NOTE 17 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserve Information. The preparation of our natural gas, oil and NGL reserve estimates was completed in accordance with our prescribed internal control procedures by our reserve engineers. Other than for our Rangely assets, for the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to us. The reserve information for us includes natural gas, oil and NGL reserves which are all located throughout the United States. The independent reserve engineer’s evaluation was based on more than 40 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. For our Rangely assets, Cawley, Gillespie, and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserve engineer’s evaluation was based on more than 34 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by our President.

The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last three years. Proved oil, gas and NGL reserves are those quantities of oil, gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows were estimated using an unweighted average of the first-day-of-the-month prices for each of the previous twelve months from the period presented, including adjustments related to regional price differentials and energy content.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of our oil, gas and NGL reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil, gas and NGL prices and in production and development costs and other factors, for their effects have not been proved.

Reserve quantity information and a reconciliation of changes in proved reserve quantities are as follows:

	Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)			Total (MMcfe)
Predecessor, January 1, 2014		1,003,538			14,989			18,957		1,207,214
Extensions, discoveries and other additions⁽¹⁾		58,455			3,372			3,986		102,603
Sales of reserves in-place		(169	)		(2	)		(11	)	(247	)
Purchase of reserves in-place⁽²⁾		82,280			36,539			3,567		322,916
Transfers to Drilling Partnerships		(4,887	)		(685	)		(665	)	(12,987	)
Revisions of previous estimates⁽³⁾		3,806			(4,941	)		(2,689	)	(41,974	)
Production		(86,638	)		(1,254	)		(1,387	)	(102,484	)
Predecessor Balance, December 31, 2014		1,056,385			48,018			21,758		1,475,041
Extensions, discoveries and other additions⁽¹⁾		6,442			2,492			218		22,702
Sales of reserves in-place		(2,713	)		(2	)		—		(2,725	)
Purchase of reserves in-place⁽²⁾		3,555			8,645			653		59,343
Transfers to Drilling Partnerships		(2,959	)		(482	)		(342	)	(7,903	)
Revisions of previous estimates⁽³⁾		(377,067	)		(11,992	)		(13,382	)	(529,311	)
Production		(79,064	)		(1,875	)		(1,055	)	(96,644	)
Predecessor Balance, December 31, 2015		604,579			44,804			7,850		920,504
Extensions, discoveries and other additions	902			154			—			1,826
Sales of reserves in-place	(201		)	—			(20		)	(321	)
Purchase of reserves in-place	1,615			13			—			1,693
Revisions of previous estimates⁽³⁾	(41,487		)	(7,003		)	(1,593		)	(93,063	)
Production	(45,561		)	(1,026		)	(488		)	(54,645	)
Predecessor Balance, August 31, 2016	519,847			36,942			5,749			775,993
Successor Balance, September 1, 2016	519,847			36,942			5,749			775,993
Extensions, discoveries and other additions⁽¹⁾	1,538			2,469			299			18,146
Sales of reserves in-place	(59		)	—			—			(59	)
Purchase of reserves in-place⁽²⁾	52,419			170			56			53,775
Revisions of previous estimates⁽³⁾	143,066			43			965			149,114
Production	(22,239		)	(574		)	(204		)	(26,907	)
Successor Balance, December 31, 2016	694,572			39,050			6,865			970,062


Proved developed reserves at:
Predecessor January 1, 2014		766,631			3,459			7,676		833,441
Predecessor December 31, 2014		887,819			30,538			12,005		1,143,077
Predecessor December 31, 2015		567,993			25,484			6,334		758,901
Predecessor August 31, 2016		508,922			18,863			4,637		649,922
Successor December 31, 2016	690,894			24,936			5,975			876,360
Proved undeveloped reserves at:
Predecessor January 1, 2014		236,907			11,530			11,281		373,773
Predecessor December 31, 2014		168,566			17,480			9,753		331,964
Predecessor December 31, 2015		36,586			19,320			1,516		161,602
Predecessor August 31, 2016		10,925			18,079			1,112		126,071
Successor December 31, 2016	3,678			14,114			890			93,702

(1)

For the Successor period from September 1, 2016 through December 31, 2016, the increase represents PUD additions related to our development and leasing activity in the Eagle Ford Shale. For the Predecessor year ended December 31, 2015, the increase represents PUD additions related to our development activity in the Eagle Ford Shale. For the Predecessor year ended December 31, 2014, the increase was primarily due to the addition of Marble Falls wells.

(2)

Represents purchase of proved reserves from Drilling Partnership consolidations for the Successor period from September 1, 2016 through December 31, 2016 (see Note 10). Represents purchase of proved reserves from the Eagle Ford Acquisitions for the Predecessor year ended December 31, 2015 (see Note 4). Represents purchase of proved reserves from the Rangely, Eagle Ford and GeoMet Acquisitions for the Predecessor year ended December 31, 2014 (see Note 4).

(3)	See “Revisions of Previous Estimates” section below for additional discussion and analysis of significant components of revisions of previous estimates.

Revisions of Previous Estimates

The following represents the unweighted average of the first-day-of-the-month prices for each of the previous twelve months from the periods presented above:

		Successor		Predecessor
		December 31, 2016		August 31, 2016	December 31, 2015				December 31, 2014
Unadjusted Prices
Natural gas (per MMBtu)	$	2.48	$	2.26		$	2.59	$	4.35
Oil (per Bbl)	$	42.75	$	41.87		$	50.28	$	94.99
Natural gas liquids (per Bbl)	$	19.57	$	13.07		$	11.02	$	30.21

For the Successor period from September 1, 2016 through December 31, 2016 we had positive revisions of 145,507 MMcfe due to our production outperforming the comparable period’s forecast and 41,859 MMcfe due to increases in pricing, partially offset by a negative revision of 38,252 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing.

For the Predecessor period from January 1, 2016 through August 31, 2016 we had negative revisions of 66,376 MMcfe due to decreases in pricing and 42,361 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing, partially offset by positive revision of 15,674 MMcfe due to our production outperforming the comparable period’s forecast.

For the Predecessor year ended December 31, 2015, we had negative revisions of 260,727 MMcfe due to decreases in pricing, 220,283 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing and 48,301 MMcfe due to production underperforming previous year’s forecast.

For the Predecessor year ended December 31, 2014, we had negative revisions of 147,189 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing, partially offset by positive revisions of 58,690 MMcfe due to our production outperforming the comparable period’s forecast and 46,525 MMcfe due to increases in pricing.

Capitalized Costs Related to Oil and Gas Producing Activities. The components of our capitalized costs related to oil and gas producing activities at the periods indicated were as follows (in thousands):

	Successor			Predecessor
	December 31, 2016			December 31, 2015
Natural gas and oil properties:
Proved properties	$	717,839		$	3,585,839
Unproved properties		74,434			213,047
Support equipment		2,643			44,921
		794,916			3,843,807
Accumulated depreciation, depletion and amortization		(21,056	)		(2,691,692	)
Net capitalized costs	$	773,860		$	1,152,115

Results of Operations from Oil and Gas Producing Activities. The results of operations related to our oil and gas producing activities during the periods indicated were as follows (in thousands):

		Successor		Predecessor
		Period from September 1, 2016 through December 31, 2016		Period from January 1, 2016 through August 31, 2016			Year Ended December 31, 2015				Year Ended December 31, 2014
Revenues	$	86,936		$	139,094			$	356,999			$	470,051
Production costs		(39,418	)		(86,566	)			(169,653	)			(182,226	)
Depletion		(21,012	)		(64,049	)			(145,161	)			(229,482	)
Asset impairment⁽¹⁾		—			—				(966,635	)			(573,774	)
Income tax (expense) benefit		—			—				—				—
	$	26,506		$	(11,521	)		$	(924,450	)		$	(515,431)

(1)

During the Predecessor year ended December 31, 2015, our Predecessor recognized $966.6 million of asset impairment primarily related to oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income, and $6.6 million of asset impairment of unproved acreage in the New Albany Shale, which was impaired due to expiring acreage and no intention to pursue development.. During the Predecessor year ended December 31, 2014, our Predecessor recognized $573.8 million of asset impairment consisting of $555.7 million related to oil and gas properties within the Appalachia and Mid-Continent operating areas, which was net of $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $18.1 million of goodwill impairment resulting from the decline in overall commodity prices.

Costs Incurred in Oil and Gas Producing Activities. Our costs incurred in our oil and gas activities during the periods indicated were as follows (in thousands):

		Successor	Predecessor
		Period from September 1, 2016 through December 31, 2016	Period from January 1, 2016 through August 31, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Property acquisition costs:
Proved properties	$	1,307	$	2,359	$	11,513	$	699,451
Unproved properties		—		—		43,820		10,978
Exploration costs⁽¹⁾		383		943		1,601		722
Development costs		20,835		12,395		73,288		164,853
Total costs incurred in oil & gas producing activities	$	22,525	$	15,697	$	130,222	$	876,004

(1)	There were no exploratory wells drilled during the periods presented.

Standardized Measure of Discounted Future Cash Flows. The following table presents the standardized measure of estimated discounted future net cash flows relating our proved oil and gas reserves. The estimated future production was priced at an unweighted average of the first-day-of-the-month prices for each of the previous twelve months from the periods presented, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. For the Successor period presented, future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved reserves and the tax basis of proved oil and gas properties as well as the effects of statutory depletion in excess of tax basis, available net operating loss carryforwards and alternative minimum tax credits. For the Predecessor periods presented, future income tax expenses were not applicable since our Predecessor allocated taxable income to its unit holders. The resulting annual net cash inflows were then discounted using a 10% annual rate. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):

		Successor		Predecessor
		December 31, 2016		August 31, 2016			December 31, 2015			December 31, 2014
Future cash inflows	$	3,136,665		$	2,484,094		$	3,514,198		$	9,317,915
Future production costs		(1,774,007	)		(1,506,678	)		(1,836,779	)		(4,188,364	)
Future development costs		(394,863	)		(460,195	)		(1,156,367	)		(1,157,305	)
Future income tax expense		(99,233	)		—			—			—
Future net cash flows		868,562			517,221			521,052			3,972,246
Less 10% annual discount for estimated timing of cash flows		(412,904	)		(249,576	)		(18,283	)		(1,987,975	)
Standardized measure of discounted future net cash flows	$	455,658		$	267,645		$	502,769		$	1,984,271

Change in Standardized Discounted Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands).

		Successor		Predecessor
		December 31, 2016		August 31, 2016			December 31, 2015			December 31, 2014
Balance, beginning of period	$	267,645		$	502,769		$	1,984,271		$	1,076,182
Increase (decrease) in discounted future net cash flows⁽¹⁾
Sales of oil and gas produced, net of related costs		(37,136	)		(57,700	)		(129,352	)		(272,961	)
Net changes in prices and production costs		70,716			(237,106	)		(1,453,854	)		339,718
Revisions of previous quantity estimates		101,366			(102	)		(52,775	)		4,352
Development costs incurred		18,838			—			58,117			52,077
Changes in future development costs		20,098			10,492			(152,305	)		(90,887	)
Transfers to Drilling Partnerships		—			—			(13,291	)		(2,966	)
Extensions, discoveries, and improved recovery less related costs		16,438			(57	)		13,980			60,832
Purchases of reserves in-place		24,794			711			53,102			737,101
Sales of reserves in-place		(7	)		(117	)		(2,162	)		(332	)
Accretion of discount		26,765			50,277			198,427			107,618
Estimated settlement of asset retirement obligations		(5,886	)		(1,522	)		(216	)		(16,708	)
Estimated proceeds on disposals of well equipment		(1,732	)		—			(1,173	)		(21,906	)
Changes in production rates (timing) and other		—			—			—			12,151
Net changes in income taxes		(46,241	)		—			—			—
Outstanding, end of period	$	455,658		$	267,645		$	502,769		$	1,984,271

(1)	See “Reserve Quantity Information” and “Revisions of Previous Estimates” sections above for additional discussion and analysis of significant changes within the periods presented.