Oklahoma
|
1-13726
|
73-1395733
|
||
(State or other jurisdiction of incorporation)
|
(Commission File No.)
|
(IRS Employer Identification No.)
|
6100 North Western Avenue, Oklahoma City, Oklahoma
|
73118
|
|
(Address of principal executive offices)
|
(Zip Code)
|
(405) 848-8000
|
||
(Registrant’s telephone number, including area code)
|
CHESAPEAKE ENERGY CORPORATION
|
||
By:
|
/s/ JENNIFER M. GRIGSBY
|
|
Jennifer M. Grigsby
Senior Vice President, Treasurer and Corporate Secretary
|
Exhibit No.
|
Document Description
|
||
99.1
|
Chesapeake Energy Corporation press release dated February 21, 2013 – Financial and operational results and updated outlook
|
||
News Release
|
![]() |
FOR IMMEDIATE RELEASE
|
|
FEBRUARY 21, 2013
|
|
·
|
a noncash after-tax impairment charge of $2.022 billion for the full year related to the carrying value of natural gas and oil properties;
|
|
·
|
an after-tax charge of $122 million related to the full repayment of the company’s May 2012 term loans for the fourth quarter and full year;
|
|
·
|
net unrealized noncash after-tax mark-to-market gains of $78 million for the fourth quarter and $347 million for the full year resulting from the company’s natural gas, oil and natural gas liquids (NGL) and interest rate hedging programs;
|
INVESTOR CONTACTS:
|
MEDIA CONTACTS:
|
CHESAPEAKE ENERGY CORPORATION
|
||||||
Jeffrey L. Mobley, CFA
|
Gary T. Clark, CFA
|
Michael Kehs
|
Jim Gipson
|
6100 North Western Avenue
|
||||
(405) 767-4763
|
(405) 935-6741
|
(405) 935-2560
|
(405) 935-1310
|
P.O. Box 18496
|
||||
jeff.mobley@chk.com
|
gary.clark@chk.com
|
michael.kehs@chk.com
|
jim.gipson@chk.com
|
Oklahoma City, OK 73154
|
|
·
|
net after-tax gains of $166 million for the fourth quarter and $163 million for the full year related to gains and losses on sales, including a $176 million after-tax gain on the sale of the company’s midstream subsidiary for the fourth quarter and full year;
|
|
·
|
noncash after-tax charges of $36 million for the fourth quarter and $208 million for the full year related to the impairment of certain fixed assets; and
|
|
·
|
net after-tax gains of $19 million for the fourth quarter and $622 million for the full year related to certain investments, including a $629 million gain for the full year related to the sale of all of the company’s interests in Access Midstream Partners, L.P. (NYSE:ACMP).
|
Three Months Ended
|
Full Year Ended
|
|||||||||
12/31/12
|
9/30/12
|
12/31/11
|
12/31/12
|
12/31/11
|
||||||
Average daily production (in mmcfe)
|
3,931
|
4,142
|
3,596
|
3,886
|
3,272
|
|||||
Natural gas equivalent production (in bcfe)
|
362
|
381
|
331
|
1,422
|
1,194
|
|||||
Natural gas equivalent realized price ($/mcfe)(a)
|
4.23
|
4.04
|
5.08
|
4.02
|
5.70
|
|||||
Oil production (in mbbls)
|
8,936
|
8,996
|
5,291
|
31,265
|
16,964
|
|||||
Average realized oil price ($/bbl)(a)
|
92.23
|
90.79
|
88.02
|
91.74
|
86.25
|
|||||
Oil as % of total production
|
15
|
14
|
10
|
13
|
9
|
|||||
NGL production (in mbbls)
|
4,634
|
4,130
|
4,476
|
17,615
|
14,712
|
|||||
Average realized NGL price ($/bbl)(a)
|
27.12
|
31.22
|
35.87
|
29.37
|
38.12
|
|||||
NGL as % of total production
|
8
|
7
|
8
|
7
|
7
|
|||||
Liquids as % of total realized revenue(b)
|
62
|
61
|
37
|
59
|
30
|
|||||
Liquids as % of unhedged revenue(b)
|
59
|
63
|
47
|
63
|
40
|
|||||
Natural gas production (in bcf)
|
280
|
302
|
272
|
1,129
|
1,004
|
|||||
Average realized natural gas price ($/mcf)(a)
|
2.07
|
1.97
|
3.87
|
2.07
|
4.77
|
|||||
Natural gas as % of total production
|
77
|
79
|
82
|
80
|
84
|
|||||
Natural gas as % of realized revenue
|
38
|
39
|
63
|
41
|
70
|
|||||
Natural gas as % of unhedged revenue
|
41
|
37
|
53
|
37
|
60
|
|||||
Marketing, gathering and compression net margin ($/mcfe)(c)
|
0.11
|
0.11
|
0.07
|
0.08
|
0.10
|
|||||
Oilfield services net margin ($/mcfe) (c)(d)
|
0.05
|
0.09
|
0.09
|
0.10
|
0.10
|
|||||
Production expenses ($/mcfe)
|
(0.83
|
)
|
(0.84
|
)
|
(0.88
|
)
|
(0.92
|
)
|
(0.90
|
)
|
Production taxes ($/mcfe)
|
(0.13
|
)
|
(0.14
|
)
|
(0.15
|
)
|
(0.13
|
)
|
(0.16
|
)
|
General and administrative costs ($/mcfe)(e)
|
(0.23
|
)
|
(0.33
|
)
|
(0.35
|
)
|
(0.33
|
)
|
(0.38
|
)
|
Stock-based compensation ($/mcfe)
|
(0.04
|
)
|
(0.05
|
)
|
(0.06
|
)
|
(0.05
|
)
|
(0.08
|
)
|
DD&A of natural gas and liquids properties ($/mcfe)
|
(1.80
|
)
|
(2.00
|
)
|
(1.46
|
)
|
(1.76
|
)
|
(1.37
|
)
|
D&A of other assets ($/mcfe)(f)
|
(0.20
|
)
|
(0.17
|
)
|
(0.26
|
)
|
(0.21
|
)
|
(0.24
|
)
|
Interest expense ($/mcfe)(a)
|
(0.05
|
)
|
(0.10
|
)
|
(0.04
|
)
|
(0.06
|
)
|
(0.03
|
)
|
Operating cash flow ($ in millions)(g)
|
1,146
|
1,118
|
1,311
|
4,069
|
5,309
|
|||||
Operating cash flow ($/mcfe)
|
3.17
|
2.93
|
3.96
|
2.86
|
4.45
|
|||||
Adjusted ebitda ($ in millions)(h)
|
1,089
|
1,021
|
1,308
|
3,754
|
5,406
|
|||||
Adjusted ebitda ($/mcfe)
|
3.01
|
2.68
|
3.95
|
2.64
|
4.53
|
|||||
Net income (loss) to common stockholders ($ in millions)
|
257
|
(2,055
|
)
|
429
|
(940
|
)
|
1,570
|
|||
Earnings (loss) per share – diluted ($)
|
0.39
|
(3.19
|
)
|
0.63
|
(1.46
|
)
|
2.32
|
|||
Adjusted net income to common stockholders ($ in millions)(i)
|
153
|
35
|
394
|
285
|
1,936
|
|||||
Adjusted earnings per share – diluted ($)
|
0.26
|
0.10
|
0.58
|
0.61
|
2.80
|
|||||
(a)
|
Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging.
|
(b)
|
“Liquids” includes both oil and NGL.
|
(c)
|
Includes revenue and operating costs and excludes depreciation and amortization of other assets.
|
(d)
|
2012 fourth quarter and full year include impact of certain consolidated investments along with results from Chesapeake Oilfield Services.
|
(e)
|
Excludes expenses associated with noncash stock-based compensation.
|
(f)
|
The decrease from 2011 to 2012 (year over year and quarter over quarter) is due to assets being classified as held for sale as of June 30, 2012 and not subject to depreciation thereafter. The assets were sold as part of the midstream sale to ACMP in December 2012.
|
(g)
|
Defined as cash flow provided by operating activities before changes in assets and liabilities.
|
(h)
|
Defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 20.
|
(i)
|
Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 21.
|
Natural Gas
|
Oil
|
|||||||
Year
|
% of Forecasted
Production
|
NYMEX
Natural Gas
|
% of Forecasted
Production
|
NYMEX
Oil WTI
|
||||
2013
|
50%
|
$3.62
|
85%
|
$95.45
|
Pricing Method
|
Natural Gas
Price
($/mcf)
|
Oil Price
($/bbl)
|
Proved
Reserves
(tcfe)
|
PV-10
(billions)
|
Proved
Developed
Percentage
|
Trailing 12-month avg (SEC)(a)
|
$2.76
|
$94.84
|
15.7
|
$17.8
|
57%
|
12/31/12 avg NYMEX strip(b)
|
$4.85
|
$87.90
|
19.6
|
$27.9
|
55%
|
|
a)
|
Reserve volumes estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of December 31, 2012. This pricing assumption yields estimated proved reserves for SEC reporting purposes.
|
|
b)
|
Natural gas and oil volumes estimated under the 10-year average NYMEX strip reflect an alternative pricing scenario that illustrates the sensitivity of proved reserves to a different pricing assumption. Futures prices represent an unbiased consensus estimate by market participants about the likely prices to be received for future production. Management believes that 10-year average NYMEX strip prices provide a better indicator of the likely economic producibility of the company’s proved reserves than the historical 12-month average price.
|
|
·
|
The Hahn Dew 1H in DeWitt County, TX achieved a peak rate of approximately 1,985 boe per day, which included 550 bbls of oil, 360 bbls of NGL and 6.4 mmcf of natural gas per day;
|
|
·
|
The Flat Creek Unit A Dim 2H in Dimmit County, TX achieved a peak rate of approximately 1,470 boe per day, which included 1,210 bbls of oil, 160 bbls of NGL and 0.6 mmcf of natural gas per day; and
|
|
·
|
The JJ Henry IX M 1H in McMullen County, TX achieved a peak rate of approximately 1,275 boe per day, which included 1,160 bbls of oil, 55 bbls of NGL and 0.4 mmcf of natural gas per day.
|
|
·
|
The Houyouse 15-13-5 1H in Carroll County, OH achieved a peak rate of approximately 1,730 boe per day, which included 525 bbls of oil, 305 bbls of NGL and 5.4 mmcf of natural gas per day;
|
|
·
|
The Cain South 16-12-4 8H in Jefferson County, OH achieved a peak rate of approximately 1,540 boe per day, which included 425 bbls of NGL and 6.7 mmcf of natural gas per day; and
|
|
·
|
The Walters 30-12-5 8H in Carroll County, OH achieved a peak rate of approximately 1,140 boe per day, which included 315 bbls of oil, 220 bbls of NGL and 3.6 mmcf of natural gas per day.
|
|
·
|
The Holtan 5H in Susquehanna County, PA achieved a peak rate of 12.6 mmcf of natural gas per day;
|
|
·
|
The Lopatofsky 2H in Wyoming County, PA achieved a peak rate of 11.4 mmcf of natural gas per day; and
|
|
·
|
The Messersmith S Bra 1H in Bradford County, PA achieved a peak rate of 10.5 mmcf of natural gas per day.
|
|
·
|
The Mark Hickman 5H in Ohio County, WV achieved an initial test rate of approximately 1,195 boe per day, which included 290 bbls of oil, 305 bbls of NGL and 3.6 mmcf of natural gas per day;
|
|
·
|
The Esther Weeks 1H in Ohio County, WV achieved an initial test rate of approximately 1,000 boe per day, which included 195 bbls of oil, 265 bbls of NGL and 3.3 mmcf of natural gas per day; and
|
|
·
|
The Michael Southworth 8H in Marshall County, WV achieved an initial test rate of approximately 955 boe per day, which included 305 bbls of oil, 215 bbls of NGL and 2.6 mmcf of natural gas per day.
|
|
·
|
The Mike 2-28-15 1H in Woods County, OK achieved a peak rate of approximately 2,820 boe per day, which included 2,345 bbls of oil, 100 bbls of NGL and 2.3 mmcf of natural gas per day;
|
|
·
|
The Roper 1-28-15 1H in Woods County, OK achieved a peak rate of approximately 1,985 boe per day, which included 1,645 bbls of oil, 70 bbls of NGL and 1.6 mmcf of natural gas per day; and
|
|
·
|
The Thorp 4-24-10 1H in Alfalfa County, OK achieved a peak rate of approximately 1,365 boe per day, which included 465 bbls of oil, 215 bbls of NGL and 4.1 mmcf of natural gas per day.
|
December 31,
|
December 31,
|
|||||||||||||||
THREE MONTHS ENDED:
|
2012
|
2011
|
||||||||||||||
$
|
$/mcfe
|
$
|
$/mcfe
|
|||||||||||||
REVENUES:
|
||||||||||||||||
Natural gas, oil and NGL
|
1,657
|
4.58
|
1,336
|
4.03
|
||||||||||||
Marketing, gathering and compression
|
1,721
|
4.76
|
1,246
|
3.77
|
||||||||||||
Oilfield services
|
161
|
0.45
|
145
|
0.44
|
||||||||||||
Total Revenues
|
3,539
|
9.79
|
2,727
|
8.24
|
||||||||||||
OPERATING EXPENSES:
|
||||||||||||||||
Natural gas, oil and NGL production
|
299
|
0.83
|
292
|
0.88
|
||||||||||||
Production taxes
|
47
|
0.13
|
51
|
0.15
|
||||||||||||
Marketing, gathering and compression
|
1,681
|
4.65
|
1,223
|
3.70
|
||||||||||||
Oilfield services
|
145
|
0.40
|
115
|
0.35
|
||||||||||||
General and administrative
|
99
|
0.27
|
138
|
0.42
|
||||||||||||
Employee retirement expense and other termination benefits
|
3
|
0.01
|
—
|
—
|
||||||||||||
Natural gas, oil and NGL depreciation, depletion and amortization
|
651
|
1.80
|
484
|
1.46
|
||||||||||||
Depreciation and amortization of other assets
|
71
|
0.20
|
85
|
0.26
|
||||||||||||
Net gains on sales of fixed assets
|
(272
|
)
|
(0.75
|
)
|
(439
|
)
|
(1.33
|
)
|
||||||||
Impairments of fixed assets and other
|
59
|
0.16
|
42
|
0.13
|
||||||||||||
Total Operating Expenses
|
2,783
|
7.70
|
1,991
|
6.02
|
||||||||||||
INCOME (LOSS) FROM OPERATIONS
|
756
|
2.09
|
736
|
2.22
|
||||||||||||
OTHER INCOME (EXPENSE):
|
||||||||||||||||
Interest expense
|
(14
|
)
|
(0.04
|
)
|
(7
|
)
|
(0.02
|
)
|
||||||||
Earnings (losses) on investments
|
(16
|
)
|
(0.04
|
)
|
56
|
0.17
|
||||||||||
Gain on sale of investment
|
31
|
0.09
|
—
|
—
|
||||||||||||
Losses on purchases of debt
|
(200
|
)
|
(0.55
|
)
|
—
|
—
|
||||||||||
Other income
|
6
|
0.01
|
14
|
0.04
|
||||||||||||
Total Other Income (Expense)
|
(193
|
)
|
(0.53
|
)
|
63
|
0.19
|
||||||||||
INCOME (LOSS) BEFORE INCOME TAXES
|
563
|
1.56
|
799
|
2.41
|
||||||||||||
INCOME TAX EXPENSE (BENEFIT):
|
||||||||||||||||
Current income taxes
|
23
|
0.06
|
2
|
—
|
||||||||||||
Deferred income taxes
|
196
|
0.55
|
310
|
0.94
|
||||||||||||
Total Income Tax Expense (Benefit)
|
219
|
0.61
|
312
|
0.94
|
||||||||||||
NET INCOME (LOSS)
|
344
|
0.95
|
487
|
1.47
|
||||||||||||
Net income attributable to noncontrolling interests
|
(44
|
)
|
(0.12
|
)
|
(15
|
)
|
(0.04
|
)
|
||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
|
300
|
0.83
|
472
|
1.43
|
||||||||||||
Preferred stock dividends
|
(43
|
)
|
(0.12
|
)
|
(43
|
)
|
(0.13
|
)
|
||||||||
NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS
|
257
|
0.71
|
429
|
1.30
|
||||||||||||
EARNINGS (LOSS) PER COMMON SHARE:
|
||||||||||||||||
Basic
|
$
|
0.39
|
$
|
0.67
|
||||||||||||
Diluted
|
$
|
0.39
|
$
|
0.63
|
||||||||||||
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
|
||||||||||||||||
Basic
|
644
|
640
|
||||||||||||||
Diluted
|
648
|
750
|
December 31,
|
December 31,
|
|||||||||||||||
TWELVE MONTHS ENDED:
|
2012
|
2011
|
||||||||||||||
$
|
$/mcfe
|
$
|
$/mcfe
|
|||||||||||||
REVENUES:
|
||||||||||||||||
Natural gas, oil and NGL
|
6,278
|
4.42
|
6,024
|
5.04
|
||||||||||||
Marketing, gathering and compression
|
5,431
|
3.81
|
5,090
|
4.26
|
||||||||||||
Oilfield services
|
607
|
0.43
|
521
|
0.44
|
||||||||||||
Total Revenues
|
12,316
|
8.66
|
11,635
|
9.74
|
||||||||||||
OPERATING EXPENSES:
|
||||||||||||||||
Natural gas, oil and NGL production
|
1,304
|
0.92
|
1,073
|
0.90
|
||||||||||||
Production taxes
|
188
|
0.13
|
192
|
0.16
|
||||||||||||
Marketing, gathering and compression
|
5,312
|
3.73
|
4,967
|
4.16
|
||||||||||||
Oilfield services
|
465
|
0.33
|
402
|
0.34
|
||||||||||||
General and administrative
|
535
|
0.38
|
548
|
0.46
|
||||||||||||
Employee retirement expense and other termination benefits
|
7
|
0.01
|
—
|
—
|
||||||||||||
Natural gas, oil and NGL depreciation, depletion and amortization
|
2,507
|
1.76
|
1,632
|
1.37
|
||||||||||||
Depreciation and amortization of other assets
|
304
|
0.21
|
291
|
0.24
|
||||||||||||
Impairment of natural gas and oil properties
|
3,315
|
2.33
|
—
|
—
|
||||||||||||
Net gains on sales of fixed assets
|
(267
|
)
|
(0.18
|
)
|
(437
|
)
|
(0.37
|
)
|
||||||||
Impairments of fixed assets and other
|
340
|
0.24
|
46
|
0.03
|
||||||||||||
Total Operating Expenses
|
14,010
|
9.86
|
8,714
|
7.29
|
||||||||||||
INCOME (LOSS) FROM OPERATIONS
|
(1,694
|
)
|
(1.20
|
)
|
2,921
|
2.45
|
||||||||||
OTHER INCOME (EXPENSE):
|
||||||||||||||||
Interest expense
|
(77
|
)
|
(0.05
|
)
|
(44
|
)
|
(0.04
|
)
|
||||||||
Earnings (losses) on investments
|
(103
|
)
|
(0.08
|
)
|
156
|
0.13
|
||||||||||
Gain on sales of investments
|
1,092
|
0.77
|
—
|
—
|
||||||||||||
Losses on purchases of debt
|
(200
|
)
|
(0.14
|
)
|
(176
|
)
|
(0.15
|
)
|
||||||||
Other income
|
8
|
0.01
|
23
|
0.02
|
||||||||||||
Total Other Income (Expense)
|
720
|
0.51
|
(41
|
)
|
(0.04
|
)
|
||||||||||
INCOME (LOSS) BEFORE INCOME TAXES
|
(974
|
)
|
(0.69
|
)
|
2,880
|
2.41
|
||||||||||
INCOME TAX EXPENSE (BENEFIT):
|
||||||||||||||||
Current income taxes
|
47
|
0.03
|
13
|
0.01
|
||||||||||||
Deferred income taxes
|
(427
|
)
|
(0.30
|
)
|
1,110
|
0.93
|
||||||||||
Total Income Tax Expense (Benefit)
|
(380
|
)
|
(0.27
|
)
|
1,123
|
0.94
|
||||||||||
NET INCOME (LOSS)
|
(594
|
)
|
(0.42
|
)
|
1,757
|
1.47
|
||||||||||
Net income attributable to noncontrolling interests
|
(175
|
)
|
(0.12
|
)
|
(15
|
)
|
(0.01
|
)
|
||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
|
(769
|
)
|
(0.54
|
)
|
1,742
|
1.46
|
||||||||||
Preferred stock dividends
|
(171
|
)
|
(0.12
|
)
|
(172
|
)
|
(0.15
|
)
|
||||||||
NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS
|
(940
|
)
|
(0.66
|
)
|
1,570
|
1.31
|
||||||||||
EARNINGS (LOSS) PER COMMON SHARE:
|
||||||||||||||||
Basic
|
$
|
(1.46
|
)
|
$
|
2.47
|
|||||||||||
Diluted
|
$
|
(1.46
|
)
|
$
|
2.32
|
|||||||||||
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
|
||||||||||||||||
Basic
|
643
|
637
|
||||||||||||||
Diluted
|
643
|
752
|
December 31,
|
December 31,
|
|||||||
2012
|
2011
|
|||||||
Cash and cash equivalents
|
$
|
287
|
$
|
351
|
||||
Other current assets
|
2,661
|
2,826
|
||||||
Total Current Assets
|
2,948
|
3,177
|
||||||
Property and equipment (net)
|
37,167
|
36,739
|
||||||
Other assets
|
1,496
|
1,919
|
||||||
Total Assets
|
$
|
41,611
|
$
|
41,835
|
||||
Current liabilities
|
$
|
6,266
|
$
|
7,082
|
||||
Long-term debt, net of discounts
|
12,157
|
10,626
|
||||||
Other long-term liabilities
|
2,485
|
2,682
|
||||||
Deferred income tax liabilities
|
2,807
|
3,484
|
||||||
Total Liabilities
|
23,715
|
23,874
|
||||||
Chesapeake stockholders' equity
|
15,569
|
16,624
|
||||||
Noncontrolling interests
|
2,327
|
1,337
|
||||||
Total Equity
|
17,896
|
17,961
|
||||||
Total Liabilities and Equity
|
$
|
41,611
|
$
|
41,835
|
||||
Common Shares Outstanding (in millions)
|
664
|
659
|
December 31,
|
December 31,
|
||||||||
2012
|
2011
|
||||||||
Total debt, net of unrestricted cash
|
$
|
12,333
|
$
|
10,275
|
|||||
Chesapeake stockholders' equity
|
15,569
|
16,624
|
|||||||
Noncontrolling interests(a)
|
2,327
|
1,337
|
|||||||
Total
|
$
|
30,229
|
$
|
28,236
|
|||||
Debt to capitalization ratio
|
41%
|
36%
|
(a)
|
Includes third-party ownership as follows:
|
CHK Cleveland Tonkawa, L.L.C.
|
$
|
1,015
|
$
|
—
|
|||||
CHK Utica, L.L.C.
|
950
|
950
|
|||||||
Chesapeake Granite Wash Trust
|
356
|
380
|
|||||||
Other
|
6
|
7
|
|||||||
Total
|
$
|
2,327
|
$
|
1,337
|
Proved Reserves
|
||||||||||||
Cost
|
Bcfe(a)
|
$/Mcfe
|
||||||||||
PROVED PROPERTIES:
|
||||||||||||
Well costs on proved properties(b)(c)
|
$
|
9,168
|
5,042
|
(d)
|
1.82
|
|||||||
Acquisition of proved properties(e)
|
332
|
42
|
7.91
|
|||||||||
Sale of proved properties
|
(2,462
|
)
|
(1,347
|
)
|
1.83
|
|||||||
Total net proved properties
|
7,038
|
3,737
|
1.88
|
|||||||||
Revisions – price
|
—
|
(5,414
|
)
|
—
|
||||||||
UNPROVED PROPERTIES:
|
||||||||||||
Well costs on unproved properties(f)
|
(337
|
)
|
—
|
—
|
||||||||
Acquisition of unproved properties, net(g)
|
1,718
|
—
|
—
|
|||||||||
Acquisition of minerals
|
68
|
—
|
—
|
|||||||||
Sale of unproved properties
|
(3,146
|
)
|
—
|
—
|
||||||||
Total net unproved properties
|
(1,697
|
)
|
—
|
—
|
||||||||
OTHER:
|
||||||||||||
Capitalized interest on unproved properties
|
976
|
—
|
—
|
|||||||||
Geological and geophysical costs
|
170
|
—
|
—
|
|||||||||
Asset retirement obligations
|
32
|
—
|
—
|
|||||||||
Total other
|
1,178
|
—
|
—
|
|||||||||
Total
|
$
|
6,519
|
(1,677
|
)
|
—
|
Bcfe(a)
|
||||
Beginning balance, January 1, 2012
|
18,789
|
|||
Production
|
(1,422
|
)
|
||
Acquisitions
|
42
|
|||
Divestitures
|
(1,347
|
)
|
||
Revisions – changes to previous estimates
|
(1,349
|
)
|
||
Revisions – price
|
(5,414
|
)
|
||
Extensions and discoveries
|
6,391
|
|||
Ending balance, December 31, 2012
|
15,690
|
|||
Proved reserves decline rate before acquisitions and divestitures
|
10
|
%
|
||
Proved reserves decline rate after acquisitions and divestitures
|
17
|
%
|
||
Proved developed reserves
|
8,944
|
|||
Proved developed reserves percentage
|
57
|
%
|
||
PV-10 ($ in billions)(a)
|
$
|
17.8
|
(a)
|
Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of December 31, 2012 of $2.76 per mcf of natural gas and $94.84 per bbl of oil, before field differential adjustments.
|
(b)
|
Net of well cost carries of $784 million associated with the Statoil-Marcellus, CNOOC-Eagle Ford, CNOOC-Niobrara and Total-Utica joint ventures.
|
(c)
|
Includes $1.389 billion of well costs incurred in prior quarters (previously classified as well costs on unproved properties) related to wells that were evaluated for the existence of proved reserves in the current quarter.
|
(d)
|
Includes 1.349 tcfe of downward revisions resulting from changes to previous estimates and excludes downward revisions of 5.414 tcfe primarily resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended December 31, 2012, compared to the twelve months ended December 31, 2011.
|
(e)
|
Includes 28 bcfe of proved reserves associated with the company’s Permian Basin volumetric production payment repurchased by the company for $313 million and subsequently resold to multiple parties in September and October 2012.
|
(f)
|
Includes $1.052 million of well costs on unproved properties incurred in the current year, offset by the transfer of $1.389 billion previously classified as well costs on unproved properties that were evaluated for the existence of proved reserves in the current quarter. See footnote (c).
|
(g)
|
Net of joint venture partner reimbursements.
|
December 31,
|
December 31,
|
||||||
2012
|
2011
|
||||||
Standardized measure of discounted future net cash flows
|
$
|
14,666
|
$
|
15,630
|
|||
|
|||||||
Discounted future cash flows for income taxes
|
3,107
|
4,247
|
|||||
Discounted future net cash flows before income taxes (PV-10)
|
$
|
17,773
|
$
|
19,877
|
|||
PV-10 is discounted (at 10% per year) future net cash flows before income taxes. The standardized measure of discounted future net cash flows includes the effects of estimated future income tax expenses and is calculated in accordance with Accounting Standards Topic 932. Management uses PV-10 as one measure of the value of the company's current proved reserves and to compare relative values among peer companies without regard to income taxes. The company also understands that securities analysts and rating agencies use this measure in similar ways. While PV-10 is based on prices, costs and discount factors which are consistent from company to company, the standardized measure is dependent on the unique tax situation of each individual company.
The company’s PV-10 and standardized measure were calculated using trailing 12-month average first-day-of-the-month prices. As of December 31, 2012 and 2011, the prices used were $2.76 per mcf and $94.84 per bbl and $4.12 per mcf and $95.97 per bbl, respectively, before field differential adjustments.
|
Three Months Ended
|
Twelve Months Ended
|
|||||||||||||||
December 31,
|
December 31,
|
|||||||||||||||
2012
|
2011
|
2012
|
2011
|
|||||||||||||
Natural Gas, Oil and NGL Sales ($ in millions):
|
||||||||||||||||
Natural gas sales
|
$
|
645
|
$
|
720
|
$
|
2,004
|
$
|
3,133
|
||||||||
Natural gas derivatives – realized gains (losses)
|
(63
|
)
|
335
|
328
|
1,656
|
|||||||||||
Natural gas derivatives – unrealized gains (losses)
|
70
|
24
|
(331
|
)
|
(669
|
)
|
||||||||||
Total Natural Gas Sales
|
652
|
1,079
|
2,001
|
4,120
|
||||||||||||
Oil sales
|
790
|
475
|
2,829
|
1,523
|
||||||||||||
Oil derivatives – realized gains (losses)
|
34
|
(10
|
)
|
39
|
(60
|
)
|
||||||||||
Oil derivatives – unrealized gains (losses)
|
54
|
(375
|
)
|
857
|
(128
|
)
|
||||||||||
Total Oil Sales
|
878
|
90
|
3,725
|
1,335
|
||||||||||||
NGL sales
|
126
|
171
|
526
|
603
|
||||||||||||
NGL derivatives – realized gains (losses)
|
—
|
(10
|
)
|
(9
|
)
|
(42
|
)
|
|||||||||
NGL derivatives – unrealized gains (losses)
|
1
|
6
|
35
|
8
|
||||||||||||
Total NGL Sales
|
127
|
167
|
552
|
569
|
||||||||||||
Total Natural Gas, Oil and NGL Sales
|
$
|
1,657
|
$
|
1,336
|
$
|
6,278
|
$
|
6,024
|
||||||||
Average Sales Price –
excluding gains (losses) on derivatives:
|
||||||||||||||||
Natural gas ($ per mcf)
|
$
|
2.30
|
$
|
2.64
|
$
|
1.77
|
$
|
3.12
|
||||||||
Oil ($ per bbl)
|
$
|
88.44
|
$
|
89.85
|
$
|
90.49
|
$
|
89.80
|
||||||||
NGL ($ per bbl)
|
$
|
27.20
|
$
|
38.19
|
$
|
29.89
|
$
|
40.96
|
||||||||
Natural gas equivalent ($ per mcfe)
|
$
|
4.32
|
$
|
4.13
|
$
|
3.77
|
$
|
4.40
|
||||||||
Average Sales Price –
excluding unrealized gains (losses) on derivatives:
|
||||||||||||||||
Natural gas ($ per mcf)
|
$
|
2.07
|
$
|
3.87
|
$
|
2.07
|
$
|
4.77
|
||||||||
Oil ($ per bbl)
|
$
|
92.23
|
$
|
88.02
|
$
|
91.74
|
$
|
86.25
|
||||||||
NGL ($ per bbl)
|
$
|
27.12
|
$
|
35.87
|
$
|
29.37
|
$
|
38.12
|
||||||||
Natural gas equivalent ($ per mcfe)
|
$
|
4.23
|
$
|
5.08
|
$
|
4.02
|
$
|
5.70
|
||||||||
Interest Expense (Income) ($ in millions):
|
||||||||||||||||
Interest(a)
|
$
|
17
|
$
|
11
|
$
|
84
|
$
|
30
|
||||||||
Derivatives – realized (gains) losses
|
—
|
1
|
(1
|
)
|
7
|
|||||||||||
Derivatives – unrealized (gains) losses
|
(3
|
)
|
(5
|
)
|
(6
|
)
|
7
|
|||||||||
Total Interest Expense
|
$
|
14
|
$
|
7
|
$
|
77
|
$
|
44
|
(a)
|
Net of amounts capitalized.
|
THREE MONTHS ENDED:
|
December 31,
|
December 31,
|
|||||
2012
|
2011
|
||||||
Beginning cash
|
$
|
142
|
$
|
111
|
|||
Cash provided by operating activities
|
864
|
2,179
|
|||||
Cash flows from investing activities:
|
|||||||
Well costs on proved and unproved properties
|
(1,377
|
)
|
(2,080
|
)
|
|||
Acquisition of proved and unproved properties(a)
|
(295
|
)
|
(1,163
|
)
|
|||
Sale of proved and unproved properties
|
3,386
|
1,257
|
|||||
Geological and geophysical costs
|
(28
|
)
|
(42
|
)
|
|||
Additions to other property and equipment
|
(719
|
)
|
(593
|
)
|
|||
Proceeds from sales of other assets
|
2,273
|
630
|
|||||
Additions to investments
|
(145
|
)
|
(25
|
)
|
|||
Other
|
79
|
(81
|
)
|
||||
Total cash provided by (used in) investing activities
|
3,174
|
(2,097
|
)
|
||||
Cash provided by (used in) financing activities
|
(3,907
|
)
|
158
|
||||
Change in cash and cash equivalents classified in current assets held for sale
|
14
|
—
|
|||||
Ending cash
|
$
|
287
|
$
|
351
|
TWELVE MONTHS ENDED:
|
December 31,
|
December 31,
|
|||||
2012
|
2011
|
||||||
Beginning cash
|
$
|
351
|
$
|
102
|
|||
Cash provided by operating activities
|
2,841
|
5,903
|
|||||
Cash flows from investing activities:
|
|||||||
Well costs on proved and unproved properties
|
(8,737
|
)
|
(7,257
|
)
|
|||
Acquisition of proved and unproved properties(b)
|
(2,890
|
)
|
(4,463
|
)
|
|||
Sale of proved and unproved properties
|
5,613
|
7,140
|
|||||
Geological and geophysical costs
|
(193
|
)
|
(210
|
)
|
|||
Additions to other property and equipment
|
(2,635
|
)
|
(2,009
|
)
|
|||
Proceeds from sales of other assets
|
2,492
|
1,312
|
|||||
Acquisition of drilling company
|
—
|
(339
|
)
|
||||
Proceeds from (additions to) investments
|
(406
|
)
|
101
|
||||
Proceeds from sale of midstream investment
|
2,000
|
—
|
|||||
Other
|
(224
|
)
|
(87
|
)
|
|||
Total cash used in investing activities
|
(4,980
|
)
|
(5,812
|
)
|
|||
Cash provided by financing activities
|
2,075
|
158
|
|||||
Ending cash
|
$
|
287
|
$
|
351
|
(a)
|
Includes capitalized interest of $153 million and $152 million for the current quarter and the prior quarter, respectively.
|
|||||||
(b)
|
Includes capitalized interest of $776 million and $630 million for the current period and the prior period, respectively.
|
December 31,
|
September 30,
|
December 31,
|
||||||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
|||||||||
CASH PROVIDED BY OPERATING ACTIVITIES
|
$
|
864
|
$
|
949
|
$
|
2,179
|
||||||
Changes in assets and liabilities
|
282
|
169
|
(868
|
)
|
||||||||
OPERATING CASH FLOW(a)
|
$
|
1,146
|
$
|
1,118
|
$
|
1,311
|
December 31,
|
September 30,
|
December 31,
|
||||||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
|||||||||
NET INCOME (LOSS)
|
$
|
344
|
$
|
(1,971
|
)
|
$
|
487
|
|||||
Income tax expense (benefit)
|
219
|
(1,260
|
)
|
312
|
||||||||
Interest expense
|
14
|
36
|
7
|
|||||||||
Depreciation and amortization of other assets
|
71
|
66
|
85
|
|||||||||
Natural gas, oil and NGL depreciation, depletion and amortization
|
651
|
762
|
484
|
|||||||||
EBITDA(b)
|
$
|
1,299
|
$
|
(2,367
|
)
|
$
|
1,375
|
December 31,
|
September 30,
|
December 31,
|
||||||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
|||||||||
CASH PROVIDED BY OPERATING ACTIVITIES
|
$
|
864
|
$
|
949
|
$
|
2,179
|
||||||
Changes in assets and liabilities
|
282
|
169
|
(868
|
)
|
||||||||
Interest expense
|
14
|
36
|
7
|
|||||||||
Unrealized gains (losses) on natural gas, oil and NGL derivatives
|
125
|
(104
|
)
|
(345
|
)
|
|||||||
Impairment of natural gas and oil properties
|
—
|
(3,315
|
)
|
—
|
||||||||
Net gains (losses) on sales of fixed assets
|
272
|
(7
|
)
|
439
|
||||||||
Impairments of fixed assets and other
|
(59
|
)
|
(14
|
)
|
(42
|
)
|
||||||
Gains (losses) on investments
|
(2
|
)
|
4
|
22
|
||||||||
Stock-based compensation
|
(27
|
)
|
(30
|
)
|
(34
|
)
|
||||||
Losses on purchases of debt
|
(200
|
)
|
—
|
—
|
||||||||
Other items
|
30
|
(55
|
)
|
17
|
||||||||
EBITDA(b)
|
$
|
1,299
|
$
|
(2,367
|
)
|
$
|
1,375
|
(a)
|
Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.
|
(b)
|
Ebitda represents net income (loss) before income tax expense, interest expense and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.
|
December 31,
|
December 31,
|
||||||
TWELVE MONTHS ENDED:
|
2012
|
2011
|
|||||
CASH PROVIDED BY OPERATING ACTIVITIES
|
$
|
2,841
|
$
|
5,903
|
|||
Changes in assets and liabilities
|
1,228
|
(594
|
)
|
||||
OPERATING CASH FLOW(a)
|
$
|
4,069
|
$
|
5,309
|
December 31,
|
December 31,
|
||||||
TWELVE MONTHS ENDED:
|
2012
|
2011
|
|||||
NET INCOME (LOSS)
|
$
|
(594
|
)
|
$
|
1,757
|
||
Income tax expense (benefit)
|
(380
|
)
|
1,123
|
||||
Interest expense
|
77
|
44
|
|||||
Depreciation and amortization of other assets
|
304
|
291
|
|||||
Natural gas, oil and NGL depreciation, depletion and amortization
|
2,507
|
1,632
|
|||||
EBITDA(b)
|
$
|
1,914
|
$
|
4,847
|
December 31,
|
December 31,
|
||||||
TWELVE MONTHS ENDED:
|
2012
|
2011
|
|||||
CASH PROVIDED BY OPERATING ACTIVITIES
|
$
|
2,841
|
$
|
5,903
|
|||
Changes in assets and liabilities
|
1,228
|
(594
|
)
|
||||
Interest expense
|
77
|
44
|
|||||
Unrealized gains (losses) on natural gas, oil and NGL derivatives
|
561
|
(789
|
)
|
||||
Impairment of natural gas and oil properties
|
(3,315
|
)
|
—
|
||||
Net gains on sales of fixed assets
|
267
|
437
|
|||||
Impairments of fixed assets and other
|
(316
|
)
|
(46)
|
||||
Gains (losses) on investments
|
(180
|
)
|
41
|
||||
Stock-based compensation
|
(120
|
)
|
(153
|
)
|
|||
Gains on sales of investments
|
1,092
|
—
|
|||||
Losses on purchases of debt
|
(200
|
)
|
(5)
|
||||
Other items
|
(21
|
)
|
9
|
||||
EBITDA(b)
|
$
|
1,914
|
$
|
4,847
|
(a)
|
Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.
|
(b)
|
Ebitda represents net income (loss) before income tax expense, interest expense and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP.
|
December 31,
|
September 30,
|
December 31,
|
||||||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
|||||||||
EBITDA
|
$
|
1,299
|
$
|
(2,367
|
)
|
$
|
1,375
|
|||||
Adjustments:
|
||||||||||||
Unrealized (gains) losses on natural gas, oil and NGL derivatives
|
(125
|
)
|
104
|
345
|
||||||||
Impairment of natural gas and oil properties
|
—
|
3,315
|
—
|
|||||||||
Net (gains) losses on sales of fixed assets
|
(272
|
)
|
7
|
(439
|
)
|
|||||||
Impairments of fixed assets and other
|
59
|
38
|
42
|
|||||||||
Net income attributable to noncontrolling interests
|
(44
|
)
|
(41
|
)
|
(15
|
)
|
||||||
Gains on sales of investments
|
(31
|
)
|
(31
|
)
|
—
|
|||||||
Losses on purchases of debt
|
200
|
—
|
—
|
|||||||||
Other
|
3
|
(4
|
)
|
—
|
||||||||
Adjusted EBITDA(a)
|
$
|
1,089
|
$
|
1,021
|
$
|
1,308
|
December 31,
|
December 31,
|
|||||||
TWELVE MONTHS ENDED:
|
2012
|
2011
|
||||||
EBITDA
|
$
|
1,914
|
$
|
4,847
|
||||
Adjustments:
|
||||||||
Unrealized (gains) losses on natural gas, oil and NGL derivatives
|
(561
|
)
|
789
|
|||||
Impairment of natural gas and oil properties
|
3,315
|
—
|
||||||
Net gains on sales of fixed assets
|
(267
|
)
|
(437
|
)
|
||||
Impairments of fixed assets and other
|
340
|
46
|
||||||
Net income attributable to noncontrolling interests
|
(175
|
)
|
(15
|
)
|
||||
Losses on purchases of debt
|
200
|
176
|
||||||
(Gains) on investments
|
(1,019
|
)
|
—
|
|||||
Other
|
7
|
—
|
||||||
Adjusted EBITDA(a)
|
$
|
3,754
|
$
|
5,406
|
(a)
|
Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to ebitda because:
|
|
(i)
|
Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies.
|
|
(ii)
|
Adjusted ebitda is more comparable to estimates provided by securities analysts.
|
|
(iii)
|
Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.
|
December 31,
|
September 30,
|
December 31,
|
||||||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
|||||||||
Net income (loss) available to common stockholders
|
$
|
257
|
$
|
(2,055
|
)
|
$
|
429
|
|||||
Adjustments, net of tax:
|
||||||||||||
Unrealized (gains) losses on derivatives
|
(78
|
)
|
63
|
207
|
||||||||
Impairment of natural gas and oil properties
|
—
|
2,022
|
—
|
|||||||||
Net (gains) losses on sales of fixed assets
|
(166
|
)
|
4
|
(268
|
)
|
|||||||
Impairments of fixed assets and other
|
36
|
23
|
26
|
|||||||||
Gains on sales of investments
|
(19
|
)
|
(19
|
)
|
—
|
|||||||
Losses on purchases or exchanges of debt
|
122
|
—
|
—
|
|||||||||
Other
|
1
|
(3
|
)
|
—
|
||||||||
Adjusted net income available to common
stockholders(a)
|
153
|
35
|
394
|
|||||||||
Preferred stock dividends
|
43
|
43
|
43
|
|||||||||
Total adjusted net income
|
$
|
196
|
$
|
78
|
$
|
437
|
||||||
Weighted average fully diluted shares outstanding(b)
|
754
|
754
|
750
|
|||||||||
Adjusted earnings per share assuming dilution(a)
|
$
|
0.26
|
$
|
0.10
|
$
|
0.58
|
December 31,
|
December 31,
|
|||||||
TWELVE MONTHS ENDED:
|
2012
|
2011
|
||||||
Net income (loss) available to common stockholders
|
$
|
(940
|
)
|
$
|
1,570
|
|||
Adjustments, net of tax:
|
||||||||
Unrealized (gains) losses on derivatives
|
(347
|
)
|
486
|
|||||
Impairment of natural gas and oil properties
|
2,022
|
—
|
||||||
Net gains on sales of fixed assets
|
(163
|
)
|
(266
|
)
|
||||
Impairments of fixed assets and other
|
208
|
28
|
||||||
Losses on purchases or exchanges of debt
|
122
|
107
|
||||||
Loss on foreign currency derivatives
|
—
|
11
|
||||||
Gains on investments
|
(622
|
)
|
—
|
|||||
Other
|
5
|
—
|
||||||
Adjusted net income available to common stockholders(a)
|
285
|
1,936
|
||||||
Preferred stock dividends
|
171
|
172
|
||||||
Total adjusted net income
|
$
|
456
|
$
|
2,108
|
||||
Weighted average fully diluted shares outstanding(b)
|
755
|
752
|
||||||
Adjusted earnings per share assuming dilution(a)
|
$
|
0.61
|
$
|
2.80
|
(a)
|
Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to GAAP earnings because:
|
|
(i)
|
Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies.
|
|
(ii)
|
Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts.
|
|
(iii)
|
Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.
|
|
(b)
|
Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.
|
Year Ending
12/31/13
|
|||||
Estimated Production:
|
|||||
Natural gas – bcf
|
1,030 – 1,070
|
||||
Oil – mbbls
|
36,000 – 38,000
|
||||
NGL – mbbls(a)
|
24,000 – 26,000
|
||||
Natural gas equivalent – bcfe
|
1,390 – 1,454
|
||||
Daily natural gas equivalent midpoint – mmcfe
|
3,895
|
||||
YOY estimated production increase (adjusted for planned asset sales)
|
0%
|
||||
NYMEX Price(b) (for calculation of realized hedging effects only):
|
|||||
Natural gas - $/mcf
|
$3.67
|
||||
Oil - $/bbl
|
$95.00
|
||||
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
|
|||||
Natural gas - $/mcf
|
($0.05)
|
||||
Oil - $/bbl
|
$0.30
|
||||
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
|
|||||
Natural gas - $/mcf
|
$1.15 – 1.25
|
||||
Oil - $/bbl
|
$0.00 – 2.00
|
||||
NGL - $/bbl
|
$66.00 – 70.00
|
||||
Operating Costs per Mcfe of Projected Production:
|
|||||
Production expense
|
$0.90 – 0.95
|
||||
Production taxes
|
$0.20 – 0.25
|
||||
General and administrative(c)
|
$0.34 – 0.39
|
||||
Stock-based compensation (noncash)
|
$0.04 – 0.06
|
||||
DD&A of natural gas and liquids assets
|
$1.65 – 1.85
|
||||
Depreciation of other assets
|
$0.25 – 0.30
|
||||
Interest expense(d)
|
$0.05 – 0.10
|
||||
Other ($ millions):
|
|||||
Marketing, gathering and compression net margin(e)
|
$90 – 100
|
||||
Oilfield services net margin(e)
|
$175 – 225
|
||||
Net income attributable to noncontrolling interests and other(f)
|
($180) – (220)
|
||||
Book Tax Rate
|
39%
|
||||
Weighted average shares outstanding (in millions):
|
|||||
Basic
|
645 – 650
|
||||
Diluted
|
758 – 763
|
||||
Operating cash flow before changes in assets and liabilities(g)(h)
|
$4,850 – 5,150
|
||||
Well costs on proved and unproved properties
|
($5,750 – 6,250)
|
||||
Acquisition of unproved properties, net
|
($400)
|
a)
|
Assumes no ethane rejection.
|
b)
|
NYMEX natural gas and oil prices have been updated for actual contract prices through February and January, respectively.
|
c)
|
Excludes expenses associated with noncash stock-based compensation.
|
d)
|
Does not include unrealized gains or losses on interest rate derivatives.
|
e)
|
Includes revenue and operating costs and excludes depreciation and amortization of other assets.
|
f)
|
Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica, L.L.C. and CHK Cleveland Tonkawa, L.L.C.
|
g)
|
A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.
|
h)
|
Assumes NYMEX prices on open contracts of $3.50 to $4.00 per mcf and $95.00 per bbl in 2013.
|
Open
Swaps
(bcf)
|
Avg. NYMEX
Price of
Open Swaps
|
Forecasted
Natural Gas
Production
(bcf)
|
Open Swap
Positions as
a % of
Forecasted
Natural Gas
Production
|
Total Gains
(Losses) from
Closed Trades
and Premiums
for Call Options
($ in millions)
|
Total Gains
(Losses) from
Closed Trades
and Premiums for
Call Options per
mcf of Forecasted
Natural Gas
Production
|
|||||||||||||
Q1 2013
|
53
|
$
|
3.72
|
$
|
(9
|
)
|
||||||||||||
Q2 2013
|
137
|
3.66
|
11
|
|||||||||||||||
Q3 2013
|
141
|
3.59
|
7
|
|||||||||||||||
Q4 2013
|
141
|
3.59
|
(3
|
)
|
||||||||||||||
Total 2013
|
472
|
$
|
3.63
|
1,050
|
45%
|
$
|
6
|
$
|
0.00
|
|||||||||
Total 2014
|
0
|
-
|
$
|
(74
|
)
|
|||||||||||||
Total 2015
|
0
|
-
|
$
|
(131
|
)
|
|||||||||||||
Total 2016 – 2022
|
0
|
-
|
$
|
(187
|
)
|
Open
Collars
(bcf)
|
Avg. NYMEX
Sold Put Price
|
Avg. NYMEX
Bought Put Price
|
Avg. NYMEX
Ceiling Price
|
Forecasted
Natural Gas
Production
(bcf)
|
Open Collars as
a % of
Forecasted
Natural Gas
Production
|
|||||||||||||||
Q1 2013
|
0
|
$
|
-
|
$
|
-
|
$
|
-
|
|||||||||||||
Q2 2013
|
18
|
3.03
|
3.55
|
4.03
|
||||||||||||||||
Q3 2013
|
18
|
3.03
|
3.55
|
4.03
|
||||||||||||||||
Q4 2013
|
18
|
3.03
|
3.55
|
4.03
|
||||||||||||||||
Total 2013
|
54
|
$
|
3.03
|
$
|
3.55
|
$
|
4.03
|
1,050
|
5%
|
Call Options
(bcf)
|
Avg. NYMEX
Strike Price
|
Forecasted
Natural Gas
Production
(bcf)
|
Call Options
as a % of
Forecasted Natural
Gas
Production
|
|||||||
Q1 2013
|
0
|
$
|
-
|
|||||||
Q2 2013
|
0
|
-
|
||||||||
Q3 2013
|
0
|
-
|
||||||||
Q4 2013
|
0
|
-
|
||||||||
Total 2013
|
0
|
$
|
-
|
1,050
|
0%
|
|||||
Total 2014
|
0
|
$
|
-
|
|||||||
Total 2015
|
0
|
$
|
-
|
|||||||
Total 2016 – 2020
|
193
|
$
|
9.92
|
Volume (bcf)
|
Avg. NYMEX less
|
||||
Q1 2013
|
11
|
$
|
0.21
|
||
Q2 2013
|
11
|
0.21
|
|||
Q3 2013
|
11
|
0.21
|
|||
Q4 2013
|
11
|
0.21
|
|||
Total 2013
|
44
|
$
|
0.21
|
||
Total 2014
|
28
|
$
|
0.32
|
||
Total 2015
|
31
|
$
|
0.34
|
||
Total 2016-2022
|
8
|
$
|
1.02
|
||
Open
Swaps
(mbbls)
|
Avg. NYMEX
Price of
Open Swaps
|
Forecasted
Oil
Production
(mbbls)
|
Open Swap
Positions as
a % of
Forecasted
Oil
Production
|
Total Gains
(Losses) from
Closed Trades
and Premiums for Call Options
($ in millions)
|
Total Gains
(Losses) from
Closed Trades
and Premiums for
Call Options per
bbl of Forecasted
Oil
Production
|
|||||||||||||
Q1 2013
|
6,401
|
$
|
95.52
|
$
|
1
|
|||||||||||||
Q2 2013
|
7,935
|
95.56
|
1
|
|||||||||||||||
Q3 2013
|
8,451
|
95.42
|
2
|
|||||||||||||||
Q4 2013
|
8,796
|
95.33
|
2
|
|||||||||||||||
Total 2013
|
31,583
|
$
|
95.45
|
37,000
|
85%
|
$
|
6
|
$
|
0.17
|
|||||||||
Total 2014
|
18,073
|
$
|
93.67
|
$
|
(151
|
)
|
||||||||||||
Total 2015
|
500
|
$
|
88.75
|
$
|
265
|
|||||||||||||
Total 2016 – 2022
|
0
|
$
|
-
|
$
|
117
|
Call Options
(mbbls)
|
Avg. NYMEX
Strike Price
|
Forecasted
Oil
Production
(mbbls)
|
Call Options
as a % of
Forecasted Oil
Production
|
|||||||
Q1 2013
|
2,125
|
$
|
98.09
|
|||||||
Q2 2013
|
1,954
|
97.90
|
||||||||
Q3 2013
|
1,975
|
97.90
|
||||||||
Q4 2013
|
1,975
|
97.90
|
||||||||
Total 2013
|
8,029
|
$
|
97.95
|
37,000
|
22%
|
|||||
Total 2014
|
17,612
|
$
|
98.79
|
|||||||
Total 2015
|
27,048
|
$
|
100.99
|
|||||||
Total 2016 – 2017
|
24,220
|
$
|
100.07
|
Volume (mbbls)
|
Avg. NYMEX plus
|
||||
Q1 2013
|
2,340
|
$
|
15.09
|
||
Q2 2013
|
2,457
|
12.34
|
|||
Q3 2013
|
736
|
10.07
|
|||
Q4 2013
|
0
|
-
|
|||
Total 2013
|
5,533
|
$
|
13.20
|
Year Ending
12/31/12
|
Year Ending
12/31/13
|
|||||
Estimated Production:
|
||||||
Natural gas – bcf
|
1,120 – 1,140
|
1,030 – 1,070
|
||||
Oil – mbbls
|
30,000 – 31,000
|
36,000 – 38,000
|
||||
NGL – mbbls
|
17,000 – 18,000
|
24,000 – 26,000
|
||||
Natural gas equivalent – bcfe
|
1,402 – 1,434
|
1,390 – 1,454
|
||||
Daily natural gas equivalent midpoint – mmcfe
|
3,870
|
3,895
|
||||
YOY estimated production increase (adjusted for planned asset sales)
|
18%
|
1%
|
||||
NYMEX Price(a) (for calculation of realized hedging effects only):
|
||||||
Natural gas - $/mcf
|
$2.77
|
$4.00
|
||||
Oil - $/bbl
|
$94.66
|
$90.00
|
||||
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
|
||||||
Natural gas - $/mcf
|
$0.30
|
$0.00
|
||||
Oil - $/bbl
|
$0.99
|
$4.50
|
||||
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
|
||||||
Natural gas - $/mcf
|
$1.00 –1.10
|
$1.15 – 1.25
|
||||
Oil - $/bbl
|
$4.50 – 6.50
|
$4.50 – 6.50
|
||||
NGL - $/bbl
|
$67.00 – 70.00
|
$63.00 – 67.00
|
||||
Operating Costs per Mcfe of Projected Production:
|
||||||
Production expense
|
$0.90 – 1.00
|
$0.90 – 1.00
|
||||
Production taxes (~5% of O&G revenues)
|
$0.15 – 0.20
|
$0.25 – 0.30
|
||||
General and administrative(b)
|
$0.39 – 0.44
|
$0.39 – 0.44
|
||||
Stock-based compensation (noncash)
|
$0.04 – 0.06
|
$0.04 – 0.06
|
||||
DD&A of natural gas and liquids assets
|
$1.65 – 1.85
|
$1.65 – 1.85
|
||||
Depreciation of other assets
|
$0.22 – 0.27
|
$0.25 – 0.30
|
||||
Interest expense(c)
|
$0.05 – 0.10
|
$0.05 – 0.10
|
||||
Other ($ millions):
|
||||||
Marketing, gathering and compression net margin(d)
|
$90 – 100
|
$50 – 75
|
||||
Oilfield services net margin(d)
|
$175 – 200
|
$200 – 250
|
||||
Other income (including certain equity investments)
|
$25
|
–
|
||||
Net income attributable to noncontrolling interest(e)
|
($180) – (200)
|
($200) – (240)
|
||||
Book Tax Rate
|
39%
|
39%
|
||||
Weighted average shares outstanding (in millions):
|
||||||
Basic
|
640 – 645
|
645 – 650
|
||||
Diluted
|
753 – 758
|
758 – 763
|
||||
Operating cash flow before changes in assets and liabilities(f)(g)
|
$3,800
|
$4,250 – 5,250
|
||||
Well costs on proved and unproved properties
|
($8,750)
|
($5,750 – 6,250)
|
||||
Acquisition of unproved properties, net
|
($1,750)
|
($400)
|
a)
|
NYMEX natural gas and oil prices have been updated for actual contract prices through October and September, respectively.
|
b)
|
Excludes expenses associated with noncash stock-based compensation.
|
c)
|
Does not include unrealized gains or losses on interest rate derivatives.
|
d)
|
Includes revenue and operating costs and excludes depreciation and amortization of other assets.
|
e)
|
Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica, L.L.C., CHK Cleveland Tonkawa, L.L.C. and Cardinal Gas Services, L.L.C.
|
f)
|
A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.
|
g)
|
Assumes NYMEX prices on open contracts of $3.50 per mcf and $90.00 per bbl in 2012 and $3.50 to $4.50 per mcf and $90.00 per bbl in 2013.
|
|
Open Swaps
(bcf)
|
Avg. NYMEX
Price of
Open Swaps
|
Forecasted
Natural Gas
Production
(bcf)
|
Open Swap
Positions
as a % of
Forecasted
Natural Gas
Production
|
Total Gains
(Losses) from
Closed Trades
and Premiums
for Call Options
($ in millions)
|
Total Gains from
Closed Trades
and Premiums
for Call Options
per mcf of
Forecasted
Natural Gas
Production
|
||||||||||||
Q4 2012
|
215
|
$
|
3.06
|
281
|
76%
|
$
|
15
|
$
|
0.05
|
|||||||||
Q1 2013
|
0
|
$
|
(11
|
)
|
||||||||||||||
Q2 2013
|
0
|
8
|
||||||||||||||||
Q3 2013
|
0
|
6
|
||||||||||||||||
Q4 2013
|
0
|
(3
|
)
|
|||||||||||||||
Total 2013
|
0
|
$
|
0.00
|
1,050
|
0%
|
$
|
0
|
$
|
0.00
|
|||||||||
Total 2014
|
0
|
$
|
(74
|
)
|
||||||||||||||
Total 2015
|
0
|
$
|
(131
|
)
|
||||||||||||||
Total 2016 – 2022
|
0
|
$
|
(161
|
)
|
Call Options
(bcf)
|
Avg. NYMEX
Strike Price
|
Forecasted
Natural Gas
Production
(bcf)
|
Call Options
as a % of
Forecasted
Natural Gas
Production
|
|||||||
Q4 2012
|
40
|
$
|
3.25
|
281
|
14%
|
|||||
Total 2013
|
0
|
$
|
0.00
|
1,050
|
0%
|
|||||
Total 2014
|
0
|
$
|
0.00
|
|||||||
Total 2015
|
0
|
$
|
0.00
|
|||||||
Total 2016 – 2020
|
260
|
$
|
8.90
|
Put Swaptions
(bcf)
|
Avg. NYMEX
Price of Swap
|
Forecasted
Natural Gas
Production
(bcf)
|
Put Swaption
as a % of
Forecasted
Natural Gas
Production
|
|||||||
Q1 2013
|
8
|
$
|
3.66
|
|||||||
Q2 2013
|
10
|
$
|
3.64
|
|||||||
Q3 2013
|
2
|
$
|
3.50
|
|||||||
Q4 2013
|
0
|
$
|
0.00
|
|||||||
Total 2013
|
20
|
$
|
3.64
|
1,050
|
2%
|
Volume (Bcf)
|
Avg. NYMEX less
|
||||
Q4 2012
|
8
|
$
|
0.74
|
||
2013
|
44
|
$
|
0.21
|
||
2014
|
28
|
$
|
0.32
|
||
2015 - 2022
|
40
|
$
|
0.48
|
Open
Swaps
(mbbls)
|
Avg. NYMEX
Price of
Open Swaps
|
Forecasted
Oil
Production
(mbbls)
|
Open Swap
Positions as
a % of
Forecasted
Oil
Production
|
Total Gains
(Losses) from
Closed Trades
and Premiums
for Call Options
($ in millions)
|
Total Gains
(Losses) from
Closed Trades
and Premiums for
Call Options per
bbl of Forecasted
Oil
Production
|
||||||||||||||
Q4 2012
|
6,197
|
$
|
99.14
|
8,171
|
76%
|
$
|
(31
|
)
|
$
|
(3.83
|
)
|
||||||||
Q1 2013
|
5,647
|
95.95
|
$
|
1
|
|||||||||||||||
Q2 2013
|
6,672
|
96.10
|
$
|
1
|
|||||||||||||||
Q3 2013
|
6,687
|
96.02
|
$
|
2
|
|||||||||||||||
Q4 2013
|
6,662
|
95.97
|
$
|
2
|
|||||||||||||||
Total 2013
|
25,668
|
$
|
96.01
|
37,000
|
69%
|
$
|
6
|
$
|
0.17
|
||||||||||
Total 2014
|
918
|
$
|
90.85
|
$
|
(151
|
)
|
|||||||||||||
Total 2015
|
500
|
$
|
88.75
|
$
|
265
|
||||||||||||||
Total 2016 – 2021
|
0
|
$
|
117
|
Call Options
(mbbls)
|
Avg. NYMEX
Strike Price
|
Forecasted
Oil
Production
(mbbls)
|
Call Options
as a % of
Forecasted Oil
Production
|
||||||||
Q4 2012
|
0
|
$
|
--
|
8,171
|
0%
|
||||||
Q1 2013
|
3,390
|
$
|
99.56
|
||||||||
Q2 2013
|
3,428
|
$
|
99.56
|
||||||||
Q3 2013
|
3,006
|
$
|
98.62
|
||||||||
Q4 2013
|
3,006
|
$
|
98.62
|
||||||||
Total 2013
|
12,830
|
$
|
99.12
|
37,000
|
35%
|
||||||
Total 2014
|
17,612
|
$
|
98.79
|
||||||||
Total 2015
|
27,048
|
$
|
100.99
|
||||||||
Total 2016 – 2017
|
24,220
|
$
|
100.07
|
Volume (mbbls)
|
Avg. NYMEX plus
|
|||||
Q4 2012
|
951
|
$
|
17.70
|
|||
Q1 2013
|
2,070
|
$
|
14.99
|
|||
Q2 2013
|
1,365
|
$
|
12.55
|
|||
Total 2013
|
3,435
|
$
|
14.02
|