(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, 2013 and 2012:


	2013			2012

	(in thousands)

Proved properties	$	12,337,372		$	10,259,226
Unproved properties		956,469	(1)		1,023,888	(1)

Total capitalized costs		13,293,841			11,283,114
Less: Accumulated depreciation, depletion and amortization		7,481,335			6,774,174
Net capitalized costs	$	5,812,506		$	4,508,940

(1) Includes $72.3 and $40.4 million related to our exploration program in Canada as of December 31, 2013 and 2012, respectively.

Oil and gas properties not subject to amortization represent investments in unproved properties and major development projects in which we own an interest. These unproved property costs include unevaluated costs associated with leasehold or drilling interests and unevaluated costs associated with wells in progress. The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2013.


	2013		2012		2011		Prior		Total

	(in thousands)
Property acquisition costs	$	147,791	$	81,889	$	221,451	$	109,994	$	561,125	(1)
Exploration and development costs		166,725		48,428		47,784		38,858		301,795	(1)
Capitalized interest		7,792		11,067		38,145		36,545		93,549	(1)
	$	322,308	$	141,384	$	307,380	$	185,397	$	956,469

(1)Property acquisition costs include $35.0 million, exploration costs include $31.8 million and capitalized interest includes $5.5 million related to our exploration program in Canada.

Of the total net unevaluated costs excluded from amortization as of December 31, 2013, approximately $23.1 million is related to unevaluated seismic costs in the Fayetteville Shale, approximately $39.0 million is related to acquisition of undeveloped properties in the Company’s Fayetteville Shale, approximately $195.7 million is related to acquisition of undeveloped properties in the Company’s Marcellus Shale and approximately $275.8 million is related to acquisition of undeveloped properties in the Company’s New Ventures, excluding our exploration program in Canada. The Company has $72.3 million of unevaluated costs related to its exploration program in Canada. Additionally, the Company has approximately $220.7 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:


	2013			2012			2011

	(in thousands, except per Mcfe amounts)

Proved property acquisition costs	$	572		$	–		$	17
Unproved property acquisition costs		168,404	(1)		220,822	(1)		262,886	(1)
Exploration costs		192,164	(2)		197,280	(2)		63,419	(2)
Development costs		1,662,138			1,492,841			1,633,784
Capitalized costs incurred		2,023,278			1,910,943			1,960,106
Full cost pool amortization per Mcfe	$	1.08		$	1.31		$	1.30

(1)

Includes $17.1 million, $3.6 million and $0.2 million, in 2013, 2012 and 2011, respectively, related to our exploration program in Canada.

(2)

Includes $11.5 million, $2.5 million and $18.4 million in 2013, 2012 and 2011, 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 $61.6 million, $62.1 million and $43.4 million during 2013, 2012 and 2011, respectively, based on the Company’s weighted average cost of borrowings used to finance expenditures.

In addition to capitalized interest, the Company capitalized internal costs totaling $262.2 million, $236.5 million and $207.9 million during 2013, 2012 and 2011, respectively, that were directly related to the acquisition, exploration and development of the Company’s natural gas and oil and oil properties Included in these amounts are internal costs from the Company’s subsidiaries involved with vertical integration of the Company’s exploration and development activities and totaled $104.3 million, $81.7 million and $51.3 million during 2013, 2012 and 2011, respectively. All internal costs are included in the Company’s 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:


	2013		2012		2011

	(in thousands)

Sales	$	2,404,165	$	1,963,172	$	2,098,914
Production (lifting) costs		(628,817)		(505,271)		(469,153)
Depreciation, depletion and amortization		(735,215)		(765,192)		(666,107)
Impairment of natural gas and oil properties		–		(1,939,734)		–
		1,040,133		(1,247,025)		963,654
Provision (benefit) for income taxes		416,042		(496,738)		375,435
Results of operations (1)	$	624,091	$	(750,287)	$	588,219

(1) Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments. See Note 5 Derivatives and Risk Management.

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., or 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 95%, 93% and 90% of the present worth of the Company’s total proved reserves as of December 31, 2013, 2012 and 2011, 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. For more information over reserves, refer to the table titled “Changes in Proved Undeveloped Reserves (Bcfe)” in “Business – Exploration and Production” in Item 1 of this Form 10-K.

The following table summarizes the changes in the Company’s proved natural gas and oil reserves for 2013, 2012 and 2011 all of which were located in the United States:


	2013		2012		2011
	Natural		Natural		Natural
	Gas	Oil	Gas	Oil	Gas	Oil
	(MMcf)	(MBbls)	(MMcf)	(MBbls)	(MMcf)	(MBbls)

Proved reserves, beginning of year	4,016,798	244	5,887,207	996	4,929,980	1,219
Revisions of previous estimates	325,374	88	(2,087,985)	(44)	34,505	(125)
Extensions, discoveries and other additions	3,283,495	229	918,594	154	1,459,428	2
Production	(655,704)	(188)	(564,484)	(83)	(499,433)	(97)
Acquisition of reserves in place	4,114	–	–	–	13	–
Disposition of reserves in place	–	–	(136,534)	(779)	(37,286)	(3)
Proved reserves, end of year	6,974,077	373	4,016,798	244	5,887,207	996

Proved developed reserves:
Beginning of year	3,195,662	243	3,254,018	983	2,687,238	1,173
End of year	4,237,495	372	3,195,662	243	3,254,018	983

Proved undeveloped reserves:
Beginning of year	821,136	1	2,633,189	13	2,242,742	46
End of year	2,736,582	1	821,136	1	2,633,189	13

The significant revision of previous estimates in 2012 was primarily due to price revision, as a result of lower average natural gas prices in 2012. 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, 2013, 2012 and 2011 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:


	2013		2012		2011

	(in thousands)

Future cash inflows	$	22,624,562	$	9,570,652	$	22,012,205
Future production costs		(8,895,956)		(4,737,297)		(8,080,207)
Future development costs		(3,626,496)		(711,050)		(3,425,185)
Future income tax expense		(3,223,271)		(745,251)		(3,366,175)
Future net cash flows		6,878,839		3,377,054		7,140,638
10% annual discount for estimated timing of cash flows		(3,142,795)		(1,326,389)		(3,689,838)
Standardized measure of discounted future net cash flows	$	3,736,044	$	2,050,665	$	3,450,800

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 $3.67 per MMBtu for natural gas and $93.42 per barrel for oil in 2013, $2.76 per MMBtu for natural gas and $91.21 per barrel for oil in 2012, and $4.12 per MMBtu for natural gas and $92.71 per barrel for oil in 2011. 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 2013, 2012 and 2011:


	2013		2012		2011

	(in thousands)
Standardized measure, beginning of year	$	2,050,665	$	3,450,800	$	3,013,750
Sales and transfers of natural gas and oil produced, net of production costs		(1,774,043)		(1,443,606)		(1,632,156)
Net changes in prices and production costs		1,852,772		(2,604,591)		(381,131)
Extensions, discoveries, and other additions, net of future production and development costs		1,454,634		549,601		1,163,992
Acquisition of reserves in place		4,914		–		30
Sales of reserves in place		–		(157,108)		(11,761)
Revisions of previous quantity estimates		348,996		(1,109,409)		34,221
Accretion of discount		232,385		480,315		426,245
Net change in income taxes		(1,119,798)		1,079,158		(103,643)
Changes in estimated future development costs		(196,394)		2,475,470		70,492
Previously estimated development costs incurred during the year		222,982		61,949		564,894
Changes in production rates (timing) and other		658,931		(731,914)		305,867
Standardized measure, end of year	$	3,736,044	$	2,050,665	$	3,450,800