SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED:

At December 31, 2015, 2014 and 2013, our oil and gas properties were located in the United States and Canada.

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,
	2015			2014			2013
Oil and gas properties – United States, proved and unevaluated:
Balance, beginning of year	$	9,348,054		$	8,517,873		$	7,692,261
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties	(14,158		)	44,634			70,903
Exploratory costs	104,169			270,850			297,113
Development costs (1)	266,982			438,334			378,242
Salaries, general and administrative costs	27,984			33,975			32,815
Interest	41,339			45,722			46,860
Less: overhead reimbursements	(913		)	(3,334		)	(321		)
Total costs incurred during the year, net of divestitures	425,403			830,181			825,612
Balance, end of year	$	9,773,457		$	9,348,054		$	8,517,873
Accumulated DD&A:
Balance, beginning of year	$	(6,970,631	)	$	(5,908,760	)	$	(5,510,166	)
Provision for DD&A	(277,088		)	(335,987		)	(346,827		)
Write-down of oil and gas properties	(1,314,817		)	(351,192		)	—
Sale of proved properties	1,064			(374,692		)	(51,767		)
Balance, end of year	$	(8,561,472	)	$	(6,970,631	)	$	(5,908,760	)
Net capitalized costs – United States, proved and unevaluated	$	1,211,985		$	2,377,423		$	2,609,113
DD&A per Mcfe	$	3.19		$	3.59		$	3.43
(1) Includes capitalized asset retirement costs of ($43,901), ($20,305) and $54,737, respectively.
Costs incurred during the year (expensed):
Lease operating expenses	$	100,139		$	176,495		$	201,153
Transportation, processing and gathering expenses	58,847			64,951			42,172
Production taxes	6,877			12,151			15,029
Accretion expense	25,988			28,411			33,575
Expensed costs – United States	$	191,851		$	282,008		$	291,929

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 March 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $491,412 based on 12-month average prices, net of applicable differentials, of $78.99 per Bbl of oil, $2.96 per Mcf of natural gas and $28.82 per Bbl of natural gas liquids ("NGLs"). At June 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $179,125 based on 12-month average prices, net of applicable differentials, of $68.68 per Bbl of oil, $2.47 per Mcf of natural gas and $29.13 per Bbl of NGLs. At September 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $295,679 based on 12-month average prices, net of applicable differentials, of $57.76 per Bbl of oil, $2.44 per Mcf of natural gas and $23.04 per Bbl of NGLs. At December 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $348,601 based on 12-month average prices, net of applicable differentials, of $51.16 per Bbl of oil, $2.19 per Mcf of natural gas and $16.40 per Bbl of NGLs. The March 31, June 30, September 30 and December 31, 2015 write-downs were decreased by $28,687, $47,784, $42,652 and $24,797, respectively, as a result of hedges.

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 12-month average prices, net of applicable differentials, of $94.94 per Bbl of oil, $4.19 per Mcf of natural gas and $41.33 per Bbl of NGLs. 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 12-month average prices, net of applicable differentials, of $89.46 per Bbl of oil, $3.68 per Mcf of natural gas and $36.79 per Bbl of NGLs. 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:	2015			2014			2013
Net costs incurred (evaluated) during year:
Acquisition costs	$	(115,767	)	$	(42,384	)	$	30,271
Exploration costs	(16,315		)	(186,308		)	188,830
Capitalized interest	41,339			45,722			46,860
	$	(90,743	)	$	(182,970	)	$	265,961

During 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Upon a more complete evaluation of this project and in response to the significant decline in commodity prices over the last year, we have discontinued our business development effort in Canada. Accordingly, we recognized a full impairment of our Canadian oil and gas properties in 2015. The following table discloses certain financial data relative to our oil and gas activities located in Canada:



	Year Ended December 31,
	2015			2014		2013
Oil and gas properties – Canada:
Balance, beginning of year	$	36,579		$	10,583	$	—
Costs incurred during the year (capitalized):
Acquisition costs	(2,862		)	6,956		8,764
Exploratory costs	8,767			19,040		1,819
Total costs incurred during the year	5,905			25,996		10,583
Balance, end of year (fully evaluated at December 31, 2015 and unevaluated at December 31, 2014 and 2013)	$	42,484		$	36,579	$	10,583
Accumulated DD&A:
Balance, beginning of year	$	—		$	—	$	—
Foreign currency translation adjustment	5,146			$	—	—
Write-down of oil and gas properties	(47,630		)	$	—	—
Balance, end of year	$	(42,484	)	$	—	$	—
Net capitalized costs – Canada	$	—		$	36,579	$	10,583

The following table discloses financial data associated with unevaluated costs (United States) at December 31, 2015:



	Balance as of		Net Costs Incurred During the Year Ended December 31,
	December 31, 2015		2015			2014			2013		2012 and prior
Acquisition costs	$	173,902	$	(33,623	)	$	(5,118	)	$	40,535	$	172,108
Exploration costs	148,518		41,936			42,899			42,186		21,497
Capitalized interest	117,623		20,257			23,538			24,162		49,666
Total unevaluated costs	$	440,043	$	28,570		$	61,319		$	106,883	$	243,271

Approximately 95 specifically identified drilling projects are included in unevaluated costs at December 31, 2015 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, 2015, 2014 and 2013 totaled $41,339, $45,722 and $46,860, respectively.

Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2015 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 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, 2015, 2014 and 2013 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, 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
Revisions of previous estimates	(6,818	)	(20,777	)	(362,102	)	(527,675	)
Extensions, discoveries and other additions	862		11		1,499		6,738
Purchase of producing properties	685		1,808		26,136		41,095
Sale of reserves	(859	)	—		(1,061	)	(6,213	)
Production	(5,991	)	(2,401	)	(36,457	)	(86,809	)
Estimated proved reserves as of December 31, 2015	30,276		6,458		121,858		342,260
Estimated proved developed reserves:
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
as of December 31, 2015	21,734		4,784		90,262		249,366
Estimated proved undeveloped reserves:
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
as of December 31, 2015	8,542		1,674		31,596		92,894

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

Year Ended December 31, 2015. Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves (570 Bcfe) primarily in Appalachia, slightly offset by positive well performance (42 Bcfe). Purchase of producing properties related to increases in our net revenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units.

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 related 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).

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, 2015. 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 2015 average historical 12-month oil and natural gas prices, net of applicable differentials, were $51.16 per Bbl of oil, $16.40 per Bbl of NGLs and $2.19 per Mcf of natural gas. The 2014 average 12-month oil and natural 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 natural gas. The 2013 average 12-month oil and natural 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 natural 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,
	2015			2014			2013
Future cash inflows	$	1,921,329		$	6,635,751		$	7,040,928
Future production costs	(651,396		)	(2,413,004		)	(2,062,657		)
Future development costs	(679,355		)	(1,511,687		)	(1,431,101		)
Future income taxes	—			(609,516		)	(884,637		)
Future net cash flows	590,578			2,101,544			2,662,533
10% annual discount	13,259			(682,752		)	(977,531		)
Standardized measure of discounted future net cash flows	$	603,837		$	1,418,792		$	1,685,002



	Changes in Standardized Measure Year Ended December 31,
	2015			2014			2013
Standardized measure at beginning of year	$	1,418,792		$	1,685,002		$	1,513,859
Sales and transfers of oil, natural gas and NGLs produced, net of production costs	(340,477		)	(486,232		)	(708,017		)
Changes in price, net of future production costs	(237,747		)	(864,118		)	229,425
Extensions and discoveries, net of future production and development costs	1,573			549,649			155,592
Changes in estimated future development costs, net of development costs incurred during the period	731,115			203,026			28,684
Revisions of quantity estimates	(1,458,652		)	(27,495		)	281,558
Accretion of discount	174,456			222,009			202,087
Net change in income taxes	325,768			209,323			(28,084		)
Purchases of reserves in-place	3,493			—			—
Sales of reserves in-place	—			(152,787		)	15,531
Changes in production rates due to timing and other	(14,484		)	80,415			(5,633		)
Net increase (decrease) in standardized measure	(814,955		)	(266,210		)	171,143
Standardized measure at end of year	$	603,837		$	1,418,792		$	1,685,002