Properties

We have six asset teams as follows: South Midway-Sunset (S. Midway), North Midway-Sunset including diatomite (N. Midway), Southern California including Poso Creek and Placerita (S. Cal), Piceance, Uinta and DJ.

 

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.

2007 - Production averaged approximately 9,600 Bbl/D in 2007. We completed 18 horizontal wells at deeper depths which slowed the natural decline of these assets. These wells targeted resource opportunities below our existing horizontal wells and along the edge of the reservoir. Of these infill wells, 25 were drilled to delineate and assess the resource base of a Berry legacy asset at Ethel D.

2008 - Capital is focused on adding 15 horizontal wells below existing horizontal wells, drilling ten vertical steam injection locations to place steam continuously along the edge of the reservoir, and further development at Ethel D including the initiation of a pilot steam flood.

N. Midway - In November 2006, we announced our plans to commence full scale development of our diatomite project in California based on the performance of a two-year pilot program. We expect this development will increase production by up to 8,500 Bbl/D by 2011. As we develop the fairway, we will also appraise the potential of recovering additional reserves in the outer portions of our acreage in subsequent development phases. We believe that the development is similar to other California fields.

2007 - Production from the diatomite project averaged approximately 990 Bbl/D in 2007 through implementation of a modified steam injection plan and new well fracturing techniques. Production continued to increase throughout the year primarily as a result of cyclic steaming. We initiated the next phase of our development program in the fairway of the asset in the latter part of the third quarter and expect to be bringing these wells on production in the first quarter of 2008. Installation of the necessary infrastructure, including steam generation equipment and fluid processing facilities, is also in progress.

2008 - Capital is focused on drilling approximately 120 wells, completing major infrastructure upgrades that will support future development, increasing steam injection and further refinement of our thermal recovery techniques including the testing of a horizontal well concept.

S. Cal - We acquired the Poso Creek properties in the San Joaquin Valley basin in early 2003 and have proceeded with a successful thermal EOR redevelopment. In the Placerita field in the Los Angeles basin, 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.

2007 - Poso Creek responded favorably to steam flood injection and our accelerated infill drilling program performed solidly above plan. Production increased to over 2,400 Bbl/D in 2007 from less than 1,000 Bbl/D in 2006. We drilled over 70 wells and installed a third steam generator during the year. We expect continued production improvement as these wells are cyclically steamed, the additional steam flood patterns are brought on line and the balance of the infill wells are drilled and completed.

2008 - Capital is directed at a 28 well drilling program at Poso Creek and further expansion of the steam flood including the installation of the fourth steam generator. The expected year end average exit rate at Poso Creek is over 3,500 Bbl/D.

Piceance - In the first half of 2006, we made two separate acquisitions in the Piceance basin 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 1,000 drilling locations which will allow us to add significant proved reserves over the next five years.

2007 - Production averaged 10,200 MMcf/D in 2007. We operated a four rig drilling program for most of the year and drilled 39 gross (19 net) wells at Garden Gulch and 8 gross (8 net) at North Parachute. Significant progress was made in the last half of 2007 in reducing the days required to drill wells on our Piceance asset. During the fourth quarter drilling days on our mesa wells averaged 16 days on Garden Gulch and 19 days in North Parachute and we are confident we can maintain this efficiency and expect improved economics as a result. Additionally, we continued to expand the infrastructure needed to support our operations, and have acquired additional firm transportation for future sales out of this region.

2008 - We plan to operate a four rig program with our capital directed at drilling 46 gross (23 net) wells in Garden Gulch and 13 gross (12 net) wells in North Parachute, constructing the necessary expansion of our gathering and water handling facilities, and continued expansion of our road infrastructure including the construction of a new access road to our mesa acreage on the Old Mountain block of North Parachute.

Uinta - The Brundage Canyon leasehold in Duchesne County, northeastern Utah consists of approximately 26,000 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 hold a 169,000 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.

2007 - During 2007 the refinery capacity for our black wax crude improved from the constraints experienced during 2006. In February 2007, we signed a six year oil contract with a refiner, allowing us to deliver 3,200 Bbl/D starting in July 2007 with up to 5,000 Bbl/D through June 30, 2013 upon the certified completion of its refinery upgrade expected in the first half of 2008. Deliveries under this contract has allowed us to sell all of our crude oil production in the Uinta Basin and has stabilized our realized sales price and reduced transportation costs.

In 2007 we drilled 50 gross (48 net) wells in the Uinta project which included 39 gross (39 net) wells at Brundage Canyon, six wells testing the Ashley Forest acreage to the south, and five wells at Lake Canyon targeting the Green River formation.  In addition, we participated in the drilling of one Lake Canyon Wasatch well with our industry partner. Average daily production during 2007 from all Uinta basin assets was approximately 5,700 net BOE/D. At the end of 2007, we had one drilling rig operating in the basin.

2008 - Capital at Brundage Canyon is directed at drilling 44 additional wells targeting high graded locations across the field and further delineation wells on our Ashley Forest acreage to the south. We are also evaluating the feasibility of waterflooding Brundage Canyon to further improve recovery and anticipate installing a waterflood pilot late this year. The Ashley Forest EIS continues to progress and we anticipate approval in the first quarter of 2009. Capital at Lake Canyon is directed at the continued appraisal of our acreage with the drilling of four wells targeting the Green River, and three exploratory wells targeting both Green River and Wasatch potential and to participate with our industry partner in deep Wasatch wells.

DJ - In 2005, we made three acquisitions for approximately $111 million establishing a core area in the Niobrara gas producing assets in Yuma County in northeastern Colorado, where we have a working interest averaging approximately 52%. This acquisition in the Tri-State region (Eastern Colorado, western Kansas and southwestern Nebraska) totaled approximately 100,000 net producing acres and 315,000 net total acres. Our other two acquisitions in the region consisted of undeveloped prospective acreage where our working interests range from 40% to 50%. Our Yuma County Niobrara projects provide sustainable and steady cash flow resulting from low capital development costs, modest production declines and long-life reserves.

2007 - We drilled over 100 successful Niobrara development wells in Yuma County adding production from both proved undeveloped and probable reserves. We continued to expand our compression and gathering infrastructure and acquired an additional 37 square miles of 3-D seismic data in Colorado. Average daily production in the DJ in 2007 was 18,700 net MMcf/D. We determined that our position in a portion of the Tri-State acreage was not sizable enough for us to continue with its development, thus we wrote down $4.6 million of our Tri-State acreage carrying value in connection with the sale of these properties, which we believe approximates fair value as of December 31, 2007 based on available information.

2008 - Capital is directed at drilling 86 gross (37 net) Niobrara wells, installing pumping units on 145 gross (45 net) wells, and installing associated compression, gathering and water disposal facilities. Over 75 square miles of 3-D seismic acquisition in Yuma County is planned for early 2008. 

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 80% 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. The remaining 20% of our revenues are primarily derived from electricity sales from cogeneration facilities which supply approximately 35% 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.

Sales of oil and gas were up 9% in 2007 compared to 2006 and up 23% from 2005. 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. While improvement in oil prices during 2007 were due to a tighter supply and demand balance, natural gas prices decreased as a result of the impact of high storage levels and mild weather conditions in the U.S. Oil and natural gas prices contributed roughly 3% of the revenue increase and the increase in production volumes contributed the other 6%. Approximately 70% of our oil and gas sales volumes in 2007 were crude oil, with 83% of the crude oil being heavy oil produced in California which was sold under contracts based on the higher of WTI minus a fixed differential or the average posted price plus a premium. Our oil contracts allowed us to improve our California revenues over the posted price by approximately $15 million, $21 million and $41 million in 2007, 2006 and 2005, respectively.

 

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

		2007				2006				2005
Sales of oil		$	385			$	360			$	289
Sales of gas			82				70				61
Total sales of oil and gas		$	467			$	430			$	350
Sales of electricity			56				53				55
Gain on sale of assets			54				1				-
Interest and other income, net			6				2				2
Total revenues and other income		$	583			$	486			$	407
Net income		$	130			$	108			$	112
Earnings per share (diluted)		$	2.89			$	2.41			$	2.50

The following companywide 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			$	84			$	100
Sales of gas			24				18				19
Total sales of oil and gas		$	133			$	102			$	119
Sales of electricity			15				13				12
Gain on sale of assets			2				-				1
Interest and other income, net			3				1				1
Total revenues and other income		$	153			$	116			$	133
Net income		$	32			$	19			$	27
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 15 to the financial statements.

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

			2007	%		2006	%		2005	%
Oil and Gas
Heavy Oil Production (Bbl/D)			16,170	60		15,972	63		16,063	70
Light Oil Production (Bbl/D)			3,583	13		3,707	15		3,336	14
Total Oil Production (Bbl/D)			19,753	73		19,679	78		19,399	84
Natural Gas Production (Mcf/D)			42,895	27		34,317	22		21,696	16
Total (BOE/D)			26,902	100		25,398	100		23,015	100
Percentage increase from prior year			6%			10%			12%
Per BOE:
Average sales price before hedging		$	49.72		$	48.38		$	47.01
Average sales price after hedging			47.50			46.67			41.62
Oil, per Bbl:
Average WTI price		$	72.41		$	66.25		$	56.70
Price sensitive royalties			(5.03	)		(5.13	)		(4.42	)
Gravity differential and other			(9.53	)		(8.20	)		(5.22	)
Crude oil hedges			(4.61	)		(2.37	)		(6.21	)
Average oil sales price after hedging		$	53.24		$	50.55		$	40.85
Natural gas price:
Average Henry Hub price per MMBtu		$	7.12		$	6.97		$	9.01
Conversion to Mcf			.34			.33			.43
Natural gas hedges			.74			.09			(.16	)
Location, quality differentials and other			(2.93	)		(1.82	)		(1.65	)
Average gas sales price after hedging		$	5.27		$	5.57		$	7.63

The following table is for the three months ended:

			December 31, 2007	%		December 31, 2006	%		September 30, 2007	%
Oil and Gas
Heavy Oil Production (Bbl/D)			16,595	59		16,833	63		15,806	59
Light Oil Production (Bbl/D)			3,395	12		3,363	13		3,675	14
Total Oil Production (Bbl/D)			19,990	71		20,196	76		19,481	73
Natural Gas Production (Mcf/D)			48,196	29		40,157	24		44,346	27
Total (BOE/D)			28,023	100		26,889	100		26,873	100
Per BOE:
Average sales price before hedging		$	60.38		$	41.53		$	49.35
Average sales price after hedging			52.32			42.00			47.93
Oil, per Bbl:
Average WTI price		$	90.50		$	60.17		$	75.15
Price sensitive royalties			(6.68	)		(4.28	)		(5.50	)
Gravity differential and other			(9.92	)		(9.06	)		(9.56	)
Crude oil hedges			(13.57	)		(.01	)		(4.37	)
Average oil sales price after hedging		$	60.33		$	46.82		$	55.72
Natural gas price:
Average Henry Hub price per MMBtu		$	7.39		$	7.24		$	6.24
Conversion to Mcf			.35			.34			.31
Natural gas hedges			.91			.31			1.07
Location, quality differentials and other			(3.21	)		(3.23	)		(3.06	)
Average gas sales price after hedging		$	5.44		$	4.66		$	4.56

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 down in the year ended 2007 from the year ended 2006 due to 2% higher electricity prices and 6% lower natural gas prices, respectively. In 2007, 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 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 are 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 margin in 2007.

We purchased approximately 38 MMBtu/D as fuel for use in our cogeneration facilities in the year ended December 31, 2007. On September 20, 2007, the CPUC issued a decision (SRAC Decision) that changes prospectively the way SRAC energy prices will be determined for existing and new SO contracts and revises the capacity prices paid under current SO1 contracts. Based on our preliminary analysis, we do not believe that the proposed pricing changes will materially affect us in 2008. The following table is for the years ended December 31:

		2007				2006				2005
Electricity
Revenues (in millions)		$	55.6			$	52.9			$	55.2
Operating costs (in millions)		$	46.0			$	48.3			$	55.1
Decrease to total oil and gas operating expenses per barrel		$	.98			$	.50			$	.02
Electric power produced - MWh/D			2,133				2,074				2,030
Electric power sold - MWh/D			1,932				1,867				1,834
Average sales price/MWh (no hedging was in place)		$	78.62			$	77.13			$	82.73
Fuel gas cost/MMBtu (including transportation)		$	6.08			$	6.44			$	7.72

The following table is for the three months ended:

		December 31, 2007				December 31, 2006				September 30, 2007
Electricity
Revenues (in millions)		$	14.9			$	13.5			$	12.3
Operating costs (in millions)		$	11.0			$	12.1			$	9.8
Electric power produced - MWh/D			2,099				2,093				2,257
Electric power sold - MWh/D			2,077				1,861				2,077
Average sales price/MWh		$	78.98			$	75.05			$	71.28
Fuel gas cost/MMBtu (including transportation)		$	6.10			$	6.44			$	5.07

Royalties. A price-sensitive royalty burdens certain of our S. Midway properties which produced approximately 2,900 BOE/D in 2007. This royalty is 75% of the amount of the heavy oil posted price above a base price which was $15.79 in 2007. This base price escalates at 2% annually, thus the threshold price is $16.11 per barrel in 2008. Liabilities payable for these royalties were $36 million, $36 million and $29 million in the years ended December 31, 2007, 2006 and 2005, respectively. Because our interest in the revenue varies according to crude prices, the continuing development on this property will depend on its future profitability.

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)
	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%)

• As we remain in a strong commodity price environment, we anticipate that cost pressures within our industry may continue due to greater field activity and rising service costs in general. Based on current plans, we are targeting average steam injection in 2008 of approximately 110,000 BSPD or a 25% increase compared to 2007.
• 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 2007 by 31% from 2006. 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 basin 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 70% of our G&A is 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 has been capitalized and we expect to capitalize approximately $20 million of interest cost during the full year of 2008.

The following table presents information about our operating expenses for the three months ended:

		Amount per BOE												Amount (in thousands)
		December 31, 2007				December 31, 2006				September 30, 2007				December 31, 2007				December 31, 2006				September 30, 2007
Operating costs - oil and gas production		$	14.70			$	13.69			$	13.75			$	37,889			$	33,804			$	33,995
Production taxes			1.91				1.15				1.76				4,918				2,840				4,344
DD&A - oil and gas production			10.94				8.24				9.45				28,212				20,335				23,356
G&A			4.24				4.55				3.78				10,918				11,231				9,333
Interest expense			1.43				1.27				1.75				3,693				3,503				4,326
Total		$	33.22			$	28.90			$	30.49			$	85,630			$	71,713			$	75,354

	December 31, 2007	December 31, 2006	Change	September 30, 2007	Change
Average volume of steam injected (Bbl/D)	90,894	85,349	6%	88,711	2 %
Fuel gas cost/MMBtu (including transportation)	$ 6.10	$ 6.05	1%	$ 5.07	20%

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

	Amount per BOE								Amount (in thousands)
	2006			2005		Change			2006			2005			Change
Operating costs - oil and gas production	$	12.69		$	11.79		8	%	$	117,624		$	99,066		19	%
Production taxes		1.58			1.37		15	%		14,674			11,506		28	%
DD&A - oil and gas production		7.30			4.54		61	%		67,668			38,150		77	%
G&A		3.98			2.55		56	%		36,841			21,396		72	%
Interest expense		1.05			.72		46	%		10,247			6,048		69	%
Total	$	26.60		$	20.97		27	%	$	247,054		$	176,166		40	%

Our total operating costs, production taxes, G&A and interest expenses for 2006, stated on a unit-of-production basis, increased 27% over 2005. The changes were primarily related to the following items:

• Operating costs: Operating costs in 2006 were 8% higher than 2005 due to an increase in well servicing activities and higher cost of goods and services in general. We installed additional steam generators in California and as a result of the increased steam injection, our crude oil production on these properties increased. The cost of our steaming operations varies depending on the cost of natural gas used as fuel and the volume of steam injected. The following table presents steam information:

	2006	2005	Change
Average volume of steam injected (Bbl/D)	81,246	70,032	16%
Fuel gas cost/MMBtu (including transportation)	$ 6.44	$ 7.72	(17%)

• Production taxes: During 2006 our production taxes increased as a result of higher assessed values on our properties, increased production and higher investment in mineral interests.
• Depreciation, depletion and amortization: DD&A increased per BOE in 2006 due to large increases in capital spending since 2005 and particularly more extensive development in fields with higher drilling costs. Higher leasehold acquisition costs in 2003 through 2006 are expected to increase our DD&A expense over the life of these assets as development increases. Our capital program experienced cost pressures in our labor and for goods and services commensurate with other energy developers. As these costs increase, our DD&A rates per BOE will also increase.
• General and administrative: Approximately two-thirds of our G&A is compensation or compensation related costs. Our employee headcount increased 16% in 2006 as we added an important new core asset into our portfolio and as we strengthened our talent base. Other items increasing our G&A in 2006 were contributions to fund the opposition of Proposition 87 in California, increased travel and consulting costs and a generally higher level of activity.
• Interest expense: Our outstanding borrowings, including our senior unsecured money market line of credit and senior subordinated notes, was $406 million at December 31, 2006 compared to $87 million at December 31, 2005. Average borrowings in 2006 increased as a result of our Piceance basin acquisitions during 2006 and capital expenditures program. A certain portion of our interest cost related to our Piceance basin acquisition and joint venture has been capitalized into the basis of the assets. For the year ended December 31, 2006, $9.3 million was capitalized.

Estimated 2008 Oil and Gas Operating, G&A and Interest Expenses. We estimate our 2008 production volume will range between 29,500 BOE/D and 30,500 BOE/D. Based on WTI of $75 and NYMEX HH of $7.50 MMBtu, we expect our expenses to be within the following ranges:

		Amount per BOE
		Anticipated
		range in 2008			2007			2006
Operating costs-oil and gas production (1)		$	16.00 to 17.50		$	14.38		$	12.69
Production taxes			1.75 to 2.25			1.75			1.58
DD&A			9.75 to 10.75			9.54			7.30
G&A			4.00 to 4.50			4.09			3.98
Interest expense			1.25 to 1.50			1.76			1.05
Total		$	32.75 to 36.50		$	31.52		$	26.60

(1) We expect operating costs to increase in 2008 as compared to 2007 due to higher projected natural gas costs.

Dry hole, abandonment, impairment and exploration. In 2007 we had dry hole, abandonment and impairment charges of $13.7 million consisting primarily of a $4.6 million writedown of a portion of our Tri-State acreage in connection with the 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 writedown of our Bakken properties sold in September 2007, and other dry hole charges of $2.2 million. We incurred exploration costs of $.7 million in 2007 compared to $3.8 million and $3.6 million in 2006 and 2005, respectively. These costs consist primarily of geological and geophysical costs in the DJ basin. We are projecting geological and geophysical costs in 2008 of between $2 million and $3 million.

In 2006 we incurred $8.3 million of dry hole, abandonment and impairment consisting primarily of two Coyote Flats, Utah wells for $5.2 million, our 25% share in an exploration well (located in the Lake Canyon project area of the Uinta basin) drilled for approximately $1.6 million net to our interest, four wells in Bakken and four wells in the DJ basin for $1.5 million. For the year ended 2005, costs of $5.7 million were incurred on the following: one exploratory well on the Coyote Flats prospect, one well on the Midway-Sunset property, two exploratory wells on northern Brundage Canyon in the Uinta basin, and impairment of $2.5 million on the remaining carrying value of our Illinois and eastern Kansas prospective CBM acreage were charged to expense.

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. We don’t expect to generate the EOR tax credit for 2008, due to current oil prices. As of December 31, 2007 we have approximately $24 million of federal and $18 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 38%, 39% and 31% in 2007, 2006 and 2005, respectively. The rate is lower than our combined federal and state statutory tax rate of 40% primarily due to certain business incentives. In anticipation of the continued full EOR credit phase out in 2008, we expect our effective tax rate to approximate 38%, given the current oil price environment. See Note 9 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 basin 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 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. Post May 2006 changes in the marked-to-market fair values are reflected in Other Comprehensive Income.

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 $1.4 million as of December 31, 2007 in accordance with SFAS No. 144. See Note 2 to the financial statements.

Reserve Replacement Rate. The reserve replacement rate is calculated by dividing total new proved reserves added for the year by total production for the year. Total new proved reserves include revisions of previous estimates, improved recovery, extensions and discoveries, and purchase of reserves in place. This measure is important because it is an indication of growth in proved reserves and thus may impact our market value. We believe our calculation of this measure is substantially similar to how other companies compute the reserve replacement rate. See Item 8 Supplemental Information About Oil & Gas Producing Activities (unaudited).

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. In 2006, we revised our senior unsecured revolving credit facility to increase our maximum credit amount under the facility to $750 million and in 2007 we increased our borrowing base from $500 million to $550 million. On October 24, 2006, we completed the sale of $200 million of ten year 8.25% senior subordinated notes and paid down our borrowings under our facility by $141 million. As of December 31, 2007, we had total borrowings under the senior unsecured revolving credit facility and senior unsecured money market line of credit of $259 million and $200 million under our senior subordinated notes. See Item 7A Quantitative and Qualitative Disclosures About Market Risk for discussion of interest rate sensitivity.

Capital Expenditures. 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 acquisitions, debt reduction or other corporate purposes.

In 2008, we have a capital program of approximately $295 million, excluding acquisitions. Our 2008 expenditures will be directed toward developing reserves, increasing oil and gas production and exploration opportunities. For 2008, we plan to invest approximately $118 million, or 40%, in our heavy crude oil assets, and $175 million, or 59%, in our natural gas and light oil assets. Approximately two-thirds of the capital budget is focused on converting probable and possible reserves into proved reserves and on our appraisal and exploratory projects, while the other one-third is for the development of our proved undeveloped reserves and facility costs.

Dividends. Our regular annual dividend is currently $.30 per share, payable quarterly in March, June, September and December.

Working Capital and Cash Flows. 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 increased in 2007 (see graphs on pages 32 and 33) and we increased production by 6%.

Our working capital balance fluctuates as a result of the amount of borrowings and the timing of repayments under our credit arrangements. We used 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 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 we paid the third and final installment of approximately $54 million for the North Parachute Ranch property located in the Piceance basin.

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):

		2007				2006				Change
Average production (BOE/D)			26,902				25,398				6	%
Average oil and gas sales prices, per BOE after hedging		$	47.50			$	46.67				2	%
Net cash provided by operating activities		$	248			$	243				2	%
Working capital		$	(110	)		$	(117	)			6	%
Sales of oil and gas		$	467			$	430				9	%
Total debt		$	459			$	406				13	%
Capital expenditures, including acquisitions and deposits on acquisitions		$	338			$	523				(35	%)
Dividends paid		$	13.3			$	13.2				1	%

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

		December 31, 2007				December 31, 2006				Change				September 30, 2007				Change
Average production (BOE/D)			28,023				26,889				4	%			26,873				4	%
Average oil and gas sales prices, per BOE after hedging		$	52.31			$	42.00				25	%		$	47.93				9	%
Net cash provided by operating activities		$	64			$	58				10	%		$	93				(31	%)
Working capital		$	(110	)		$	(117	)			6	%		$	(91	)			(21	%)
Sales of oil and gas		$	133			$	102				30	%		$	119				12	%
Total debt		$	459			$	406				13	%		$	440				4	%
Capital expenditures, including acquisitions and deposits on acquisitions		$	76			$	127				(40	%)		$	63				21	%
Dividends paid		$	3.3			$	3.3				-	%		$	3.4				(3	%)

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

Credit Facility. See Note 6 to the financial statements for more information.

Contractual Obligations.

Our contractual obligations as of December 31, 2007 are as follows (in thousands):

		Total				2008				2009				2010				2011				2012				Thereafter
Long-term debt and interest		$	649,658			$	36,336			$	31,029			$	31,029			$	268,764			$	16,500			$	266,000
Abandonment obligations			36,426				1,456				1,456				1,456				1,456				1,456				29,146
Operating lease obligations			12,407				1,690				1,374				1,357				1,357				1,357				5,272
Drilling and rig obligations			74,749				23,559				18,817				7,353				25,020				-				-
Firm natural gas     transportation contracts			173,243				15,206				19,545				19,544				19,545				19,054				80,349
Total		$	946,483			$	78,247			$	72,221			$	60,739			$	316,142			$	38,367			$	380,767

Long-term debt and interest - Our credit facility borrowings and related interest of approximately 5.9% 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, 2007, 2006 and 2005 was $1.5 million, $1 million and $.6 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, 2007 the remaining obligation is $5.4 million. Also included above, under our June 2006 joint venture agreement in the Piceance basin we are required to have 120 wells drilled by February 2011 to avoid penalties of $.2 million per well or a maximum of $24 million. As of December 31, 2007 we have drilled 12 of these wells.

Drilling rig obligations - We are obligated in operating lease agreements for the use of multiple drilling rigs.

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 seven long-term transportation contracts on four 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, 2007, we had a gross liability for uncertain tax benefits of $12 million of which $9.1 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, 2007, we had accrued approximately $1.1 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 with a refiner for our Uinta basin light crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D on July 1, 2007. Upon completion of its refinery expansion in Salt Lake City, which is expected in the first half of 2008, the refiner will increase its total purchased volumes to 5,000 Bbl/D through June 30, 2013. Pricing under the contract, which includes transportation and gravity adjustments, is at a fixed percentage of WTI, which was near the posted price at the contract’s starting date.

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.

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 amount 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.

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.

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 obtained estimates from third parties and used 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.

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 December 2004, SFAS No. 123(R), Share-Based Payment, was issued which establishes standards for transactions in which an entity exchanges its equity instruments for goods or services. This standard requires an issuer 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. In April 2005, the SEC issued a rule that SFAS No. 123(R) will be effective for annual reporting periods beginning on or after June 15, 2005. As a result, we adopted this statement beginning January 1, 2006. We previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Accordingly, the adoption of SFAS No. 123(R) using the modified prospective method did not have a material impact on our condensed financial statements for the year ended December 31, 2006.

In May 2005, SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 was issued. SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 became effective for our fiscal year beginning January 1, 2006. The adoption of SFAS No. 154 had no effect to our financial position and result of operations.

In February 2006, SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140 was issued. This Statement resolves issues addressed in Statement 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial Interests in Securitized Financial Assets. SFAS No. 155 became effective for our fiscal year beginning January 1, 2007. While there was no impact on our financial statements as of December 31, 2007, based on our existing derivatives, we may experience a financial impact depending on the nature and extent of any new derivative instruments entered into after the effective date of SFAS No. 155.

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 9. 

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. SFAS No. 157 will become effective for our fiscal year beginning January 1, 2008, and we are currently assessing the effect this statement may have on our financial statements. . However, we do not believe that the implementation of SFAS 157 will have a material impact on our financial statements.

In September 2006, Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements was issued by the Securities and Exchange Commission. Registrants must quantify the impact on current period financial statements of correcting all misstatements, including both those occurring in the current period and the effect of reversing those that have accumulated from prior periods. This SAB was adopted at December 31, 2006. The adoption of SAB No. 108 had no effect on our financial position or on our results of operations. 

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. This statement is effective beginning January 1, 2008 and we do not expect this Statement to 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 will become effective for our fiscal year beginning January 1, 2008 and will have no effect on our financial statements as we do not post collateral under our hedging agreements.

In December 2007, the FASB issued 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. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. 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 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).

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