The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:



	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Property acquisition costs: ⁽¹⁾
Proved	$	2,531,419	$	1,328,328	$	1,290,826
Unproved	181,124		188,409		65,604
Exploration costs	452		80		74
Development costs	1,062,043		639,395		244,834
Asset retirement costs	4,675		2,427		748
Total costs incurred	$	3,779,713	$	2,158,639	$	1,602,086


⁽¹⁾	See Note 2 for details about the Company’s acquisitions.

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:



	December 31,
	2012			2011
	(in thousands)
Proved properties:
Leasehold acquisition	$	8,603,888		$	6,040,239
Development	2,553,127			1,484,486
Unproved properties	454,315			310,925
	11,611,330			7,835,650
Less accumulated depletion and amortization	(2,025,656		)	(1,033,617		)
	$	9,585,674		$	6,802,033

Results of Oil and Natural Gas Producing Activities

The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below:



	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	1,601,180		$	1,162,037		$	690,054
Gains on oil and natural gas derivatives	124,762			449,940			75,211
	1,725,942			1,611,977			765,265
Production costs:
Lease operating expenses	317,699			232,619			158,382
Transportation expenses	77,322			28,358			19,594
Severance and ad valorem taxes	130,805			78,458			45,114
	525,826			339,435			223,090
Other costs:
Exploration costs	1,915			2,390			5,168
Depletion and amortization	579,382			320,096			226,552
Impairment of long-lived assets	422,499			—			38,600
Gains on sale of assets and other, net	(1,369		)	(1,001		)	—
Texas margin tax (benefit) expense	(787		)	1,599			657
	1,001,640			323,084			270,977
Results of operations	$	198,476		$	949,458		$	271,198

There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. Limited liability companies were also subject to state income taxes in the state of Michigan during 2011 and 2010; however, no taxes were assessed in this state for producing activities during these years. See Note 14 for additional information about income taxes.

Proved Oil, Natural Gas and NGL Reserves

The proved reserves of oil, natural gas and NGL of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with SEC regulations, reserves at December 31, 2012, December 31, 2011, and December 31, 2010, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below:



	Year Ended December 31, 2012
	Natural Gas (Bcf)		Oil (MMBbls)		NGL (MMBbls)		Total (Bcfe)
Proved developed and undeveloped reserves:
Beginning of year	1,675		189.0		93.5		3,370
Revisions of previous estimates	(559	)	(26.5	)	(14.1	)	(803	)
Purchase of minerals in place	1,176		23.1		75.3		1,766
Extensions, discoveries and other additions	407		16.6		33.7		709
Production	(128	)	(10.7	)	(9.0	)	(246	)
End of year	2,571		191.5		179.4		4,796
Proved developed reserves:
Beginning of year	998		124.8		47.8		2,034
End of year	1,661		131.4		113.0		3,127
Proved undeveloped reserves:
Beginning of year	677		64.2		45.7		1,336
End of year	910		60.1		66.4		1,669



	Year Ended December 31, 2011
	Natural Gas (Bcf)		Oil (MMBbls)		NGL (MMBbls)		Total (Bcfe)
Proved developed and undeveloped reserves:
Beginning of year	1,233		156.4		70.9		2,597
Revisions of previous estimates	(71	)	(9.2	)	0.9		(121	)
Purchase of minerals in place	337		39.3		1.0		579
Extensions, discoveries and other additions	240		10.3		24.6		450
Production	(64	)	(7.8	)	(3.9	)	(135	)
End of year	1,675		189.0		93.5		3,370
Proved developed reserves:
Beginning of year	805		103.0		39.9		1,662
End of year	998		124.8		47.8		2,034
Proved undeveloped reserves:
Beginning of year	428		53.4		31.0		935
End of year	677		64.2		45.7		1,336



	Year Ended December 31, 2010
	Natural Gas (Bcf)		Oil (MMBbls)		NGL (MMBbls)		Total (Bcfe)
Proved developed and undeveloped reserves:
Beginning of year	774		102.1		54.2		1,712
Revisions of previous estimates	22		3.9		5.2		77
Purchase of minerals in place	369		49.1		1.2		671
Extensions, discoveries and other additions	118		6.1		13.3		234
Production	(50	)	(4.8	)	(3.0	)	(97	)
End of year	1,233		156.4		70.9		2,597
Proved developed reserves:
Beginning of year	549		77.9		33.9		1,220
End of year	805		103.0		39.9		1,662
Proved undeveloped reserves:
Beginning of year	225		24.2		20.3		492
End of year	428		53.4		31.0		935

The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents at a rate of one barrel per six Mcf.

Proved reserves increased by approximately 1,426 Bcfe to approximately 4,796 Bcfe for the year ended December 31, 2012, from 3,370 Bcfe for the year ended December 31, 2011. The year ended December 31, 2012, includes 803 Bcfe of negative revisions of previous estimates, due primarily to 340 Bcfe of negative revisions due to asset performance, 248 Bcfe of negative revisions primarily due to lower natural gas prices and 215 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs. Seven acquisitions during the year ended December 31, 2012, increased proved reserves by approximately 1,766 Bcfe. In addition, extensions and discoveries, primarily from 436 productive wells drilled during the year, contributed approximately 709 Bcfe to the increase in proved reserves.

Proved reserves increased by approximately 773 Bcfe to approximately 3,370 Bcfe for the year ended December 31, 2011, from 2,597 Bcfe for the year ended December 31, 2010. The year ended December 31, 2011, includes 121 Bcfe of negative revisions of previous estimates, due primarily to 153 Bcfe of negative revisions due to asset performance. These negative revisions were partially offset by 32 Bcfe of positive revisions primarily due to higher oil prices. Twelve acquisitions during the year ended December 31, 2011, increased proved reserves by approximately 579 Bcfe. In addition, extensions and discoveries, primarily from 292 productive wells drilled during the year, contributed approximately 450 Bcfe to the increase in proved reserves.

Proved reserves increased by approximately 885 Bcfe to approximately 2,597 Bcfe for the year ended December 31, 2010, from 1,712 Bcfe for the year ended December 31, 2009. The year ended December 31, 2010, includes 77 Bcfe of positive revisions of previous estimates, due primarily to higher oil and natural gas prices, which contributed approximately 155 Bcfe. These positive revisions were partially offset by 78 Bcfe of negative revisions primarily due to asset performance. Eleven acquisitions during the year ended December 31, 2010, increased proved reserves by approximately 671 Bcfe. In addition, extensions and discoveries, primarily from 138 productive wells drilled during the year, contributed approximately 234 Bcfe to the increase in proved reserves.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves

Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax. Limited liabilities companies were also subject to state income taxes in the state of Michigan during 2011 and 2010; however, these amounts are not material. See Note 14 for additional information about income taxes.



	December 31,
	2012			2011			2010
	(in thousands)

Future estimated revenues	$	30,374,380		$	29,319,369		$	20,160,275
Future estimated production costs	(11,460,854		)	(9,464,319		)	(6,825,147		)
Future estimated development costs	(3,574,058		)	(2,848,497		)	(1,733,929		)
Future net cash flows	15,339,468			17,006,553			11,601,199
10% annual discount for estimated timing of cash flows	(9,266,487		)	(10,391,693		)	(7,377,667		)
Standardized measure of discounted future net cash flows	$	6,072,981		$	6,614,860		$	4,223,532

Representative NYMEX prices: ⁽¹⁾
Natural gas (MMBtu)	$	2.76		$	4.12		$	4.38
Oil (Bbl)	$	94.64		$	95.84		$	79.29

⁽¹⁾

In accordance with SEC regulations, reserves at December 31, 2012, December 31, 2011, and December 31, 2010, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The price used to estimate reserves is held constant over the life of the reserves.

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:



	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Sales and transfers of oil, natural gas and NGL produced during the period	$	(1,075,354	)	$	(822,602	)	$	(466,964	)
Changes in estimated future development costs	289,762			27,236			(56,001		)
Net change in sales and transfer prices and production costs related to future production	(1,463,820		)	784,308			886,438
Purchase of minerals in place	2,153,651			1,452,169			1,277,134
Extensions, discoveries, and improved recovery	413,702			552,704			329,642
Previously estimated development costs incurred during the period	442,322			306,827			42,947
Net change due to revisions in quantity estimates	(1,595,302		)	(292,343		)	164,999
Accretion of discount	661,486			422,353			172,328
Changes in production rates and other	(368,326		)	(39,324		)	149,727
	$	(541,879	)	$	2,391,328		$	2,500,250

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.