(4) NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

The Company’s natural gas and oil properties are located in the United States and Canada.

Net Capitalized Costs

The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortization as of December 31, 2012 and 2011:


	2012				2011

	(in thousands)

Proved properties	$	10,259,226		$		8,601,818
Unproved properties		1,023,888	⁽¹⁾			942,890	⁽¹⁾

Total capitalized costs		11,283,114				9,544,708
Less: Accumulated depreciation, depletion and amortization		6,774,174				4,092,410
Net capitalized costs	$	4,508,940		$		5,452,298

(1) Includes $40.4 and $27.9 million related to our exploration program in Canada as of December 31, 2012 and 2011, respectively.

The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2012.


	2012		2011		2010		Prior		Total

	(in thousands)

Property acquisition costs	$	193,258	$	232,615	$	123,736	$	45,081	$	594,690	⁽¹⁾
Exploration and development costs		233,888		65,479		15,357		36,958		351,682	⁽¹⁾
Capitalized interest		11,578		25,163		18,989		21,786		77,516	⁽¹⁾
	$	438,724	$	323,257	$	158,082	$	103,825	$	1,023,888

(1)Property acquisition costs include $14.8 million, exploration costs include $22.5 million and capitalized interest includes $3.1 million related to our exploration program in Canada.

Of the total net unevaluated costs excluded from amortization as of December 31, 2012, approximately $25.9 million is related to unevaluated seismic costs in the Fayetteville Shale play, approximately $44.0 million is related to acquisition of undeveloped properties in the Company’s Fayetteville Shale play, approximately $145.6 million is related to acquisition of undeveloped properties in the Company’s Marcellus Shale play and approximately $387.1 million is related to acquisition of undeveloped properties in the Company’s New Ventures, excluding our exploration program in Canada. The Company has $40.4 million of unevaluated costs related to its exploration program in Canada. Additionally, the Company has approximately $270.8 million of unevaluated costs related to costs of wells in progress. The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of drilling, and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.

Costs Incurred in Natural Gas and Oil Exploration and Development

The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities:


	2012			2011			2010

	(in thousands, except per Mcfe amounts)

Proved property acquisition costs	$	–		$	17		$	–
Unproved property acquisition costs		220,822	⁽¹⁾		262,886	⁽¹⁾		229,909	⁽¹⁾
Exploration costs		197,280	⁽²⁾		63,419	⁽²⁾		27,062	⁽²⁾
Development costs		1,492,841			1,633,784			1,524,453
Capitalized costs incurred		1,910,943			1,960,106			1,781,424
Full cost pool amortization per Mcfe	$	1.31		$	1.30		$	1.34

(1)	Includes $3.6 million, $0.2 million and $2.5 million, in 2012, 2011 and 2010, respectively, related to our exploration program in Canada.

(2)	Includes $2.5 million, $18.4 million and $8.2 million in 2012, 2011 and 2010, respectively, related to our exploration program in Canada.

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $62.1 million, $43.4 million and $32.9 million during 2012, 2011 and 2010, respectively, based on the Company’s weighted average cost of borrowings used to finance the expenditures.

In addition to capitalized interest, the Company also capitalized internal costs of $159.7 million, $147.7 million and $139.2 million during 2012, 2011 and 2010, respectively. These internal costs were directly related to acquisition, exploration and development activities and are included as part of the cost of natural gas and oil properties.

Results of Operations from Natural Gas and Oil Producing Activities

The table below sets forth the results of operations from natural gas and oil producing activities:


	2012		2011		2010

	(in thousands)

Sales	$	1,948,222	$	2,100,488	$	1,890,444
Production (lifting) costs		(505,271)		(469,153)		(376,939)
Depreciation, depletion and amortization		(765,192)		(666,107)		(561,003)
Impairment of natural gas and oil properties		(1,939,734)		–		–
		(1,261,975)		965,228		952,502
Provision (benefit) for income taxes		(502,690)		376,049		371,281
Results of operations	$	(759,285)	$	589,179	$	581,221

The results of operations shown above exclude general and administrative expenses, and interest expense and are not necessarily indicative of the contribution made by our natural gas and oil operations to the Company’s consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.

Natural Gas and Oil Reserve Quantities

Company engaged the services of Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties and accounted for approximately 93%, 90% and 85% of the present worth of the Company’s total proved reserves as of December 31, 2012, 2011 and 2010, respectively. A reserve audit is not the same as a financial audit and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves. Reserve estimates are inherently imprecise and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.

The following table summarizes the changes in the Company’s proved natural gas and oil reserves for 2012, 2011 and 2010 all of which were located in the United States:


	2012		2011		2010
	Natural		Natural		Natural
	Gas	Oil	Gas	Oil	Gas	Oil
	(MMcf)	(MBbls)	(MMcf)	(MBbls)	(MMcf)	(MBbls)

Proved reserves, beginning of year	5,887,207	996	4,929,980	1,219	3,650,303	1,059
Revisions of previous estimates	(2,087,985)	(44)	34,505	(125)	309,292	50
Extensions, discoveries and other additions	918,594	154	1,459,428	2	1,429,439	281
Production	(564,484)	(83)	(499,433)	(97)	(403,636)	(171)
Acquisition of reserves in place	–	–	13	–	–	–
Disposition of reserves in place	(136,534)	(779)	(37,286)	(3)	(55,418)	–
Proved reserves, end of year	4,016,798	244	5,887,207	996	4,929,980	1,219

Proved developed reserves:
Beginning of year	3,254,018	983	2,687,238	1,173	1,972,767	1,028
End of year	3,195,662	243	3,254,018	983	2,687,238	1,173

Proved undeveloped reserves:
Beginning of year	2,633,189	13	2,242,742	46	1,677,536	31
End of year	821,136	1	2,633,189	13	2,242,742	46

The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil.

Standardized Measure of Discounted Future Net Cash Flows

The following standardized measures of discounted future net cash flows relating to proved natural gas and oil reserves as of December 31, 2012, 2011 and 2010 are calculated after income taxes and discounted using a 10% annual discount rate and do not purport to present the fair market value the Company’s proved gas and oil reserves:


	2012		2011		2010

	(in thousands)

Future cash inflows	$	9,570,652	$	22,012,205	$	19,620,254
Future production costs		(4,737,297)		(8,080,207)		(6,826,915)
Future development costs		(711,050)		(3,425,185)		(3,025,433)
Future income tax expense		(745,251)		(3,366,175)		(3,143,571)
Future net cash flows		3,377,054		7,140,638		6,624,335
10% annual discount for estimated timing of cash flows		(1,326,389)		(3,689,838)		(3,610,585)
Standardized measure of discounted future net cash flows	$	2,050,665	$	3,450,800	$	3,013,750

Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardized measure above were $2.76 per MMBtu for natural gas and $91.21 per barrel for oil in 2012, $4.12 per MMBtu for natural gas and $92.71 per barrel for oil in 2011, and $4.38 per MMBtu for natural gas and $75.96 per barrel for oil in 2010. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits.

Following is an analysis of changes in the standardized measure during 2012, 2011 and 2010:


	2012		2011		2010

	(in thousands)
Standardized measure, beginning of year	$	3,450,800	$	3,013,750	$	1,801,818
Sales and transfers of natural gas and oil produced, net of production costs		(1,443,606)		(1,632,156)		(1,516,571)
Net changes in prices and production costs		(2,604,591)		(381,131)		706,062
Extensions, discoveries, and other additions, net of future production and development costs		549,601		1,163,992		1,205,464
Acquisition of reserves in place		–		30		–
Sales of reserves in place		(157,108)		(11,761)		(6,269)
Revisions of previous quantity estimates		(1,109,409)		34,221		324,284
Accretion of discount		480,315		426,245		230,355
Net change in income taxes		1,079,158		(103,643)		(746,971)
Changes in estimated future development costs		2,475,470		70,492		(10,558)
Previously estimated development costs incurred during the year		61,949		564,894		353,560
Changes in production rates (timing) and other		(731,914)		305,867		672,576
Standardized measure, end of year	$	2,050,665	$	3,450,800	$	3,013,750