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Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (Notes - unaudited) (Notes)
 12 Months Ended
Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Oil and Gas Exploration and Production Industries Disclosures [Text Block]
Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (Unaudited)
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.
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).
Natural Gas, Oil and NGL Reserve Quantities
Chesapeake's petroleum engineers and independent petroleum engineering firms estimated all of our proved reserves as of December 31, 2012, 2011 and 2010. 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
%

Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
Developed natural gas, oil and NGL reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
The information below on our natural gas, oil and NGL reserves is presented in accordance with regulations prescribed by the SEC as in effect as of the date of such estimates. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. Such changes could be material and could occur in the near term.
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.
During 2012, we acquired approximately 42 bcfe of proved reserves through purchases of natural gas and oil properties for consideration of $332 million, and we sold 1.347 tcfe of our proved reserves for approximately $2.381 billion. During 2012, we recorded downward revisions of 6.763 tcfe to the December 31, 2011 estimates of our reserves. Included in the revisions were 5.414 tcfe of downward revisions resulting from lower natural gas prices in 2012 and 1.349 tcfe of downward revisions resulting from changes to previous estimates. Lower prices decrease the economic lives of the underlying natural gas and oil properties and thereby decrease the estimated future reserves. The natural gas and oil prices used in computing our reserves as of December 31, 2012 were $2.76 per mcf and $94.84 per bbl before price differentials. Including the effect of price differential adjustments, the prices used in computing our reserves as of December 31, 2012 were $1.75 per mcf of natural gas, $91.78 per barrel of oil and $30.81 per barrel of NGL. The nonprice-related revisions were primarily the result of our continued execution of the Company's strategy to shift its drilling focus from natural gas to liquids-rich areas and to drill in the "core of the core" of its acreage positions. As rigs were reallocated, PUDs were removed from various non-core areas resulting in downward revisions. As of December 31, 2012, there were no PUDs that had remained undeveloped for five years or more.
During 2011, we acquired approximately 30 bcfe of proved reserves through purchases of natural gas and oil properties for consideration of $48 million, and we sold 2.776 tcfe of our proved reserves for approximately $2.612 billion, including divestitures related to our Fayetteville Shale assets, a VPP transaction and other non-core asset sales. During 2011, we recorded negative revisions of 50 bcfe to the December 31, 2010 estimates of our reserves. Included in the revisions were 273 bcfe of positive revisions to producing properties, offset by 337 bcfe of negative revisions associated with the deletion of PUD reserves no longer consistent with our development plans. In addition, we had 14 bcfe of positive revisions resulting from higher oil prices. Higher prices increase the economic lives of the underlying natural gas and oil properties and thereby increase the estimated future reserves. The natural gas and oil prices used in computing our reserves as of December 31, 2011 were $4.12 per mcf and $95.97 per bbl before price differentials. Including the effect of price differential adjustments, the prices used in computing our reserves as of December 31, 2011 were $3.19 per mcf of natural gas, $88.50 per bbl of oil and $40.38 per bbl of NGL.
During 2010, we acquired approximately 89 bcfe of proved reserves through purchases of natural gas and oil properties for consideration of $243 million and we sold 1.493 tcfe of our proved reserves for approximately $2.876 billion, including divestitures related to three VPP transactions, the sale of a portion of our Barnett Shale assets and other non-core asset sales. During 2010, we recorded positive revisions of 183 bcfe to the December 31, 2009 estimates of our reserves. Included in the revisions were 189 bcfe of positive revisions resulting from higher natural gas prices and 6 bcfe of downward revisions resulting from changes to previous estimates. The natural gas and oil prices used in computing our reserves as of December 31, 2010 were $4.38 per mcf and $79.42 per bbl before price differentials. Including the effect of price differential adjustments, the prices used in computing our reserves as of December 31, 2010 were $3.52 per mcf of natural gas, $75.17 per bbl of oil and $32.06 per bbl of NGL.
Standardized Measure of Discounted Future Net Cash Flows
Accounting Standards Topic 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs as of December 31, 2012, 2011 and 2010 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of natural gas, oil and NGL to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year. Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.
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.