SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED:

At December 31, 2016, 2015 and 2014, 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,
	2016			2015			2014
Oil and gas properties – United States, proved and unevaluated:
Balance, beginning of year	$	9,773,457		$	9,348,054		$	8,517,873
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties	3,923			(14,158		)	44,634
Exploratory costs	17,891			104,169			270,850
Development costs (1)	102,665			266,982			438,334
Salaries, general and administrative costs	21,753			27,984			33,975
Interest	26,634			41,339			45,722
Less: overhead reimbursements	(521		)	(913		)	(3,334		)
Total costs incurred during the year, net of divestitures	172,345			425,403			830,181
Balance, end of year	$	9,945,802		$	9,773,457		$	9,348,054
Accumulated DD&A:
Balance, beginning of year	$	(8,561,472	)	$	(6,970,631	)	$	(5,908,760	)
Provision for DD&A	(215,737		)	(277,088		)	(335,987		)
Write-down of oil and gas properties	(357,079		)	(1,314,817		)	(351,192		)
Sale of proved properties	—			1,064			(374,692		)
Balance, end of year	$	(9,134,288	)	$	(8,561,472	)	$	(6,970,631	)
Net capitalized costs – United States, proved and unevaluated	$	811,514		$	1,211,985		$	2,377,423
DD&A per Mcfe	$	2.68		$	3.19		$	3.59

(1) Includes capitalized asset retirement costs of ($4,461), ($43,901) and ($20,305), respectively.



Costs incurred during the year (expensed):
Lease operating expenses	$	79,650	$	100,139	$	176,495
Transportation, processing and gathering expenses	27,760		58,847		64,951
Production taxes	3,148		6,877		12,151
Accretion expense	40,229		25,988		28,411
Expensed costs – United States	$	150,787	$	191,851	$	282,008

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, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $128,852 based on twelve-month average prices, net of applicable differentials, of $46.72 per Bbl of oil, $2.01 per Mcf of natural gas and $13.65 per Bbl of NGLs. At March 31, 2016, the write-down of oil and gas properties also included $352 related to our Canadian oil and gas properties, which were deemed to be fully impaired at the end of 2015. At June 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $118,649 based on twelve-month average prices, net of applicable differentials, of $43.49 per Bbl of oil, $1.93 per Mcf of natural gas and $9.33 per Bbl of NGLs. At September 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $36,484 based on twelve-month average prices, net of applicable differentials, of $40.51 per Bbl of oil, $1.99 per Mcf of natural gas and $13.88 per Bbl of NGLs. At December 31, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $73,094 based on twelve-month average prices, net of applicable differentials, of $40.15 per Bbl of oil, $1.71 per Mcf of natural gas and $9.46 per Bbl of NGLs. The March 31, June 30 and September 30, 2016 write-downs were decreased by $22,986, $18,112 and $9,636, respectively, as a result of hedges. There was no hedging impact on the December 31, 2016 write-down.

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 twelve-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 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 twelve-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 twelve-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 twelve-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 twelve-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 twelve-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:	2016			2015			2014
Net costs incurred (evaluated) during year:
Acquisition costs	$	(71,378	)	$	(115,767	)	$	(42,384	)
Exploration costs	(21,579		)	(16,315		)	(186,308		)
Capitalized interest	26,634			41,339			45,722
	$	(66,323	)	$	(90,743	)	$	(182,970	)

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, we discontinued our business development effort in Canada during 2015 and recognized a full impairment of our Canadian oil and gas properties. The following table discloses certain financial data relative to our oil and gas activities located in Canada:



	Year Ended December 31,
	2016			2015			2014
Oil and gas properties – Canada:
Balance, beginning of year	$	42,484		$	36,579		$	10,583
Costs incurred during the year (capitalized):
Acquisition costs	(498		)	(2,862		)	6,956
Exploratory costs	2,168			8,767			19,040
Total costs incurred during the year	1,670			5,905			25,996
Balance, end of year (fully evaluated at December 31, 2016 and 2015 and unevaluated at December 31, 2014)	$	44,154		$	42,484		$	36,579
Accumulated DD&A:
Balance, beginning of year	$	(42,484	)	$	—		$	—
Foreign currency translation adjustment	(1,318		)	5,146			—
Write-down of oil and gas properties	(352		)	(47,630		)	—
Balance, end of year	$	(44,154	)	$	(42,484	)	$	—
Net capitalized costs – Canada	$	—		$	—		$	36,579

The following table discloses financial data associated with unevaluated costs (United States) at December 31, 2016:



	Balance as of		Net Costs Incurred During the Year Ended December 31,
	December 31, 2016		2016		2015		2014		2013 and prior
Acquisition costs	$	122,589	$	8,278	$	17,308	$	47,490	$	49,513
Exploration costs	153,320		34,183		38,686		42,298		38,153
Capitalized interest	97,811		24,759		33,232		32,287		7,533
Total unevaluated costs	$	373,720	$	67,220	$	89,226	$	122,075	$	95,199

Approximately 73 specifically identified drilling projects are included in unevaluated costs at December 31, 2016 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, 2016, 2015 and 2014 totaled $26,634, $41,339 and $45,722, respectively.

Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2016 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, 2016, 2015 and 2014 are prepared in accordance with the SEC’s rule, "Modernization of Oil and Gas Reporting," using a historical twelve-month average pricing assumption.



	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Oil, Natural Gas and NGLs (MMcfe)
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
Revisions of previous estimates	(751	)	6,352		24,858		58,465
Extensions, discoveries and other additions	63		2		45		435
Production	(6,308	)	(2,183	)	(29,441	)	(80,387	)
Estimated proved reserves as of December 31, 2016	23,280		10,629		117,320		320,773
Estimated proved developed reserves:
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
as of December 31, 2016	18,269		9,255		90,741		255,884
Estimated proved undeveloped reserves:
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
as of December 31, 2016	5,011		1,374		26,579		64,889

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

Year Ended December 31, 2016. Revisions of previous estimates were primarily the result of positive reserve report gas pricing changes extending the economic limits of the reservoirs (92 Bcfe) primarily in Appalachia, slightly offset by negative well performance (35 Bcfe).

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).

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, 2016. 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 twelve-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The 2016 average historical twelve-month oil and natural gas prices, net of applicable differentials, were $40.15 per Bbl of oil, $9.46 per Bbl of NGLs and $1.71 per Mcf of natural gas. The 2015 average twelve-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 twelve-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. 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. Our GOM Basin properties represented approximately 66% of our estimated proved oil and natural gas reserves and virtually all of the standardized measure of discounted future net cash flows at December 31, 2016.



	Standardized Measure Year Ended December 31,
	2016			2015			2014
Future cash inflows	$	1,236,097		$	1,921,329		$	6,635,751
Future production costs	(480,815		)	(651,396		)	(2,413,004		)
Future development costs	(638,988		)	(679,355		)	(1,511,687		)
Future income taxes	—			—			(609,516		)
Future net cash flows	116,294			590,578			2,101,544
10% annual discount	109,628			13,259			(682,752		)
Standardized measure of discounted future net cash flows	$	225,922		$	603,837		$	1,418,792



	Changes in Standardized Measure Year Ended December 31,
	2016			2015			2014
Standardized measure at beginning of year	$	603,837		$	1,418,792		$	1,685,002
Sales and transfers of oil, natural gas and NGLs produced, net of production costs	(223,948		)	(340,477		)	(486,232		)
Changes in price, net of future production costs	(448,861		)	(237,747		)	(864,118		)
Extensions and discoveries, net of future production and development costs	5,243			1,573			549,649
Changes in estimated future development costs, net of development costs incurred during the period	54,406			731,115			203,026
Revisions of quantity estimates	139,759			(1,458,652		)	(27,495		)
Accretion of discount	60,384			174,456			222,009
Net change in income taxes	—			325,768			209,323
Purchases of reserves in-place	—			3,493			—
Sales of reserves in-place	—			—			(152,787		)
Changes in production rates due to timing and other	35,102			(14,484		)	80,415
Net decrease in standardized measure	(377,915		)	(814,955		)	(266,210		)
Standardized measure at end of year	$	225,922		$	603,837		$	1,418,792