Chesapeake Energy Corporation Reports Financial And Operational Results For The 2013 Third Quarter

Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2013 third quarter. Key information related to the quarter and Chesapeake's updated Outlook is as follows:
  • Adjusted net income per fully diluted share of $0.43, compared to $0.10 in the 2012 third quarter
  • Adjusted ebitda of $1.325 billion increases 29% year over year
  • Net daily oil production rises 23% year over year to 120,000 bbls per day
  • Full-year 2013 oil production outlook increases by 2 million barrels to 40 – 42 million barrels, a 28 – 34% increase year over year
  • Full-year 2013 drilling, completion and leasehold capital expenditure outlook decreases by $300 million to $5.700 – $6.050 billion
  • Conference call at 9:00 am EST today; dial-in 913-312-0713, passcode 5588965

Chesapeake reported net income available to common stockholders of $156 million or $0.24 per fully diluted share. These results include the effects of the following after-tax items:
  • noncash unrealized mark-to-market losses of $118 million from the company’s derivative instruments;
  • a charge of $55 million for the impairment of certain of the company’s property and equipment and other assets;
  • a net gain of $82 million on sales of certain of the company’s property and equipment, consisting primarily of midstream assets; and
  • a $39 million charge for restructuring and other termination benefits.

Adjusting for these and other items not typically included in earnings estimates by securities analysts, Chesapeake reported adjusted net income available to common stockholders of $282 million, or $0.43 per fully diluted share, which compares to adjusted net income available to common stockholders of $35 million, or $0.10 per fully diluted share, in the 2012 third quarter.

The company reported adjusted ebitda of $1.325 billion, an increase of 29% year over year. Operating cash flow, which is cash flow provided by operating activities before changes in assets and liabilities, was $1.368 billion, an increase of 22% year over year. Additional definitions and reconciliations to comparable financial measures calculated in accordance with generally accepted accounting principles of adjusted net income available to common stockholders, operating cash flow, ebitda and adjusted ebitda are provided on pages 12 – 16 of this release.

Doug Lawler, Chesapeake’s Chief Executive Officer, said, "We are pleased with our operational performance during the third quarter. Our strong results compared to the 2012 third quarter were driven by a substantial increase in oil and natural gas liquids production, higher realized natural gas prices and significantly lower per-unit production, overhead and DD&A expenses. Additionally, our focus on financial discipline and operational efficiencies generated lower-than-expected capital expenditures during the 2013 third quarter, and we have reduced our full-year 2013 capital spending outlook accordingly. I am particularly impressed by the strong performance of the company while we implemented significant transformational initiatives over the past few months. We look forward to achieving further efficiency gains and improvements in returns on capital in 2014."

2013 Third Quarter Oil Production Increases 23% Year over Year to 120,000 Bbls per Day; Total Production Decreases 2% Year over Year to 4.0 Bcfe per Day, Primarily Due to Asset Sales

Chesapeake’s daily production for the 2013 third quarter averaged approximately 4.0 billion cubic feet of natural gas equivalent (bcfe), a decrease of 2% from the 2012 third quarter and a nominal decrease from the 2013 second quarter. This decrease is primarily due to production losses associated with recent asset sales in the Mississippi Lime, northern Eagle Ford Shale and Haynesville Shale, as well as the sale of Permian Basin assets in September and October of 2012. Adjusted for asset sales, the company's production increased approximately 8% year over year and 5% sequentially.

The company’s average daily production consisted of approximately 3.0 billion cubic feet (bcf) of natural gas and 178,500 barrels (bbls) of liquids, comprised of approximately 120,000 bbls of oil and 58,500 bbls of natural gas liquids (NGL).

During the 2013 third quarter, average daily oil production increased 23% year over year and 4% sequentially, and average daily NGL production increased 31% year over year and 12% sequentially. Natural gas production in the third quarter decreased 10% year over year and 3% sequentially. Liquids accounted for 27% of total production during the 2013 third quarter, up from 21% during the 2012 third quarter and 25% during the 2013 second quarter.

Mr. Lawler added, "Our oil assets in the Eagle Ford Shale continue to deliver strong results, prompting us to raise our full-year 2013 oil production guidance by 2 million barrels (mmbbls) to 40 – 42 mmbbls. We are also reducing the midpoint of our 2013 NGL production guidance range by 1.5 mmbbls, primarily reflecting continued high levels of ethane rejection as well as a slower production ramp in the Utica Shale, resulting from unexpected downtime at a third-party gas processing facility. "

Capital Spending and Cost Overview

During the 2013 third quarter, Chesapeake operated an average of 67 rigs and invested approximately $1.2 billion in drilling and completion activities. This represents a decrease of approximately $350 million compared to the 2013 second quarter. Chesapeake spud a total of 253 gross wells and completed 321 gross wells during the 2013 third quarter, compared to 312 gross wells spud and 410 gross wells completed during the 2013 second quarter.

Mr. Lawler noted, "Although we have reduced our drilling and completion activities in the second half of 2013 and we are planning for a lower capital expenditure budget next year, we expect to continue delivering organic production growth in 2014. We anticipate our growth will be led by an increase in oil production from the Eagle Ford Shale and an increase in natural gas and NGL production from the Utica and Marcellus shales, which will benefit from new gas processing and pipeline takeaway capacity."

During the 2013 fourth quarter, Chesapeake plans to operate an average of 59 rigs and to complete approximately 14% fewer gross wells compared to the 2013 third quarter. Based on this planned activity level, the company is reducing its 2013 full-year guidance for drilling and completion costs from a range of $5.7 – $6.0 billion to $5.5 – $5.8 billion.

Net expenditures for the acquisition of unproved properties were approximately $45 million during the 2013 third quarter. The company continues to track below its budgeted leasehold expenditures for the year and is lowering its 2013 full-year leasehold expenditure guidance from $300 – $350 million to $200 – $250 million. Other capital expenditures were approximately $170 million during the 2013 third quarter.

Average production expenses during the 2013 third quarter were $0.76 per thousand cubic feet of natural gas equivalent (mcfe), a decrease of 10% year over year. General and administrative (G&A) expenses (excluding stock-based compensation and restructuring and other termination benefits) were $0.29 per mcfe, a decrease of 12% year over year.

A complete summary of the company’s guidance for 2013 is provided in the Outlook dated November 6, 2013 which is attached to this release as Schedule "A” beginning on Page 17. This updates information previously provided in the Outlook dated August 1, 2013.

Asset Sales Update

As of September 30, 2013, Chesapeake had completed asset sales of approximately $3.6 billion in 2013. During the 2013 fourth quarter, the company anticipates completing additional asset sales for net proceeds of approximately $600 million. Chesapeake continues to pursue other asset sale transactions that may close in the first half of 2014. The proceeds from such sales are anticipated to be directed toward reducing financial leverage and complexity and further enhancing liquidity.

Operational Update

The company continues to achieve strong operational results in its most active plays.

Eagle Ford Shale (South Texas) : Eagle Ford Shale net production averaged approximately 95,000 barrels of oil equivalent (boe) per day (211,000 gross operated boe per day) during the 2013 third quarter. This production is net of approximately 6,300 boe per day of production associated with assets sold in the northern Eagle Ford on July 31, 2013, and represents an increase of 82% year over year and 11% sequentially. Approximately 68% of the company’s Eagle Ford production consisted of oil, 12% was NGL and 20% was natural gas.

Chesapeake operated an average of 13 rigs and connected 100 gross wells to sales during the 2013 third quarter, compared to 14 average operated rigs and 140 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 100 wells that commenced first production during the 2013 third quarter was approximately 930 boe per day.

As of September 30, 2013, net of recent asset sales, Chesapeake had 788 producing wells and 117 wells waiting on pipeline or in various stages of completion in the Eagle Ford Shale.

Utica Shale (eastern Ohio, Pennsylvania, West Virginia) : Utica Shale net production averaged approximately 164 million cubic feet of natural gas equivalent (mmcfe) per day (312 gross operated mmcfe per day) during the 2013 third quarter, an increase of 91% sequentially from the 2013 second quarter.

During the 2013 third quarter, Chesapeake operated an average of 11 rigs and connected 63 gross wells to sales, compared to 12 average operated rigs and 42 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 63 wells that commenced first production in the Utica during the 2013 third quarter was approximately 6.6 mmcfe per day.

As of September 30, 2013, Chesapeake had drilled a total of 377 wells in the Utica, which included 169 producing wells and 208 wells waiting on pipeline connection or in various stages of completion.

Greater Anadarko Basin (Oklahoma, Texas Panhandle, southern Kansas) : Chesapeake's production in the Greater Anadarko Basin comes primarily from five plays: the Mississippi Lime, Granite Wash, Cleveland, Tonkawa and Hogshooter. Aggregate net production from these plays during the 2013 third quarter averaged 109,000 boe per day (196,000 gross operated boe per day), an increase of 12% year over year and a decrease of 14% sequentially. The sequential production decrease is primarily driven by the sale of assets in the Mississippi Lime at the end of June 2013 that produced approximately 22,200 boe per day during the 2013 second quarter. Approximately 34% of the company’s Greater Anadarko Basin production during the 2013 third quarter was oil, 21% was NGL and 45% was natural gas.

During the 2013 third quarter, Chesapeake operated an average of 22 rigs and connected 89 gross wells to sales, compared to 28 operated rigs and 123 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 89 wells that commenced first production in the Greater Anadarko Basin during the 2013 third quarter was approximately 830 boe per day.

As of September 30, 2013, the company had 44 wells waiting on pipeline connection or in various stages of completion in the Greater Anadarko Basin.

Northern Marcellus Shale (Pennsylvania) : The company’s production from the northern Marcellus continued to grow during the 2013 third quarter, despite certain temporary downstream takeaway constraints. The company expects that these constraints will be significantly or completely relieved in the 2013 fourth quarter as new capacity expansion projects are placed in-service on several key pipelines. Chesapeake has contracted for approximately one-third of the estimated 1.4 bcf per day of new pipeline capacity expected to be placed on-line in the 2013 fourth quarter, which the company believes will benefit both its production volumes and gas price realizations.

Average daily net production in this play was approximately 825 mmcfe per day (1,900 gross operated mmcfe per day), an increase of 53% year over year and 6% sequentially. All of Chesapeake's production in the northern Marcellus consists of natural gas.

During the 2013 third quarter, Chesapeake operated an average of five rigs and connected 37 gross wells to sales, compared to five operated rigs and 79 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 37 wells that commenced first production during the 2013 third quarter was approximately 9.3 mmcfe per day.

As of September 30, 2013, Chesapeake had 128 wells waiting on pipeline connection or in various stages of completion in the northern Marcellus.

Southern Marcellus Shale (Pennsylvania, West Virginia) : Chesapeake’s average daily net production in the southern wet-gas portion of the Marcellus was approximately 275 mmcfe per day (470 gross operated mmcfe per day), an increase of 123% year over year and 33% sequentially. Approximately 13% of the company’s southern Marcellus production was oil, 17% was NGL and 70% was natural gas.

During the 2013 third quarter, Chesapeake operated an average of three rigs and connected 30 gross wells to sales, compared to three operated rigs and 52 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 30 wells that commenced first production during the 2013 third quarter was approximately 6.7 mmcfe per day.

As of September 30, 2013, Chesapeake had 62 wells waiting on pipeline connection or in various stages of completion in the southern Marcellus.

Key Financial and Operational Results

The table below summarizes Chesapeake’s key financial and operational results during the 2013 third quarter and compares them to results during the 2013 second quarter and the 2012 third quarter.
 
Three Months Ended
9/30/2013   6/30/2013   9/30/2012
Natural gas equivalent production (in bcfe) 372 369 381
Natural gas equivalent realized price ($/mcfe)(a) 4.78 4.96 4.04
Oil production (in mmbbls) 11.0 10.5 9.0
Average realized oil price ($/bbl)(a) 92.09 93.81 90.79
Oil as % of total production 18 17 14
NGL production (in mmbbls) 5.4 4.8 4.1
Average realized NGL price ($/bbl)(a) 26.52 24.22 31.22
NGL as % of total production 9 8 7
Liquids as % of realized revenue(b) 65 60 61
Liquids as % of unhedged revenue(b) 69 58 63
Natural gas production (in bcf) 273 278 302
Average realized natural gas price ($/mcf)(a) 2.26 2.62 1.97
Natural gas as % of total production 73 75 79
Natural gas as % of realized revenue 35 40 39
Natural gas as % of unhedged revenue 31 42 37
Production expenses ($/mcfe) (0.76 ) (0.78 ) (0.84 )
Production taxes ($/mcfe) (0.17 ) (0.16 ) (0.14 )
General and administrative costs ($/mcfe)(c) (0.29 ) (0.25 ) (0.33 )
Stock-based compensation ($/mcfe) (0.04 ) (0.04 ) (0.05 )
DD&A of natural gas and liquids properties ($/mcfe) (1.75 ) (1.75 ) (2.00 )
D&A of other assets ($/mcfe) (0.21 ) (0.21 ) (0.17 )
Interest expense ($/mcfe)(a) (0.11 ) (0.14 ) (0.10 )
Marketing, gathering and compression net margin ($ in millions)(d) 23 29 42
Oilfield services net margin ($ in millions)(d) 38 35 36
Operating cash flow ($ in millions)(e) 1,368 1,370 1,118
Operating cash flow ($/mcfe) 3.68 3.71 2.93
Adjusted ebitda ($ in millions)(f) 1,325 1,424 1,024
Adjusted ebitda ($/mcfe) 3.56 3.86 2.69
Net income available to common stockholders ($ in millions) 156 457 (2,055 )
Earnings per share – diluted ($) 0.24 0.66 (3.19 )
Adjusted net income available to common stockholders ($ in millions)(g) 282 334 35
Adjusted earnings per share – diluted ($) 0.43 0.51 0.10
 

(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) Excludes expenses associated with stock-based compensation and restructuring and other termination benefits.

(d) Includes revenue and operating costs and excludes depreciation and amortization of other assets, impairments of fixed assets and other, and gains or losses on sales of fixed assets.

(e) Defined as cash flow provided by operating activities before changes in assets and liabilities.

(f) Defined as net income before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on Page 16.

(g) Defined as net income available to common stockholders, as adjusted to remove effects of certain items detailed on Page 12.
 

2013 Third Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled for Wednesday, November 6, 2013, at 9:00 am EST. The telephone number to access the conference call is 913-312-0713 or toll-free 888-778-9069. The passcode for the call is 5588965. 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 2:00 pm EST on Wednesday, November 6, 2013, and will run through 2:00 pm EST on Wednesday, November 20, 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 5588965. 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.

Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas and the 11th largest producer of oil and natural gas liquids in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing its large and geographically diverse resource base of unconventional natural gas and oil assets onshore in the U.S. The company also owns substantial marketing, compression and oilfield services businesses. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.

This news release and the accompanying Outlook includes "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 production forecasts, estimates of operating costs, planned development drilling, expected capital expenditures, expected efficiency gains, anticipated asset sales, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. Although we believe the expectations and forecasts reflected in the 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.

Factors that could cause actual results to differ materially from expected results are described under "Risk Factors” in Item 1A of our 2012 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, 2013. These risk factors include the volatility of natural gas, oil and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the prices of natural gas and oil potentially resulting in a write-down of our asset carrying values; 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, oil and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability 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, oil and NGL 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, air emissions and endangered species; current worldwide economic uncertainty which may have a material adverse effect on our results of operations, liquidity and financial condition; oilfield services shortages, gathering system and transportation capacity constraints and various transportation interruptions that could adversely affect our revenues and cash flow; losses possible from pending or future litigation and regulatory investigations; cyber attacks adversely impacting our operations; and the loss of key operational personnel or inability to maintain our corporate culture. In addition, 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. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Further, asset sales we are evaluating as we focus on our strategic priorities are subject to market conditions and other factors beyond our control. 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.
     

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)
               
THREE MONTHS ENDED:  

September 30,2013
 

September 30,2012
$   $/mcfe $ $/mcfe
REVENUES:
Natural gas, oil and NGL 1,586 4.26 1,437 3.77
Marketing, gathering and compression 3,032 8.15 1,381 3.62
Oilfield services 249   0.67   152   0.40  
Total Revenues 4,867   13.08   2,970   7.79  
 
OPERATING EXPENSES:
Natural gas, oil and NGL production 282 0.76 320 0.84
Production taxes 62 0.17 53 0.14
Marketing, gathering and compression 3,009 8.09 1,339 3.51
Oilfield services 211 0.57 116 0.30
General and administrative 120 0.31 145 0.38
Restructuring and other termination benefits 63 0.18 3 0.01

Natural gas, oil and NGL depreciation, depletion and amortization
652 1.75 762 2.00
Depreciation and amortization of other assets 79 0.21 66 0.17
Impairment of natural gas and oil properties 3,315 8.70
Impairments of fixed assets and other 85 (0.36 ) 38 0.10
Net (gains) losses on sales of fixed assets (132 ) 0.23   7   0.02  
Total Operating Expenses 4,431   11.91   6,164   16.17  
 
INCOME (LOSS) FROM OPERATIONS 436   1.17   (3,194 ) (8.38 )
 
OTHER INCOME (EXPENSE):
Interest expense (40 ) (0.11 ) (36 ) (0.10 )
Losses on investments (22 ) (0.06 ) (23 ) (0.06 )
Gains (losses) on sales of investments 3 0.01 31 0.08
Other income (expense) 10   0.03   (9 ) (0.02 )
Total Other Income (Expense) (49 ) (0.13 ) (37 ) (0.10 )
 
INCOME (LOSS) BEFORE INCOME TAXES 387 1.04 (3,231 ) (8.48 )
 
INCOME TAX EXPENSE (BENEFIT):
Current income taxes 7 0.02 22 0.05
Deferred income taxes 140   0.38   (1,282 ) (3.36 )
Total Income Tax Expense (Benefit) 147   0.40   (1,260 ) (3.31 )
 
NET INCOME (LOSS) 240 0.64 (1,971 ) (5.17 )
 
Net income attributable to noncontrolling interests (38 ) (0.10 ) (41 ) (0.11 )
 
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 202   0.54   (2,012 ) (5.28 )
 
Preferred stock dividends (43 ) (0.11 ) (43 ) (0.11 )
Earnings allocated to participating securities (3 ) (0.01 )    
 
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS 156   0.42   (2,055 ) (5.39 )
 
EARNINGS (LOSS) PER COMMON SHARE:
Basic $ 0.24   $ (3.19 )
Diluted $ 0.24   $ (3.19 )
 
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic 656   644  
Diluted 656   644  
 
     

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)
               
NINE MONTHS ENDED:  

September 30,2013
 

September 30,2012
$   $/mcfe $ $/mcfe
REVENUES:
Natural gas, oil and NGL 5,444 4.95 4,622 4.36
Marketing, gathering and compression 6,871 6.25 3,710 3.50
Oilfield services 650   0.59   446   0.42  
Total Revenues 12,965   11.79   8,778   8.28  
OPERATING EXPENSES:
Natural gas, oil and NGL production 877 0.80 1,005 0.95
Production taxes 173 0.16 141 0.13
Marketing, gathering and compression 6,781 6.17 3,631 3.43
Oilfield services 543 0.49 321 0.30
General and administrative 336 0.30 436 0.41
Restructuring and other termination benefits 203 0.19 4

Natural gas, oil and NGL depreciation, depletion and amortization
1,945 1.77 1,856 1.75
Depreciation and amortization of other assets 234 0.21 233 0.22
Impairment of natural gas and oil properties 3,315 3.13
Impairments of fixed assets and other 343 (0.26 ) 281 0.27
Net (gains) losses on sales of fixed assets (290 ) 0.31   5    
Total Operating Expenses 11,145   10.14   11,228   10.59  
INCOME (LOSS) FROM OPERATIONS 1,820   1.65   (2,450 ) (2.31 )
 
OTHER INCOME (EXPENSE):
Interest expense (164 ) (0.15 ) (63 ) (0.06 )
Losses on investments (26 ) (0.02 ) (87 ) (0.08 )
Impairment of investment (10 ) (0.01 )
Gains (losses) on sales of investments (7 ) (0.01 ) 1,061 1.00
Losses on purchases of debt (70 ) (0.06 )
Other income (expense) 18   0.02   2    
Total Other Income (Expense) (259 ) (0.23 ) 913   0.86  
 
INCOME (LOSS) BEFORE INCOME TAXES 1,561 1.42 (1,537 ) (1.45 )
 
INCOME TAX EXPENSE (BENEFIT):
Current income taxes 9 0.01 24 0.02
Deferred income taxes 585   0.53   (623 ) (0.59 )
Total Income Tax Expense (Benefit) 594   0.54   (599 ) (0.57 )
 
NET INCOME (LOSS) 967 0.88 (938 ) (0.88 )
 
Net income attributable to noncontrolling interests (127 ) (0.12 ) (131 ) (0.13 )
 
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 840   0.76   (1,069 ) (1.01 )
 
Preferred stock dividends (128 ) (0.12 ) (128 ) (0.12 )

Premium on purchase of preferred shares of a subsidiary
(69 ) (0.06 )
Earnings allocated to participating securities (14 ) (0.01 )    
 

NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
629   0.57   (1,197 ) (1.13 )
 
EARNINGS (LOSS) PER COMMON SHARE:
Basic $ 0.96   $ (1.86 )
Diluted $ 0.96   $ (1.86 )
 

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic 654   643  
Diluted 654   643  
 
   

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)
         
   

September 30,2013
 

December 31,2012
 
Cash and cash equivalents $ 987 $ 287
Other current assets 3,007   2,661
Total Current Assets 3,994   2,948
 
Property and equipment (net) 37,121 37,167
Other assets 1,173   1,496
Total Assets $ 42,288   $ 41,611
 
Current liabilities $ 5,678 $ 6,266
Long-term debt, net of discounts 12,736 12,157
Other long-term liabilities 2,103 2,485
Deferred income tax liabilities 3,423   2,807
Total Liabilities 23,940   23,715
 
Preferred stock 3,062 3,062
Noncontrolling interests 2,152 2,327
Common stock and other stockholders’ equity 13,134   12,507
Total Equity 18,348   17,896
 
Total Liabilities and Equity $ 42,288   $ 41,611
 
Common Shares Outstanding (in millions) 665   664
 
 

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)
         
   

September 30,2013
 

December 31,2012
 
Total debt, net of unrestricted cash $ 11,749 $ 12,333
Preferred stock 3,062 3,062
Noncontrolling interests(a) 2,152 2,327
Common stock and other stockholders’ equity 13,134   12,507  
Total $ 30,097   $ 30,229  
 
Total debt to capitalization ratio 39 % 41 %
 
 

(a) Includes third-party ownership as follows:
 
CHK Cleveland Tonkawa, L.L.C. $ 1,015 $ 1,015
CHK Utica, L.L.C. 807 950
Chesapeake Granite Wash Trust 323 356
Other 7   6
Total $ 2,152   $ 2,327
 
       

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA - NATURAL GAS, OIL AND NGL PRODUCTION, SALES AND INTEREST EXPENSE

(unaudited)
                 
Three Months EndedSeptember 30, Nine Months EndedSeptember 30,
2013 2012 2013 2012
Net Production:
Natural gas (bcf) 273.3 302.3 824.1 848.6
Oil (mmbbl) 11.0 9.0 30.9 22.3
NGL (mmbbl) 5.4 4.1 15.0 13.0
Natural gas equivalent (bcfe) 371.9 381.1 1,099.4 1,060.5
 

Natural Gas, Oil and NGL Sales ($ in millions):
Natural gas sales $ 581 $ 543 $ 1,932 $ 1,359
Natural gas derivatives – realized gains (losses)(a) 37 52 (7 ) 391
Natural gas derivatives – unrealized gains (losses) 6   (90 ) 74   (401 )
Total Natural Gas Sales 624   505   1,999   1,349  
 
Oil sales 1,115 792 2,975 2,038
Oil derivatives – realized gains (losses)(a) (99 ) 25 (89 ) 6
Oil derivatives – unrealized gains (losses) (197 ) (14 ) 163   803  
Total Oil Sales 819   803   3,049   2,847  
 
NGL sales 143 129 396 401

NGL derivatives – realized gains (losses)(a)
(9 )
NGL derivatives – unrealized gains (losses)       34  
Total NGL Sales 143   129   396   426  
Total Natural Gas, Oil and NGL Sales $ 1,586   $ 1,437   $ 5,444   $ 4,622  
 

Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf) $ 2.12 $ 1.80 $ 2.34 $ 1.60
Oil ($ per bbl) $ 101.08 $ 88.07 $ 96.40 $ 91.31
NGL ($ per bbl) $ 26.52 $ 31.22 $ 26.35 $ 30.86
Natural gas equivalent ($ per mcfe) $ 4.94 $ 3.84 $ 4.82 $ 3.58
 

Average Sales Price – excluding unrealized gains (losses) on derivatives(a):
Natural gas ($ per mcf) $ 2.26 $ 1.97 $ 2.34 $ 2.06
Oil ($ per bbl) $ 92.09 $ 90.79 $ 93.51 $ 91.55
NGL ($ per bbl) $ 26.52 $ 31.22 $ 26.35 $ 30.17
Natural gas equivalent ($ per mcfe) $ 4.78 $ 4.04 $ 4.74 $ 3.95
 
Interest Expense (Income) ($ in millions):
Interest(b) $ 43 $ 38 $ 113 $ 67
Derivatives – realized (gains) losses (3 ) (6 )
Derivatives – unrealized (gains) losses   (2 ) 57   (4 )
Total Interest Expense $ 40   $ 36   $ 164   $ 63  
 

(a) Includes settlements for commodity derivatives adjusted for option premiums. For derivatives closed early, settlements are reflected in the period of original contract expiration.

(b) Net of amounts capitalized.
 
   

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)
         
THREE MONTHS ENDED:   September 30,2013   September 30,2012
 
Beginning cash $ 677   $ 1,024  
 
Cash provided by operating activities 1,356   949  
 
Cash flows from investing activities:

Drilling and completion costs on proved and unproved properties(a)
(1,303 ) (2,353 )
Acquisition of proved and unproved properties(b) (266 ) (936 )
Sale of proved and unproved properties 885 808
Geological and geophysical costs (8 ) (52 )
Additions to other property and equipment (133 ) (605 )
Proceeds from sales of other assets 337 140
Investments, net 9 (133 )
Other 7   (102 )
Total cash used in investing activities (472 ) (3,233 )
 
Cash provided by (used in) financing activities (574 ) 1,409  

Change in cash and cash equivalents classified as current assets held for sale
  (7 )
Change in cash and cash equivalents 310   (882 )
Ending cash $ 987   $ 142  
 

(a) Includes capitalized interest of $1 million and $18 million for the three months ended September 30, 2013 and 2012, respectively.
 

(b) Includes capitalized interest of $205 million and $309 million for the three months ended September 30, 2013 and 2012, respectively.
 
         
NINE MONTHS ENDED:   September 30,2013   September 30,2012
 
Beginning cash $ 287   $ 351  
 
Cash provided by operating activities 3,561   1,978  
 
Cash flows from investing activities:

Drilling and completion costs on proved and unproved properties(c)
(4,435 ) (7,360 )
Acquisition of proved and unproved properties(d) (763 ) (2,594 )
Sale of proved and unproved properties 2,742 2,226
Geological and geophysical costs (36 ) (165 )
Additions to other property and equipment (639 ) (1,916 )
Proceeds from sales of other assets 796 219
Investments, net 107 1,739
Other 181   (303 )
Total cash used in investing activities (2,047 ) (8,154 )
 
Cash provided by (used in) financing activities (814 ) 5,981  

Change in cash and cash equivalents classified as current assets held for sale
  (14 )
Change in cash and cash equivalents 700   (209 )
Ending cash $ 987   $ 142  
 

(c) Includes capitalized interest of $47 million and $30 million for the nine months ended September 30, 2013 and 2012, respectively.
 

(d) Includes capitalized interest of $571 million and $623 million for the nine months ended September 30, 2013 and 2012, respectively.
 
     

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions, except per share data)

(unaudited)
             
THREE MONTHS ENDED:  

September 30,2013
 

June 30,2013
 

September 30,2012
 

Net income (loss) available to common stockholders
$ 156 $ 457 $ (2,055 )
 
Adjustments, net of tax:
Unrealized (gains) losses on derivatives 118 (325 ) 63
Net (gains) losses on sales of fixed assets (82 ) (68 ) 4
Impairment of natural gas and oil properties 2,022
Impairments of fixed assets and other 55 143 23
Restructuring and other termination benefits 39 5 2
(Gains) losses on sales of investments (2 ) 6 (19 )
Losses on purchases of debt 44

Premium on purchase of preferred shares of a subsidiary
69
Other (2 ) 3   (5 )
 

Adjusted net income available to common stockholders(a)
282 334 35
Preferred stock dividends 43 43 43
Earnings allocated to participating securities 3   11    
Total adjusted net income $ 328   $ 388   $ 78  
 

Weighted average fully diluted shares outstanding (in millions)(b)
765 763 754
 
Adjusted earnings per share assuming dilution(a) $ 0.43 $ 0.51 $ 0.10
 

(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 adjusted financial measures are a useful adjunct to earnings calculated in accordance with accounting principles generally accepted in the United States (GAAP) 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.
 
   

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions, except per share data)

(unaudited)
         
NINE MONTHS ENDED:  

September 30,2013
 

September 30,2012
 
Net income (loss) available to common stockholders $ 629 $ (1,197 )
 
Adjustments, net of tax:
Unrealized gains on derivatives (112 ) (268 )
Net (gains) losses on sales of fixed assets (180 ) 3
Impairment of natural gas and oil properties 2,022
Impairments of fixed assets and other 215 171
Restructuring and other termination benefits 126 2
Impairment of investments 6
(Gains) losses on sales of investments 4 (603 )
Losses on purchases of debt 44
Premium on purchase of preferred shares of a subsidiary 69
Other (2 ) 2  
 
Adjusted net income available to common stockholders(a) 799 132
Preferred stock dividends 128 128
Earnings allocated to participating securities 14    
Total adjusted net income $ 941   $ 260  
 
Weighted average fully diluted shares outstanding (in millions)(b) 763 753
 
Adjusted earnings per share assuming dilution(a) $ 1.23 $ 0.35
 

(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 adjusted 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.
 
     

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)
             
THREE MONTHS ENDED:  

September 30,2013
 

June 30,2013
 

September 30,2012
 
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,356 $ 1,281 $ 949
Changes in assets and liabilities 12   89   169  
OPERATING CASH FLOW(a) $ 1,368   $ 1,370   $ 1,118  
 
             
THREE MONTHS ENDED:  

September 30,2013
 

June 30,2013
 

September 30,2012
 
NET INCOME $ 240 $ 625 $ (1,971 )
Interest expense 40 104 36
Income tax expense (benefit) 147 384 (1,260 )
Depreciation and amortization of other assets 79 76 66
Natural gas, oil and NGL depreciation, depletion and amortization 652   645   762  
EBITDA(b) $ 1,158   $ 1,834   $ (2,367 )
 
             
THREE MONTHS ENDED:  

September 30,2013
 

June 30,2013
 

September 30,2012
 
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,356 $ 1,281 $ 949
Changes in assets and liabilities 12 89 169
Interest expense, net of unrealized gains (losses) on derivatives 40 53 36
Unrealized gains (losses) on natural gas, oil and NGL derivatives (191 ) 576 (104 )
Net gains (losses) on sales of fixed assets 132 109 (7 )
Impairment of natural gas and oil properties (3,315 )
Impairments of fixed assets and other (59 ) (231 ) (14 )
Restructuring and other termination benefits (60 ) 1 (4 )
Gains (losses) on sales of investments 3 (10 ) 31
Earnings (losses) on investments (23 ) 22 (27 )
Stock-based compensation (22 ) (24 ) (30 )
Losses on purchases of debt (17 )
Other items (30 ) (15 ) (51 )
EBITDA(b) $ 1,158   $ 1,834   $ (2,367 )
 

(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 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 interest expense, income taxes, 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.
 
   

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)
         
NINE MONTHS ENDED:  

September 30,2013
 

September 30,2012
 
CASH PROVIDED BY OPERATING ACTIVITIES $ 3,561 $ 1,978
Changes in assets and liabilities 352   946  
OPERATING CASH FLOW(a) $ 3,913   $ 2,924  
 
         
NINE MONTHS ENDED:  

September 30,2013
 

September 30,2012
 
NET INCOME (LOSS) $ 967 $ (938 )
Interest expense, net of unrealized gains 164 63
Income tax expense (benefit) 594 (599 )
Depreciation and amortization of other assets 234 233
Natural gas, oil and NGL depreciation, depletion and amortization 1,945   1,856  
EBITDA(b) $ 3,904   $ 615  
 
         
NINE MONTHS ENDED:  

September 30,2013
 

September 30,2012
 
CASH PROVIDED BY OPERATING ACTIVITIES $ 3,561 $ 1,978
Changes in assets and liabilities 352 946
Interest expense, net of unrealized gains on derivatives 107 63
Unrealized gains on natural gas, oil and NGL derivatives 238 436
Net gains (losses) on sales of fixed assets 290 (6 )
Impairment of natural gas and oil properties (3,315 )
Impairments of fixed assets and other (317 ) (256 )
Restructuring and other termination benefits (164 ) (4 )
Gains (losses) on sales of investments (7 ) 1,061
Losses on investments (30 ) (147 )
Impairment of investment (10 )
Stock-based compensation (78 ) (93 )
Losses on purchases of debt (12 )
Other items (26 ) (48 )
EBITDA(b) $ 3,904   $ 615  
 

(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 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 interest expense, income taxes, 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.
 
   

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)
             
THREE MONTHS ENDED:   September 30,2013   June 30,2013   September 30,2012
 
EBITDA $ 1,158 $ 1,834 $ (2,367 )
 
Adjustments:
Unrealized (gains) losses on natural gas, oil and NGL derivatives 191 (576 ) 104
Impairment of natural gas and oil properties 3,315
Net (gains) losses on sales of fixed assets (132 ) (109 ) 7
Impairments of fixed assets and other 89 231 38

Net income attributable to noncontrolling interests
(38 ) (45 ) (41 )
(Gains) losses on sales of investments (3 ) 10 (31 )
Losses on purchases of debt 70
Restructuring and other termination benefits 63 7 3
Other (3 ) 2   (4 )
 
Adjusted EBITDA(a) $ 1,325   $ 1,424   $ 1,024  
 
         
NINE MONTHS ENDED:   September 30,2013   September 30,2012
 
EBITDA $ 3,904 $ 615
 
Adjustments:
Unrealized gains on natural gas, oil and NGL derivatives (238 ) (436 )
Impairment of natural gas and oil properties 3,315
Impairment of investment 10
Net (gains) losses on sales of fixed assets (290 ) 5
Impairments of fixed assets and other 347 281
Net income attributable to noncontrolling interests (127 ) (131 )
(Gains) losses on sales of investments 7 (988 )
Losses on purchases of debt 70
Restructuring and other termination benefits 203 4
Other (3 ) (3 )
 
Adjusted EBITDA(a) $ 3,883   $ 2,662  
 

(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.
 

SCHEDULE "A” MANAGEMENT’S OUTLOOK AS OF NOVEMBER 6, 2013

Chesapeake periodically provides management guidance on certain factors that affect its future financial performance. The primary changes from the company’s August 1, 2013 Outlook are in italicized bold below.
 

Chesapeake Energy Corporation Consolidated Projections
 
Year Ending

12/31/13
Estimated Production:
Natural gas – bcf 1,080 – 1,090
Oil – mbbls 40,000 – 42,000
NGL – mbbls(a) 20,000 – 21,000
Natural gas equivalent – bcfe 1,440 – 1,468
 
Daily natural gas equivalent midpoint – mmcfe 3,985
 
YOY estimated production increase (adjusted for planned asset sales) 3%
 
NYMEX Price(b) (for calculation of realized hedging effects only):
Natural gas - $/mcf $3.67
Oil - $/bbl $98.60
 
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf $0.00
Oil - $/bbl ($3.17)
 
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
Natural gas - $/mcf $1.30 – 1.50
Oil - $/bbl $1.00 – 3.00
NGL - $/bbl $70.50 – 74.50
 
Operating Costs per Mcfe of Projected Production:
Production expense $0.80 – 0.85
Production taxes $0.15 – 0.20
General and administrative(c) $0.25 – 0.30
Stock-based compensation (noncash) $0.04 – 0.06
DD&A of natural gas and liquids assets $1.65 – 1.85
Depreciation of other assets $0.20 – 0.25
Interest expense(d) $0.10 – 0.15
 
Other ($ millions):
Marketing, gathering and compression net margin(e) $100 – 125
Oilfield services net margin(e) $125 – 175
Net income attributable to noncontrolling interests and other(f) ($160 – 200)
 
Book Tax Rate 38%

 
Weighted average shares outstanding (in millions):
Basic 650 – 655
Diluted 760 – 765
 
Operating cash flow before changes in assets and liabilities(g)(h)(i) $5,050 – 5,100
Drilling and completion costs on proved and unproved properties ($5,500 – 5,800)
Acquisition of unproved properties, net ($200 – 250)
 

a) Reflects actual and assumed ethane rejection in the 2013 second quarter through 2013 fourth quarter.

b) NYMEX natural gas and oil prices have been updated for actual contract prices through October and September, respectively.

c) Excludes expenses associated with stock-based compensation and restructuring and other termination benefits.

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 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 $3.75 per mcf and $100.00 per bbl in 2013.

i) Excludes the expected impact of fourth quarter cash charges related to lease termination and financing extinguishment costs.
 

Natural Gas, Oil and NGL Hedging Activities

Chesapeake enters into natural gas, oil and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end and year-end derivative positions and accounting for natural gas, oil and NGL derivatives.

The company’s natural gas hedging positions as of November 5, 2013 were as follows:

                       

Open Natural Gas Swaps; Gains (Losses) from Closed

Natural Gas Trades and Call Option Premiums
 
      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
Q4 2013     190       $ 3.71       260       73%     $ (3 )     $ (0.01 )
Total 2014     233       $ 4.23                   $ (74 )      
Total 2015     0       -                 $ (131 )      
Total 2016 – 2022     0       -                 $ (187 )      
 
                       

Natural Gas Three-Way Collars
 
      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
Q4 2013     18     $ 3.03       $ 3.55       $ 4.03       260       7%
Total 2014     18     $ 3.50       $ 4.00       $ 4.70              
 
               

Natural Gas Swaptions
 
      Swaptions

(bcf)
    Avg. NYMEX

Strike Price
    Forecasted

Natural Gas

Production

(bcf)
    Swaptions

as a % of

Forecasted Natural

Gas

Production
Q4 2013     0     $       260       0%
Total 2014     12     $ 4.80              
 
               

Natural Gas Written Call Options
 
      Call Options

(bcf)
    Avg. NYMEX

Strike Price
    Forecasted

Natural Gas

Production

(bcf)
    Call Options

as a % of

Forecasted Natural

Gas

Production
Q4 2013     0     $       260       0%
Total 2016 – 2020     193     $ 9.92              
 
       

Natural Gas Basis Protection Swaps
 
      Volume

(bcf)
    Avg. NYMEX less
Q4 2013     11     $ 0.21
Total 2014     28     $ 0.32
Total 2015     31     $ 0.34
Total 2016 - 2022     8     $ 1.02
 

The company’s crude oil hedging positions as of November 5, 2013 were as follows:
                       

Open Crude Oil Swaps; Gains (Losses) from Closed

Crude Oil Trades and Call Option Premiums
 
      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 2013     9,181       $ 95.59       10,140       91%     $ 2       $0.18
Total 2014     21,750       $ 93.79                   $ (176 )      
Total 2015     693       $ 89.48                   $ 252        
Total 2016 – 2022     0       $                   $ 117        
 
               

Crude Oil Swaptions
 
      Swaptions

(mbbls)
    Avg. NYMEX

Strike Price
    Forecasted

Natural Gas

Production

(mbbls)
    Swaptions

as a % of

Forecasted Natural

Gas

Production
Q4 2013     0     $       10,140       0%
Total 2014     2,920     $ 106.69              
Total 2015     2,368     $ 106.61              
 
               

Crude Oil Written Call Options
 
      Call Options

(mbbls)
    Avg. NYMEX

Strike Price
    Forecasted

Oil

Production

(mbbls)
    Call Options

as a % of

Forecasted Oil

Production
Q4 2013     1,975     $ 97.90       10,140       19%
Total 2014     6,697     $ 93.90              
Total 2015     15,823     $ 93.12              
Total 2016 – 2017     24,220     $ 100.07              
 
       

Crude Oil Basis Protection Swaps
 
      Volume (mbbls)     Avg. NYMEX plus
Q4 2013     92     $ 6.00
Total 2014     365     $ 6.00
 

Copyright Business Wire 2010

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