SUPPLEMENTAL OIL AND GAS DISCLOSURES

(UNAUDITED)

Our oil and gas operations are substantially located in the United States. The capitalized costs at year end and costs incurred during the year were as follows:



	2017			2016			2015
	(In thousands)
Capitalized costs:
Proved properties	$	5,712,813		$	5,446,305		$	5,401,618
Unproved properties	296,764			314,867			337,099
	6,009,577			5,761,172			5,738,717
Accumulated depreciation, depletion, amortization, and impairment	(4,996,696		)	(4,900,304		)	(4,631,404		)
Net capitalized costs	$	1,012,881		$	860,868		$	1,107,313
Cost incurred:
Unproved properties acquired	$	47,029		$	21,675		$	41,777
Proved properties acquired	47,638			564			179
Exploration	14,811			17,325			19,222
Development	160,941			80,582			208,845
Asset retirement obligation	(3,613		)	(30,906		)	(5,693		)
Total costs incurred	$	266,806		$	89,240		$	264,330

The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2017, by the year in which such costs were incurred:



	2017		2016		2015		2014 and Prior		Total
	(In thousands)
Unproved properties acquired and wells in progress	$	50,447	$	22,092	$	40,254	$	183,971	$	296,764

Unproved properties not subject to amortization relates to properties which are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the company is unable to estimate when these costs will be included in the amortization calculation.

The results of operations for producing activities are as follows:



	2017			2016			2015
	(In thousands)
Revenues	$	347,285		$	282,742		$	371,335
Production costs	(107,332		)	(108,822		)	(152,560		)
Depreciation, depletion, amortization, and impairment	(96,392		)	(268,901		)	(1,844,726		)
	143,561			(94,981		)	(1,625,951		)
Income tax (expense) benefit	(56,376		)	32,696			612,496
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	87,185		$	(62,285	)	$	(1,013,455	)

Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows:



	Oil Bbls		NGLs Bbls		Natural Gas Mcf		Total MBoe
	(In thousands)
2015
Proved developed and undeveloped reserves:
Beginning of year	22,667		48,529		646,961		179,023
Revision of previous estimates ⁽¹⁾	(3,954	)	(9,367	)	(139,514	)	(36,573	)
Extensions and discoveries	1,208		1,948		20,974		6,651
Infill reserves in existing proved fields	670		1,861		22,641		6,304
Purchases of minerals in place	—		—		—		—
Production	(3,783	)	(5,274	)	(65,546	)	(19,981	)
Sales	(73	)	(10	)	(648	)	(191	)
End of year	16,735		37,687		484,868		135,233
Proved developed reserves:
Beginning of year	17,448		35,850		500,950		136,790
End of year	14,679		31,218		416,395		115,296
Proved undeveloped reserves:
Beginning of year	5,219		12,679		146,011		42,233
End of year	2,056		6,469		68,473		19,937
2016
Proved developed and undeveloped reserves:
Beginning of year	16,735		37,687		484,868		135,233
Revision of previous estimates ⁽¹⁾	(549	)	(2,473	)	(31,670	)	(8,300	)
Extensions and discoveries	1,816		1,588		13,720		5,690
Infill reserves in existing proved fields	663		2,724		24,704		7,504
Purchases of minerals in place	114		43		630		262
Production	(2,974	)	(5,014	)	(55,735	)	(17,277	)
Sales	(109	)	(73	)	(30,938	)	(5,338	)
End of year	15,696		34,482		405,579		117,774
Proved developed reserves:
Beginning of year	14,679		31,218		416,395		115,296
End of year	12,724		28,502		347,121		99,079
Proved undeveloped reserves:
Beginning of year	2,056		6,469		68,473		19,937
End of year	2,972		5,980		58,458		18,695
2017
Proved developed and undeveloped reserves:
Beginning of year	15,696		34,482		405,579		117,774
Revision of previous estimates	730		4,325		38,330		11,444
Extensions and discoveries	2,235		4,520		49,321		14,975
Infill reserves in existing proved fields	1,632		5,779		52,270		16,123
Purchases of minerals in place	2,019		1,197		15,313		5,768
Production	(2,715	)	(4,737	)	(51,260	)	(15,996	)
Sales	(84	)	(80	)	(903	)	(314	)
End of year	19,513		45,486		508,650		149,774
Proved developed reserves:
Beginning of year	12,724		28,502		347,121		99,079
End of year	14,862		33,358		388,446		112,961
Proved undeveloped reserves:
Beginning of year	2,972		5,980		58,458		18,695
End of year	4,651		12,128		120,204		36,813

_________________________


(1)	Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.

Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows.

The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year end costs adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows:



	2017			2016			2015
	(In thousands)
Future cash flows	$	3,347,396		$	2,030,925		$	2,475,898
Future production costs	(1,308,244		)	(861,625		)	(1,017,777		)
Future development costs	(369,560		)	(173,446		)	(228,445		)
Future income tax expenses	(234,152		)	(141,752		)	(230,544		)
Future net cash flows	1,435,440			854,102			999,132
10% annual discount for estimated timing of cash flows	(628,270		)	(335,892		)	(409,646		)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	807,170		$	518,210		$	589,486

The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:



	2017			2016			2015
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(239,953	)	$	(173,920	)	$	(218,115	)
Net changes in prices and production costs	236,126			(94,026		)	(1,356,333		)
Revisions in quantity estimates and changes in production timing	87,239			(51,979		)	(213,945		)
Extensions, discoveries, and improved recovery, less related costs	102,965			84,738			95,671
Changes in estimated future development costs	(5,194		)	70,976			227,857
Previously estimated cost incurred during the period	36,044			16,602			59,117
Purchases of minerals in place	51,686			2,652			—
Sales of minerals in place	(1,447		)	(17,248		)	(3,338		)
Accretion of discount	57,517			69,069			209,979
Net change in income taxes	(33,389		)	44,241			562,838
Other—net	(2,634		)	(22,381		)	(209,989		)
Net change	288,960			(71,276		)	(846,258		)
Beginning of year	518,210			589,486			1,435,744
End of year	$	807,170		$	518,210		$	589,486

Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented.

The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from neither those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.

The December 31, 2017, future cash flows were computed by applying the unescalated 12-month average prices of $51.34 per barrel for oil, $31.83 per barrel for NGLs, and $2.98 per Mcf for natural gas (then adjusted for price differentials) relating to proved reserves and to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.

Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil, NGLs, and natural gas reserves at the end of the year, based on continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil, NGLs, and natural gas reserves less the tax basis of our properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs, and natural gas reserves.

Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur.