Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) [Abstract]

Changes in Oil and Gas Reserve Estimates [Table Text Block] [Table Text Block]

Presented below is a summary of changes in estimated reserves for 2012, 2011 and 2010.

	Gas		Oil		NGL		Total
	(bcf)		(mmbbl)		(mmbbl)		(bcfe)
December 31, 2012
Proved reserves, beginning of period	15,515		291.6		253.9		18,789
Extensions, discoveries and other additions	3,317		374.0		139.4		6,391
Revisions of previous estimates	(6,080	)	(67.5	)	(47.3	)	(6,763	)
Production	(1,129	)	(31.3	)	(17.6	)	(1,422	)
Sale of reserves-in-place	(704	)	(75.5	)	(31.7	)	(1,347	)
Purchase of reserves-in-place	14		4.2		0.6		42
Proved reserves, end of period(a)	10,933		495.5		297.3		15,690
Proved developed reserves:
Beginning of period	8,578		124.0		130.6		10,106
End of period	7,174		162.9		132.1		8,944
Proved undeveloped reserves:
Beginning of period	6,937		167.6		123.3		8,683
End of period	3,759		332.6		165.2		6,746

	Gas		Oil		NGL		Total
	(bcf)		(mmbbl)		(mmbbl)		(bcfe)
December 31, 2011
Proved reserves, beginning of period	15,455		150.1		123.3		17,096
Extensions, discoveries and other additions	4,156		168.4		85.2		5,683
Revisions of previous estimates	(361	)	(7.8	)	60.6		(50	)
Production	(1,004	)	(17.0	)	(14.7	)	(1,194	)
Sale of reserves-in-place	(2,754	)	(2.6	)	(1.2	)	(2,776	)
Purchase of reserves-in-place	23		0.5		0.7		30
Proved reserves, end of period(b)	15,515		291.6		253.9		18,789
Proved developed reserves:
Beginning of period	8,246		84.2		64.0		9,143
End of period	8,578		124.0		130.6		10,106
Proved undeveloped reserves:
Beginning of period	7,209		65.9		59.3		7,953
End of period	6,937		167.6		123.3		8,683
December 31, 2010
Proved reserves, beginning of period(c)	13,510		124.0		—		14,254
Extensions, discoveries and other additions	4,678		47.6		22.3		5,098
Revisions of previous estimates	(445	)	(3.6	)	108.3		183
Production	(925	)	(10.9	)	(7.5	)	(1,035	)
Sale of reserves-in-place	(1,426	)	(11.2	)	—		(1,493	)
Purchase of reserves-in-place	63		4.2		0.2		89
Proved reserves, end of period	15,455		150.1		123.3		17,096
Proved developed reserves:
Beginning of period	7,859		78.8		—		8,331
End of period	8,246		84.2		64.0		9,143
Proved undeveloped reserves:
Beginning of period	5,651		45.2		—		5,923
End of period	7,209		65.9		59.3		7,953

___________________________________________

(a) Includes 91 bcf of natural gas, 4 mmbbls of oil and 9 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 45 bcf of natural gas, 2 mmbbls of oil and 4 mmbbls of NGL of which are attributable to the noncontrolling interest holders.

(b) Includes 136 bcf of natural gas, 6 mmbbls of oil and 14 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 67 bcf of natural gas, 3 mmbbls of oil and 7 mmbbls of NGL of which are attributable to the noncontrolling interest holders.

(c) Prior to 2010, NGL reserve volumes were recognized as a component of natural gas volumes.

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

Net Capitalized Costs

Evaluated and unevaluated capitalized costs related to Chesapeake's natural gas, oil and NGL producing activities are summarized as follows:

	December 31,
	2012			2011
	($ in millions)
Natural gas and oil properties:
Proved	$	50,172		$	41,723
Unproved	14,755			16,685
Total	64,927			58,408
Less accumulated depreciation, depletion and amortization	(33,009		)	(27,208		)
Net capitalized costs	$	31,918		$	31,200

Unproved properties not subject to amortization at December 31, 2012, 2011 and 2010 consisted mainly of leasehold acquired through direct purchases of significant natural gas and oil property interests. We capitalized approximately $976 million, $727 million and $711 million of interest during 2012, 2011 and 2010, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full cost pool. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

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

Costs incurred in natural gas and oil property acquisition, exploration and development activities which have been capitalized are summarized as follows:

	Years Ended December 31,
	2012		2011		2010
	($ in millions)
Acquisitions of properties:
Proved properties	$	332	$	48	$	243
Unproved properties	2,981		4,736		6,953
Exploratory costs	2,353		2,261		872
Development costs	6,733		5,497		4,741
Costs incurred(a)(b)	$	12,399	$	12,542	$	12,809

___________________________________________

(a) Exploratory and development costs are net of joint venture drilling and completion cost carries of $784 million, $2.570 billion and $1.151 billion in 2012, 2011 and 2010, respectively.

(b) Includes capitalized interest and asset retirement cost as follows:

Capitalized interest	$	976	$	727	$	711
Asset retirement obligations	$	32	$	3	$	2

In 2012, we invested approximately $1.035 billion, net of drilling and completion cost carries of $86 million, to convert 961 bcfe of PUDs to proved developed reserves.

Results of Operations from Natural Gas, Oil and NGL Producing Activities

Chesapeake's results of operations from natural gas, oil and NGL producing activities are presented below for 2012, 2011 and 2010. The following table includes revenues and expenses associated directly with our natural gas, oil and NGL producing activities. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas, oil and NGL operations.

	Years Ended December 31,
	2012			2011			2010
	($ in millions)
Natural gas, oil and NGL sales	$	6,278		$	6,024		$	5,647
Natural gas, oil and NGL production expenses	(1,304		)	(1,073		)	(893		)
Production taxes	(188		)	(192		)	(157		)
Impairment of natural gas and oil properties	(3,315		)	—			—
Depletion and depreciation	(2,507		)	(1,632		)	(1,394		)
Imputed income tax provision(a)	404			(1,220		)	(1,233		)
Results of operations from natural gas, oil and NGL producing  activities	$	(632	)	$	1,907		$	1,970

___________________________________________

(a) The imputed income tax provision is hypothetical (at the effective income tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable).

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

Results of Operations from Natural Gas, Oil and NGL Producing Activities

Chesapeake's results of operations from natural gas, oil and NGL producing activities are presented below for 2012, 2011 and 2010. The following table includes revenues and expenses associated directly with our natural gas, oil and NGL producing activities. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas, oil and NGL operations.

	Years Ended December 31,
	2012			2011			2010
	($ in millions)
Natural gas, oil and NGL sales	$	6,278		$	6,024		$	5,647
Natural gas, oil and NGL production expenses	(1,304		)	(1,073		)	(893		)
Production taxes	(188		)	(192		)	(157		)
Impairment of natural gas and oil properties	(3,315		)	—			—
Depletion and depreciation	(2,507		)	(1,632		)	(1,394		)
Imputed income tax provision(a)	404			(1,220		)	(1,233		)
Results of operations from natural gas, oil and NGL producing  activities	$	(632	)	$	1,907		$	1,970

___________________________________________

(a) The imputed income tax provision is hypothetical (at the effective income tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable).

Proved Oil and Gas Reserve Quantities [Table Text Block]

Independent petroleum engineering firms estimated an aggregate of 89%, 77% and 78% of our estimated proved reserves (by volume) as of December 31, 2012, 2011 and 2010, respectively, as set forth below.

	December 31,
	2012		2011		2010
Ryder Scott Company, L.P.	44	%	19	%	6	%
PetroTechnical Services, Division of Schlumberger Technology Corporation	24	%	7	%	7	%
Netherland, Sewell & Associates, Inc.	21	%	42	%	58	%
Lee Keeling and Associates, Inc.	—	%	9	%	7	%

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

The following summary sets forth our future net cash flows relating to proved natural gas, oil and NGL reserves based on the standardized measure:

	Years Ended December 31,
	2012				2011				2010
	($ in millions)
Future cash inflows	$	73,754		(a)	$	85,537		(b)	$	69,616		(c)
Future production costs	(18,809		)		(23,022		)		(20,384		)
Future development costs	(12,656		)		(14,471		)		(11,602		)
Future income tax provisions	(9,824		)		(12,266		)		(6,859		)
Future net cash flows	32,465				35,778				30,771
Less effect of a 10% discount factor	(17,799		)		(20,148		)		(17,588		)
Standardized measure of discounted future net cash flows(d)	$	14,666			$	15,630			$	13,183

___________________________________________

(a) Calculated using prices of $2.76 per mcf of natural gas and $94.84 per bbl of oil, before field differentials.

(b) Calculated using prices of $4.12 per mcf of natural gas and $95.97 per bbl of oil, before field differentials.

(c) Calculated using prices of $4.38 per mcf of natural gas and $79.42 per bbl of oil, before field differentials.

(d) Excludes future cash inflows attributable to production volumes sold to VPP buyers and includes future cash outflows attributable to the costs of such production. See Note 11.

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

	Years Ended December 31,
	2012			2011			2010
	($ in millions)
Standardized measure, beginning of period(a)	$	15,630		$	13,183		$	8,203
Sales of natural gas and oil produced, net of production costs(b)	(3,867		)	(3,993		)	(3,199		)
Net changes in prices and production costs	(2,720		)	512			3,337
Extensions and discoveries, net of production and development costs	11,115			9,139			5,580
Changes in future development costs	3,687			667			173
Development costs incurred during the period that reduced future development costs	1,046			680			717
Revisions of previous quantity estimates	(8,699		)	(708		)	199
Purchase of reserves-in-place	285			50			255
Sales of reserves-in-place	(3,246		)	(2,083		)	(2,235		)
Accretion of discount	1,988			1,515			945
Net change in income taxes	1,142			(2,286		)	(716		)
Changes in production rates and other	(1,695		)	(1,046		)	(76		)
Standardized measure, end of period(a)(c)(d)	$	14,666		$	15,630		$	13,183

___________________________________________

(a) The impact of cash flow hedges has not been included in any of the periods presented.

(b) Excluding gains (losses) on derivatives.

(c) Effect of noncontrolling interest of the Chesapeake Granite Wash Trust is immaterial.

(d) The standardized measure of discounted future net cash flows does not include estimated future cash inflows attributable to future production of VPP volumes sold and does include estimated future cash outflows attributable to the costs of future production of VPP volumes sold.