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:



	2014			2013			2012
	(In thousands)
Capitalized costs:
Proved properties	$	4,990,753		$	4,235,712		$	3,822,381
Unproved properties	485,568			545,588			521,659
	5,476,321			4,781,300			4,344,040
Accumulated depreciation, depletion, amortization, and impairment	(2,786,678		)	(2,439,458		)	(2,216,787		)
Net capitalized costs	$	2,689,643		$	2,341,842		$	2,127,253
Cost incurred:
Unproved properties acquired	$	76,041		$	76,304		$	420,467
Proved properties acquired	5,723			—			225,669
Exploration	68,811			33,373			46,467
Development	615,252			424,314			390,649
Asset retirement obligation	(37,687		)	(17,951		)	45,097
Total costs incurred	$	728,140		$	516,040		$	1,128,349

The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2014, by the year in which such costs were incurred:



	2014		2013		2012		2011 and Prior		Total
	(In thousands)
Unproved properties acquired and wells in progress	$	102,930	$	64,795	$	310,891	$	6,952	$	485,568

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:



	2014			2013			2012
	(In thousands)
Revenues	$	723,566		$	633,792		$	557,003
Production costs	(165,315		)	(162,822		)	(131,389		)
Depreciation, depletion, amortization, and impairment	(347,220		)	(222,672		)	(492,475		)
	211,031			248,298			(66,861		)
Income tax (expense) benefit	(82,028		)	(96,091		)	27,533
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	129,003		$	152,207		$	(39,328	)

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
	(In thousands)
2014
Proved developed and undeveloped reserves:
Beginning of year	21,765		41,205		581,784
Revision of previous estimates ⁽¹⁾	(3,174	)	(2,266	)	(32,790	)
Extensions and discoveries	5,327		10,850		113,541
Infill reserves in existing proved fields	2,775		3,577		47,189
Purchases of minerals in place	236		88		368
Production	(3,844	)	(4,629	)	(58,854	)
Sales	(418	)	(296	)	(4,277	)
End of year	22,667		48,529		646,961
Proved developed reserves:
Beginning of year	15,594		30,437		464,234
End of year	17,448		35,850		500,950
Proved undeveloped reserves:
Beginning of year	6,171		10,768		117,550
End of year	5,219		12,679		146,011
2013
Proved developed and undeveloped reserves:
Beginning of year	21,998		35,166		555,647
Revision of previous estimates ⁽¹⁾	(2,113	)	836		2,421
Extensions and discoveries	4,678		7,273		68,611
Infill reserves in existing proved fields	2,299		1,945		21,573
Purchases of minerals in place	—		—		11
Production	(3,360	)	(3,914	)	(56,757	)
Sales	(1,737	)	(101	)	(9,722	)
End of year	21,765		41,205		581,784
Proved developed reserves:
Beginning of year	16,441		25,657		452,844
End of year	15,594		30,437		464,234
Proved undeveloped reserves:
Beginning of year	5,557		9,509		102,803
End of year	6,171		10,768		117,550
2012
Proved developed and undeveloped reserves:
Beginning of year	20,255		22,087		442,135
Revision of previous estimates ⁽¹⁾	(1,747	)	(2,682	)	(55,110	)
Extensions and discoveries	5,014		4,819		54,761
Infill reserves in existing proved fields	4,196		3,018		25,057
Purchases of minerals in place	2,830		11,098		141,494
Production	(3,279	)	(2,796	)	(48,930	)
Sales	(5,271	)	(378	)	(3,760	)
End of year	21,998		35,166		555,647
Proved developed reserves:
Beginning of year	15,618		16,649		372,311
End of year	16,441		25,657		452,844
Proved undeveloped reserves:
Beginning of year	4,637		5,438		69,824
End of year	5,557		9,509		102,803

_________________________


(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 and statutory tax rates, adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. SMOG as of December 31 is as follows:



	2014			2013			2012
	(In thousands)
Future cash flows	$	6,398,236		$	5,573,119		$	4,522,351
Future production costs	(2,069,636		)	(1,734,985		)	(1,405,773		)
Future development costs	(560,102		)	(571,170		)	(431,673		)
Future income tax expenses	(1,228,533		)	(1,044,608		)	(762,519		)
Future net cash flows	2,539,965			2,222,356			1,922,386
10% annual discount for estimated timing of cash flows	(1,104,221		)	(996,380		)	(842,430		)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	1,435,744		$	1,225,976		$	1,079,956

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



	2014			2013			2012
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(558,252	)	$	(470,970	)	$	(425,626	)
Net changes in prices and production costs	(33,259		)	188,826			(321,099		)
Revisions in quantity estimates and changes in production timing	(135,125		)	(10,650		)	(148,648		)
Extensions, discoveries, and improved recovery, less related costs	635,752			426,377			432,058
Changes in estimated future development costs	96,339			26,629			51,587
Previously estimated cost incurred during the period	164,430			96,457			104,377
Purchases of minerals in place	8,395			9			283,774
Sales of minerals in place	(19,135		)	(43,435		)	(112,359		)
Accretion of discount	179,190			147,579			157,842
Net change in income taxes	(98,119		)	(170,091		)	94,678
Other—net	(30,448		)	(44,711		)	(124,537		)
Net change	209,768			146,020			(7,953		)
Beginning of year	1,225,976			1,079,956			1,087,909
End of year	$	1,435,744		$	1,225,976		$	1,079,956

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 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, 2014, future cash flows were computed by applying the unescalated 12-month average prices of $94.99 per barrel for oil, $45.25 per barrel for NGLs, and $4.36 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.