Chesapeake Energy Corporation Reports Financial and Operational Results for the 2013 Second Quarter
Chesapeake Energy Corporation Reports Financial and Operational Results for the 2013 Second Quarter
OKLAHOMA CITY--(BUSINESS WIRE)-- Chesapeake Energy Corporation (NYS: CHK) today reported financial and operational results for the 2013 second quarter. Key information related to the quarter is as follows:
- Adjusted net income per fully diluted share of $0.51, compared to $0.06 in the 2012 second quarter
- Adjusted ebitda of $1.424 billion increases 77% year over year
- Daily oil production rises 44% year over year to 116,000 bbls per day
- Full-year 2013 oil production outlook increases by 1 million barrels to 38 - 40 million barrels, a 22 to 28% increase year over year
- Total daily production increases 7% year over year to 4.1 bcfe per day
- Conference call at 9:00 am EDT today; dial-in 913-312-0968, passcode 3533928
Chesapeake reported net income available to common stockholders of $457 million, or $0.66 per fully diluted share. These results include the effects of the following after-tax items:
- noncash unrealized mark-to-market gains of $325 million from the company's derivative instruments;
- a noncash charge of $143 million for the impairment of certain of the company's property and equipment, consisting primarily of noncore real estate;
- a net gain of $68 million on sales of certain of the company's property and equipment, consisting primarily of midstream assets;
- a charge of $44 million on the repurchase of $1.894 billion aggregate principal amount of the company's senior notes; and
- a $69 million premium paid over the carrying value on the purchase of preferred shares of a company subsidiary.
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 $334 million, or $0.51 per fully diluted share, which compares to adjusted net income available to common stockholders of $3 million, or $0.06 per fully diluted share, in the 2012 second quarter.
The company reported adjusted ebitda of $1.424 billion, an increase of 77% year over year. Operating cash flow, which is cash flow provided by operating activities before changes in assets and liabilities, was $1.370billion, an increase of 53% 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, "Chesapeake reported a strong quarter operationally and financially. I am very excited and energized by what I have seen during my first six weeks with the company. Chesapeake has an exceptionally broad and deep asset base, which offers tremendous opportunity for value creation. A comprehensive companywide review of our capital allocation and other processes is underway and I believe these initiatives will result in substantial further improvement in both near-term and long-term capital efficiency and returns."
2013 Second Quarter Total Production Increases 7% Year over Year to 4.1 Bcfe per Day; Oil Production Increases 44% Year over Year to 116,000 Bbls per Day
Chesapeake's daily production for the 2013 second quarter averaged approximately 4.1 billion cubic feet of natural gas equivalent (bcfe), an increase of 7% from the 2012 second quarter and an increase of 2% from the 2013 first quarter. The company's average daily production consisted of approximately 3.1 billion cubic feet (bcf) of natural gas and approximately 168,000 barrels (bbls) of liquids, comprised of approximately 116,000 bbls of oil and approximately 52,000 bbls of natural gas liquids (NGL).
During the 2013 second quarter, average daily oil production increased 44% year over year and 12% sequentially, and average daily NGL production increased 5% year over year and decreased 4% sequentially. The sequential NGL volume decrease was primarily the result of increased ethane rejection during the second quarter. Liquids accounted for 25% of total production during the 2013 second quarter, up from 21% during the 2012 second quarter.
Steve Dixon, Chesapeake's Chief Operating Officer, commented, "We are raising our full-year 2013 oil production guidance by 1 million barrels (mmbbls) to 38 - 40 mmbbls, representing a growth rate of 22 to 28% year over year, due to good well performance, an accelerated pace of well completions in the Eagle Ford Shale and timing of asset sales. We are also reducing our 2013 NGL production guidance by 2 mmbbls to 21 - 23 mmbbls to reflect ethane rejection that occurred during the second quarter and thus far in the third quarter as well as anticipated delays associated with third-party gathering, compression and processing in the Utica Shale."
Capital Spending and Cost Overview
During the 2013 second quarter, Chesapeake operated an average of 76 rigs, a decrease of seven rigs compared to the 2013 first quarter, and invested approximately $1.6 billion in drilling and completion costs. This brings drilling and completion costs for the first half of 2013 to approximately $3.1 billion. Chesapeake spud a total of 312 wells and completed 410 wells during the 2013 second quarter, compared to 294 wells spud and 352 wells completed during the 2013 first quarter.
During the second half of 2013, Chesapeake plans to operate an average of 64 rigs compared to an average of 81 rigs during the first half of the year. The company also plans to complete approximately 20% fewer wells in the second half of 2013 compared to the first half of the year. Based on these planned activity levels, the company is reducing its 2013 full-year guidance for drilling and completion costs from a range of $5.75 - $6.25 billion to $5.7 -$6.0 billion.
Net expenditures for the acquisition of unproved properties were approximately $55 million during the 2013 second quarter, bringing 2013 first-half net expenditures for the acquisition of unproved properties to approximately $100 million. The company continues to track below its budgeted leasehold expenditures for the year and is lowering its 2013 full-year leasehold expenditure guidance from $400 million to $300 - $350 million. Other capital expenditures were approximately $190 million during the 2013 second quarter and $535 million during the first half of 2013.
Average production expenses during the 2013 second quarter were $0.78 per thousand cubic feet of natural gas equivalent (mcfe), a decrease of 20% year over year. General and administrative (G&A) expenses (excluding stock-based compensation) were $0.25 per mcfe, a decrease of 36% year over year. To reflect improvements in cost control, Chesapeake is reducing its 2013 per unit G&A expense guidance range by $0.05 to $0.25 - $0.30 per mcfe.
A complete summary of the company's guidance for 2013 is provided in the Outlook dated August 1, 2013 which is attached to this release as Schedule "A" beginning on Page 17. This updates information previously provided in the Outlook dated May 1, 2013.
Asset Sales Update
Chesapeake continues to make significant progress in selling noncore assets. During the first half of 2013, the company received proceeds of approximately $2.4 billion from asset sales. During the 2013 third quarter to date, the company has completed the sales of additional assets in the Haynesville Shale and Eagle Ford Shale to subsidiaries of EXCO Resources, Inc. (NYS: XCO) for total consideration of approximately $1 billion (inclusive of approximately $100 million that is subject to customary post-closing contingencies) and expects to complete today the sale of midstream assets in the Mississippi Lime play to SemGroup Corporation (NYS: SEMG) for total consideration of approximately $300 million. Chesapeake is also pursuing several other transactions of varying sizes that may reach completion before the end of 2013.
The company continues to achieve strong operational results in its most active plays, as highlighted below.
Eagle Ford Shale (South Texas): In the Eagle Ford Shale play, Chesapeake connected 140 wells to sales during the 2013 second quarter, which was substantially more than the 111 wells connected during the 2013 first quarter. Net production during the 2013 second quarter averaged approximately 85,000 barrels of oil equivalent (boe) per day (190,000 gross operated boe per day). This represents an increase of 135% year over year and 14% sequentially. The average peak daily production rate of the 140 wells that commenced first production during the 2013 second quarter was approximately 900 boe per day. Approximately 66% of the company's Eagle Ford production during the 2013 second quarter was oil, 14% was NGL and 20% was natural gas.
Chesapeake is currently operating 15 rigs in the Eagle Ford and, due to reduced cycle times and the sale discussed above, plans to reduce its operated rig count to 10 by the end of 2013. Average spud-to-spud cycle time during the quarter was 16 days, down from 21 days year over year. As of June 30, 2013, Chesapeake had drilled a total of 963 wells in the Eagle Ford, which included 795 producing wells, 24 additional wells waiting on pipeline connection and 144 wells in various stages of completion.
Utica Shale (eastern Ohio, Pennsylvania, West Virginia): Net production from the Utica Shale play averaged approximately 85 million cubic feet of natural gas equivalent (mmcfe) per day during the 2013 second quarter, an increase of 48% sequentially from the 2013 first quarter. The average peak daily production rate of the 42 wells that commenced first production in the Utica during the 2013 second quarter was approximately 6.6 mmcfe per day.
Chesapeake is currently operating 11 rigs in the Utica, which it plans to reduce to 10 rigs by year end. Average spud-to-spud cycle time during the quarter was 18 days, down from 26 days a year ago. As of June 30, 2013, Chesapeake had drilled a total of 321 wells in the Utica, which included 106 producing wells, 93 additional wells waiting on pipeline connection and 122 wells in various stages of completion.
Greater Anadarko Basin (Oklahoma, Texas Panhandle, southern Kansas): Chesapeake continues to generate steady liquids production growth in the Greater Anadarko Basin primarily from five plays: the Mississippi Lime, Granite Wash, Cleveland, Tonkawa and Hogshooter. Aggregate net production from these plays during the 2013 second quarter averaged 126,000 boe per day (192,000 gross operated boe per day), an increase of 43% year over year and 11% sequentially. The average peak daily production rate of the 123 wells that commenced first production in the Greater Anadarko Basin during the 2013 second quarter was approximately 800 boe per day. Approximately 38% of the company's Greater Anadarko Basin production during the 2013 second quarter was oil, 18% was NGL and 44% was natural gas.
Chesapeake is currently operating 26 rigs across these plays, which it plans to reduce to 19 rigs by year end. As of June 30, 2013, the company had an inventory of 58 drilled but uncompleted and/or unconnected wells in the Greater Anadarko Basin.
Marcellus Shale (Pennsylvania, West Virginia): The company's production from the Marcellus Shale continued to grow during the 2013 second quarter, benefiting from the availability of downstream takeaway capacity and the completion of wells in backlog. Chesapeake connected 131 wells to sales during the 2013 second quarter, which was substantially more than the 52 wells connected during the 2013 first quarter. Approximately 2% of the company's Marcellus production during the 2013 second quarter was oil, 3% was NGL and 95% was natural gas.
During the 2013 second quarter, Chesapeake's average daily net production in the northern dry- gas portion of the Marcellus was approximately 780 mmcfe per day (1,810 gross operated mmcfe per day), an increase of 58% year over year and 11% sequentially. The average peak daily production rate of the 79 wells that commenced first production during the 2013 second quarter in the northern Marcellus was approximately 9 mmcfe per day.
Chesapeake is currently operating five rigs in the northern dry-gas portion of the play and anticipates maintaining this activity level for the remainder of 2013. Average spud-to-spud cycle time during the 2013 second quarter was 29 days, down from 31 days a year ago. As of June 30, 2013, Chesapeake had an inventory of 144 drilled but uncompleted and/or unconnected wells in the northern Marcellus.
During the 2013 second quarter, Chesapeake's average daily net production in the southern wet-gas portion of the Marcellus was approximately 208 mmcfe per day (355 gross operated mmcfe per day), an increase of 56% year over year and 23% sequentially. The average peak daily production rate of the 52 wells that commenced first production during the 2013 second quarter in the southern Marcellus was approximately 6.5 mmcfe per day.
Chesapeake is currently operating three rigs in the southern wet-gas portion of the play, which it plans to reduce to two rigs by year end. Average spud-to-spud cycle time during the 2013 second quarter was 21 days, down from 33 days a year ago. As of June 30, 2013, Chesapeake had an inventory of 76 drilled but uncompleted and/or unconnected wells in the southern Marcellus.
Key Financial and Operational Results
The table below summarizes Chesapeake's key financial and operational results during the 2013 second quarter and compares them to results during the 2013 first quarter and the 2012 second quarter.
|Three Months Ended|
|Natural gas equivalent production (in bcfe)||369||358||347|
|Natural gas equivalent realized price ($/mcfe)(a)||4.96||4.46||3.77|
|Oil production (in mbbls)||10,539||9,283||7,325|
|Average realized oil price ($/bbl)(a)||93.81||94.85||91.58|
|Oil as % of total production||17||16||13|
|NGL production (in mbbls)||4,751||4,882||4,525|
|Average realized NGL price ($/bbl)(a)||24.22||28.25||25.94|
|NGL as % of total production||8||8||8|
|Liquids as % of realized revenue(b)||60||64||60|
|Liquids as % of unhedged revenue(b)||58||64||70|
|Natural gas production (in bcf)||278||273||275|
|Average realized natural gas price ($/mcf)(a)||2.62||2.13||1.88|
|Natural gas as % of total production||75||76||79|
|Natural gas as % of realized revenue||40||36||40|
|Natural gas as % of unhedged revenue||42||36||30|
|Production expenses ($/mcfe)||(0.78||)||(0.86||)||(0.97||)|
|Production taxes ($/mcfe)||(0.16||)||(0.15||)||(0.12||)|
|General and administrative costs ($/mcfe)(c)||(0.25||)||(0.25||)||(0.39||)|
|Stock-based compensation ($/mcfe)||(0.04||)||(0.06||)||(0.06||)|
|DD&A of natural gas and liquids properties ($/mcfe)||(1.75||)||(1.81||)||(1.70||)|
|D&A of other assets ($/mcfe)||(0.21||)||(0.22||)||(0.24||)|
|Interest expense ($/mcfe)(a)||(0.14||)||(0.04||)||(0.06||)|
|Marketing, gathering and compression net margin ($ in millions) (d)||29||36||17|
|Oilfield services net margin ($ in millions) (d)||35||35||50|
|Operating cash flow ($ in millions)(e)||1,370||1,176||895|
|Operating cash flow ($/mcfe)||3.71||3.28||2.58|
|Adjusted ebitda ($ in millions)(f)||1,424||1,134||803|
|Adjusted ebitda ($/mcfe)||3.86||3.17||2.32|
|Net income available to common stockholders ($ in millions)||457||15||929|
|Earnings per share - diluted ($)||0.66||0.02||1.29|
|Adjusted net income available to common stockholders ($ in millions)(g)||334||183||3|
|Adjusted earnings per share - diluted ($)||0.51||0.30||0.06|
(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 noncash stock-based compensation.
(d) Includes revenue and operating costs 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 16.
(g) Defined as net income available to common stockholders, as adjusted to remove the effects of certain items detailed on Page 12.
2013 Second Quarter Financial and Operational Results Conference Call Information
A conference call to discuss this release has been scheduled for Thursday, August 1, 2013, at 9:00 am EDT. The telephone number to access the conference call is 913-312-0968 or toll-free 888-215-6895. The passcode for the call is 3533928. 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 Thursday, August 1, 2013, and will run through 2:00 pm EDT on Thursday, August 15, 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 3533928. 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
This news release and the accompanying Outlooks include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.Forward-looking statements are statements other than statements of historical fact that give our current expectations or forecasts of future events.They include production forecasts, estimates of operating costs, planned development drilling, expected capital expenditures, 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.We do not have binding agreements for all of our planned 2013 asset sales.Our ability to consummate each of these transactions is subject to changes in market conditions and other factors.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)
|June 30,||June 30,|
|THREE MONTHS ENDED:||2013||2012|
|Natural gas, oil and NGL||2,406||6.51||2,117||6.11|
|Marketing, gathering and compression||2,057||5.57||1,113||3.21|
|Natural gas, oil and NGL production||288||0.78||335||0.97|
|Marketing, gathering and compression||2,028||5.49||1,096||3.16|
|General and administrative||106||0.29||155||0.45|
|Employee retirement and other termination benefits||7||0.02||1||0.00|
Natural gas, oil and NGL depreciation, depletion and amortization
|Depreciation and amortization of other assets||76||0.21||83||0.24|
|Impairments of fixed assets and other||231||0.62||243||0.70|
|Net gains on sales of fixed assets||(109||)||(0.30||)||—||—|
|Total Operating Expenses||3,508||9.50||2,651||7.65|
|INCOME FROM OPERATIONS||1,167||3.16||738||2.13|
|OTHER INCOME (EXPENSE):|
|Earnings (losses) on investments||23||0.06||(59||)||(0.17||)|
|Gains (losses) on sales of investments||(10||)||(0.03||)||1,030||2.97|
|Losses on purchases of debt||(70||)||(0.19||)||—||—|
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