NOTE 17 — OIL AND GAS RESERVE INFORMATION – UNAUDITED:

Our estimated net proved oil and natural gas reserves at December 31, 2013 have been prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

The following table sets forth an analysis of the estimated quantities of net proved and proved developed oil (including condensate), natural gas and natural gas liquids (“NGL”) reserves, all of which are located onshore and offshore the continental United States. Estimated proved oil, natural gas and NGL reserves at December 31, 2013, 2012 and 2011 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical 12-month average pricing assumption. In the first quarter of 2012, we began reporting NGL volumes and revenues separately from gas volumes. Historically, we reported “wet” gas volumes, which included entrained liquids. We now report NGLs and “dry” gas (shrunk for removal of liquids) volumes. Reserve volumes for the year ended December 31, 2011 have been reclassified to conform to the current presentation. Reserve volumes for the year ended December 31, 2010 have not been reclassified to conform to the current presentation given the immateriality of NGL volumes in such period.


	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			Oil, Natural Gas and NGLs (MMcfe)
Estimated proved reserves as of December 31, 2010		33,203			—			274,705			473,923
Revisions of previous estimates		2,889			4,911			(26,725	)		20,075
Extensions, discoveries and other additions		3,544			—			93,520			114,784
Purchase of producing properties		14,396			—			24,595			110,971
Sale of reserves		(1,950	)		—			(2,150	)		(13,850	)
Production		(6,427	)		(506	)		(38,466	)		(80,064	)

Estimated proved reserves as of December 31, 2011		45,655			4,405			325,479			625,839
Revisions of previous estimates		(1,559	)		9,349			(26,694	)		20,050
Extensions, discoveries and other additions		3,681			4,856			131,408			182,633
Purchase of producing properties		4,336			619			8,168			37,895
Sale of reserves		(60	)		—			(418	)		(775	)
Production		(7,135	)		(1,163	)		(42,569	)		(92,357	)

Estimated proved reserves as of December 31, 2012		44,918			18,066			395,374			773,285
Revisions of previous estimates		3,606			2,439			36,006			72,275
Extensions, discoveries and other additions		2,367			4,395			79,729			120,299
Sale of reserves		(170	)		—			(214	)		(1,235	)
Production		(6,894	)		(1,603	)		(50,129	)		(101,111	)

Estimated proved reserves as of December 31, 2013		43,827			23,297			460,766			863,513

Estimated proved developed reserves:
as of December 31, 2011		30,914			3,195			171,871			376,528

as of December 31, 2012		29,005			8,593			210,956			436,540

as of December 31, 2013		27,920			11,569			246,946			483,885

The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year.

Year Ended December 31, 2013. Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (117 Bcfe). Revisions of previous estimates were primarily the result of positive reserve report pricing changes extending the economic limits of reservoirs (17.8 Bcfe) and well performance (54.5 Bcfe).

Year Ended December 31, 2012. Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (162 Bcfe) and our deep gas development project at LaCantera (17 Bcfe). Purchase of producing properties relates to our acquisition of an additional interest in the Pompano field.

Year Ended December 31, 2011. Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (94 Bcfe), our deep gas development project at LaPosada (11 Bcfe) and our GOM drilling program at Mississippi Canyon Block 109 (6 Bcfe). Purchase of producing properties primarily relates to our acquisition of the Pompano and Mica fields (102 Bcfe) and our acquisition of an additional 15% working interest in the Pyrenees project (6 Bcfe). Sale of reserves primarily relates to the sale of our non-operated interest in the Main Pass Block 296 and 311 fields (13 Bcfe).

The following tables present the standardized measure of discounted future net cash flows related to estimated proved oil, natural gas and NGL reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2013. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil, natural gas and NGL reserves. Prices are based on either the historical 12-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The 2013 average historical 12-month oil and gas prices, net of applicable differentials, were $102.21 per Bbl of oil, $37.59 per Bbl of NGLs and $3.66 per Mcf of gas. The 2012 average 12-month oil and gas prices, net of applicable differentials, were $101.20 per Bbl of oil, $38.23 per Bbl of NGLs and $2.68 per Mcf of gas. The 2011 average 12-month oil and gas prices, net of applicable differentials, were $100.97 per Bbl of oil, $58.26 per Bbl of NGLs and $4.74 per Mcf of gas. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.


	Standardized Measure Year Ended December 31,
	2013			2012			2011
Future cash inflows	$	7,040,928		$	6,295,455		$	6,171,279
Future production costs		(2,062,657	)		(1,946,426	)		(1,747,806	)
Future development costs		(1,431,101	)		(1,241,531	)		(1,219,214	)
Future income taxes		(884,637	)		(799,007	)		(852,364	)

Future net cash flows		2,662,533			2,308,491			2,351,895
10% annual discount		(977,531	)		(794,632	)		(808,933	)

Standardized measure of discounted future net cash flows	$	1,685,002		$	1,513,859		$	1,542,962


	Changes in Standardized Measure Year Ended December 31,
	2013			2012			2011
Standardized measure at beginning of year	$	1,513,859		$	1,542,962		$	957,629
Sales and transfers of oil, gas and NGLs produced, net of production costs		(708,017	)		(697,741	)		(670,347	)
Changes in price, net of future production costs		229,425			(380,841	)		502,324
Extensions and discoveries, net of future production and development costs		155,592			178,272			293,168
Changes in estimated future development costs, net of development costs incurred during the period		28,684			212,329			97,852
Revisions of quantity estimates		281,558			76,450			(27,854	)
Accretion of discount		202,087			207,292			118,722
Net change in income taxes		(28,084	)		22,947			(300,363	)
Purchases of reserves in-place		—			276,389			567,286
Sales of reserves in-place		15,531			2,480			(36,278	)
Changes in production rates due to timing and other		(5,633	)		73,320			40,823

Net increase (decrease) in standardized measure		171,143			(29,103	)		585,333

Standardized measure at end of year	$	1,685,002		$	1,513,859		$	1,542,962