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 November 1, 2012 – Financial and operational results and updated outlook
|
||
News Release
|
![]() |
FOR IMMEDIATE RELEASE
|
|
NOVEMBER 1, 2012
|
·
|
a noncash after-tax impairment charge of $2.022 billion related to the carrying value of natural gas and oil properties (primarily resulting from a 10% decrease in trailing 12-month average first-day-of-the-month natural gas prices as of September 30, 2012, compared to June 30, 2012, and the impairment of certain undeveloped leasehold, primarily in the Williston and DJ Basins);
|
·
|
an unrealized noncash after-tax mark-to-market loss of $63 million resulting from the company’s natural gas, oil and natural gas liquids (NGL) and interest rate hedging programs;
|
·
|
an after-tax charge of $28 million related to losses on sales and impairments of certain fixed assets and other; and
|
·
|
a net after-tax gain of $19 million related to the sale of an investment.
|
CHESAPEAKE CONTACTS:
|
MEDIA CONTACTS:
|
CHESAPEAKE ENERGY CORPORATION
|
||||||
Jeffrey L. Mobley, CFA
|
John J. Kilgallon
|
Michael Kehs
|
Jim Gipson
|
6100 North Western Avenue
|
||||
(405) 767-4763
|
(405) 935-4441
|
(405) 935-2560
|
(405) 935-1310
|
P.O. Box 18496
|
||||
jeff.mobley@chk.com
|
john.kilgallon@chk.com
|
michael.kehs@chk.com
|
jim.gipson@chk.com
|
Oklahoma City, OK 73154
|
Three Months Ended
|
||||||
9/30/12
|
6/30/12
|
9/30/11
|
||||
Average daily production (in mmcfe)(a)
|
4,142
|
3,808
|
3,329
|
|||
Natural gas equivalent production (in bcfe)
|
381
|
347
|
306
|
|||
Natural gas equivalent realized price ($/mcfe)(b)
|
4.04
|
3.77
|
5.78
|
|||
Oil production (in mbbls)
|
8,996
|
7,325
|
4,589
|
|||
Average realized oil price ($/bbl)(b)
|
90.79
|
91.58
|
82.47
|
|||
Oil as % of total production
|
14
|
13
|
9
|
|||
NGL production (in mbbls)
|
4,130
|
4,525
|
4,080
|
|||
Average realized NGL price ($/bbl)(b)
|
31.22
|
25.94
|
41.16
|
|||
NGL as % of total production
|
7
|
8
|
8
|
|||
Liquids as % of realized revenue(c)
|
61
|
60
|
31
|
|||
Liquids as % of unhedged revenue(c)
|
63
|
70
|
40
|
|||
Natural gas production (in bcf)
|
302
|
275
|
254
|
|||
Average realized natural gas price ($/mcf)(b)
|
1.97
|
1.88
|
4.82
|
|||
Natural gas as % of total production
|
79
|
79
|
83
|
|||
Natural gas as % of realized revenue
|
39
|
40
|
69
|
|||
Natural gas as % of unhedged revenue
|
37
|
30
|
60
|
|||
Marketing, gathering and compression net margin ($/mcfe)(d)
|
0.11
|
0.05
|
0.10
|
|||
Oilfield services net margin ($/mcfe)(d)
|
0.09
|
0.14
|
0.11
|
|||
Production expenses ($/mcfe)
|
(0.84)
|
(0.97)
|
(0.92)
|
|
||
Production taxes ($/mcfe)
|
(0.14)
|
(0.12)
|
(0.16)
|
|
||
General and administrative costs ($/mcfe)(e)
|
(0.34)
|
(0.39)
|
(0.41)
|
|
||
Stock-based compensation ($/mcfe)
|
(0.05)
|
(0.06)
|
(0.08)
|
|
||
DD&A of natural gas and liquids properties ($/mcfe)(f)
|
(2.00)
|
(1.70)
|
(1.38)
|
|
||
D&A of other assets ($/mcfe)(g)
|
(0.17)
|
(0.24)
|
(0.24)
|
|
||
Interest expense ($/mcfe)(b)
|
(0.10)
|
(0.06)
|
(0.01)
|
|
||
Operating cash flow ($ in millions)(h)
|
1,118
|
895
|
1,409
|
|||
Operating cash flow ($/mcfe)
|
2.93
|
2.58
|
4.60
|
|||
Adjusted ebitda ($ in millions)(i)
|
1,021
|
803
|
1,385
|
|||
Adjusted ebitda ($/mcfe)
|
2.68
|
2.32
|
4.52
|
|||
Net income (loss) to common stockholders ($ in millions)
|
(2,055)
|
929
|
879
|
|||
Earnings (loss) per share – diluted ($)
|
(3.19)
|
1.29
|
1.23
|
|||
Adjusted net income to common stockholders ($ in millions)(j)
|
33
|
3
|
496
|
|||
Adjusted earnings per share – diluted ($)
|
0.10
|
0.06
|
0.72
|
|||
(a)
|
Includes the effect of VPP #10 sale in March 2012 (which had an average production loss impact of approximately 100 mmcfe and 115 mmcfe per day in the 2012 third and second quarters, respectively). Also includes the effect of net natural gas production curtailments of approximately 30 bcf in the 2012 second quarter, or an average of approximately 330 mmcf per day.
|
(b)
|
Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging.
|
(c)
|
“Liquids” includes both oil and NGL.
|
(d)
|
Includes revenue and operating costs and excludes depreciation and amortization of other assets.
|
(e)
|
Excludes expenses associated with noncash stock-based compensation.
|
(f)
|
Increase from 2012 second quarter due to an increase in the amortizable base resulting from leasehold impairments and expirations in addition to a further decrease in estimated proved reserves resulting from lower natural gas prices.
|
(g)
|
Decrease from 2012 second quarter due to approximately $2.4 billion of fixed assets held for sale throughout the 2012 third quarter. Assets classified as held for sale are not subject to depreciation.
|
(h)
|
Defined as cash flow provided by operating activities before changes in assets and liabilities.
|
(i)
|
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 21.
|
(j)
|
Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 22.
|
Natural Gas
|
Oil
|
|||||||
Year
|
% of Forecasted
Production
|
NYMEX
Natural Gas
|
% of Forecasted
Production
|
NYMEX
Oil WTI
|
||||
4Q 2012
|
76%
|
$3.06
|
76%
|
$99.14
|
||||
2013
|
—
|
—
|
69%
|
$96.01
|
Pricing Method
|
Natural Gas
Price
($/mcf)
|
Oil Price
($/bbl)
|
Proved
Reserves
(tcfe)
|
PV-10
(billions)
|
Proved
Developed
Percentage
|
Trailing 12-month avg (SEC)(a)
|
$2.83
|
$95.05
|
16.2
|
$18.5
|
59%
|
9/30/12 10-year avg NYMEX strip(b)
|
$4.80
|
$88.58
|
22.2
|
$29.5
|
52%
|
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 September 30, 2012. This pricing 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 Faith-Yana A Unit C1H in Dimmit County, TX achieved a peak rate of approximately 2,175 boe per day, consisting of 1,580 bbls of oil, 295 bbls of NGL and 1.8 mmcf of natural gas per day;
|
·
|
The Gates 010-CHK-B 1286-D3H in Webb County, TX achieved a peak rate of approximately 2,100 boe per day, consisting of 660 bbls of oil, 655 bbls of NGL and 4.7 mmcf of natural gas per day; and
|
·
|
The Shining Star Ranch B 1H in La Salle County, TX achieved a peak rate of approximately 1,580 boe per day, consisting of 1,450 bbls of oil, 80 bbls of NGL and 0.3 mmcf of natural gas per day.
|
·
|
The Houyouse 15-13-5 8H in Carroll County, OH achieved a peak rate of approximately 1,735 boe per day, consisting of 465 bbls of oil, 335 bbls of NGL and 5.6 mmcf of natural gas per day;
|
·
|
The White 17-13-5 8H in Carroll County, OH achieved a peak rate of approximately 1,360 boe per day, consisting of 390 bbls of oil, 285 bbls of NGL and 4.1 mmcf of natural gas per day; and
|
·
|
The Stuart Henderson 11-12-6 1H in Harrison County, OH achieved a peak rate of approximately 825 boe per day, consisting of 410 bbls of oil, 100 bbls of NGL and 1.9 mmcf of natural gas per day.
|
·
|
The Linski S Bra 4H in Bradford County, PA achieved a peak rate of 8.4 mmcf of natural gas per day;
|
·
|
The Folta N Bra 2H in Bradford County, PA achieved a peak rate of 8.4 mmcf of natural gas per day; and
|
·
|
The Champluvier 2H in Bradford County, PA achieved a peak rate of 8.3 mmcf of natural gas per day.
|
·
|
The Roy Ferrell 8H in Ohio County, WV achieved an initial test rate of approximately 1,525 boe per day, consisting of 5.3 mmcf of natural gas, 220 bbls of oil and 430 bbls of NGL per day;
|
·
|
The Deborah Craig 3H in Ohio County, WV achieved an initial test rate of approximately 830 boe per day, consisting of 2.6 mmcf of natural gas, 200 bbls of oil and 205 bbls of NGL per day; and
|
·
|
The George Gantzer 8H in Ohio County, WV achieved an initial test rate of approximately 800 boe per day, consisting of 2.7 mmcf of natural gas, 130 bbls of oil and 220 bbls of NGL per day.
|
·
|
The Herold 3-28-15 1H in Woods County, OK achieved a peak rate of approximately 2,025 boe per day, which included 1,740 bbls of oil, 100 bbls of NGL and 1.1 mmcf of natural gas per day;
|
·
|
The Rauh 3-26-12 1H in Alfalfa County, OK achieved a peak rate of approximately 2,020 boe per day, which included 1,210 bbls of oil, 225 bbls of NGL and 3.5 mmcf of natural gas per day; and
|
·
|
The Hada Land & Cattle 3-28-15 1H in Woods County, OK achieved a peak rate of approximately 1,405 boe per day, which included 1,150 bbls of oil, 90 bbls of NGL and 1.0 mmcf of natural gas per day.
|
·
|
The Sloan HMH 1H in Hemphill County, TX achieved a peak rate of approximately 1,345 boe per day, which included 360 bbls of oil, 400 bbls of NGL and 3.5 mmcf of natural gas per day;
|
·
|
The Larry Imke 9-19-25 1H in Ellis County, OK achieved a peak rate of approximately 1,035 boe per day, which included 640 bbls of oil, 145 bbls of NGL and 1.5 mmcf of natural gas per day; and
|
·
|
The Mathers 131 HMH 1H in Hemphill County, TX achieved a peak rate of approximately 920 boe per day, which included 745 bbls of oil, 75 bbls of NGL and 0.6 mmcf of natural gas per day.
|
·
|
The Fariss 2-16-20 1H in Dewey County, OK achieved a peak rate of approximately 775 boe per day, which included 680 bbls of oil, 30 bbls of NGL and 0.4 mmcf of natural gas per day;
|
·
|
The Mike 11-15-22 1H in Roger Mills County, OK achieved a peak rate of approximately 735 boe per day, which included 665 bbls of oil, 20 bbls of NGL and 0.3 mmcf of natural gas per day; and
|
·
|
The Shrewder 8-16-22 1H in Ellis County, OK achieved a peak rate of approximately 595 boe per day, which included 480 bbls of oil, 30 bbls of NGL and 0.5 mmcf of natural gas per day.
|
·
|
The Davis 65 21H in Wheeler County, TX achieved a peak rate of approximately 3,765 boe per day, which included 765 bbls of oil, 1,230 bbls of NGL and 10.6 mmcf of natural gas per day;
|
·
|
The Clarence B 21-11-26 1H in Beckham County, OK achieved a peak rate of approximately 2,305 boe per day, which included 750 bbls of oil, 490 bbls of NGL and 6.4 mmcf of natural gas per day; and
|
·
|
The Ervin 17-11-17 2H in Washita County, OK achieved a peak rate of approximately 1,790 boe per day, which included 460 bbls of oil, 495 bbls of NGL and 5.0 mmcf of natural gas per day.
|
·
|
The Hannah-Roy Trust 17-11-20 1H in Washita County, OK achieved a peak rate of approximately 2,285 boe per day, which included 1,665 bbls of oil, 215 bbls of NGL and 2.4 mmcf of natural gas per day;
|
·
|
The D E Atherton 5057H in Wheeler County, TX achieved a peak rate of approximately 2,280 boe per day, which included 1,710 bbls of oil, 220 bbls of NGL and 2.1 mmcf of natural gas per day; and
|
·
|
The Wheeler 10-11-231H in Roger Mills County, OK achieved a peak rate of approximately 1,120 boe per day, which included 1,005 bbls of oil, 45 bbls of NGL and 0.4 mmcf of natural gas per day.
|
·
|
The Wallis 23-33-71 A 3H in Converse County, WY achieved a peak rate of approximately 1,990 boe per day, which included 1,105 bbls of oil, 385 bbls of NGL and 3.0 mmcf of natural gas per day;
|
·
|
The York Ranch 26-33-70 A 1H in Converse County, WY achieved a peak rate of approximately 1,750 boe per day, which included 745 bbls of oil, 440 bbls of NGL and 3.4 mmcf of natural gas per day; and
|
·
|
The Clausen Ranch 25-34-71 ST A 1H in Converse County, WY achieved a peak rate of approximately 1,720 boe per day, which included 1,075 bbls of oil, 280 bbls of NGL and 2.2 mmcf of natural gas per day.
|
September 30,
2012
|
September 30,
2011
|
|||||||||||
THREE MONTHS ENDED:
|
||||||||||||
$
|
$/mcfe
|
$
|
$/mcfe
|
|||||||||
REVENUES:
|
||||||||||||
Natural gas, oil and NGL
|
1,437
|
3.77
|
2,402
|
7.84
|
||||||||
Marketing, gathering and compression
|
1,381
|
3.62
|
1,422
|
4.64
|
||||||||
Oilfield services
|
152
|
0.40
|
153
|
0.50
|
||||||||
Total Revenues
|
2,970
|
7.79
|
3,977
|
12.98
|
||||||||
OPERATING EXPENSES:
|
||||||||||||
Natural gas, oil and NGL production
|
320
|
0.84
|
282
|
0.92
|
||||||||
Production taxes
|
53
|
0.14
|
50
|
0.16
|
||||||||
Marketing, gathering and compression
|
1,339
|
3.51
|
1,392
|
4.55
|
||||||||
Oilfield services
|
116
|
0.30
|
118
|
0.39
|
||||||||
General and administrative
|
148
|
0.39
|
151
|
0.49
|
||||||||
Natural gas, oil and NGL depreciation, depletion and amortization
|
762
|
2.00
|
423
|
1.38
|
||||||||
Depreciation and amortization of other assets
|
66
|
0.17
|
75
|
0.24
|
||||||||
Impairment of natural gas and oil properties
|
3,315
|
8.70
|
—
|
—
|
||||||||
Losses on sales and impairments of fixed assets and other
|
45
|
0.12
|
3
|
0.01
|
||||||||
Total Operating Expenses
|
6,164
|
16.17
|
2,494
|
8.14
|
||||||||
INCOME (LOSS) FROM OPERATIONS
|
(3,194)
|
|
(8.38)
|
|
1,483
|
4.84
|
||||||
OTHER INCOME (EXPENSE):
|
||||||||||||
Interest expense
|
(36)
|
|
(0.10)
|
|
(4)
|
|
(0.01)
|
|
||||
Earnings (losses) on investments
|
(23)
|
|
(0.06)
|
|
28
|
0.09
|
||||||
Gain on sale of investment
|
31
|
0.08
|
—
|
—
|
||||||||
Other income
|
(9)
|
|
(0.02)
|
|
4
|
0.01
|
||||||
Total Other Income (Expense)
|
(37)
|
|
(0.10)
|
|
28
|
0.09
|
||||||
INCOME (LOSS) BEFORE INCOME TAXES
|
(3,231)
|
|
(8.48)
|
|
1,511
|
4.93
|
||||||
INCOME TAX EXPENSE (BENEFIT):
|
||||||||||||
Current income taxes
|
22
|
0.05
|
(1)
|
|
—
|
|||||||
Deferred income taxes
|
(1,282)
|
|
(3.36)
|
|
590
|
1.92
|
||||||
Total Income Tax Expense (Benefit)
|
(1,260)
|
|
(3.31)
|
|
589
|
1.92
|
||||||
NET INCOME (LOSS)
|
(1,971)
|
|
(5.17)
|
|
922
|
3.01
|
||||||
Net income attributable to noncontrolling interests
|
(41)
|
|
(0.11)
|
|
—
|
—
|
||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
|
(2,012)
|
|
(5.28)
|
|
922
|
3.01
|
||||||
Preferred stock dividends
|
(43)
|
|
(0.11)
|
|
(43)
|
|
(0.14)
|
|
||||
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
|
(2,055)
|
|
(5.39)
|
|
879
|
2.87
|
||||||
EARNINGS (LOSS) PER COMMON SHARE:
|
||||||||||||
Basic
|
$
|
(3.19)
|
|
$
|
1.38
|
|||||||
Diluted
|
$
|
(3.19)
|
|
$
|
1.23
|
|||||||
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
|
||||||||||||
Basic
|
644
|
638
|
||||||||||
Diluted
|
644
|
753
|
September 30,
2012
|
September 30,
2011
|
|||||||||||
NINE MONTHS ENDED:
|
||||||||||||
$
|
$/mcfe
|
$
|
$/mcfe
|
|||||||||
REVENUES:
|
||||||||||||
Natural gas, oil and NGL
|
4,622
|
4.36
|
4,688
|
5.43
|
||||||||
Marketing, gathering and compression
|
3,710
|
3.50
|
3,844
|
4.45
|
||||||||
Oilfield services
|
446
|
0.42
|
376
|
0.44
|
||||||||
Total Revenues
|
8,778
|
8.28
|
8,908
|
10.32
|
||||||||
OPERATING EXPENSES:
|
||||||||||||
Natural gas, oil and NGL production
|
1,005
|
0.95
|
782
|
0.91
|
||||||||
Production taxes
|
141
|
0.13
|
140
|
0.16
|
||||||||
Marketing, gathering and compression
|
3,631
|
3.43
|
3,744
|
4.34
|
||||||||
Oilfield services
|
321
|
0.30
|
287
|
0.33
|
||||||||
General and administrative
|
440
|
0.41
|
410
|
0.47
|
||||||||
Natural gas, oil and NGL depreciation, depletion and amortization
|
1,856
|
1.75
|
1,147
|
1.33
|
||||||||
Depreciation and amortization of other assets
|
233
|
0.22
|
206
|
0.24
|
||||||||
Impairment of natural gas and oil properties
|
3,315
|
3.13
|
—
|
—
|
||||||||
Losses on sales and impairments of fixed assets and other
|
286
|
0.27
|
7
|
0.01
|
||||||||
Total Operating Expenses
|
11,228
|
10.59
|
6,723
|
7.79
|
||||||||
INCOME (LOSS) FROM OPERATIONS
|
(2,450)
|
|
(2.31)
|
|
2,185
|
2.53
|
||||||
OTHER INCOME (EXPENSE):
|
||||||||||||
Interest expense
|
(63)
|
|
(0.06)
|
|
(37)
|
|
(0.04)
|
|
||||
Earnings (losses) on investments
|
(87)
|
|
(0.08)
|
|
100
|
0.11
|
||||||
Gain on sales of investments
|
1,061
|
1.00
|
—
|
—
|
||||||||
Losses on purchases or exchanges of debt
|
—
|
—
|
(176)
|
|
(0.20)
|
|
||||||
Other income
|
2
|
—
|
9
|
0.01
|
||||||||
Total Other Income (Expense)
|
913
|
0.86
|
(104)
|
|
(0.12)
|
|
||||||
INCOME (LOSS) BEFORE INCOME TAXES
|
(1,537)
|
|
(1.45)
|
|
2,081
|
2.41
|
||||||
INCOME TAX EXPENSE (BENEFIT):
|
||||||||||||
Current income taxes
|
24
|
0.02
|
11
|
0.01
|
||||||||
Deferred income taxes
|
(623)
|
|
(0.59)
|
|
801
|
0.93
|
||||||
Total Income Tax Expense (Benefit)
|
(599)
|
|
(0.57)
|
|
812
|
0.94
|
||||||
NET INCOME (LOSS)
|
(938)
|
|
(0.88)
|
|
1,269
|
1.47
|
||||||
Net income attributable to noncontrolling interests
|
(131)
|
|
(0.13)
|
|
—
|
—
|
||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
|
(1,069
|
)
|
(1.01)
|
|
1,269
|
1.47
|
||||||
Preferred stock dividends
|
(128)
|
|
(0.12)
|
|
(128)
|
|
(0.15)
|
|
||||
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
|
(1,197)
|
|
(1.13)
|
|
1,141
|
1.32
|
||||||
EARNINGS (LOSS) PER COMMON SHARE:
|
||||||||||||
Basic
|
$
|
(1.86)
|
|
$
|
1.79
|
|||||||
Diluted
|
$
|
(1.86)
|
|
$
|
1.69
|
|||||||
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
|
||||||||||||
Basic
|
643
|
636
|
||||||||||
Diluted
|
643
|
752
|
September 30,
|
December 31,
|
|||||
2012
|
2011
|
|||||
Cash and cash equivalents
|
$
|
142
|
$
|
351
|
||
Other current assets
|
3,469
|
2,826
|
||||
Total Current Assets
|
3,611
|
3,177
|
||||
Property and equipment (net)
|
40,603
|
36,739
|
||||
Other assets
|
1,457
|
1,919
|
||||
Total Assets
|
$
|
45,671
|
$
|
41,835
|
||
Current liabilities
|
$
|
6,456
|
$
|
7,082
|
||
Long-term debt, net of discounts
|
15,755
|
10,626
|
||||
Other long-term liabilities
|
2,351
|
2,682
|
||||
Deferred income tax liabilities
|
3,418
|
3,484
|
||||
Total Liabilities
|
27,980
|
23,874
|
||||
Chesapeake stockholders' equity
|
15,327
|
16,624
|
||||
Noncontrolling interests
|
2,364
|
1,337
|
||||
Total Equity
|
17,691
|
17,961
|
||||
Total Liabilities and Equity
|
$
|
45,671
|
$
|
41,835
|
||
Common Shares Outstanding (in millions)
|
665
|
659
|
September 30,
|
December 31,
|
|||||
2012
|
2011
|
|||||
Total debt, net of unrestricted cash
|
$
|
16,076
|
$
|
10,275
|
||
Chesapeake stockholders' equity
|
15,327
|
16,624
|
||||
Noncontrolling interests(a)
|
2,364
|
1,337
|
||||
Total
|
$
|
33,767
|
$
|
28,236
|
||
Debt to capitalization ratio
|
48
|
%
|
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
|
365
|
380
|
||||
Cardinal Gas Services, L.L.C.
|
34
|
7
|
||||
Total
|
$
|
2,364
|
$
|
1,337
|
Proved Reserves
|
||||||||||||
Cost
|
Bcfe(a)
|
$/Mcfe
|
||||||||||
PROVED PROPERTIES:
|
||||||||||||
Well costs on proved properties (b) (c)
|
$
|
7,430
|
3,878
|
(d)
|
1.92
|
|||||||
Acquisition of proved properties(e)
|
319
|
37
|
8.67
|
|||||||||
Sale of proved properties
|
(1,322)
|
|
(544)
|
|
2.43
|
|||||||
Total net proved properties
|
6,427
|
3,371
|
1.91
|
|||||||||
Revisions – price
|
—
|
(4,878)
|
|
—
|
||||||||
UNPROVED PROPERTIES:
|
||||||||||||
Well costs on unproved properties(f)
|
(195)
|
|
—
|
—
|
||||||||
Acquisition of unproved properties, net(g)
|
1,628
|
—
|
—
|
|||||||||
Sale of unproved properties
|
(930)
|
|
—
|
—
|
||||||||
Total net unproved properties
|
503
|
—
|
—
|
|||||||||
OTHER:
|
||||||||||||
Capitalized interest on unproved properties
|
766
|
—
|
—
|
|||||||||
Geological and geophysical costs
|
148
|
—
|
—
|
|||||||||
Asset retirement obligations
|
16
|
—
|
—
|
|||||||||
Total other
|
930
|
—
|
—
|
|||||||||
Total
|
$
|
7,860
|
(1,507)
|
|
—
|
Bcfe(a)
|
||||
Beginning balance, January 1, 2012
|
18,789
|
|||
Production
|
(1,060)
|
|
||
Acquisitions
|
37
|
|||
Divestitures
|
(544)
|
|
||
Revisions – changes to previous estimates
|
(596)
|
|
||
Revisions – price
|
(4,878)
|
|
||
Extensions and discoveries
|
4,474
|
|||
Ending balance, September 30, 2012
|
16,222
|
|||
Proved reserves decline rate before acquisitions and divestitures
|
(11)
|
%
|
||
Proved reserves decline rate after acquisitions and divestitures
|
(14)
|
%
|
||
Proved developed reserves
|
9,608
|
|||
Proved developed reserves percentage
|
59
|
%
|
||
PV-10 ($ in billions)(a)
|
$
|
18,451
|
(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 September 30, 2012 of $2.83 per mcf of natural gas and $95.05 per bbl of oil, before field differential adjustments.
|
(b)
|
Net of well cost carries of $655 million associated with the Statoil-Marcellus, CNOOC-Eagle Ford, CNOOC-Niobrara and Total-Utica joint ventures.
|
(c)
|
Includes $1.055 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 596 bcfe of downward revisions resulting from changes to previous estimates and excludes downward revisions of 4.9 tcfe primarily resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended September 30, 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 $860 million of well costs on unproved properties incurred in the current quarter, offset by the transfer of $1.055 billion previously classified as well costs on unproved properties that were evaluated for the existence of proved reserves in the current quarter. See footnote (e).
|
(g)
|
Net of joint venture partner reimbursements.
|
Three Months Ended
|
Nine Months Ended
|
|||||||||||
September 30,
|
September 30,
|
|||||||||||
2012
|
2011
|
2012
|
2011
|
|||||||||
Natural Gas, Oil and NGL Sales ($ in millions):
|
||||||||||||
Natural gas sales
|
$
|
543
|
$
|
861
|
$
|
1,359
|
$
|
2,412
|
||||
Natural gas derivatives – realized gains (losses)
|
52
|
364
|
391
|
1,322
|
||||||||
Natural gas derivatives – unrealized gains (losses)
|
(90)
|
|
(28)
|
|
(401)
|
|
(693)
|
|
||||
Total Natural Gas Sales
|
505
|
1,197
|
1,349
|
3,041
|
||||||||
Oil sales
|
792
|
386
|
2,038
|
1,048
|
||||||||
Oil derivatives – realized gains (losses)
|
25
|
(8)
|
|
6
|
(51)
|
|
||||||
Oil derivatives – unrealized gains (losses)
|
(14)
|
|
645
|
803
|
247
|
|||||||
Total Oil Sales
|
803
|
1,023
|
2,847
|
1,244
|
||||||||
NGL sales
|
129
|
180
|
401
|
432
|
||||||||
NGL derivatives – realized gains (losses)
|
—
|
(12)
|
|
(9)
|
|
(31)
|
|
|||||
NGL derivatives – unrealized gains (losses)
|
—
|
14
|
34
|
2
|
||||||||
Total NGL Sales
|
129
|
182
|
426
|
403
|
||||||||
Total Natural Gas, Oil and NGL Sales
|
$
|
1,437
|
$
|
2,402
|
$
|
4,622
|
$
|
4,688
|
||||
Average Sales Price –
excluding gains (losses) on derivatives:
|
||||||||||||
Natural gas ($ per mcf)
|
$
|
1.80
|
$
|
3.39
|
$
|
1.60
|
$
|
3.30
|
||||
Oil ($ per bbl)
|
$
|
88.07
|
$
|
84.18
|
$
|
91.31
|
$
|
89.78
|
||||
NGL ($ per bbl)
|
$
|
31.22
|
$
|
44.04
|
$
|
30.86
|
$
|
42.17
|
||||
Natural gas equivalent ($ per mcfe)
|
$
|
3.84
|
$
|
4.66
|
$
|
3.58
|
$
|
4.51
|
||||
Average Sales Price –
excluding unrealized gains (losses) on derivatives:
|
||||||||||||
Natural gas ($ per mcf)
|
$
|
1.97
|
$
|
4.82
|
$
|
2.06
|
$
|
5.10
|
||||
Oil ($ per bbl)
|
$
|
90.79
|
$
|
82.47
|
$
|
91.55
|
$
|
85.45
|
||||
NGL ($ per bbl)
|
$
|
31.22
|
$
|
41.16
|
$
|
30.17
|
$
|
39.10
|
||||
Natural gas equivalent ($ per mcfe)
|
$
|
4.04
|
$
|
5.78
|
$
|
3.95
|
$
|
5.94
|
||||
Interest Expense (Income) ($ in millions):
|
||||||||||||
Interest(a)
|
$
|
38
|
$
|
4
|
$
|
67
|
$
|
18
|
||||
Derivatives – realized (gains) losses
|
—
|
—
|
—
|
6
|
||||||||
Derivatives – unrealized (gains) losses
|
(2)
|
|
—
|
(4)
|
|
13
|
||||||
Total Interest Expense
|
$
|
36
|
$
|
4
|
$
|
63
|
$
|
37
|
(a)
|
Net of amounts capitalized.
|
THREE MONTHS ENDED:
|
September 30,
|
September 30,
|
||||
2012
|
2011
|
|||||
Beginning cash
|
$
|
1,024
|
$
|
109
|
||
Cash provided by operating activities
|
949
|
1,631
|
||||
Cash flows from investing activities:
|
||||||
Well costs on proved and unproved properties
|
(2,353)
|
|
(1,895)
|
|
||
Acquisition of proved and unproved properties(a)
|
(936)
|
|
(1,116)
|
|
||
Sale of proved and unproved properties
|
808
|
55
|
||||
Geological and geophysical costs
|
(52)
|
|
(55)
|
|
||
Additions to other property and equipment
|
(605)
|
|
(554)
|
|
||
Proceeds from sales of other assets
|
140
|
157
|
||||
Additions to investments
|
(133)
|
|
(86)
|
|
||
Other
|
(102)
|
|
19
|
|||
Total cash used in investing activities
|
(3,233)
|
|
(3,475)
|
|
||
Cash provided by financing activities
|
1,409
|
1,846
|
||||
Cash and cash equivalents classified in current assets
held for sale
|
(7)
|
|
—
|
|||
Ending cash
|
$
|
142
|
$
|
111
|
(a)
|
Includes capitalized interest of $327 million and $151 million for the current quarter and the prior quarter, respectively.
|
NINE MONTHS ENDED:
|
September 30,
|
September 30,
|
||||
2012
|
2011
|
|||||
Beginning cash
|
$
|
351
|
$
|
102
|
||
Cash provided by operating activities
|
1,978
|
3,724
|
||||
Cash flows from investing activities:
|
||||||
Well costs on proved and unproved properties
|
(7,360)
|
|
(5,177)
|
|
||
Acquisition of proved and unproved properties(b)
|
(2,594)
|
|
(3,300)
|
|
||
Sale of proved and unproved properties
|
2,226
|
5,883
|
||||
Geological and geophysical costs
|
(165)
|
|
(168)
|
|
||
Additions to other property and equipment
|
(1,916)
|
|
(1,416)
|
|
||
Proceeds from sales of other assets
|
219
|
682
|
||||
Acquisition of drilling company
|
—
|
(339)
|
|
|||
Proceeds from (additions to) investments
|
(261)
|
|
126
|
|||
Proceeds from sale of select midstream investment
|
2,000
|
—
|
||||
Other
|
(303)
|
|
(6)
|
|
||
Total cash used in investing activities
|
(8,154)
|
|
(3,715)
|
|
||
Cash provided by (used in) financing activities
|
5,981
|
—
|
||||
Cash and cash equivalents classified in current assets
held for sale
|
(14)
|
|
—
|
|||
Ending cash
|
$
|
142
|
$
|
111
|
(b)
|
Includes capitalized interest of $653 million and $478 million for the current period and the prior period, respectively.
|
September 30,
|
June 30,
|
September 30,
|
|||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
||||||
CASH PROVIDED BY OPERATING ACTIVITIES
|
$
|
949
|
$
|
755
|
$
|
1,631
|
|||
Changes in assets and liabilities
|
169
|
140
|
(222)
|
|
|||||
OPERATING CASH FLOW(a)
|
$
|
1,118
|
$
|
895
|
$
|
1,409
|
September 30,
|
June 30,
|
September 30,
|
|||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
||||||
NET INCOME (LOSS)
|
$
|
(1,971)
|
|
$
|
1,037
|
$
|
922
|
||
Income tax expense (benefit)
|
(1,260)
|
|
663
|
589
|
|||||
Interest expense
|
36
|
14
|
4
|
||||||
Depreciation and amortization of other assets
|
66
|
83
|
75
|
||||||
Natural gas, oil and NGL depreciation, depletion
and amortization
|
762
|
588
|
423
|
||||||
EBITDA(b)
|
$
|
(2,367)
|
|
$
|
2,385
|
$
|
2,013
|
September 30,
|
June 30,
|
September 30,
|
|||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
||||||
CASH PROVIDED BY OPERATING ACTIVITIES
|
$
|
949
|
$
|
755
|
$
|
1,631
|
|||
Changes in assets and liabilities
|
169
|
140
|
(222)
|
|
|||||
Interest expense
|
36
|
14
|
4
|
||||||
Unrealized gains (losses) on natural gas, oil and NGL
Derivatives
|
(104)
|
|
810
|
631
|
|||||
Impairment of natural gas and oil properties
|
(3,315)
|
|
—
|
—
|
|||||
Losses on sales and impairments of fixed
assets and other
|
(25)
|
|
(243)
|
|
(3)
|
|
|||
Gains (losses) on investments
|
4
|
943
|
(4)
|
|
|||||
Stock-based compensation
|
(30)
|
|
(31)
|
|
(40)
|
|
|||
Other items
|
(51)
|
|
(3)
|
|
16
|
||||
EBITDA(b)
|
$
|
(2,367)
|
|
$
|
2,385
|
$
|
2,013
|
(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.
|
September 30,
|
September 30,
|
|||||
NINE MONTHS ENDED:
|
2012
|
2011
|
||||
CASH PROVIDED BY OPERATING ACTIVITIES
|
$
|
1,978
|
$
|
3,724
|
||
Changes in assets and liabilities
|
946
|
274
|
||||
OPERATING CASH FLOW(a)
|
$
|
2,924
|
$
|
3,998
|
September 30,
|
September 30,
|
|||||
NINE MONTHS ENDED:
|
2012
|
2011
|
||||
NET INCOME (LOSS)
|
$
|
(938)
|
|
$
|
1,269
|
|
Income tax expense (benefit)
|
(599)
|
|
812
|
|||
Interest expense
|
63
|
37
|
||||
Depreciation and amortization of other assets
|
233
|
206
|
||||
Natural gas, oil and NGL depreciation, depletion and amortization
|
1,856
|
1,147
|
||||
EBITDA(b)
|
$
|
615
|
$
|
3,471
|
September 30,
|
September 30,
|
|||||
NINE MONTHS ENDED:
|
2012
|
2011
|
||||
CASH PROVIDED BY OPERATING ACTIVITIES
|
$
|
1,978
|
$
|
3,724
|
||
Changes in assets and liabilities
|
946
|
274
|
||||
Interest expense
|
63
|
37
|
||||
Unrealized gains (losses) on natural gas, oil and NGL derivatives
|
436
|
(444)
|
|
|||
Impairment of natural gas and oil properties
|
(3,315)
|
|
—
|
|||
Losses on sales and impairments of fixed assets and other
|
(262)
|
|
(7)
|
|
||
Gains on investments
|
914
|
19
|
||||
Stock-based compensation
|
(93)
|
|
(119)
|
|
||
Other items
|
(52)
|
|
(13)
|
|
||
EBITDA(b)
|
$
|
615
|
$
|
3,471
|
(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.
|
September 30,
|
June 30,
|
September 30,
|
|||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
||||||
EBITDA
|
$
|
(2,367)
|
|
$
|
2,385
|
$
|
2,013
|
||
Adjustments:
|
|||||||||
Unrealized (gains) losses on natural gas, oil and
NGL derivatives
|
104
|
(810)
|
|
(631)
|
|
||||
Impairment of natural gas and oil properties
|
3,315
|
—
|
—
|
||||||
Losses on sales and impairments of
fixed assets and other
|
45
|
243
|
3
|
||||||
Net income attributable to noncontrolling interests
|
(41)
|
|
(65)
|
|
—
|
||||
Gains on investments
|
(31)
|
|
(957)
|
|
—
|
||||
Other
|
(4)
|
|
7
|
—
|
|||||
Adjusted EBITDA(a)
|
$
|
1,021
|
$
|
803
|
$
|
1,385
|
(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.
|
September 30,
|
September 30,
|
|||||
NINE MONTHS ENDED:
|
2012
|
2011
|
||||
EBITDA
|
$
|
615
|
$
|
3,471
|
||
Adjustments:
|
||||||
Unrealized (gains) losses on natural gas, oil and NGL derivatives
|
(436)
|
|
444
|
|||
Impairment of natural gas and oil properties
|
3,315
|
—
|
||||
Losses on sales and impairments of fixed assets and other
|
286
|
7
|
||||
Net income attributable to noncontrolling interests
|
(131)
|
|
—
|
|||
Losses on purchases or exchanges of debt
|
—
|
176
|
||||
Gains on investments
|
(988)
|
|
—
|
|||
Other
|
1
|
—
|
||||
Adjusted EBITDA(a)
|
$
|
2,662
|
$
|
4,098
|
(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.
|
September 30,
|
June 30,
|
September 30,
|
|||||||
THREE MONTHS ENDED:
|
2012
|
2012
|
2011
|
||||||
Net income (loss) available to common stockholders
|
$
|
(2,055)
|
|
$
|
929
|
$
|
879
|
||
Adjustments, net of tax:
|
|||||||||
Unrealized (gains) losses on derivatives
|
63
|
(498)
|
|
(385)
|
|
||||
Impairment of natural gas and oil properties
|
2,022
|
—
|
—
|
||||||
Losses on sales and impairments of
fixed assets and other
|
28
|
148
|
2
|
||||||
Gains on investments
|
(19)
|
|
(584)
|
|
—
|
||||
Other
|
(6)
|
|
8
|
—
|
|||||
Adjusted net income available to common
stockholders(a)
|
33
|
3
|
496
|
||||||
Preferred stock dividends
|
43
|
43
|
43
|
||||||
Total adjusted net income
|
$
|
76
|
$
|
46
|
$
|
539
|
|||
Weighted average fully diluted shares outstanding(b)
|
754
|
751
|
753
|
||||||
Adjusted earnings per share assuming dilution(a)
|
$
|
0.10
|
$
|
0.06
|
$
|
0.72
|
(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.
|
September 30,
|
September 30,
|
|||||
NINE MONTHS ENDED:
|
2012
|
2011
|
||||
Net income (loss) available to common stockholders
|
$
|
(1,197)
|
|
$
|
1,141
|
|
Adjustments, net of tax:
|
||||||
Unrealized (gains) losses on derivatives
|
(268)
|
|
279
|
|||
Impairment of natural gas and oil properties
|
2,022
|
—
|
||||
Losses on sales and impairments of fixed assets and other
|
174
|
4
|
||||
Losses on purchases or exchanges of debt
|
—
|
107
|
||||
Loss on foreign currency derivatives
|
—
|
11
|
||||
Gains on investments
|
(603)
|
|
—
|
|||
Other
|
2
|
—
|
||||
Adjusted net income available to common stockholders(a)
|
130
|
1,542
|
||||
Preferred stock dividends
|
128
|
128
|
||||
Total adjusted net income
|
$
|
258
|
$
|
1,670
|
||
Weighted average fully diluted shares outstanding(b)
|
753
|
752
|
||||
Adjusted earnings per share assuming dilution(a)
|
$
|
0.34
|
$
|
2.22
|
(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
12/31/12
|
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
($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
|
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
|
29,000 – 30,000
|
36,000 – 38,000
|
|||
NGL – mbbls
|
17,000 – 18,000
|
24,000 – 26,000
|
|||
Natural gas equivalent – bcfe
|
1,396 – 1,428
|
1,390 – 1,454
|
|||
Daily natural gas equivalent midpoint – mmcfe
|
3,855
|
3,895
|
|||
YOY estimated production increase including asset sales
|
18%
|
1%
|
|||
NYMEX Price(a) (for calculation of realized hedging effects only):
|
|||||
Natural gas - $/mcf
|
$2.79
|
$3.75
|
|||
Oil - $/bbl
|
$93.93
|
$90.00
|
|||
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
|
|||||
Natural gas - $/mcf
|
$0.29
|
$0.01
|
|||
Oil - $/bbl
|
$0.81
|
$0.48
|
|||
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
|
$0.95 – 1.05
|
$0.95 – 1.05
|
|||
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
|
$1.40 – 1.60
|
$1.50 – 1.70
|
|||
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)
|
$70 – 80
|
$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)
|
($200) – (240)
|
|||
Book Tax Rate
|
39%
|
39%
|
|||
Weighted average shares outstanding (in millions):
|
|||||
Basic
|
640 – 645
|
645 – 650
|
|||
Diluted
|
753 – 758
|
758 – 763
|
Year Ending
12/31/12
|
Year Ending
12/31/13
|
||||
($ millions)
|
|||||
Operating cash flow before changes in assets and liabilities(f)(g)
|
$3,200 – 3,250
|
$3,750 – 4,750
|
|||
Well costs on proved and unproved properties
|
($8,000 – 8,500)
|
($5,750 – 6,250)
|
|||
Acquisition of unproved properties, net
|
($2,000)
|
($400)
|
|||
Investment in oilfield services, midstream and other
|
($2,800 – 3,100)
|
($850 – 1,100)
|
|||
Subtotal of net investment
|
($12,800 – 13,600)
|
($7,000 – 7,750)
|
|||
Asset sales and other transactions
|
$13,000 – 14,000
|
$4,250 – 5,000
|
|||
Interest, dividends and cash taxes
|
($1,100 –1,350)
|
($1,000 – 1,250)
|
|||
Total budgeted cash flow surplus
|
$2,300
|
$0 – 750
|
|||
a)
|
NYMEX natural gas prices and NYMEX oil prices have been updated for actual contract prices through August and July, respectively.
|
b)
|
Excludes expenses associated with noncash stock-based compensation.
|
c)
|
Does not include 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 $3.00 to $3.25 per mcf and $90.00 per bbl in 2012 and $3.25 to $4.25 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
|
|||||||||||||||
Q3 2012
|
167
|
$
|
3.02
|
$
|
32
|
||||||||||||||||
Q4 2012
|
204
|
$
|
3.04
|
15
|
|||||||||||||||||
Q2-Q4 2012
|
371
|
$
|
3.03
|
584
|
64
|
%
|
$
|
47
|
$
|
0.08
|
|||||||||||
Total 2013
|
0
|
$
|
0.00
|
1,050
|
0
|
%
|
$
|
16
|
$
|
0.01
|
|||||||||||
Total 2014
|
0
|
$
|
(34)
|
||||||||||||||||||
Total 2015
|
0
|
$
|
(110)
|
||||||||||||||||||
Total 2016 – 2022
|
0
|
$
|
(131)
|
Call Options
(bcf)
|
Avg. NYMEX
Strike Price
|
Forecasted
Natural Gas
Production
(bcf)
|
Call Options
as a % of
Forecasted
Natural Gas
Production
|
||||||||||
Q3 2012
|
40
|
$
|
3.25
|
||||||||||
Q4 2012
|
41
|
3.25
|
|||||||||||
Q3-Q4 2012
|
81
|
$
|
3.25
|
584
|
14
|
%
|
|||||||
Total 2013
|
251
|
$
|
6.31
|
1,050
|
24
|
%
|
|||||||
Total 2014
|
330
|
$
|
6.43
|
||||||||||
Total 2015
|
116
|
$
|
6.45
|
||||||||||
Total 2016 – 2020
|
349
|
$
|
8.18
|
Volume (Bcf)
|
Avg. NYMEX less
|
|||||
2012
|
29
|
$
|
0.78
|
|||
2013
|
44
|
$
|
0.21
|
|||
2014 - 2022
|
67
|
$
|
0.42
|
|||
Totals
|
140
|
$
|
0.43
|
Open
Swaps
(mbbls)
|
Avg. NYMEX
Price of
Open Swaps
|
Forecasted
Liquids
Production
(mbbls)
|
Open Swap
Positions as
a % of
Forecasted
Liquids
Production
|
Total Gains
(Losses) from
Closed Trades
and Premiums
for Call Options
($millions)
|
Total Gains
(Losses) from
Closed Trades
and Premiums for
Call Options per
bbl of Forecasted
Liquids
Production
|
|||||||||||||||
Q3 2012
|
3,754
|
$
|
101.56
|
$
|
(11
|
)
|
||||||||||||||
Q4 2012
|
3,841
|
101.12
|
(33
|
)
|
||||||||||||||||
Q3-Q4 2012
|
7,595
|
$
|
101.34
|
24,816
|
31%
|
$
|
(44
|
)
|
$
|
(1.78)
|
||||||||||
Total 2013
|
3,122
|
$
|
94.06
|
62,000
|
5%
|
$
|
6
|
$
|
0.10
|
|||||||||||
Total 2014
|
902
|
$
|
90.72
|
$
|
(151
|
)
|
||||||||||||||
Total 2015
|
500
|
$
|
88.75
|
$
|
265
|
|||||||||||||||
Total 2016 – 2021
|
$
|
117
|
Call Options
(mbbls)
|
Avg. NYMEX
Strike Price
|
Forecasted
Liquids
Production
(mbbls)
|
Call Options
as a % of
Forecasted Liquids
Production
|
|||||||||
Q3 2012
|
0
|
$
|
--
|
|||||||||
Q4 2012
|
460
|
106.72
|
||||||||||
Q3-Q4 2012
|
460
|
$
|
106.72
|
24,816
|
2%
|
|||||||
Total 2013
|
15,633
|
$
|
100.50
|
62,000
|
25%
|
|||||||
Total 2014
|
17,612
|
$
|
98.79
|
|||||||||
Total 2015
|
27,048
|
$
|
100.99
|
|||||||||
Total 2016 – 2017
|
24,220
|
$
|
100.07
|