SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED

12 Months Ended

Dec. 31, 2017

Extractive Industries [Abstract]

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED

At December 31, 2017 and 2016, our oil and gas properties were located in the United States (onshore and offshore). On February 27, 2017, we completed the sale of the Appalachia Properties in connection with our restructuring (see Note 4 – Divestiture). During 2015, we discontinued our business development effort in Canada.

With the adoption of fresh start accounting, the Company recorded its oil and gas properties at fair value as of February 28, 2017. The Company’s proved, probable and possible reserves and unevaluated properties (including inventory) were assigned values of $380.8 million, $16.8 million and $80.2 million, respectively. See Note 3 – Fresh Start Accounting for a discussion of the valuation approach used.

Costs Incurred

United States. The following table discloses the total amount of capitalized costs and accumulated DD&A relative to our proved and unevaluated oil and natural gas properties located in the United States (in thousands):

	Successor			Predecessor
	December 31, 2017			December 31, 2016
Proved properties	$	713,157		$	9,572,082
Unevaluated properties	102,187			373,720
Total proved and unevaluated properties	815,344			9,945,802
Less accumulated depreciation, depletion and amortization	(353,462		)	(9,134,288		)
Balance, end of year	$	461,882		$	811,514

The following table sets forth certain information regarding the costs incurred in our acquisition, exploratory and development activities in the United States during the periods indicated (in thousands):

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Costs incurred during the period (capitalized):
Acquisition costs, net of sales of unevaluated properties	$	(8,371	)	$	(324	)	$	3,923		$	(14,158	)
Exploratory costs	12,079			2,055			17,891			104,169
Development costs (1)	33,356			12,547			102,665			266,982
Salaries, general and administrative costs	7,495			2,976			21,753			27,984
Interest	3,927			2,524			26,634			41,339
Less: overhead reimbursements	(1,004		)	—			(521		)	(913		)
Total costs incurred during the period, net of divestitures	$	47,482		$	19,778		$	172,345		$	425,403

(1) Includes net changes in capitalized asset retirement costs of ($17,446), $0, ($4,461) and ($43,901), respectively.

The following table discloses operational expenses incurred during the periods indicated relative to our oil and natural gas producing activities located in the United States (in thousands):

	Successor		Predecessor
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017		Year Ended December 31,
					2016		2015
Lease operating expenses	$	49,800	$	8,820	$	79,650	$	100,139
Transportation, processing and gathering expenses	4,084		6,933		27,760		58,847
Production taxes	629		682		3,148		6,877
Accretion expense	21,151		5,447		40,229		25,988
Expensed costs – United States	$	75,664	$	21,882	$	150,787	$	191,851

The following table sets forth certain information relative to the amortization of our investment in oil and gas properties and the impairment of our oil and gas properties in the United States for the periods indicated (in thousands, except per unit amounts):

	Successor		Predecessor
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017		Year Ended December 31,
					2016		2015
Provision for DD&A	$	97,027	$	36,751	$	215,737	$	277,088
Write-down of oil and gas properties	$	256,435	$	—	$	357,079	$	1,314,817
DD&A per Boe	$	16.61	$	17.05	$	16.10	$	19.15

At March 31, 2017 (Successor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $256.4 million based on twelve-month average prices, net of applicable differentials, of $45.40 per Bbl of oil, $2.24 per Mcf of natural gas and $19.18 per Bbl of NGLs. The write-down at March 31, 2017 is reflected in the statement of operations of the Successor Company for the period from March 1, 2017 through December 31, 2017 and was primarily due to differences between the trailing twelve-month average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017. Weighted average commodity prices used in the determination of the fair value of our oil and gas properties for purposes of fresh start accounting were $56.01 per Bbl of oil, $2.52 per Mcf of natural gas and $14.18 per Bbl of NGLs, net of applicable differentials.

Since none of our derivatives as of March 31, 2017 were designated as cash flow hedges (see Note 9 – Derivative Instruments and Hedging Activities), the write-down at March 31, 2017 was not affected by hedging. The 2016 and 2015 write-downs were decreased by $50.7 million and $143.9 million, 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 periods indicated (in thousands):

	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Net costs incurred (evaluated) during period:
Acquisition costs	$	(9,155	)	$	959		$	(71,378	)	$	(115,767	)
Exploration costs	10,405			(6,063		)	(21,579		)	(16,315		)
Capitalized interest	3,927			2,524			26,634			41,339
	$	5,177		$	(2,580	)	$	(66,323	)	$	(90,743	)

Under fresh start accounting, our oil and gas properties were recorded at fair value as of February 28, 2017. The following table discloses financial data associated with unevaluated costs (United States) for the Successor Company at December 31, 2017 (in thousands):

	Successor		Net Costs Incurred During the Period from March 1, 2017 through December 31, 2017			Successor
	March 1, 2017					December 31, 2017
Acquisition costs	$	58,359	$	(9,155	)	$	49,204
Exploration costs	38,651		10,405			49,056
Capitalized interest	—		3,927			3,927
Total unevaluated costs	$	97,010	$	5,177		$	102,187

Approximately 34 specifically identified drilling projects are included in unevaluated costs at December 31, 2017 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.

Canada. 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 (in thousands):

	Predecessor
	Year Ended December 31,
	2016			2015
Oil and gas properties – Canada:
Balance, beginning of year	$	42,484		$	36,579
Costs incurred during the year (capitalized):
Acquisition costs	(498		)	(2,862		)
Exploratory costs	2,168			8,767
Total costs incurred during the year	1,670			5,905
Balance, end of year (fully evaluated at December 31, 2016 and 2015)	$	44,154		$	42,484
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	$	—		$	—

Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2017 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 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 (MBoe)
Estimated proved developed and undeveloped reserves:
As of December 31, 2014 (Predecessor)	42,397		27,817		493,843		152,520
Revisions of previous estimates	(6,818	)	(20,777	)	(362,102	)	(87,945	)
Extensions, discoveries and other additions	862		11		1,499		1,123
Purchase of producing properties	685		1,808		26,136		6,849
Sale of reserves	(859	)	—		(1,061	)	(1,036	)
Production	(5,991	)	(2,401	)	(36,457	)	(14,468	)
As of December 31, 2015 (Predecessor)	30,276		6,458		121,858		57,043
Revisions of previous estimates	(751	)	6,352		24,858		9,744
Extensions, discoveries and other additions	63		2		45		73
Production	(6,308	)	(2,183	)	(29,441	)	(13,398	)
As of December 31, 2016 (Predecessor)	23,280		10,629		117,320		53,462
Revisions of previous estimates	730		(2	)	1,242		935
Sale of reserves	(826	)	(7,417	)	(52,992	)	(17,075	)
Production	(908	)	(408	)	(5,037	)	(2,156	)
As of February 28, 2017 (Predecessor)	22,276		2,802		60,533		35,166
Revisions of previous estimates	3,769		(94	)	(2,801	)	3,208
Production	(4,169	)	(403	)	(7,616	)	(5,841	)
As of December 31, 2017 (Successor)	21,876		2,305		50,116		32,533
Estimated proved developed reserves:
As of December 31, 2015 (Predecessor)	21,734		4,784		90,262		41,562
As of December 31, 2016 (Predecessor)	18,269		9,255		90,741		42,647
As of February 28, 2017 (Predecessor)	18,344		1,515		35,865		25,836
As of December 31, 2017 (Successor)	20,275		1,689		37,946		28,288
Estimated proved undeveloped reserves:
As of December 31, 2015 (Predecessor)	8,542		1,674		31,596		15,481
As of December 31, 2016 (Predecessor)	5,011		1,374		26,579		10,815
As of February 28, 2017 (Predecessor)	3,932		1,287		24,668		9,330
As of December 31, 2017 (Successor)	1,601		616		12,170		4,245

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

2017 Periods. Revisions of previous estimates were primarily the result of positive well performance (4 MMBoe). The sale of reserves represents the sale of the Appalachia Properties (17 MMBoe) in connection with our restructuring (see Note 4 – Divestiture).

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 (15 MMBoe) primarily in Appalachia, slightly offset by negative well performance (6 MMBoe).

Year Ended December 31, 2015. Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves (95 MMBoe) primarily in Appalachia, slightly offset by positive well performance (7 MMBoe). 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.

Standardized Measure of Discounted Future Net Cash Flows

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, 2017. 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. 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 100% of our estimated proved oil and natural gas reserves and standardized measure of discounted future net cash flows at December 31, 2017. The standardized measure of discounted future net cash flows and changes therein are as follows (in thousands, except average prices):

	Standardized Measure
	Successor			Predecessor
	December 31,			December 31,
	2017			2016			2015
Future cash inflows	$	1,264,809		$	1,236,097		$	1,921,329
Future production costs	(497,538		)	(480,815		)	(651,396		)
Future development costs	(431,752		)	(638,988		)	(679,355		)
Future income taxes	—			—			—
Future net cash flows	335,519			116,294			590,578
10% annual discount	57,591			109,628			13,259
Standardized measure of discounted future net cash flows	$	393,110		$	225,922		$	603,837
Average prices related to proved reserves:
Oil (per Bbl)	$	50.05		$	40.15		$	51.16
NGLs (per Bbl)	22.90			9.46			16.40
Natural gas (per Mcf)	2.34			1.71			2.19

	Changes in Standardized Measure
	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period From January 1, 2017 through February 28, 2017			Year Ended December 31,
							2016			2015
Standardized measure at beginning of period	$	303,086		$	225,922		$	603,837		$	1,418,792
Sales and transfers of oil, natural gas and NGLs produced, net of production costs	(164,612		)	(46,137		)	(223,948		)	(340,477		)
Changes in price, net of future production costs	66,192			17,455			(448,861		)	(237,747		)
Extensions and discoveries, net of future production and development costs	—			—			5,243			1,573
Changes in estimated future development costs, net of development costs incurred during the period	88,111			20,756			54,406			731,115
Revisions of quantity estimates	96,454			36,557			139,759			(1,458,652		)
Accretion of discount	30,309			22,592			60,384			174,456
Net change in income taxes	—			—			—			325,768
Purchases of reserves in-place	—			—			—			3,493
Sales of reserves in-place	—			14,584			—			—
Changes in production rates due to timing and other	(26,430		)	11,357			35,102			(14,484		)
Net change in standardized measure	90,024			77,164			(377,915		)	(814,955		)
Standardized measure at end of period	$	393,110		$	303,086		$	225,922		$	603,837