NOTE 17 — SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED:

At December 31, 2014 and 2013, our oil and gas properties were located in the United States and Canada. At December 31, 2012, all of our oil and gas properties were located in the United States.

Costs Incurred

The following table discloses certain financial data relative to our oil and gas producing activities located onshore and offshore in the continental United States:


	Year Ended December 31,
	2014		2013		2012
Oil and gas properties – United States, proved and unevaluated:
Balance, beginning of year		$8,517,873		$7,692,261		$7,049,777
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties		44,634		70,903		102,807
Exploratory costs		270,850		297,113		81,458
Development costs (1)		438,334		378,242		395,555
Salaries, general and administrative costs		33,975		32,815		25,318
Interest		45,722		46,860		37,656
Less: overhead reimbursements		(3,334)		(321)		(310)

Total costs incurred during the year, net of divestitures		830,181		825,612		642,484

Balance, end of year		$9,348,054		$8,517,873		$7,692,261


Accumulated DD&A:
Balance, beginning of year		($5,908,760)		($5,510,166)		($5,174,729)
Provision for DD&A		(335,987)		(346,827)		(341,096)
Write-down of oil and gas properties		(351,192)		-		-
Sale of proved properties		(374,692)		(51,767)		5,659

Balance, end of year		($6,970,631)		($5,908,760)		($5,510,166)


Net capitalized costs – United States, proved and unevaluated		$2,377,423		$2,609,113		$2,182,095


DD&A per Mcfe		$3.59		$3.43		$3.69


(1) Includes capitalized asset retirement costs of ($20,305), $54,737 and $95,293, respectively.

Costs incurred during the year (expensed):
Lease operating expenses		$176,495		$201,153		$215,003
Transportation, processing and gathering expenses		64,951		42,172		21,782
Production taxes		12,151		15,029		10,015
Accretion expense		28,411		33,575		33,331

Expensed costs – United States		$282,008		$291,929		$280,131

Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows. At September 30, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $47,130 based on twelve month average prices, net of applicable differentials, of $94.94 per barrel of oil, $4.19 per Mcf of natural gas and $41.33 per barrel of natural gas liquids. At December 31, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $304,062 based on twelve month average prices, net of applicable differentials, of $89.46 per barrel of oil, $3.68 per Mcf of natural gas and $36.79 per barrel of natural gas liquids. The September 30 and December 31, 2014 write-downs were increased by $29,001 and $13,342, respectively, as a result of hedges.

The following table discloses net costs incurred (evaluated) on our unevaluated properties located in the United States for the years indicated:


	Year Ended December 31,
Unevaluated oil and gas properties – United States:	2014		2013		2012
Net costs incurred (evaluated) during year:
Acquisition costs		($42,384)		$30,271		$9,739
Exploration costs		(186,308)		188,830		(1,209)
Capitalized interest		45,722		46,860		37,656

		($182,970)		$265,961		$46,186

During 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. The following table discloses certain financial data relative to our oil and gas activities located in Canada:


	Year Ended December 31,
	2014		2013
Oil and gas properties – Canada, unevaluated:
Balance, beginning of year		$10,583		$ -
Costs incurred during the year (capitalized):
Acquisition costs		6,956		8,764
Exploratory costs		19,040		1,819

Total costs incurred during the year		25,996		10,583

Balance, end of year, unevaluated		$36,579		$10,583

The following table discloses financial data associated with unevaluated costs (United States and Canada) at December 31, 2014:


	Balance as of December 31, 2014		Net Costs Incurred During the Year Ended December 31,
	Balance as of December 31, 2014		2014		2013		2012		2011 and prior
Acquisition costs		$285,896		$7,330		$82,990		$24,736		$170,840
Exploration costs		167,510		66,512		78,684		5,318		16,996
Capitalized interest		113,959		22,352		36,137		21,993		33,477

Total unevaluated costs		$567,365		$96,194		$197,811		$52,047		$221,313

Approximately 108 specifically identified drilling projects are included in unevaluated costs at December 31, 2014 and are expected to be evaluated in the next four years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. Interest costs capitalized on unevaluated properties during the years ended December 31, 2014, 2013 and 2012 totaled $45,722, $46,860 and $37,656, respectively.

Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2014 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 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, 2014, 2013 and 2012 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical 12-month average pricing assumption.


	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Oil, Natural Gas and NGLs (MMcfe)
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
Revisions of previous estimates		(624)		(331)		(4,631)		(10,362)
Extensions, discoveries and other additions		9,650		7,521		131,617		234,639
Sale of reserves		(4,888)		(556)		(46,483)		(79,151)
Production		(5,568)		(2,114)		(47,426)		(93,515)

Estimated proved reserves as of December 31, 2014		42,397		27,817		493,843		915,124


Estimated proved developed reserves:
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

as of December 31, 2014		22,957		13,743		249,924		470,118

Estimated proved undeveloped reserves:
as of December 31, 2012		15,913		9,473		184,418		336,745

as of December 31, 2013		15,907		11,728		213,820		379,628

as of December 31, 2014		19,440		14,074		243,919		445,006

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

Year Ended December 31, 2014. Extensions, discoveries and other additions were primarily the result of our Appalachia (118 Bcfe) and our deep water (116 Bcfe) drilling programs. Sale of reserves primarily relates to the sale of certain of our non-core GOM conventional shelf properties (63 Bcfe) and our Katie field in Appalachia (15 Bcfe).

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 (18 Bcfe) and well performance (55 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.

Standardized Measure of Discounted Future Net Cash Flow

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, 2014. 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 2014 average historical 12-month oil and gas prices, net of applicable differentials, were $89.46 per Bbl of oil, $36.79 per Bbl of NGLs and $3.68 per Mcf of gas. The 2013 average 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. 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,
	2014		2013		2012
Future cash inflows		$ 6,635,751		$ 7,040,928		$ 6,295,455
Future production costs		(2,413,004)		(2,062,657)		(1,946,426)
Future development costs		(1,511,687)		(1,431,101)		(1,241,531)
Future income taxes		(609,516)		(884,637)		(799,007)

Future net cash flows		2,101,544		2,662,533		2,308,491
10% annual discount		(682,752)		(977,531)		(794,632)


Standardized measure of discounted future net cash flows		$ 1,418,792		$ 1,685,002		$ 1,513,859


	Changes in Standardized Measure Year Ended December 31,
	2014		2013		2012
Standardized measure at beginning of year		$1,685,002		$1,513,859		$1,542,962
Sales and transfers of oil, gas and NGLs produced, net of production costs		(486,232)		(708,017)		(697,741)
Changes in price, net of future production costs		(864,118)		229,425		(380,841)
Extensions and discoveries, net of future production and development costs		549,649		155,592		178,272
Changes in estimated future development costs, net of development costs incurred during the period		203,026		28,684		212,329
Revisions of quantity estimates		(27,495)		281,558		76,450
Accretion of discount		222,009		202,087		207,292
Net change in income taxes		209,323		(28,084)		22,947
Purchases of reserves in-place		-		-		276,389
Sales of reserves in-place		(152,787)		15,531		2,480
Changes in production rates due to timing and other		80,415		(5,633)		73,320

Net increase (decrease) in standardized measure		(266,210)		171,143		(29,103)

Standardized measure at end of year		$1,418,792		$1,685,002		$1,513,859