NOTE K—OIL AND GAS RESERVE DATA (UNAUDITED)

The following estimates of proved reserve quantities and related standardized measure of discounted future net cash flows are estimates only, and do not purport to reflect realizable values or fair market values of the Company's reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company's reserves are located in the United States.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods.

The standardized measure of discounted future net cash flows for were computed by applying 12-month average prices for oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10%.

The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of proved reserves provided by Netherland, Sewell & Associates, Inc. for 2013, 2012 and 2011

Summary of Changes in Proved Reserves

	Year ended December 31,

	2013						2012						2011
	Mbbls			Mmcf			Mbbls			Mmcf			Mbbls			Mmcf
Proved reserves
Beginning of year		16,380			51,236			14,963			43,860			10,250			68,200
Purchase of reserves in place		128			—			—			20,649			—			—
Discoveries and extensions		500			46,532			3,337			2,054			3,744			—
Revisions of previous estimates		171			14,492			(811	)		(9,813	)		1,880			(19,320	)
Production		(1,105	)		(6,232	)		(1,109	)		(5,514	)		(911	)		(5,020	)


End of year		16,074			106,028			16,380			51,236			14,963			43,860




Proved developed reserves
Beginning of year		8,064			51,236			8,348			28,515			7,518			49,300
End of year		8,512			78,038			8,064			51,236			8,348			28,515
Proved undeveloped reserves
Beginning of year		8,316			—			6,615			15,345			2,732			18,900
End of year		7,562			27,990			8,316			—			6,615			15,345

(a): Undeveloped reserves transferred to developed reserves were 1.1 MMBoe for the year ended December 31, 2013. Capital costs incurred to convert these proved undeveloped reserves to proved developed reserves were $32.8 million.
(b): Positive revisions increased 2013 proved natural gas reserves by a net amount of 61.0 Bcf, of which 9.0 Bcf was due to pricing, 5.5 Bcf due to performance, and the remainder due to extensions and discoveries.
(c): The Company revised its 2013 year-end proved oil reserves upward by 0.8 MMbbls. In 2013, total extensions and discoveries of 0.5 MMbbls resulted from the Company's drilling and completion activities in the Wilmington Townlot and North Wilmington Units in California. Positive revisions of 0.2 MMbbls were made based on production performance and an additional 0.1 MMbbls was relating to the acquisition of the Leroy Pine Project in California.

Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves

	December 31,

	2013			2012			2011
	(Amounts in thousands)
Future cash inflows	$	1,928,019		$	1,836,212		$	1,708,079
Future production costs and taxes		(688,056	)		(574,959	)		(514,968	)
Future development costs(1)		(314,091	)		(303,062	)		(254,982	)
Future income tax expenses		(82,576	)		(105,078	)		(108,977	)


Net future cash flows		843,296			853,113			829,152
Discounted at 10% for estimated timing of cash flows		(368,295	)		(393,233	)		(343,146	)


Standardized measure of discounted future net cash flows	$	475,001		$	459,880		$	486,006

(1): Includes future estimated asset retirement obligations of $64.4 million in 2013, $79.9 million in 2012 and $66.3 million in 2011.

Changes in Standardized Measure of Discounted Future Net Cash Flows
Related to Proved Oil and Gas Reserves

	Year ended December 31,

	2013			2012			2011
	(Amounts in thousands)
Sales, net of production costs and taxes	$	(91,146	)	$	(88,725	)	$	(72,734	)
Discoveries and extensions		52,189			108,438			152,973
Purchases of reserves in place		2,823			4,966			—
Changes in prices and production costs		(109	)		(17,286	)		196,010
Revisions of quantity estimates		22,911			(39,172	)		56,710
Development costs incurred		(39,233	)		36,539			30,892
Net changes in development costs		(10,502	)		(90,392	)		(149,662	)
Interest factor—accretion of discount		49,491			48,601			28,763
Net change in income taxes		6,328			5,037			(40,070	)
Changes in production rates (timing) and other		22,369			5,868			(4,504	)


Net (decrease) increase		15,121			(26,126	)		198,378
Balance at beginning of year		459,880			486,006			287,628


Balance at end of year	$	475,001		$	459,880		$	486,006

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2013, 2012 and 2011 along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The prices used at December 31, 2013, 2012 and 2011 were $97.33, $104.27 and $104.75 per Bbl and $3.43, $2.51 and $3.21 per Mcf, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company's portion of proved undeveloped properties through December 31, 2017 is $249.7 million.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards, for both regular and alternative minimum tax.

The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.