(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 at December 31, 2011 and 2010:

	2011		2010
	(in thousands)

Proved properties	$ 8,601,818		$ 7,037,746
Unproved properties	942,890	(1)	712,117	⁽¹⁾

Total capitalized costs	9,544,708		7,749,863
Less: Accumulated depreciation, depletion and amortization	4,092,410		3,444,477
Net capitalized costs	$ 5,452,298		$ 4,305,386

(1) Includes $27.9 and $10.7 million related to our exploration program in New Brunswick, Canada at December 31, 2011 and 2010, respectively.

The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2011.

	2011	2010	2009	Prior	Total
	(in thousands)

Property acquisition costs	$ 254,622	$ 143,165	$ 44,513	$ 110,767	$ 553,067
Exploration and development costs	190,240	20,844	29,527	67,335	307,946
Capitalized interest	14,651	12,901	10,261	44,064	81,877
	$ 459,513	$ 176,910	$ 84,301	$ 222,166	$ 942,890

(1) Property acquisition costs include $7.5 million, exploration costs include $19.2 million and capitalized interest includes $1.2 million related to our exploration program in New Brunswick, Canada.

Of the total net unevaluated costs excluded from amortization at December 31, 2011, approximately $83.2 million is related to unevaluated seismic costs in the Fayetteville Shale play, approximately $101.3 million is related to acquisition of undeveloped properties in the Company's Fayetteville Shale play, approximately $179.4 million is related to acquisition of undeveloped properties in the Company's Marcellus Shale play and approximately $245.0 million is related to acquisition of undeveloped properties in the Company's New Ventures, excluding our exploration program in New Brunswick, Canada. The Company has $27.9 million of unevaluated costs related to its exploration program in Canada. Additionally, the Company has approximately $180.2 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:

	2011		2010		2009
	(in thousands, except per Mcfe amounts)

Proved property acquisition costs	$ 17		$ 0		$ 4,372
Unproved property acquisition costs	262,886	⁽¹⁾	229,909	⁽¹⁾	115,217
Exploration costs	63,419	⁽²⁾	27,062	⁽²⁾	52,178
Development costs	1,633,784		1,524,453		1,358,109
Capitalized costs incurred	1,960,106		1,781,424		1,529,876
Full cost pool amortization per Mcfe	$ 1.30		$ 1.34		$ 1.51

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

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

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $43.4 million, $32.9 million and $40.2 million during 2011, 2010 and 2009, 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 $147.7 million, $139.2 million and $112.9 million during 2011, 2010 and 2009, 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:

	2011	2010	2009
	(in thousands)

Sales	$ 2,100,488	$ 1,890,444	$ 1,593,231
Production (lifting) costs	(469,153)	(376,939)	(259,588)
Depreciation, depletion and amortization	(666,107)	(561,003)	(474,014)
Impairment of natural gas and oil properties	0	0	(907,812)
	965,228	952,502	(48,183)
Provision (benefit) for income taxes	376,049	371,281	(15,650)
Results of operations	$ 589,179	$ 581,221	$ (32,533)

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

The 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 90%, 85% and 88% of the present worth of the Company's total proved reserves at December 31, 2011, 2010 and 2009, 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 2011, 2010 and 2009 all of which were located in the United States:


	2011		2010		2009
	Natural		Natural		Natural
	Gas	Oil	Gas	Oil	Gas	Oil
	(MMcf)	(MBbls)	(MMcf)	(MBbls)	(MMcf)	(MBbls)

Proved reserves, beginning of year	4,929,980	1,219	3,650,303	1,059	2,175,528	1,507
Revisions of previous estimates	34,505	(125)	309,292	50	94,930	(346)
Extensions, discoveries and other additions	1,459,428	2	1,429,439	281	1,683,264	22
Production	(499,433)	(97)	(403,636)	(171)	(299,698)	(124)
Acquisition of reserves in place	13	0	0	0	1,795	0
Disposition of reserves in place	(37,286)	(3)	(55,418)	0	(5,516)	0
Proved reserves, end of year	5,887,207	996	4,929,980	1,219	3,650,303	1,059

Proved developed reserves:
Beginning of year	2,687,238	1,173	1,972,767	1,028	1,336,370	1,352
End of year	3,254,018	983	2,687,238	1,173	1,972,767	1,028

Proved undeveloped reserves:
Beginning of year	2,242,742	46	1,677,536	31	839,158	155
End of year	2,633,189	13	2,242,742	46	1,677,536	31

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 at December 31, 2011, 2010 and 2009 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:

	2011	2010	2009
	(in thousands)

Future cash inflows	$ 22,012,205	$ 19,620,254	$ 12,533,868
Future production costs	(8,080,207)	(6,826,915)	(4,488,884)
Future development costs	(3,425,185)	(3,025,433)	(2,367,206)
Future income tax expense	(3,366,175)	(3,143,571)	(1,569,242)
Future net cash flows	7,140,638	6,624,335	4,108,536
10% annual discount for estimated timing of cash flows	(3,689,838)	(3,610,585)	(2,306,718)
Standardized measure of discounted future net cash flows	$ 3,450,800	$ 3,013,750	$ 1,801,818

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 in 2011 and 2010, and utilized year-end pricing in 2009. Prices used for the standardized measure above were average market prices of $4.12 per MMBtu for natural gas and $92.71 per barrel for oil in 2011, average market prices of $4.38 per MMBtu for natural gas and $75.96 per barrel for oil in 2010, and year-end prices of $3.87 per MMBtu for natural gas and $57.65 per barrel for oil in 2009. 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 2011, 2010 and 2009:

	2011	2010	2009
	(in thousands)

Standardized measure, beginning of year	$ 3,013,750	$ 1,801,818	$ 2,109,262
Sales and transfers of natural gas and oil produced, net of production costs	(1,632,156)	(1,516,571)	(1,330,256)
Net changes in prices and production costs	(381,131)	706,062	(1,321,404)
Extensions, discoveries, and other additions, net of future production and development costs	1,163,992	1,205,464	976,449
Acquisition of reserves in place	30	0	1,878
Sales of reserves in place	(11,761)	(6,269)	(4,430)
Revisions of previous quantity estimates	34,221	324,284	88,261
Accretion of discount	426,245	230,355	302,439
Net change in income taxes	(103,643)	(746,971)	413,399
Changes in estimated future development costs	70,492	(10,558)	204,005
Previously estimated development costs incurred during the year	564,894	353,560	218,625
Changes in production rates (timing) and other	305,867	672,576	143,590
Standardized measure, end of year	$ 3,450,800	$ 3,013,750	$ 1,801,818