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TheStreet Open House

Chesapeake Energy Corporation Reports Financial And Operational Results For The 2012 Fourth Quarter And Full Year

Three notable wells completed by Chesapeake in the southern wet gas portion of the Marcellus during the 2012 fourth quarter are as follows:

  • 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 company is in the process of selling various non-core Marcellus acreage.

Mississippi Lime (northern Oklahoma, southern Kansas) : Chesapeake’s approximate 2.1 million net acres of leasehold is the industry’s largest position in the Mississippi Lime play in northern Oklahoma and southern Kansas. Production for the 2012 fourth quarter averaged approximately 32,500 boe per day (41,600 gross operated boe per day), up 208% year over year and 30% sequentially. Approximately 45% of total Mississippi Lime production during the 2012 fourth quarter was oil, 9% was NGL and 46% was natural gas. As of December 31, 2012, Chesapeake had 273 producing wells in the Mississippi Lime play, which included 55 wells that reached first production in the 2012 fourth quarter, compared to 73 in the 2012 third quarter and 49 in the 2012 second quarter. Also, as of December 31, 2012, Chesapeake had approximately 46 wells drilled, but not yet producing, that were in various stages of completion and/or waiting on pipeline connection. Chesapeake is currently operating eight rigs in the Mississippi Lime and anticipates maintaining that level of activity for the remainder of 2013.

Three notable wells completed by Chesapeake in the Mississippi Lime during the 2012 fourth quarter are as follows:

  • 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.

2012 Fourth Quarter and Full Year Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled for Thursday, February 21, 2013 at 9:00 am EST. The telephone number to access the conference call is 913-981-5550 or toll-free 800-289-0508. The passcode for the call is 8878841. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EST. For those unable to participate in the conference call, a replay will be available for audio playback at 1:00 pm EST on Thursday, February 21, 2013 and will run through midnight Thursday, March 7, 2013. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 8878841. The conference call will also be webcast live on Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of the company’s website. The webcast of the conference will be available on the company’s website for one year.

This news release and the accompanying Outlooks include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact that give our current expectations or forecasts of future events. They include estimates of natural gas and liquids reserves, projected production, estimates of operating costs, planned development drilling and use of joint venture drilling carries, anticipated asset sales, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update this information.

Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1A of our 2011 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 29, 2012. These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including through planned asset sales, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; inability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; general economic conditions negatively impacting us and our business counterparties; oilfield services shortages and transportation capacity constraints and interruptions that could adversely affect our cash flow; and losses possible from pending or future litigation and regulatory investigations. We do not have binding agreements for all of our planned 2013 asset sales. Our ability to consummate each of these transactions is subject to changes in market conditions and other factors. If one or more of the transactions is not completed in the anticipated time frame or at all or for less proceeds than anticipated, our ability to fund budgeted capital expenditures and reduce our indebtedness as planned could be adversely affected.

Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas, a Top 11 producer of oil and natural gas liquids and the most active driller of new wells in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S. Chesapeake owns leading positions in the Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime and Niobrara unconventional liquids plays and in the Marcellus, Haynesville/Bossier and Barnett unconventional natural gas shale plays. The company has also vertically integrated its operations and owns substantial marketing and oilfield services businesses through its subsidiaries Chesapeake Energy Marketing, Inc. and Chesapeake Oilfield Operating, L.L.C. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.

   

 

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except per-share and unit data)

(unaudited)

 
           
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
   

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except per-share and unit data)

(unaudited)

 
           
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
     

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)

 
           
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
   

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)

         
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
 

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2012 CHANGES TO NATURAL GAS AND OIL PROPERTIES

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AS OF DECEMBER 31, 2012

($ in millions, except per-unit data)

(unaudited)

     
    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 )
 

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

TWELVE MONTHS ENDED DECEMBER 31, 2012

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AS OF DECEMBER 31, 2012

(unaudited)

       
    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.

     

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF PV-10

($ in millions)

(unaudited)

           
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.

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