Chesapeake Energy Corporation Reports Financial and Operational Results for the 2014 First Quarter

OKLAHOMA CITY--()--Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2014 first quarter. Key information related to the first quarter and the company's full-year 2014 Outlook is as follows:

  • 2014 first quarter adjusted net income per fully diluted share increases 97% to $0.59 from $0.30 in the 2013 first quarter
  • Adjusted ebitda increases 34% year over year to $1.5 billion
  • Average production of 675,200 boe per day increases 11% year over year, adjusted for 2013 asset sales
  • Total capital expenditures of $850 million decrease approximately 50% year over year
  • 2014 full-year adjusted production growth outlook increased to 9 – 12% from 8 – 10%
  • 2014 full-year operating cash flow outlook raised to $5.8 – $6.0 billion from $5.1 – $5.3 billion

Doug Lawler, Chesapeake’s Chief Executive Officer, commented, "This was an important and defining quarter for Chesapeake, as our competitive capital allocation, cost leadership and capital efficiency initiatives are driving tangible improvements in the company's growth profile and financial performance. We are raising our 2014 total production growth outlook on an adjusted basis to 9 – 12% to reflect higher-than-expected natural gas liquids volumes. Additionally, we are raising the midpoint of our 2014 operating cash flow outlook by $700 million, or 13%, due primarily to our increased production outlook, better-than-expected first quarter cash flow and an increase in our benchmark commodity price assumptions for the full year."

For the 2014 first quarter, Chesapeake reported net income available to common stockholders of $374 million, or $0.54 per fully diluted share. Items typically excluded by securities analysts in their earnings estimates reduced net income available to common stockholders for the 2014 first quarter by approximately $31 million on an after-tax basis. Adjusting for these items, 2014 first quarter net income available to common stockholders was $405 million, or $0.59 per fully diluted share, which compares to adjusted net income available to common stockholders of $183 million, or $0.30 per fully diluted share, in the 2013 first quarter. This increase is primarily the result of substantially higher year-over-year realized natural gas prices, higher oil and natural gas liquids (NGL) production and lower per unit production and general and administrative (G&A) expenses, partially offset by higher interest expense during the quarter.

Adjusted ebitda was $1.515 billion in the 2014 first quarter, an increase of 34% year over year. Operating cash flow, which is cash flow provided by operating activities before changes in assets and liabilities, was $1.614 billion in the 2014 first quarter, an increase of 37% year over year.

Adjusted net income available to common stockholders, operating cash flow, ebitda and adjusted ebitda are non-GAAP financial measures. Reconciliations of these measures to comparable financial measures calculated in accordance with generally accepted accounting principles are provided on pages 12 14 of this release.

2014 First Quarter Average Daily Production of 675 Mboe Increases 11% Year over Year, Adjusted for 2013 Asset Sales

Chesapeake’s daily production for the 2014 first quarter averaged 675,200 barrels of oil equivalent (boe), a year-over-year increase of 11%, adjusted for asset sales. Average daily production consisted of approximately 109,500 barrels (bbls) of oil, 84,200 bbls of NGL and 2.9 billion cubic feet (bcf) of natural gas. Chesapeake estimates that weather-related downtime adversely impacted its production during the 2014 first quarter by approximately 7,600 boe per day, predominantly in the Mid-Continent region. This production loss was within the range of Chesapeake's budgeted winter weather downtime, which was previously accounted for in the company's 2014 Outlook issued on February 6, 2014.

On an adjusted basis, 2014 first quarter average daily oil production increased 20% year over year, average daily NGL production increased 63% year over year and natural gas production increased 4% year over year.

Chesapeake Realizes Substantially Higher Natural Gas Prices during the 2014 First Quarter

Chesapeake's realized natural gas price increased to $3.27 per thousand cubic feet (mcf) during the 2014 first quarter from $1.90 per mcf in the 2013 fourth quarter, or approximately 72%. The increase was due to higher natural gas prices in general resulting from cold winter temperatures as well as Chesapeake's increased access to premium priced markets in the Northeast. More specifically, the company had firm natural gas transportation capacity commitments in place that enabled it to access the New York City market where natural gas prices during the 2014 first quarter traded at a substantial premium to NYMEX Henry Hub benchmark prices. As a result, Chesapeake's natural gas price differential on a companywide basis decreased to $1.08 per mcf in the 2014 first quarter from $1.76 per mcf in the 2013 fourth quarter.

Asset Sales Update

Chesapeake continues to pursue opportunities to high-grade its portfolio to focus on assets that best fit its strategy of profitable growth from captured resources. The company believes its targeted asset dispositions will be value-accretive and enable it to further reduce financial complexity and lower overall leverage.

During the 2014 first quarter the company received total proceeds of approximately $520 million from asset sales, including $209 million of net proceeds from the sale of its common equity ownership interest in Chaparral Energy, Inc.; $159 million from the sale of compression units to Access Midstream Partners, L.P. (NYSE:ACMP); and $152 million of net proceeds from the sale of real estate and other noncore assets. Additionally, Chesapeake received $362 million in April upon the closing of the previously announced sale of compression assets to Exterran Partners, L.P. (NASDAQ:EXLP). Along with proceeds from other miscellaneous asset sales, this brings year-to-date asset sale proceeds to more than $925 million. Chesapeake will provide an update on additional projected asset sales for the remainder of the year in conjunction with its Analyst Day on May 16.

On February 24, 2014, Chesapeake announced that it is pursuing strategic alternatives for its oilfield services division, Chesapeake Oilfield Services (COS), including a potential spin-off to Chesapeake shareholders or an outright sale. The company continues to evaluate both alternatives and will provide an update upon final determination of the path forward. Potential proceeds or dividend to Chesapeake upon the sale or spin-off of COS would be incremental to the anticipated asset sales detailed above.

Capital Spending and Cost Overview

Chesapeake's total capital expenditures in the 2014 first quarter were approximately $850 million, of which drilling and completion capital expenditures were approximately $729 million. The company invested cash of $882 million during the 2014 first quarter in drilling and completion activities, which was partially offset by lower-than-estimated drilling and completion costs and other adjustments, related to prior periods, of approximately $153 million. This level of expenditures represents a decrease of approximately $422 million, or 37%, compared to the 2013 fourth quarter. The sequential decrease is primarily the result of improving capital efficiencies and approximately 15% fewer well completions.

Net expenditures for the acquisition of unproved properties were approximately $24 million and other capital expenditures were approximately $97 million. In addition, the company purchased rigs and compressors previously sold under long-term lease arrangements for approximately $340 million as part of a strategic initiative to reduce complexity and future commitments as well as to facilitate asset sales and a possible spin-off or sale of COS.

Chesapeake spud a total of 299 gross wells and completed 234 gross wells during the 2014 first quarter, compared to 239 gross wells spud and 274 gross wells completed during the 2013 fourth quarter. Given expected increases in completion activity during the remainder of 2014, the company is reiterating its full-year capital expenditure guidance of $5.2 - $5.6 billion. Chesapeake plans to run a more balanced pace of drilling and completion operations in 2014 than it did 2013, when it substantially reduced its inventory of nonproducing wells.

Chesapeake's focus on cost leadership continues to generate reductions in production and G&A expenses. Average production expenses during the 2014 first quarter were $4.73 per boe, a decrease of 8% from the 2013 first quarter. G&A expenses (excluding share-based compensation and restructuring and other termination costs) during the 2014 first quarter were $1.09 per boe, a decrease of 27% from the 2013 first quarter. Interest expense (excluding unrealized gains or losses on interest rate derivatives) during the 2014 first quarter was $0.90 per boe, compared to $0.25 per boe in the 2013 first quarter, as the company capitalized a smaller percentage of its interest cost due to a decrease in the balance of its unevaluated natural gas and oil properties.

A complete summary of the company’s guidance for 2014 is provided in the Outlook dated May 7, 2014, attached to this release as Schedule "A” beginning on Page 15.

Operational Update Key Assets

The company continues to achieve strong operational results and well-cost reductions in each of its most active plays.

Eagle Ford Shale (South Texas): Eagle Ford net production averaged approximately 88,000 boe per day (187,000 gross operated boe per day) during the 2014 first quarter. Adjusted for 2013 asset sales, this represents an increase of 26% year over year and 1% sequentially. First quarter production was adversely impacted by temporary downtime at gas gathering and processing facilities, operated and competitor offset activity-related shut-ins and weather-related activity reductions. These issues have moderated during April and May, and the company is projecting a higher sequential quarterly growth trajectory for Eagle Ford production during the remainder of the year. Approximately 64% of the company’s Eagle Ford production in the 2014 first quarter was oil, 15% was NGL and 21% was natural gas.

Chesapeake operated an average of 18 rigs and connected 81 gross wells to sales during the 2014 first quarter in the Eagle Ford, compared to 12 average operated rigs and 65 gross wells connected to sales during the 2013 fourth quarter. The average peak production rate of the 81 wells that commenced first production in the Eagle Ford during the 2014 first quarter was approximately 885 boe per day.

As of March 31, 2014, Chesapeake had 945 producing wells and 114 wells awaiting pipeline connection or in various stages of completion in the Eagle Ford.

Mid-Continent (Oklahoma, Texas Panhandle, southern Kansas): Chesapeake's production in the Mid-Continent comes primarily from five plays: the Mississippi Lime, Granite Wash, Cleveland, Tonkawa and Hogshooter. Aggregate net production from these plays during the 2014 first quarter averaged 101,000 boe per day (177,000 gross operated boe per day). Adjusted for 2013 asset sales, Mid-Continent production increased 4% year over year and decreased 3% sequentially. The sequential production decrease compared to the 2013 fourth quarter was primarily driven by the impact of severe winter weather during the 2014 first quarter as well as fewer new well connections. Approximately 32% of the company’s Mid-Continent production during the 2014 first quarter was oil, 24% was NGL and 44% was natural gas.

During the 2014 first quarter Chesapeake operated an average of 17 rigs and connected 52 gross wells to sales, compared to 17 average operated rigs and 70 gross wells connected to sales during the 2013 fourth quarter. The average peak production rate of the 52 wells that commenced first production in the Mid-Continent during the 2014 first quarter was approximately 925 boe per day.

As of March 31, 2014, the company had 42 wells awaiting pipeline connection or in various stages of completion in the Mid-Continent.

Utica Shale (Ohio, Pennsylvania, West Virginia): Utica net production averaged approximately 50,000 boe per day (90,000 gross operated boe per day) during the 2014 first quarter, an increase of 422% year over year and 59% sequentially from the 2013 fourth quarter. Approximately 10% of the company’s Utica production during the 2014 first quarter was oil, 30% was NGL and 60% was natural gas.

During the 2014 first quarter Chesapeake operated an average of nine rigs and connected 47 gross wells to sales in the Utica, compared to nine average operated rigs and 49 gross wells connected to sales during the 2013 fourth quarter. The average peak production rate of the 47 wells that commenced first production in the Utica during the 2014 first quarter was approximately 1,180 boe per day.

As of March 31, 2014, Chesapeake had drilled a total of 485 wells in the Utica, which included 274 producing wells and 211 wells awaiting pipeline connection or in various stages of completion.

Haynesville Shale (Northwest Louisiana, East Texas): Chesapeake’s 2014 first quarter average net production in the Haynesville was approximately 495 million cubic feet of natural gas equivalent (mmcfe) per day (780 gross operated mmcfe per day). Adjusted for 2013 asset sales, this represents a decrease of 41% year over year and 8% sequentially. Based on the company's current drilling program, net Haynesville production is expected to return to sequential growth in the 2014 third quarter. All of the company's production in the Haynesville consists of natural gas.

During the 2014 first quarter Chesapeake operated an average of seven rigs and connected seven gross wells to sales, compared to four average operated rigs and 12 gross wells connected to sales during the 2013 fourth quarter. The company has achieved substantial drilling and completion cost reductions in the Haynesville. Most notably, two wells were drilled and completed during the 2014 first quarter for approximately $7 million each. The average peak production rate of the seven wells that commenced first production in the Haynesville during the 2014 first quarter was approximately 13.1 mmcfe per day.

As of March 31, 2014, Chesapeake had 14 wells awaiting pipeline connection or in various stages of completion in the Haynesville.

Northern Marcellus Shale (Pennsylvania): Chesapeake's production from the northern Marcellus continued to grow during the 2014 first quarter. Average net production in this play was approximately 910 mmcfe per day (2,180 gross operated mmcfe per day), an increase of 28% year over year and 3% sequentially. All of the company's production in the northern Marcellus consists of natural gas.

During the 2014 first quarter Chesapeake operated an average of five rigs and connected 22 gross wells to sales, compared to five average operated rigs and 33 gross wells connected to sales during the 2013 fourth quarter. The average peak production rate of the 22 wells that commenced first production in the northern Marcellus during the 2014 first quarter was approximately 10.9 mmcfe per day.

As of March 31, 2014, Chesapeake had 110 wells awaiting pipeline connection or in various stages of completion in the northern Marcellus.

Key Financial and Operational Results

The table below summarizes Chesapeake’s key financial and operational results during the 2014 first quarter and compares them to results in prior periods.

  Three Months Ended
03/31/14   12/31/13   03/31/13
Oil equivalent production (in mmboe) 60.8 61.2 59.7
Oil production (in mmbbls) 9.9 10.2 9.3
Average realized oil price ($/bbl)(a) 85.08 89.58 94.85
Oil as % of total production 16 17 16
NGL production (in mmbbls) 7.6 5.9 4.9
Average realized NGL price ($/bbl)(a) 29.23 31.76 28.25
NGL as % of total production 13 9 8
Natural gas production (in bcf) 260 271 273
Average realized natural gas price ($/mcf)(a) 3.27 1.90 2.13
Natural gas as % of total production 71 74 76
Production expenses ($/boe) (4.73 ) (4.62 ) (5.14 )
Production taxes ($/boe) (0.83 ) (0.91 ) (0.89 )
General and administrative costs ($/boe)(c) (1.09 ) (1.79 ) (1.50 )
Share-based compensation ($/boe) (0.21 ) (0.19 ) (0.34 )
DD&A of natural gas and liquids properties ($/boe) (10.33 ) (10.53 ) (10.86 )
D&A of other assets ($/boe) (1.29 ) (1.32 ) (1.31 )
Interest expense ($/boe)(a) (0.90 ) (0.86 ) (0.25 )
Capitalized interest ($ in millions) 178 182 228
Marketing, gathering and compression net margin

($ in millions)(d)

35 9 36
Oilfield services net margin ($ in millions)(d) 45 52 35
Operating cash flow ($ in millions)(e) 1,614 995 1,179
Operating cash flow ($/boe) 26.55 16.27 19.75
Adjusted ebitda ($ in millions)(f) 1,515 1,132 1,134
Adjusted ebitda ($/boe) 24.94 18.51 19.00
Net income (loss) available to common stockholders

($ in millions)

374 (159 ) 15
Earnings (loss) per share – diluted ($) 0.54 (0.24 ) 0.02
Adjusted net income available to common

stockholders ($ in millions)(g)

405 161 183
Adjusted earnings per share – diluted ($) 0.59 0.27 0.30

(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 share-based compensation and restructuring and other termination costs.
(d) Includes revenue and operating expenses and excludes depreciation and amortization of other 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 14.
(g) Defined as net income available to common stockholders, as adjusted to remove the effects of certain items detailed on Page 12.

2014 First Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled for Wednesday, May 7, 2014, at 9:00 am EDT. The telephone number to access the conference call is 913-312-0823 or toll-free 877-627-6580. The passcode for the call is 5839213. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EDT. For those unable to participate in the conference call, a replay will be available for audio playback at 2:00 pm EDT on Wednesday, May 7, 2014, and will run through 2:00 pm EDT on Wednesday, May 21, 2014. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 5839213. 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 website.

Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas and the 10th 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 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 production forecasts, estimates of operating costs, planned development drilling, expected capital expenditures, expected efficiency gains, anticipated asset sales and proceeds to be received therefrom, 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 include those described under "Risk Factors” in Item 1A of our 2013 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 27, 2014. 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; a deterioration in general economic, business or industry conditions having 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; adverse developments and losses in connection with pending or future litigation and regulatory investigations; cyber attacks adversely impacting our operations; and an interruption at our headquarters that adversely affects our business.

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, the timing of and amount of proceeds from future asset sales, which are subject to changes in market conditions and other factors beyond our control, will affect our ability to further reduce financial leverage and complexity. Any separation of COS is subject to satisfaction of several conditions, some of which are beyond our control, including market conditions, board approvals, consents, regulatory review and approvals, among others. There can be no assurance that the proposed separation will lead to a sale or spin-off or any other transaction, or that if any transaction is pursued, it will be consummated. 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 any of the information provided in this release or the accompanying Outlook, except as required by applicable law.

   
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per share data)
(unaudited)
                 
   

Three Months Ended
March 31,

  2014 2013
REVENUES:
Natural gas, oil and NGL $ 1,766 $ 1,453
Marketing, gathering and compression 3,015 1,781
Oilfield services   265     190  
Total Revenues   5,046     3,424  
 
OPERATING EXPENSES:
Natural gas, oil and NGL production 288 307
Production taxes 50 53
Marketing, gathering and compression 2,980 1,745
Oilfield services 220 155
General and administrative 79 110
Restructuring and other termination costs (7 ) 133
Natural gas, oil and NGL depreciation, depletion and

amortization

628 648
Depreciation and amortization of other assets 78 78
Impairments of fixed assets and other 20 27
Net gains on sales of fixed assets   (23 )   (49 )
Total Operating Expenses   4,313     3,207  
 
INCOME FROM OPERATIONS   733     217  
 
OTHER INCOME (EXPENSE):
Interest expense (39 ) (21 )
Losses on investments (21 ) (37 )
Net gains on sales of investments 67
Other income   6     6  
Total Other Income (Expense)   13     (52 )
 
INCOME BEFORE INCOME TAXES 746 165
 
INCOME TAX EXPENSE:
Current income taxes 3 1
Deferred income taxes   277     62  
Total Income Tax Expense   280     63  
 
NET INCOME 466 102
 
Net income attributable to noncontrolling interests   (41 )   (44 )
 
NET INCOME ATTRIBUTABLE TO CHESAPEAKE   425     58  
 
Preferred stock dividends (43 ) (43 )
Earnings allocated to participating securities   (8 )    
 
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS $ 374   $ 15  
 
EARNINGS PER COMMON SHARE:
Basic $ 0.57   $ 0.02  
Diluted $ 0.54   $ 0.02  
 
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic   658     651  
Diluted   765     651  
 
   
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
 
   

March 31,
2014

 

December 31,
2013

 
Cash and cash equivalents $ 1,004 $ 837
Other current assets   3,271     2,819
Total Current Assets   4,275     3,656
 
Property and equipment, (net) 37,522 37,134
Other assets   808     992
Total Assets $ 42,605   $ 41,782
 
Current liabilities $ 5,958 $ 5,515
Long-term debt, net of discounts 12,653 12,886
Other long-term liabilities 1,689 1,834
Deferred income tax liabilities   3,828     3,407
Total Liabilities   24,128     23,642
 
Preferred stock 3,062 3,062
Noncontrolling interests 2,136 2,145
Common stock and other stockholders’ equity   13,279     12,933
Total Equity   18,477     18,140
 
Total Liabilities and Equity $ 42,605   $ 41,782
 
Common Shares Outstanding (in millions)   663     664
 
   
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
 
   

March 31,
2014

 

December 31,
2013

 
Total debt, net of unrestricted cash $ 11,965 $ 12,049
Preferred stock 3,062 3,062
Noncontrolling interests(a) 2,136 2,145
Common stock and other stockholders’ equity   13,279     12,933  
Total $ 30,442   $ 30,189  
 
Total debt to capitalization ratio

39

%

40

%

 

(a) Includes third-party ownership as follows:

 
CHK Cleveland Tonkawa, L.L.C. $ 1,015 $ 1,015
CHK Utica, L.L.C. 807 807
Chesapeake Granite Wash Trust 306 314
Other   8     9  
Total $ 2,136   $ 2,145  
 
   
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - NATURAL GAS, OIL AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)
                 

Three Months Ended
March 31,

2014 2013
Net Production:
Natural gas (bcf) 260.0 273.1
Oil (mmbbl) 9.9 9.3
NGL (mmbbl) 7.6 4.9
Oil equivalent (mmboe) 60.8 59.7
 
Natural Gas, Oil and NGL Sales ($ in millions):
Natural gas sales $ 1,005 $ 573
Natural gas derivatives – realized gains (losses)(a) (154 ) 8
Natural gas derivatives – unrealized gains (losses)(a)   (154 )   (278 )
Total Natural Gas Sales   697     303  
 
Oil sales 922 884
Oil derivatives – realized gains (losses)(a) (84 ) (4 )
Oil derivatives – unrealized gains (losses)(a)   10     132  
Total Oil Sales   848     1,012  
 
NGL sales 221 138
NGL derivatives – realized gains (losses)(a)
NGL derivatives – unrealized gains (losses)(a)        
Total NGL Sales   221     138  
Total Natural Gas, Oil and NGL Sales $ 1,766   $ 1,453  
 
Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf) $ 3.86 $ 2.10
Oil ($ per bbl) $ 93.60 $ 95.23
NGL ($ per bbl) $ 29.23 $ 28.25
Oil equivalent ($ per boe) $ 35.35 $ 26.71
 
Average Sales Price – including realized gains (losses) on derivatives:
Natural gas ($ per mcf) $ 3.27 $ 2.13
Oil ($ per bbl) $ 85.08 $ 94.85
NGL ($ per bbl) $ 29.23 $ 28.25
Oil equivalent ($ per boe) $ 31.44 $ 26.79
 
Interest Expense (Income) ($ in millions):
Interest(b) $ 58 $ 17
Derivatives – realized (gains) losses(c) (3 ) (2 )
Derivatives – unrealized (gains) losses(c)   (16 )   6  
Total Interest Expense $ 39   $ 21  

(a) Realized gains and losses include the following items: (i) settlements of non-designated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period production revenues offset by amounts reclassified as realized gains and losses during the period. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program.
(b) Net of amounts capitalized.
(c) Realized (gains) losses include settlements related to the current period interest accrual and the effect of (gains) losses on early termination trades. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

   
 
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
                 
THREE MONTHS ENDED:   March 31,
2014
  March 31,
2013
 
Beginning cash $ 837   $ 287  
 
Cash provided by operating activities   1,291     924  
 
Cash flows from investing activities:

Drilling and completion costs on proved and unproved properties(a)

(894 ) (1,566 )
Acquisition of proved and unproved properties(b) (179 ) (255 )
Sale of proved and unproved properties 42 165
Geological and geophysical costs (4 ) (13 )
Cash paid to purchase leased rigs and compressors (340 )
Additions to other property and equipment (97 ) (330 )
Proceeds from sales of other assets 239 201
Additions to investments (3 ) (3 )
Proceeds from sales of investments 239
Other   (2 )   56  
Total cash used in investing activities   (999 )   (1,745 )
 
Cash provided by (used in) financing activities   (125 )   567  
Change in cash and cash equivalents   167     (254 )
Ending cash $ 1,004   $ 33  

(a) Includes capitalized interest of $12 million and $16 million for the three months ended March 31, 2014 and 2013, respectively.

(b) Includes capitalized interest of $158 million and $207 million for the three months ended March 31, 2014 and 2013, respectively.

     
 
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per share data)
(unaudited)
                         
THREE MONTHS ENDED:  

March 31,
2014

 

December 31,
2013

 

March 31,
2013

 

Net income (loss) available to common stockholders

$ 374 $ (159 ) $ 15
 
Adjustments, net of tax:
Unrealized losses on derivatives 80 13 94
Restructuring and other termination costs (4 ) 28 83
Impairments of fixed assets and other 12 126 16
Net gains on sales of fixed assets (14 ) (7 ) (30 )
Losses on investments 84 6
Net gains on sales of investments (42 )

Losses on purchases of debt and extinguishment of other financing

76
Other   (1 )       (1 )
 

Adjusted net income available to common stockholders(a)

405 161 183
Preferred stock dividends 43 43 43
Earnings allocated to participating securities   8          

Total adjusted net income attributable to Chesapeake

$ 456   $ 204   $ 226  
 

Weighted average fully diluted shares outstanding (in millions)(b)

767 767 761
 

Adjusted earnings per share assuming dilution(a)

$ 0.59 $ 0.27 $ 0.30

(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 OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
                         
THREE MONTHS ENDED:  

March 31,
2014

 

December 31,
2013

 

March 31,
2013

 
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,291 $ 1,028 $ 924
Changes in assets and liabilities   323     (33 )   255  
OPERATING CASH FLOW(a) $ 1,614   $ 995   $ 1,179  
 
                         
THREE MONTHS ENDED:  

March 31,
2014

 

December 31,
2013

 

March 31,
2013

 
NET INCOME (LOSS) $ 466 $ (74 ) $ 102
Interest expense 39 63 21
Income tax expense (benefit) 280 (45 ) 63
Depreciation and amortization of other assets 78 80 78
Natural gas, oil and NGL depreciation, depletion and amortization   628     644     648  
EBITDA(b) $ 1,491   $ 668   $ 912  
 
                         
THREE MONTHS ENDED:  

March 31,
2014

 

December 31,
2013

 

March 31,
2013

 
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,291 $ 1,028 $ 924
Changes in assets and liabilities 323 (33 ) 255
Interest expense, net of unrealized gains (losses) on derivatives 55 53 15
Natural gas, oil and NGL derivative gains (losses), net (382 ) (13 ) (142 )
Cash (receipts) payments on natural gas, oil and NGL derivative settlements, net 168 30 (19 )
Share-based compensation (20 ) (20 ) (32 )
Restructuring and other termination costs 9 (11 ) (105 )
Impairments of fixed assets and other (12 ) (166 ) (27 )
Net gains on sales of fixed assets 23 12 49
Losses on investments (21 ) (189 ) (39 )
Net gains on sales of investments 67
Losses on purchases of debt and extinguishment of other financing (3 )
Other items   (10 )   (20 )   33  
EBITDA(b) $ 1,491   $ 668   $ 912  

(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:  

March 31,
2014

 

December 31,
2013

 

March 31,
2013

 
EBITDA $ 1,491 $ 668 $ 912
 
Adjustments:
Unrealized losses on natural gas, oil and NGL derivatives 144 10 146
Restructuring and other termination costs (7 ) 45 133
Impairments of fixed assets and other 20 203 27
Net gains on sales of fixed assets (23 ) (12 ) (49 )
Losses on investments 136 10
Net gains on sales of investments (67 )
Losses on purchases of debt and extinguishment of other financing 123
Net income attributable to noncontrolling

interests

(41 ) (42 ) (44 )
Other   (2 )   1     (1 )
 
Adjusted EBITDA(a) $ 1,515   $ 1,132   $ 1,134  

(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 MAY 7, 2014
 

Chesapeake periodically provides management guidance on certain factors that affect the company’s future financial performance. The primary changes from the company’s February 6, 2014, Outlook are in italicized bold below.

 
Chesapeake Energy Corporation Consolidated Projections
 

Year Ending
12/31/2014

Production Growth (adjusted for 2013 asset sales)(a):
Liquids: 25 – 29%
Oil 8 – 12%
NGL(b) 58 – 63%
Natural gas 4 – 6%
Total Adjusted Production Growth 9 – 12%
Daily Equivalent Rate - mboe 690 – 710
NYMEX Price(c) (for calculation of realized hedging effects only):
Oil - $/bbl $95.92
Natural gas - $/mcf $4.62
Estimated Realized Hedging Effects(d) (based on assumed NYMEX prices above):
Oil - $/bbl ($6.15)
Natural gas - $/mcf ($0.31)
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
Oil - $/bbl $3.25 – 5.25
NGL - $/bbl $67.50 – 71.50
Natural gas - $/mcf $1.60 – 1.70
Operating Costs per Boe of Projected Production:
Production expense $4.25 – 4.75
Production taxes $0.85 – 0.95
General and administrative(e) $1.20 – 1.30
Share-based compensation (noncash) $0.15 – 0.20
DD&A of natural gas and liquids assets $10.00 – 11.00
Depreciation of other assets $1.20 – 1.30
Interest expense(f) $0.75 – 0.85
Other ($ millions):
Marketing, gathering and compression net margin(g) $50 – 75
Oilfield services net margin(g) $200 – 250
Net income attributable to noncontrolling interests and other(h) ($160 – 190)
Book Tax Rate 37.5%
Weighted Average Shares Outstanding (in millions):
Basic 657 – 661
Diluted 767 – 771
Operating Cash Flow before Changes in Assets and Liabilities ($ in millions) (i)(j)(k) $5,800 – 6,000
Total Capital Expenditures ($ in millions) $5,200 – 5,600
Capitalized interest, dividends and distributions ($ in millions) $1,150 – 1,200
 
a) Growth ranges based on 2013 production of 634 mboe/day adjusted for assets sales.

b) Assumes ethane recovery in the Utica and southern Marcellus to fulfill Chesapeake’s pipeline commitments, no ethane recovery in the Rockies and the Eagle Ford and partial ethane recovery in the Mid-Continent.

c) NYMEX natural gas and oil prices have been updated for actual contract prices through April and March, respectively.

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

e) Excludes expenses associated with share-based compensation and restructuring and other termination costs.
f) Excludes unrealized gains (losses) on interest rate derivatives.
g) Includes revenue and operating expenses and excludes depreciation and amortization of other assets.
h) Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica, LLC and CHK Cleveland Tonkawa, LLC.
i) 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.
j) Assumes NYMEX prices on open contracts of $95.00 per bbl and $4.50 per mcf and production growth ranges as shown above.
k) The new guidance presentation we have adopted includes only cash related hedging gains/losses and excludes noncash amortization. Previously our Outlook guidance treated all realized hedging gains/losses as cash and all unrealized gains/losses as noncash. However, a portion of our realized hedging gains/losses actually consists of noncash amortization from previously closed out hedges. Please note that cash flow from operating activities on a GAAP basis is unaffected by this presentation change.
 

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.

As of May 1, 2014, the company had downside protection on approximately 64% of its remaining projected 2014 natural gas production at an average price of $4.10 per mcf. Approximately 70% of the company's remaining projected 2014 oil production had downside protection at an average price of $94.32 per bbl.

The company’s natural gas hedging positions as of May 1, 2014, 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

 

Total Gains (Losses)
from Closed Trades
and Premiums
for Call Options
($ in millions)

Q2 2014 107 $ 4.08 $ (12 )
Q3 2014 112 4.09 (15 )
Q4 2014   112     4.08     (21 )
Total Q2 - Q4 2014   331   $ 4.08   $ (48 )
Total 2015   68   $ 4.63   $ (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

Q2 2014 51 $ 3.57 $ 4.09 $ 4.38
Q3 2014 57 3.55 4.09 4.38
Q4 2014   71     3.49     4.11     4.37
Total Q2 - Q4 2014   179   $ 3.53   $ 4.10   $ 4.38
Total 2015   207   $ 3.37   $ 4.29   $ 4.51
 
     

Natural Gas Collars

 
   

Open Collars
(bcf)

 

Avg. NYMEX
Bought Put Price

 

Avg. NYMEX
Bought Put Price

Q2 2014 2 $4.51 $5.25
Q3 2014 6 4.51 5.25
Q4 2014   6   4.51   5.25
Total Q2 - Q4 2014   14   $4.51   $5.25
 
   

Natural Gas Written Call Options

 
   

Call Options
(bcf)

 

Avg. NYMEX
Strike Price

Total 2016 – 2020   193   $ 9.92
 
   

Natural Gas Basis Protection Swaps

 
   

Volume
(bcf)

 

Avg. NYMEX
minus

Q2 2014 45 $ (0.53 )
Q3 2014 46 $ (0.53 )
Q4 2014   20   $ (0.49 )
Total Q2 - Q4 2014   111   $ (0.52 )
Total 2015   31   $ (0.34 )
Total 2016 - 2022   8   $ (1.02 )
 

The company’s crude oil hedging positions as of May 1, 2014, 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

 

Total Gains (Losses)
from Closed Trades and
Premiums for Call Options
($ in millions)

Q2 2014 8,076 $ 94.44 $ (46 )
Q3 2014 7,241 94.28 (48 )
Q4 2014   7,197     94.22     (49 )
Total Q2 - Q4 2014   22,514   $ 94.32   $ (143 )
Total 2015   1,689   $ 90.93   $ 245  
Total 2016 – 2022   0       $ 117  
 
   

Crude Oil Written Call Options

 
   

Call Options
(mbbls)

 

Avg. NYMEX
Strike Price

Q2 2014 619 $ 83.53
Q3 2014 626 83.53
Q4 2014   626     83.53
Total Q2 - Q4 2014   1,871   $ 83.53
Total 2015   13,434   $ 91.89
Total 2016 – 2017   24,220   $ 100.07
 
   

Crude Oil Basis Protection Swaps

 
    Volume (mbbls)   Avg. NYMEX plus
Q2 2014 91 $ 6.00
Q3 2014 92 6.00
Q4 2014   92     6.00
Total Q2 - Q4 2014   275   $ 6.00
 

Contacts

Chesapeake Energy Corporation
Investor Relations:
Gary T. Clark, CFA, 405-935-8870
ir@chk.com
or
Media Relations:
Gordon Pennoyer, 405-935-8878
media@chk.com

Sharing

Contacts

Chesapeake Energy Corporation
Investor Relations:
Gary T. Clark, CFA, 405-935-8870
ir@chk.com
or
Media Relations:
Gordon Pennoyer, 405-935-8878
media@chk.com