127			34,621
Deferred income taxes		13,999			3,558
Fair value of derivatives		4,281			3,243
Prepaid expenses and other		2,265			2,230
Total current assets		84,481			61,001

Oil and gas properties (successful efforts basis), buildings and equipment, net		462,407			338,706
Deposit on potential property acquisitions		3,322			10,221
Other assets		2,587			2,176

	$	552,797		$	412,104
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	30,992		$	27,750
Revenue and royalties payable		10,374			23,945
Accrued liabilities		7,680			6,132
Income taxes payable		2,124			1,067
Fair value of derivatives		34,458			5,947
Total current liabilities		85,628			64,841

Long-term liabilities:
Deferred income taxes		51,783			47,963
Long-term debt		138,000			28,000
Abandonment obligations		9,369			8,214
Fair value of derivatives		2,770			-
		201,922			84,177
Shareholders' equity:
Preferred stock, $.01 par value; 2,000,000 shares authorized; no shares outstanding		-			-
Capital stock, $.01 par value;
Class A Common Stock, 50,000,000 shares authorized; 21,164,726 shares issued and outstanding (21,060,420 in 2004)		212			210
Class B Stock, 1,500,000 shares authorized; 898,892 shares issued and outstanding (liquidation preference of $899)		9			9
Capital in excess of par value		61,051			60,676
Accumulated other comprehensive loss		(19,066	)		(987	)
Retained earnings		223,041			203,178
Total shareholders' equity		265,247			263,086

	$	552,797		$	412,104

	2005		2004
Revenues:
Sales of oil and gas	$	75,391	$	45,205
Sales of electricity		12,456		11,934
Interest and other income, net		148		203
		87,995		57,342
Expenses:
Operating costs - oil and gas production		23,407		16,782
Operating costs - electricity generation		13,358		12,403
Exploration costs		561		-
Depreciation, depletion and amortization - oil and gas production		8,527		6,354
Depreciation, depletion and amortization - electricity generation		772		855
General and administrative		4,820		7,344
Dry hole, abandonment and impairment		2,021		-
Interest		1,162		531
		54,628		44,269

Income before income taxes		33,367		13,073
Provision for income taxes		10,862		2,709

Net income	$	22,505	$	10,364

Basic net income per share	$	1.02	$	.48
Diluted net income per share	$	1.00	$	.47
Cash dividends per share	$	.12	$	.11
Weighted average number of shares of capital stock outstanding used to calculate basic net income per share		21,981		21,817
Effect of dilutive securities:
Stock options		433		215
Other		56		51

Weighted average number of shares of capital stock used to calculate diluted net income per share		22,470		22,083

	2005			2004
Net income	$	22,505		$	10,364
Unrealized gains (losses) on derivatives, (net of income taxes of $12,165and $1,135 in 2005 and 2004, respectively)		(18,831	)		(1,703	)
Reclassification of unrealized losses on derivatives included in net income (net of income taxes of ($501) and ($1,378) in 2005 and 2004, respectively)		752			2,067
Comprehensive income	$	4,426		$	10,728

	2005			2004
Cash flows from operating activities:
Net income	$	22,505		$	10,364
Depreciation, depletion and amortization		9,299			7,209
Abandonment costs		(213	)		(105	)
Deferred income taxes, net		5,042			2,270
Stock-based compensation expense		376			3,240
Other, net		89			147
Increase in current assets other than cash, cash equivalents and short-term investments		(10,541	)		(4,490	)
Increase (decrease) in current liabilities		(7,305	)		931

Net cash provided by operating activities		19,252			19,566

Cash flows from investing activities:
Capital expenditures, excluding property acquisitions		(15,681	)		(18,440	)
Property acquisitions		(109,469	)		-

Net cash used in investing activities		(125,150	)		(18,440	)

Cash flows from financing activities:
Proceeds from issuance of long-term debt		116,000			-
Payment of long-term debt		(6,000	)		-
Dividends paid		(2,642	)		(2,401	)

Net cash provided by (used in) financing activities		107,358			(2,401	)

Net increase (decrease) in cash and cash equivalents		1,460			(1,275	)

Cash and cash equivalents at beginning of year		16,690			10,658

Cash and cash equivalents at end of period	$	18,150		$	9,383

Supplemental non-cash activity:
Increase (decrease) in fair value of derivatives:
Current (net of income taxes of $10,756 and $151 in 2005 and 2004, respectively)	$	(16,717	)	$	(227	)
Non-current (net of income taxes of $908 and ($394) in 2005 and 2004, respectively)		(1,362	)		591

Net (decrease) increase to accumulated other comprehensive income	$	(18,079	)	$	364

1. All adjustments which are, in the opinion of Management, necessary for a fair statement of the Company’s financial position at March 31, 2005 and December 31, 2004 and results of operations and cash flows for the three-month periods ended March 31, 2005 and 2004 have been included. All such adjustments are of a normal recurring nature. The results of operations and cash flows are not necessarily indicative of the results for a full year.

2. The accompanying unaudited condensed financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2004 financial statements. The December 31, 2004 Form 10-K should be read in conjunction herewith. The year-end condensed balance sheet was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

3. Fair value of derivatives. Due to the increase in NYMEX future strip crude oil prices at March 31, 2005 from December 31, 2004, the Company’s fair value of derivatives liability increased to $37.2 million at March 31, 2005 from $5.9 million at December 31, 2004. The unrealized loss, net of income taxes, of $18.8 million is recorded in other comprehensive income on the Company’s balance sheet at March 31, 2005. The deferred tax benefit of the unrealized loss is reflected as an addition to the deferred income tax asset on the Company’s balance sheet.

4. Asset Retirement Obligations. The Company follows SFAS No. 143, Accounting for Asset Retirement Obligations, for recording future site restoration costs related to its oil and gas properties. Under SFAS 143, the following table summarizes the change in abandonment obligation for the three months ended March 31, 2005 and 2004, respectively, (in thousands):

5. Certain amounts in the condensed income statement for the three months ended March 31, 2004 have been reclassified to conform to the 2005 presentation. In the fourth quarter of 2004, the Company concluded that it was appropriate to revise its allocation of cogeneration costs to oil and gas operations. The revised allocation is based on the thermal efficiency (of fuel to electricity and steam) of the Company’s cogeneration facilities. In addition, in 2005 the Company is reclassifying technical labor between general and administrative expenses and operating costs - oil and gas. Accordingly, the Company has revised prior classifications for the three months ended March 31, 2004 as follows (in thousands):

	2004
Operating costs - oil and gas
As previously reported	$	18,020
As revised		16,782
Difference	$	1,238

Operating costs - electricity generation
As previously reported	$	11,934
As revised		12,403
Difference	$	(469	)

DD&A - oil and gas
As previously reported	$	7,209
As revised		6,354
Difference	$	855

DD&A - electricity generation
As previously reported	$	-
As revised		855
Difference	$	(855	)

G&A expenses as previously reported	$	6,575
As revised		7,344
Difference	$	(769	)

6. Acquisitions. On January 27, 2005, the Company acquired certain interests (J-W Acquisition) in the Niobrara field in northeastern Colorado for approximately $105 million. The properties consist of approximately 127,000 gross (69,500 net) acres. Current production is approximately 9 MMcf of natural gas per day, with estimated proved reserves of 87 Bcf. The acquisition also includes approximately 200 miles of a pipeline gathering system and gas compression facilities for delivery into interstate gas lines. In 2005, the Company plans to drill approximately 60 gross wells and complete 23 workovers as part of the development of this asset. The Company borrowed $105 million under its $200 million credit facility to fund this acquisition.

7. Dry hole, abandonment and impairment. At December 31, 2004, the Company was in the process of drilling one exploratory well on its Midway-Sunset property and one exploratory well on its Coyote Flats prospect. These two wells were determined non-commercial in February 2005. Costs of $.5 million which were incurred as of December 31, 2004 were charged to expense in 2004. The remaining costs related to these wells were approximately $2.0 million and were charged to expense during the first quarter of 2005 and are reflected on the Company’s condensed income statement under dry hole, abandonment and impairment.

The unaudited pro forma results presented below for the three months ended March 31, 2005 and 2004 have been prepared to give effect to the J-W Acquisition on the Company’s results of operations under the purchase method of accounting as if it had been consummated on January 1, 2004. The unaudited pro forma results do not purport to represent the results of operations that actually would have occurred on such date or to project the Company’s results of operations for any future date or period:

The following discussion provides information on the results of operations for each of the three month periods ended March 31, 2005, December 31, 2004 and March 31, 2004 and the financial condition, liquidity and capital resources as of March 31, 2005 and December 31, 2004. The financial statements and the notes thereto contain detailed information that should be referred to in conjunction with this discussion.

The profitability of the Company's operations in any particular accounting period will be directly related to the average realized prices of oil, gas and electricity sold, the type and volume of oil and gas produced and electricity generated and the results of development, exploitation, acquisition and exploration activities. The average realized prices for natural gas and electricity will fluctuate from one period to another due to regional market conditions and other factors, while oil prices will be predominantly influenced by world supply and demand. The aggregate amount of oil and gas produced may fluctuate based on the success of development and exploitation of oil and gas reserves pursuant to current reservoir management. The cost of natural gas used in the Company's steaming operations and electrical generation, production rates, labor, equipment costs, maintenance expenses and production taxes are expected to be the principal influences on operating costs. Accordingly, the results of operations of the Company may fluctuate from period to period based on the foregoing principal factors, among others.

The Company earned net income of $22.5 million, or $1.00 per share (diluted), on revenues of $88 million in the first quarter of 2005, up 116% from net income of $10.4 million, or $.47 per share (diluted), on revenues of $57.3 million in the first quarter of 2004, but down 11% from net income of $25.3 million, or $1.13 per share (diluted), on revenues of $80.4 million in the fourth quarter of 2004. In the fourth quarter of 2004, the Company recorded a non-recurring net tax benefit of approximately $2.3 million, primarily due to the recognition of deferred tax assets related to certain properties and other tax items.

	Mar 31 2005		%		Dec 31 2004		%		Mar 31 2004		%
Oil and Gas
Oil Production (Bbl/D)		19,156		87		19,896		93		18,392		95
Natural Gas Production (Mcf/D)		17,347		13		9,084		7		6,019		5
Total (BOE/D)		22,047		100		21,410		100		19,395		100

Per BOE:
Average sales price before hedging	$	40.89			$	39.54			$	28.26
Average sales price after hedging		37.81				34.62				25.58

Oil, per Bbl:
Average WTI price	$	49.85			$	48.28			$	35.15
Less:
Price sensitive royalties		3.12				3.18				2.38
Gravity differential		5.22				5.88				4.95
Crude oil hedges		3.54				5.29				2.78
Average sales price	$	37.97			$	33.93			$	25.04

Gas, per Mmbtu:
Average Henry Hub price	$	6.27			$	7.15			$	5.71
Less:
Location differentials		0.79				1.56				0.89
Average sales price	$	5.48			$	5.59			$	4.82

Electricity
Electric power produced - MWh/D		2,117				2,148				2,167
Electric power sold - MWh/D		1,918				1,944				1,956
Average sales price/MWh	$	68.87			$	70.20			$	67.05
Fuel gas cost/MMBtu (excluding transportation)	$	5.74			$	5.98			$	5.09

Oil and Gas Production. The Company’s revenues may vary significantly from period to period as a result of changes in commodity prices and/or production volumes. Sales of oil and gas were $75.4 million in the first quarter of 2005, up 12% from $67.4 million in the fourth quarter of 2004 and up 67% from $45.2 million in the first quarter of 2004. This improvement was due to increases in both oil and gas prices and production levels. The average sales price per BOE, net of hedging, of the Company’s oil and gas was $37.81 in the first quarter of 2005, up 9% from $34.62 in the fourth quarter of 2004 and up 48% from $25.58 in the first quarter of 2004. Oil and gas production volumes in the first quarter of 2005 averaged 22,047 BOE/D, up 3% from 21,410 BOE/D in the fourth quarter of 2004 and up 14% from 19,395 BOE/D in the first quarter of 2004 due primarily to the acquisition of the Niobrara field in January 2005 and recent development activities. For all of 2005, the Company anticipates production to average approximately 23,000 BOE/D.

In 2004, approximately 94% of the Company’s oil and gas sales volumes were crude oil. In the first quarter of 2005, crude oil represented 87% of the Company’s oil and gas production. The Company’s objective is to diversify its predominantly heavy crude oil base with light crude oil and natural gas. With the Company’s continued development of its Brundage Canyon assets and the development of its other newly acquired properties in the Niobrara fields in northeastern Colorado, the Company anticipates natural gas production in all of 2005 to more than double its 2004 level of 7,757 Mcf/D and represent a continuing higher percentage of its production mix going forward.

As a result of hedging activities, the Company’s oil and gas sales, on a per BOE basis, were reduced by $3.08 in the first quarter of 2005, $4.92 in the fourth quarter of 2004 and $2.68 in the first quarter of 2004. The Company has hedged approximately 7,750 barrels per day of its crude oil production at prices averaging $40.75 per barrel for 2005. See “Item 3. Quantitative and Qualitative Disclosure About Market Risk”.

Electricity Generation. Total electricity revenues were $12.5 million in the first quarter of 2005, down 5% from $13.1 million in the fourth quarter of 2004 and up 5% from $11.9 million in the first quarter of 2004. The Company produced 2,117 MWh/D of electricity in the first quarter of 2005 comparable to 2,148 MWh/D in the fourth quarter of 2004 and 2,167 MWh/D in the first quarter of 2004. The Company received an average sales price per MWh of $68.87 in the first quarter of 2005, compared to $70.20 in the fourth quarter of 2004 and $67.05 in the first quarter of 2004.

The Company consumes natural gas as fuel to operate its cogeneration facilities. The Company sells its electricity to utilities under Standard Offer contracts, under which its revenues are linked to the cost of natural gas. Thus, the cost of natural gas is the primary determinant of the Company’s electricity sales price. The correlation between electricity sales and natural gas prices allows the Company to more effectively manage its cost of producing steam for use in heavy oil production.

	Amount Per BOE							Amount (in thousands)

	Mar 31, 2005		Mar 31, 2004		% Change			Mar 31, 2005		Mar 31, 2004		% Change
Operating costs	$	11.80	$	9.51		24	%	$	23,407	$	16,782		39	%
DD&A		4.30		3.60		19	%		8,527		6,354		34	%
G&A		2.43		4.16		(42	)%		4,820		7,344		(34	)%
Interest expense		.59		.30		97	%		1,162		531		119	%

Operating costs for the first quarter of 2005, on a per BOE basis, increased 24% to $11.80 in the first quarter of 2005 from $9.51 in the first quarter of 2004. The cost of the Company’s steaming operations on its heavy oil properties represents a significant portion of the Company’s operating costs and will vary depending on the cost of natural gas used as fuel and the volume of steam injected during the period. Steam costs were higher in the first quarter of 2005 compared to the first quarter of 2004 because the cost of natural gas increased 13% to $5.74 per MMBtu in the first quarter of 2005 from $5.09 per MMBtu in the first quarter of 2004 and the volume of steam injected increased 10% to 70,440 barrels per day in the first quarter of 2005 from 64,060 barrels per day in the first quarter of 2004. Steam injection was higher as the Company commenced several new pilot projects and steam drives on its heavy-oil properties with peak oil response not expected for six to twelve months. Also contributing to the increase were increased cost of well servicing and other activities on the Company’s properties.

DD&A increased 19% to $4.30 per BOE in the first quarter of 2005 from $3.60 per BOE in the first quarter of 2004 due to higher acquisitions, increased capital investment and finding and development costs. Competition for drilling rigs has increased dramatically over the last year and, thus, rig rates are continuing to increase which has contributed to higher development costs.

Interest expense in the first quarter of 2005 was $.59 per BOE, up from $.30 per BOE in the first quarter of 2004. The Company’s borrowings at March 31, 2004 were $50 million. The Company’s borrowings were reduced during the latter half of 2004 to a level of $28 million at year-end. Interest expense was higher in the first quarter of 2005 compared to 2004 because the Company’s borrowings increased to $138 million during the first quarter of 2005 primarily due to the Niobrara and Tri-State acquisitions.

	Amount Per BOE							Amount (in thousands)
	Mar 31, 2005		Dec 31, 2004		% Change			Mar 31, 2005		Dec 31, 2004		% Change
Operating costs	$	11.80	$	11.09		6	%	$	23,407	$	21,847		7	%
DD&A		4.30		4.19		3	%		8,527		8,256		3	%
G&A		2.43		2.82		(14	)%		4,820		5,548		(13	)%
Interest expense		.59		.23		157	%		1,162		455		155	%

Operating costs for the first quarter of 2005 of $11.80 per BOE increased 6% from $11.09 per BOE in the quarter ended December 31, 2004. This increase was primarily related to a $2.1 million increase in severance taxes resulting from higher tax credits received in the fourth quarter of 2004 related to drilling operations at Brundage Canyon. Based on current crude oil and natural gas prices, the Company anticipates operating costs to average between $11.75 and $12.75 per BOE for all of 2005.

G&A expenses of $2.43 per BOE in the first quarter of 2005 decreased 14% from $2.82 incurred in the fourth quarter of 2004. The Company anticipates G&A to average between $1.75 and $2.25 per BOE in the full year of 2005. The Company expects G&A to trend lower during the year, on a per barrel basis, due to higher production levels anticipated upon completion of the Company’s extensive development activities planned for 2005.

Interest expense of $.59 per BOE in the first quarter of 2005 increased from $.23 per BOE in the fourth quarter of 2004. The Company’s borrowings totaled $28 million at December 31, 2004 and increased to $138 million at March 31, 2005. The Company anticipates interest expense to stay in the $.45 to $.60 per BOE range for all of 2005.

Electricity Operating Costs. Operating costs from electricity generation were $13.4 million in the first quarter of 2005, up 5% from $12.8 million in the fourth quarter of 2004 and up 8% from $12.4 million in the first quarter of 2004. Operating costs from electricity generation in the first quarter of 2005 were higher than the first quarter of 2004 since the cost of natural gas increased to $5.74 per MMBtu in the 2005 period from $5.09 per MMBtu in the first quarter of 2004.

Income Taxes. The Company experienced an effective tax rate of 33% for the first quarter of 2005 compared to 21% for the same period last year and 15% for the fourth quarter 2004. The Company benefits from EOR (enhanced oil recovery) credits on development activities on its heavy oil properties. However, with higher crude oil prices and the increasing investment in its light crude oil and natural gas properties, the Company’s effective income tax rate has been trending higher. Based on current oil prices, the Company anticipates an effective tax rate for 2005 between 30% and 35%.

Dry Hole, Abandonment and Impairment. At December 31, 2004, the Company was in the process of drilling one exploratory well on its Midway-Sunset property in California and one exploratory well on its Coyote Flats, Utah prospect. These two wells were determined non-commercial in February 2005. Costs of $.5 million which were incurred as of December 31, 2004 were charged to expense in 2004. The remaining costs incurred on these wells were approximately $2.0 million and were charged to expense during the first quarter of 2005. These costs are reflected on the Company's income statement under dry hole, abandonment and impairment.

Acquisitions. On January 27, 2005, the Company acquired certain interests in the Niobrara field in northeastern Colorado for approximately $105 million. The properties consist of approximately 127,000 gross (69,500 net) acres. Current production is approximately 9 MMcf of natural gas per day, with estimated proved reserves of 87 Bcf. The acquisition also includes approximately 200 miles of a pipeline gathering system and gas compression facilities for delivery into interstate gas lines. In the first quarter of 2005, the Company drilled 4 new wells on this acreage and plans to drill a total of approximately 60 wells and complete 23 workovers as part of the development of this asset in 2005.

In January 2005, the Company acquired a working interest in approximately 390,000 gross (172,250 net) prospective acres, located in eastern Colorado, western Kansas and southwestern Nebraska for approximately $5 million, from Bill Barrett Corporation (BBC). The Company and BBC will jointly explore and develop shallow Niobrara biogenic natural gas, Sharon Springs Shale gas and deeper Pennsylvanian formation oil assets on the acreage. The Company believes the potential of the Tri-State area can be exploited by using new drilling techniques and 3-D seismic technology to assess structural complexity, estimate potentially recoverable oil and gas and determine drilling locations. To this end, in the second quarter of 2005, the Company plans to spend approximately $.8 million, its net share, for 530 miles of 2D seismic data on this acreage. Additionally, the Company and BBC are presently evaluating the results of a well drilled in April 2005 on this acreage. This represents the first of a total of 8 new wells planned in 2005 on this acreage.

The Company has two Green River wells permitted for May 2005 drilling at its Lake Canyon acreage. These initial drill sites will be approximately three miles west of the Company’s Brundage Canyon field. The Company will also participate in the acquisition of 50 square miles of 3D seismic at Lake Canyon this summer. Drilling of the first deep Mesaverde natural gas test well in Lake Canyon is scheduled for late 2005.

In California, the Company has budgeted $37.9 million in capital development projects. The Company continues to monitor its diatomite exploitation project in the Midway-Sunset field. Production from this project has been gradually improving to a current level of approximately 100 B/D of crude oil. The Company is considering expanding this pilot and a decision as to the commerciality of this project is expected before the end of 2005. On the Company’s other California properties, the Company has drilled 17 new wells and completed 16 workovers of a planned 70 new wells and 61 workover program in 2005.

Substantial capital is required to replace and grow reserves. The Company achieves reserve replacement and growth primarily through successful development and exploration drilling and the acquisition of properties. Fluctuations in commodity prices have been the primary reason for short-term changes in the Company's cash flow from operating activities. The net long-term growth in the Company's cash flow from operating activities is the result of growth in production as affected by period to period fluctuations in commodity prices.

The Company establishes a capital budget for each calendar year based on its development opportunities and the expected cash flow from operations for that year. The Company may revise its capital budget during the year as a result of acquisitions and/or drilling outcomes. Excess cash generated from operations is expected to be applied toward acquisitions, debt reduction or other corporate purposes.

Working Capital and Cash Flows. Cash flow from operations is dependent upon the Company's ability to increase production through development, acquisitions, exploration activities and the price of crude oil and natural gas. The Company's working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under its credit arrangements. Generally, the Company uses excess cash to pay down borrowings under its credit arrangement. As a result, the Company often has a working capital deficit or a relatively small amount of positive working capital. Working capital as of March 31, 2005 was negative ($1.1) million, up from a negative ($3.8) million at December 31, 2004. Sales of oil and gas increased $30.2 million during the first quarter 2005 compared to the first quarter 2004, with oil and gas prices, net of hedges, increasing 48% and production increasing 14% in 2005 compared to the first quarter of 2004. Net cash provided by operating activities was $19.3 million, down 2% from $19.6 million in the first quarter 2004. The decrease in 2005 was a direct result of a $10.5 million increase in accounts receivable resulting from higher oil and gas prices and higher production volumes, not collected until April 2005, and an annual price-based royalty of $19 million paid in February 2005, up from $10 million paid in February 2004. The Company increased its borrowing on its credit line by $110 million during the first quarter 2005. Cash was used to fund $109.5 million in property acquisitions, $15.7 million of capital expenditures (15% of the total $107 million 2005 capital budget), and to pay dividends of $2.6 million.

			Less than		1-3		3-5		More than
Contractual Obligations	Total		1 year		years		years		5 years

Long-term debt	$	138,000	$	-	$	138,000	$	-	$	-
Abandonment obligations		9,369		304		922		1,166		6,977
Operating lease obligations		1,396		621		676		99		-
Drilling obligation		10,525		925		4,250		5,350		-
Firm natural gas
transportation contract		22,745		2,814		5,628		5,628		8,675
Total	$	182,035	$	4,664	$	149,476	$	12,243	$	15,652

The Company enters into various financial contracts to hedge its exposure to commodity price risk associated with its crude oil and natural gas production and natural gas volumes purchased for its steaming operations. These contracts related to crude oil and natural gas are generally in the form of swaps. The Company generally attempts to hedge between 25% and 50% of its anticipated crude oil and natural gas production each year and up to 30% of its anticipated net natural gas purchased each year. All of these hedges have historically been deemed to be cash flow hedges with the mark-to-market valuations provided by external sources, based on prices that are actually quoted.

	March 31, 2005 NYMEX Futures			Impact of percent change in futures prices on earnings
				20%			10%			+10%			+20%
Average WTI Price	$	56.00		$	44.80		$	50.40		$	61.60		$	67.20
Crude Oil gain/(loss) (in thousands)		(38,013	)		(8,119	)		(23,066	)		(52,959	)		(67,906	)
Average HH Price		7.93			6.35			7.14			8.73			9.52
Natural Gas gain/(loss) (in thousands)		5,931			,071			4,984			6,808			7,720
Net pre-tax future cash payments (in thousands)		(32,082	)		(4,048	)		(18,082	)		(46,151	)		(60,186	)

The Company attempts to minimize credit exposure to counterparties through monitoring procedures and diversification. The Company’s exposure to changes in interest rates results primarily from long-term debt. Total debt outstanding at March 31, 2005 and March 31, 2004 was $138 million and $28 million, respectively. Interest on amounts borrowed is charged at LIBOR plus 1.25% to 2.0%, or the higher of the lead bank’s prime rate or the federal funds rate plus 50 basis points plus a margin of 0.0% to 0.75%, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. Based on these borrowings, a 1% change in interest rates would not have a material impact on the Company’s financial statements.

Based on the Company’s hedges in place (swaps) associated with its natural gas sales volumes, a $1 increase in natural gas prices per MMBtu would reduce revenues by $ 1.6 million since the hedges are out-of-the money at March 31, 2005. Similarly, based on the Company’s hedges in place associated with its natural gas purchased volumes used in its steaming operations, if natural gas prices increased $1per MMBtu, the Company would collect an additional $2.8 million from its counterparties which would be reflected as a reduction to operating costs - oil & gas.

During 2004 and through early 2005, the differential between California heavy crude oil and WTI widened and averaged approximately $14.50 for the first quarter of 2005. While the Company is confident that it will be able to secure a contract for its California heavy crude oil in future periods, it is unlikely that the Company will be able to obtain terms similar to the current contract pricing in the existing agreement which is based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed differential approximating $6.00 per barrel. This contract expires on December 31, 2005. In the first quarter of 2005, the Company estimates that its revenues benefited from this contract by approximately $11 million, and at a current differential of approximately $14.00 per barrel, the Company estimates that its revenues in 2005 will benefit from the contract by approximately $45 million.

As of March 31, 2005, the Company has carried out an evaluation under the supervision of, and with the participation of, the Company’s Management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities and Exchange Act of 1934, as amended.

Based on their evaluation as of March 31, 2005, the Chief Executive Officer and Chief Financial Officer of the Company have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

"Safe harbor under the Private Securities Litigation Reform Act of 1995:” With the exception of historical information, the matters discussed in this Form 10-Q are forward-looking statements that involve risks and uncertainties. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, the timing and extent of changes in commodity prices for oil, gas and electricity, a limited marketplace for electricity sales within California, counterparty risk, competition, environmental risks, litigation uncertainties, drilling, development, exploration and operating risks, the availability of drilling rigs and other support services, legislative and/or judicial decisions and other government or Tribal regulations.

Exhibit No.	Description of Exhibit
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *

	DELAWARE		77-0079387
	(State or other jurisdiction of		(I.R.S. Employer
	incorporation or organization)		Identification No.)

5201 Truxtun Avenue, Suite 300, Bakersfield, California	93309-0640
(Address of principal executive offices)	(Zip Code)

.
	Page No
PART I. Financial Information

Item 1. Financial Statements

Condensed Balance Sheets at March 31, 2005 and December 31, 2004	3

Condensed Income Statements for the Three Month Periods Ended March 31, 2005 and 2004	4

Condensed Statements of Comprehensive Income for the Three Month Periods Ended March 31, 2005 and 2004	4

Condensed Statements of Cash Flows for the Three Month Periods Ended March 31, 2005 and 2004	5

Notes to Condensed Financial Statements	6

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	9

Item 3. Quantitative and Qualitative Disclosures About Market Risk	16

Item 4. Controls and Procedures	17

PART II. Other Information

Item 1. Legal Proceedings	18

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	18

Item 3. Defaults Upon Senior Securities	18

Item 4. Submission of Matters to a Vote of Security Holders	18

Item 5. Other Information	18

Item 6. Exhibits	18

SIGNATURE	18

	2005			2004

Beginning balance at January 1	$	8,214		$	7,311
Liabilities incurred		1,153			-
Liabilities settled		(213	)		(105	)
Accretion expense		215			163

Ending balance at March 31	$	9,369		$	7,369

	Three Months Ended
	March 31,
	2005		2004
Pro forma:	(in thousands, except per share data)
Revenue	$	89,358	$	61,903
Income from operations		40,016		22,223
Net income		22,809		10,980
Basic earnings per share		1.04		0.50
Diluted earnings per share		1.02		0.50