Exhibit 99.1
| News Release | |
| FOR IMMEDIATE RELEASE | |
| MAY 1, 2013 | |
CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL AND
OPERATIONAL RESULTS FOR THE 2013 FIRST QUARTER
OKLAHOMA CITY, MAY 1, 2013 – Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2013 first quarter. Key information related to the quarter is as follows:
| · | Adjusted net income per fully diluted share of $0.30 increases 67% year over year |
| · | Adjusted ebitda of $1.134 billion increases 35% year over year |
| · | Total production increases 9% year over year to 4.0 bcfe per day |
| · | Oil production rises 56% year over year to 103,000 bbls per day |
| · | Capital expenditure levels in line with or below budgeted levels |
| · | Asset sales on track for year with $2.0 billion signed or closed to date and multiple other transactions in advanced stages of negotiation |
| · | Conference call 9:00 am EDT today; dial-in 913-312-0844, passcode 8842603 |
Chesapeake reported net income available to common stockholders of $15 million, or $0.02 per fully diluted share. These results include the effects of net unrealized noncash after-tax mark-to-market losses of $94 million from the company’s hedging programs and a net after-tax charge of $83 million for employee retirement expense and other termination benefits primarily resulting from a previously announced voluntary separation program and senior management separations. Adjusting for these and other items typically not included in earnings estimates by securities analysts, Chesapeake reported adjusted net income available to common stockholders of $183 million, an increase of 95% year over year, and adjusted net income per fully diluted share of $0.30, an increase of 67% year over year.
The company reported adjusted ebitda of $1.134 billion, an increase of 35% year over year. Operating cash flow, which is cash flow provided by operating activities before changes in assets and liabilities, was $1.176
billion, an increase of 29% 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 13-15 of this release.
Steven C. Dixon, Chesapeake’s Acting Chief Executive Officer, said, “Chesapeake is off to a strong start in 2013. We are beginning to see the benefits of our operational strategy shift from identifying and capturing new assets to developing our extensive existing assets and entering a new era of shareholder value realization. Our operational focus on the core of the core is enabling our drilling program to increasingly target the best reservoir rock in each of our key plays. We are capitalizing on pad drilling efficiencies wherever possible and leveraging our substantial investments in roads, well pads, gathering lines, and compression and processing facilities. As a result, we are generating more efficient production growth, stronger cash flow and better returns on capital.”
| CHESAPEAKE CONTACTS: | | MEDIA CONTACTS: | | CHESAPEAKE ENERGY CORPORATION |
| Jeffrey L. Mobley, CFA | | Gary T. Clark, CFA | | Michael Kehs | | Jim Gipson | | 6100 North Western Avenue |
| (405) 767-4763 | | (405) 935-6741 | | (405) 935-2560 | | (405) 935-1310 | | P.O. Box 18496 |
| jeff.mobley@chk.com | | gary.clark@chk.com | | michael.kehs@chk.com | | jim.gipson@chk.com | | Oklahoma City, OK 73154 |
Chesapeake’s daily production for the 2013 first quarter averaged approximately 4.0 billion cubic feet of natural gas equivalent (bcfe), an increase of 9% from the 2012 first quarter and an increase of 1% from the 2012 fourth quarter. The company’s production consisted of approximately 3.0 billion cubic feet (bcf) per day of natural gas and approximately 157,000 barrels (bbls) per day of liquids, comprised of approximately 103,000 bbls of oil and approximately 54,000 bbls of NGL.
Dixon noted, “For the 2013 first quarter, our average daily oil production increased more than 6% sequentially and 56% year over year, and our average daily NGL production increased 8% sequentially and 14% year over year. These increases were driven primarily by strong contributions from the Eagle Ford Shale and Greater Anadarko Basin plays. Our average daily natural gas production during the quarter was flat sequentially and up 2% year over year as a result of strong growth in the northern Marcellus Shale play offset by expected declines in the Haynesville Shale play. Our liquids mix as a percentage of total production was 24% during the 2013 first quarter, up from 19% in the 2012 first quarter.
“We are pleased to raise our 2013 oil production guidance by 1 million barrels (mmbbls), largely as a result of improving performance in the Eagle Ford Shale, where we are drilling longer laterals, achieving better-than-expected well performance and encountering improved gathering system pressures along with fewer gas processing constraints. We are also increasing the mid-point of our 2013 natural gas production guidance by 25 bcf, due primarily to strong well results in the Marcellus Shale play. However, we are reducing our 2013 NGL production guidance by 1 mmbbls, primarily due to infrastructure delays and a shift in our drilling activity toward more oily plays.”
Capital Spending Review and Outlook
Chesapeake operated an average of 83 rigs in the 2013 first quarter and invested approximately $1.5 billion in drilling and completion costs, a run rate consistent with the $6 billion midpoint of the company’s full year 2013 guidance. Net expenditures for the acquisition of unproved properties were $45 million during the first quarter, putting the company on track to be in line with or below its $400 million budget for 2013. Other capital expenditures totaled approximately $345 million, including $62 million related to two midstream systems that the company expects to recover as the assets are sold.
Domenic J. Dell’Osso, Jr., Chesapeake’s Chief Financial Officer, commented, “We plan to devote more than 80% of our total capital expenditures to drilling and completion activities in 2013 as compared to an average of approximately 50% over the last three years. Going forward, we expect this capex trend to continue to improve as we capitalize on our past investments in leasehold, oilfield services and other assets to deliver meaningful improvements in returns on capital.”
The company reported that production expenses during the quarter averaged $0.86 per thousand cubic feet of natural gas equivalent (mcfe), a decrease of 18% year over year.
General and administrative (G&A) expenses (excluding stock-based compensation) were $0.25 per mcfe, a decrease of 29% year over year.
Dell’Osso added, “We have achieved good progress in controlling costs and generating efficiency gains. As a result, we are reducing our 2013 guidance ranges for per unit production and G&A expenses for the second consecutive quarter. We now project that production expenses will range from $0.85 to $0.90 per mcfe for the year, down $0.05 per mcfe versus prior guidance. We project that 2013 G&A expenses (excluding stock-based compensation) will range from $0.30 to $0.35 per mcfe, down $0.04 per mcfe versus prior guidance. These decreases in expense guidance amount to an approximate $100 million improvement to our projected 2013 operating cash flow.”
Asset Sales Update
The company continues to make progress toward its goal of completing $4.0–7.0 billion of asset sales in 2013, having closed or signed approximately $2.0 billion of asset sales year to date. These consist of $366 million of asset sale cash proceeds received during the first quarter, $262 million of asset sales cash proceeds received thus far during the second quarter and approximately $1.4 billion of cash proceeds to be received from planned asset sales under contract, but not yet closed. Chesapeake also has multiple other transactions in advanced stages of negotiation.
Dixon remarked, “We anticipate closing our previously announced Mississippi Lime joint venture transaction with Sinopec before the end of the second quarter and expect to sign agreements to sell our northern Eagle Ford Shale assets, the majority of our remaining midstream assets and other noncore properties during the second quarter. These transactions will allow us to fund current capital expenditures and reduce debt.”
Operational Update
Since 2000, Chesapeake has built a leading position in 10 of what it believes are the top 15 unconventional plays in the U.S.: the Eagle Ford Shale in South Texas; the Marcellus Shale in Pennsylvania and West Virginia; the Utica Shale in Ohio, West Virginia and Pennsylvania; the Granite Wash/Hogshooter, Cleveland, Tonkawa and Mississippi Lime plays in the Greater Anadarko Basin in Oklahoma and the Texas Panhandle; the Haynesville/Bossier shales in western Louisiana and East Texas; the Barnett Shale in North Texas; and the Niobrara Shale in the Powder River Basin in Wyoming. The company’s investments in these 10 plays represent Chesapeake’s core assets, which are the nearly exclusive focus of its planned future drilling activity. The company continues to achieve strong operational results in its most active plays, as highlighted below.
Eagle Ford Shale (South Texas): Chesapeake continues to generate strong liquids production growth rates from its Eagle Ford Shale play in South Texas. Net production during the 2013 first quarter averaged 75,000 barrels of oil equivalent (boe) per day (166,000 gross operated boe per day). This represents an increase of 225% year over year and 20% sequentially. Approximately 65% of the company’s Eagle Ford production during the 2013 first quarter was oil, 18% was NGL and 17% was natural gas.
As of March 31, 2013, Chesapeake had drilled a total of 887 wells in the Eagle Ford, which included 650 producing wells, 34 additional wells waiting on pipeline connection and 203 wells in various stages of completion. The company is currently operating 15 rigs in the play and plans to reduce its operated rig count to 13 rigs in the second half of 2013. Spud-to-spud cycle times during the quarter were 18 days, down from 25 days year over year. Chesapeake plans to have substantially all of its core Eagle Ford acreage held by production by the end of 2013. The average peak daily production rate of the 111 wells that commenced first production during the 2013 first quarter was approximately 950 boe per day.
Three notable wells completed by Chesapeake in the Eagle Ford during the 2013 first quarter are as follows:
| · | The Gates 010-CHK-A TR3-J2H in Webb County, TX achieved a peak rate of approximately 3,110 boe per day, which included 930 bbls of oil, 1,160 bbls of NGL and 6.1 million cubic feet (mmcf) of natural gas per day; |
| · | The PGE Browne G 4H in Webb County, TX achieved a peak rate of approximately 1,840 boe per day, which included 770 bbls of oil, 570 bbls of NGL and 3.0 mmcf of natural gas per day; and |
| · | The Sultenfuss Unit 6H in Dimmit County, TX achieved a peak rate of approximately 1,360 boe per day, which included 1,260 bbls of oil, 60 bbls of NGL and 0.2 mmcf of natural gas per day. |
Chesapeake is in the process of selling a portion of its northern Eagle Ford Shale leasehold and producing assets which are outside of its core development area.
Utica Shale (eastern Ohio, Pennsylvania, West Virginia): Chesapeake is currently operating 14 rigs in the Utica Shale play. As of March 31, 2013, Chesapeake had drilled a total of 249 wells in the Utica, which included 66 producing wells, 86 additional wells waiting on pipeline connection and 97 wells in various stages of completion. Net production averaged approximately 60 million cubic feet of natural gas equivalent (mmcfe) per day during the 2013 first quarter and the company continues to target a year-end 2013 net production exit rate of 330 mmcfe per day. The average peak daily production rate of the 13 wells that commenced first production during the 2013 first quarter was approximately 1,200 boe per day.
Three notable wells completed by Chesapeake in the Utica during the 2013 first quarter are as follows:
| · | The Coe 34-12-4 1H in Carroll County, OH achieved a peak rate of approximately 1,980 boe per day, which included 235 bbls of oil, 470 bbls of NGL and 7.6 mmcf of natural gas per day; |
| · | The Henderson South 10-12-6 5H in Harrison County, OH achieved a peak rate of approximately 1,625 boe per day, which included 755 bbls of oil, 240 bbls of NGL and 3.8 mmcf of natural gas per day; and |
| · | The Scott 24-12-5 6H in Carroll County, OH achieved a peak rate of approximately 1,530 boe per day, which included 285 bbls of oil, 350 bbls of NGL and 5.4 mmcf of natural gas per day. |
Chesapeake is in the process of selling certain noncore Utica Shale leasehold.
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 first quarter averaged 114,000 boe per day (168,000 gross operated boe per day). This represents an increase of 30% year over year and 9% sequentially. Approximately 38% of the company’s Greater Anadarko Basin production during the 2013 first quarter was oil, 20% was NGL and 42% was natural gas. Chesapeake is currently operating 28 rigs across these plays and plans to maintain this level for the remainder of the year. The average peak daily production rate of the 90 wells that commenced first production during the 2013 first quarter was approximately 900 boe per day.
Five notable wells completed by Chesapeake in the Greater Anadarko Basin during the 2013 first quarter are as follows:
| · | In the Mississippi Lime, the TDR 12-25-12 1H in Alfalfa County, OK achieved a peak rate of approximately 1,485 boe per day, which included 490 bbls of oil, 305 bbls of NGL and 4.1 mmcf of natural gas per day; |
| · | In the Colony Granite Wash, the Kenton 23-11-18 1H in Washita County, OK achieved a peak rate of approximately 3,665 boe per day, which included 870 bbls of oil, 1,215 bbls of NGL and 9.5 mmcf of natural gas per day; |
| · | In the Cleveland, the Edward Mary 23-16-20 1H in Dewey County, OK achieved a peak rate of approximately 1,275 boe per day, which included 555 bbls of oil, 290 bbls of NGL and 2.6 mmcf of natural gas per day; |
| · | In the Tonkawa, the Beaudette 11-16-20 1H in Dewey County, OK achieved a peak rate of approximately 930 boe per day, which included 810 bbls of oil, 35 bbls of NGL and 0.5 mmcf of natural gas per day; and |
| · | In the Hogshooter, the Roark Trust 14-14-24 1H in Roger Mills, OK achieved a peak rate of approximately 4,570 boe per day, which included 2,205 bbls of oil, 905 bbls of NGL and 8.8 mmcf of natural gas per day. |
Marcellus Shale (Pennsylvania, West Virginia): Chesapeake is the largest leasehold owner in the Marcellus Shale, which spans from northern West Virginia across much of Pennsylvania into southern New York. The company recently achieved a gross operated natural gas production milestone of more than 2.0 bcf per day. As natural gas prices have recovered from last year’s historically low levels, the company has benefited from the strong growth and returns in both the northern dry gas and the southern wet gas portions of the play.
During the 2013 first quarter, Chesapeake’s average daily net production in the northern dry gas portion of the Marcellus was 710 mmcfe per day (1,540 gross operated mmcfe per day), an increase of 70% year over year and 10% sequentially. Chesapeake has reduced its operated rig count to five rigs in the northern dry gas portion of the Marcellus and anticipates maintaining that level of activity for the remainder of 2013. The average peak daily production rate of the 39 wells that commenced first production during the 2013 first quarter in the northern Marcellus was approximately 8.0 mmcfe per day.
Three notable wells completed by Chesapeake in the northern dry gas portion of the Marcellus during the 2013 first quarter are as follows:
| The Floydie NW 4H in Bradford County, PA achieved a peak rate of 12.7 mmcf of natural gas per day; |
| · | The Matt 2H in Sullivan County, PA achieved a peak rate of 12.4 mmcf of natural gas per day; and |
| · | The Phillips 5H in Sullivan County, PA achieved a peak rate of 12.3 mmcf of natural gas per day. |
During the 2013 first quarter, Chesapeake’s average daily net production in the southern wet gas portion of the play was approximately 170 mmcfe per day (280 gross operated mmcfe per day), an increase of 21% year over year and 9% sequentially. Chesapeake is currently operating three rigs in the southern wet gas portion of the Marcellus and anticipates maintaining that level of activity for the remainder of 2013. The average peak daily production rate of the 13 wells that commenced first production during the 2013 first quarter in the southern Marcellus was approximately 6.0 mmcfe per day.
Three notable wells completed by Chesapeake in the southern wet gas portion of the Marcellus during the 2013 first quarter are as follows:
| · | The Shawn Couch 8H in Ohio County, WV achieved a peak rate of approximately 1,360 boe per day, which included 505 bbls of oil, 290 bbls of NGL and 3.4 mmcf of natural gas per day; |
| · | The Glenn Didriksen 1H in Ohio County, WV achieved a peak rate of approximately 1,355 boe per day, which included 395 bbls of oil, 195 bbls of NGL and 4.6 mmcf of natural gas per day; and |
| · | The John Briggs 5H in Greene County, PA achieved a peak rate of approximately 1,340 boe per day, which included 270 bbls of NGL and 6.4 mmcf of natural gas per day. |
The company is in the process of selling certain noncore Marcellus Shale leasehold.
2013 First Quarter Financial and Operational Results Conference Call Information
A conference call to discuss this release has been scheduled for Wednesday, May 1, 2013 at 9:00 am EDT. The telephone number to access the conference call is 913-312-0844 or toll-free 888-811-5445. The passcode for the call is 8842603. 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 1, 2013 and will run through 2:00 pm EDT on Wednesday, May 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 8842603. 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, a Top 11 producer of oil and natural gas liquids and the most active driller of new wells in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S. Chesapeake owns leading positions in the Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime and Niobrara unconventional liquids plays and in the Marcellus, Haynesville/Bossier and Barnett unconventional natural gas shale plays. The company has also vertically integrated its operations and owns substantial marketing, compression and oilfield services businesses through its subsidiaries Chesapeake Energy Marketing, Inc., MidCon Compression, L.L.C. and Chesapeake Oilfield Operating, L.L.C. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.
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 and 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 a delay in naming a new CEO, 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. If one or more of the transactions is not completed in the anticipated time frame or at all or for less proceeds than anticipated, our ability to fund budgeted capital expenditures and reduce our indebtedness as planned could be adversely affected. 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.
Key Financial and Operational Results
The table below summarizes Chesapeake’s key financial and operational results during the 2013 first quarter and compares them to results during the 2012 fourth quarter and the 2012 first quarter.
| | | | | | | |
| | Three Months Ended | |
| | 3/31/13 | | 12/31/12 | | 3/31/12 | |
| Natural gas equivalent production (in bcfe) | 358 | | 362 | | 333 | |
Natural gas equivalent realized price ($/mcfe)(a) | 4.46 | | 4.23 | | 4.02 | |
| Oil production (in mbbls) | 9,283 | | 8,936 | | 6,008 | |
Average realized oil price ($/bbl)(a) | 94.85 | | 92.23 | | 92.63 | |
| Oil as % of total production | 16 | | 15 | | 11 | |
| NGL production (in mbbls) | 4,882 | | 4,634 | | 4,326 | |
Average realized NGL price ($/bbl)(a) | 28.25 | | 27.12 | | 33.60 | |
| NGL as % of total production | 8 | | 8 | | 8 | |
Liquids as % of realized revenue(b) | 64 | | 62 | | 53 | |
Liquids as % of unhedged revenue(b) | 64 | | 59 | | 61 | |
| Natural gas production (in bcf) | 273 | | 280 | | 271 | |
Average realized natural gas price ($/mcf)(a) | 2.13 | | 2.07 | | 2.35 | |
| Natural gas as % of total production | 76 | | 77 | | 81 | |
| Natural gas as % of realized revenue | 36 | | 38 | | 47 | |
| Natural gas as % of unhedged revenue | 36 | | 41 | | 39 | |
| Production expenses ($/mcfe) | (0.86 | ) | (0.83 | ) | (1.05 | ) |
| Production taxes ($/mcfe) | (0.15 | ) | (0.13 | ) | (0.14 | ) |
General and administrative costs ($/mcfe)(c) | (0.25 | ) | (0.23 | ) | (0.35 | ) |
| Stock-based compensation ($/mcfe) | (0.06 | ) | (0.04 | ) | (0.06 | ) |
| DD&A of natural gas and liquids properties ($/mcfe) | (1.81 | ) | (1.80 | ) | (1.52 | ) |
| D&A of other assets ($/mcfe) | (0.22 | ) | (0.20 | ) | (0.25 | ) |
Interest expense ($/mcfe)(a) | (0.04 | ) | (0.05 | ) | (0.02 | ) |
Marketing, gathering and compression net margin ($ in millions)(d) | 36 | | 41 | | 19 | |
Oilfield services net margin ($ in millions)(d)(e) | 35 | | 16 | | 39 | |
Operating cash flow ($ in millions)(f) | 1,176 | | 1,129 | | 910 | |
| Operating cash flow ($/mcfe) | 3.28 | | 3.12 | | 2.73 | |
Adjusted ebitda ($ in millions)(g) | 1,134 | | 1,089 | | 838 | |
| Adjusted ebitda ($/mcfe) | 3.17 | | 3.01 | | 2.52 | |
| Net income (loss) to common stockholders ($ in millions) | 15 | | 257 | | (71 | ) |
| Earnings (loss) per share – diluted ($) | 0.02 | | 0.39 | | (0.11 | ) |
Adjusted net income to common stockholders ($ in millions)(h) | 183 | | 153 | | 94 | |
| Adjusted earnings per share – diluted ($) | 0.30 | | 0.26 | | 0.18 | |
| (a) | Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging. |
| (b) | “Liquids” includes both oil and NGL. |
| (c) | Excludes expenses associated with noncash stock-based compensation. |
| (d) | Includes revenue and operating costs and excludes depreciation and amortization of other assets. |
| (e) | 2013 first quarter and 2012 fourth quarter include the impact of certain consolidated investments along with results from Chesapeake Oilfield Services. |
| (f) | Defined as cash flow provided by operating activities before changes in assets and liabilities. |
| (g) | Defined as net income (loss) before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 15. |
| (h) | Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 13. |
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per share and unit data)
(unaudited)
| | March 31, | | March 31, | |
| THREE MONTHS ENDED: | 2013 | | 2012 | |
| | $ | | $/mcfe | | $ | | $/mcfe | |
| REVENUES: | | | | | | | | | | | | |
Natural gas, oil and NGL | | 1,453 | | | 4.06 | | | 1,068 | | | 3.21 | |
Marketing, gathering and compression | | 1,781 | | | 4.97 | | | 1,216 | | | 3.65 | |
Oilfield services | | 190 | | | 0.53 | | | 135 | | | 0.41 | |
Total Revenues | | 3,424 | | | 9.56 | | | 2,419 | | | 7.27 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES: | | | | | | | | | | | | |
Natural gas, oil and NGL production | | 307 | | | 0.86 | | | 349 | | | 1.05 | |
Production taxes | | 53 | | | 0.15 | | | 47 | | | 0.14 | |
Marketing, gathering and compression | | 1,745 | | | 4.87 | | | 1,197 | | | 3.60 | |
Oilfield services | | 155 | | | 0.43 | | | 96 | | | 0.29 | |
General and administrative | | 110 | | | 0.31 | | | 136 | | | 0.41 | |
Employee retirement expense and other termination benefits | | 133 | | | 0.37 | | | — | | | — | |
Natural gas, oil and NGL depreciation, depletion and amortization | | 648 | | | 1.81 | | | 506 | | | 1.52 | |
Depreciation and amortization of other assets | | 78 | | | 0.22 | | | 84 | | | 0.25 | |
| Net gains on sales of fixed assets | | (49 | ) | | (0.14 | ) | | (2 | ) | | (0.01 | ) |
Impairments of fixed assets and other | | 27 | | | 0.07 | | | — | | | — | |
Total Operating Expenses | | 3,207 | | | 8.95 | | | 2,413 | | | 7.25 | |
| | | | | | | | | | | | | |
| INCOME (LOSS) FROM OPERATIONS | | 217 | | | 0.61 | | | 6 | | | 0.02 | |
| | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | |
Interest expense | | (21 | ) | | (0.06 | ) | | (12 | ) | | (0.04 | ) |
Losses on investments | | (27 | ) | | (0.08 | ) | | (5 | ) | | (0.02 | ) |
Impairment of investment | | (10 | ) | | (0.03 | ) | | — | | | — | |
Other income | | 6 | | | 0.02 | | | 6 | | | 0.02 | |
Total Other Income (Expense) | | (52 | ) | | (0.15 | ) | | (11 | ) | | (0.04 | ) |
| | | | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | 165 | | | 0.46 | | | (5 | ) | | (0.02 | ) |
| | | | | | | | | | | | | |
| INCOME TAX EXPENSE (BENEFIT): | | | | | | | | | | | | |
Current income taxes | | 1 | | | 0.00 | | | — | | | — | |
Deferred income taxes | | 62 | | | 0.17 | | | (2 | ) | | (0.01 | ) |
Total Income Tax Expense (Benefit) | | 63 | | | 0.17 | | | (2 | ) | | (0.01 | ) |
| | | | | | | | | | | | | |
| NET INCOME (LOSS) | | 102 | | | 0.29 | | | (3 | ) | | (0.01 | ) |
| | | | | | | | | | | | | |
Net income attributable to noncontrolling interests | | (44 | ) | | (0.13 | ) | | (25 | ) | | (0.07 | ) |
| | | | | | | | | | | | | |
| NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | | 58 | | | 0.16 | | | (28 | ) | | (0.08 | ) |
| | | | | | | | | | | | | |
Preferred stock dividends | | (43 | ) | | (0.12 | ) | | (43 | ) | | (0.13 | ) |
| | | | | | | | | | | | | |
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS | | 15 | | | 0.04 | | | (71 | ) | | (0.21 | ) |
| | | | | | | | | | | | | |
| EARNINGS (LOSS) PER COMMON SHARE: | | | | | | | | | | | | |
Basic | $ | 0.02 | | | | | $ | (0.11 | ) | | | |
| | | | | | | | | | | | | |
Diluted | $ | 0.02 | | | | | $ | (0.11 | ) | | | |
| | | | | | | | | | | | | |
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): | | | | | | | | | | | | |
Basic | | 651 | | | | | | 642 | | | | |
| | | | | | | | | | | | | |
Diluted | | 651 | | | | | | 642 | | | | |
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
| | | March 31, | | | December 31, | |
| | | 2013 | | | 2012 | |
| | | | | | | | | |
| Cash and cash equivalents | | $ | 33 | | | $ | 287 | |
| Other current assets | | | 2,851 | | | | 2,661 | |
Total Current Assets | | | 2,884 | | | | 2,948 | |
| | | | | | | | | |
| Property and equipment (net) | | | 38,147 | | | | 37,167 | |
| Other assets | | | 1,450 | | | | 1,496 | |
Total Assets | | $ | 42,481 | | | $ | 41,611 | |
| | | | | | | | | |
| Current liabilities | | $ | 5,785 | | | $ | 6,266 | |
| Long-term debt, net of discounts | | | 13,449 | | | | 12,157 | |
| Other long-term liabilities | | | 2,212 | | | | 2,485 | |
| Deferred income tax liabilities | | | 3,021 | | | | 2,807 | |
Total Liabilities | | | 24,467 | | | | 23,715 | |
| | | | | | | | | |
| Chesapeake stockholders' equity | | | 15,700 | | | | 15,569 | |
| Noncontrolling interests | | | 2,314 | | | | 2,327 | |
Total Equity | | | 18,014 | | | | 17,896 | |
| | | | | | | | | |
| Total Liabilities and Equity | | $ | 42,481 | | | $ | 41,611 | |
| | | | | | | | | |
| Common Shares Outstanding (in millions) | | | 669 | | | | 664 | |
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
| | March 31, | December 31, | |
| | 2013 | 2012 | |
| | | | |
| Total debt, net of unrestricted cash | | $ | 13,416 | | | $ | 12,333 | |
| Chesapeake stockholders' equity | | | 15,700 | | | | 15,569 | |
Noncontrolling interests(a) | | | 2,314 | | | | 2,327 | |
Total | | $ | 31,430 | | | $ | 30,229 | |
| | | | | | | | | |
| Debt to capitalization ratio | | | 43% | | | | 41% | |
| (a) | Includes third-party ownership as follows: |
| CHK Cleveland Tonkawa, L.L.C. | | $ | 1,015 | | | $ | 1,015 | |
| CHK Utica, L.L.C. | | | 950 | | | | 950 | |
| Chesapeake Granite Wash Trust | | | 345 | | | | 356 | |
| Other | | | 4 | | | | 6 | |
| Total | | $ | 2,314 | | | $ | 2,327 | |
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - NATURAL GAS, OIL AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)
| | March 31, | March 31, | |
| THREE MONTHS ENDED: | 2013 | 2012 | |
| | | | | | | |
| Net Production: | | | | | | |
Natural gas (bcf) | | 273.1 | | | 270.8 | |
Oil (mmbbl) | | 9.3 | | | 6.0 | |
NGL (mmbbl) | | 4.9 | | | 4.3 | |
Natural gas equivalents (bcfe) | | 358.1 | | | 332.6 | |
| | | | | | | |
| Natural Gas, Oil and NGL Sales ($ in millions): | | | | | | |
Natural gas sales | $ | 573 | | $ | 478 | |
Natural gas derivatives – realized gains (losses) | | 8 | | | 158 | |
Natural gas derivatives – unrealized gains (losses) | | (278 | ) | | (147 | ) |
| | | | | | | |
Total Natural Gas Sales | | 303 | | | 489 | |
| | | | | | | |
Oil sales | | 884 | | | 591 | |
Oil derivatives – realized gains (losses) | | (4 | ) | | (34 | ) |
Oil derivatives – unrealized gains (losses) | | 132 | | | (138 | ) |
| | | | | | | |
Total Oil Sales | | 1,012 | | | 419 | |
| | | | | | | |
NGL sales | | 138 | | | 152 | |
NGL derivatives – realized gains (losses) | | — | | | (7 | ) |
NGL derivatives – unrealized gains (losses) | | — | | | 15 | |
| | | | | | | |
Total NGL Sales | | 138 | | | 160 | |
| | | | | | | |
Total Natural Gas, Oil and NGL Sales | $ | 1,453 | | $ | 1,068 | |
| | | | | | | |
Average Sales Price – excluding gains (losses) on derivatives: | | | | | | |
Natural gas ($ per mcf) | $ | 2.10 | | $ | 1.77 | |
Oil ($ per bbl) | $ | 95.23 | | $ | 98.36 | |
NGL ($ per bbl) | $ | 28.25 | | $ | 35.16 | |
Natural gas equivalent ($ per mcfe) | $ | 4.45 | | $ | 3.67 | |
| | | | | | | |
Average Sales Price – excluding unrealized gains (losses) on derivatives: | | | | | | |
Natural gas ($ per mcf) | $ | 2.13 | | $ | 2.35 | |
Oil ($ per bbl) | $ | 94.85 | | $ | 92.63 | |
NGL ($ per bbl) | $ | 28.25 | | $ | 33.60 | |
Natural gas equivalent ($ per mcfe) | $ | 4.46 | | $ | 4.02 | |
| | | | | | | |
| Interest Expense (Income) ($ in millions): | | | | | | |
Interest(a) | $ | 17 | | $ | 8 | |
Derivatives – realized (gains) losses | | (2 | ) | | — | |
Derivatives – unrealized (gains) losses | | 6 | | | 4 | |
Total Interest Expense | $ | 21 | | $ | 12 | |
| (a) | Net of amounts capitalized. |
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
| THREE MONTHS ENDED: | March 31, | | March 31, | |
| 2013 | | 2012 | |
| | | | | | | |
| Beginning cash | $ | 287 | | $ | 351 | |
| | | | | | | |
| Cash provided by operating activities | | 924 | | | 274 | |
| | | | | | | |
| Cash flows from investing activities: | | | | | | |
Well costs on proved and unproved properties(a) | | (1,566 | ) | | (2,503 | ) |
Acquisition of proved and unproved properties(b) | | (255 | ) | | (1,117 | ) |
Sale of proved and unproved properties | | 165 | | | 803 | |
Geological and geophysical costs | | (13 | ) | | (71 | ) |
Additions to other property and equipment | | (330 | ) | | (690 | ) |
Proceeds from sales of other assets | | 201 | | | 48 | |
Additions to investments, net | | (3 | ) | | (73 | ) |
Other | | 56 | | | (47 | ) |
Total cash provided by (used in) investing activities | | (1,745 | ) | | (3,650 | ) |
| | | | | | | |
| Cash provided by (used in) financing activities | | 567 | | | 3,463 | |
| | | | | | | |
| Change in cash and cash equivalents | | (254 | ) | | 87 | |
| | | | | | | |
| Ending cash | $ | 33 | | $ | 438 | |
| (a) | Includes capitalized interest of $16 million for the three months ended March 31, 2013. |
| (b) | Includes capitalized interest of $207 million and $162 million for the three months ended March 31, 2013 and 2012, respectively. |
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per share data)
(unaudited)
| | | March 31, | | December 31, | | March 31, | |
| THREE MONTHS ENDED: | | 2013 | | 2012 | | 2012 | |
| | | | | | | | | | | |
| Net income (loss) available to common stockholders | | $ | 15 | | $ | 257 | | $ | (71 | ) |
| | | | | | | | | | | |
| Adjustments, net of tax: | | | | | | | | | | |
Unrealized (gains) losses on derivatives | | | 94 | | | (78 | ) | | 167 | |
Net gains on sales of fixed assets | | | (30 | ) | | (166 | ) | | (1 | ) |
| Impairments of fixed assets and other | | | 16 | | | 36 | | | — | |
| Impairment of investment | | | 6 | | | — | | | — | |
Employee retirement expense and other termination benefits | | | 83 | | | 2 | | | — | |
Gain on sale of investment | | | — | | | (19 | ) | | — | |
| Losses on purchases of debt | | | — | | | 122 | | | — | |
Other | | | (1 | ) | | (1 | ) | | (1 | ) |
| | | | | | | | | | | |
Adjusted net income available to common stockholders(a) | | | 183 | | | 153 | | | 94 | |
| Preferred stock dividends | | | 43 | | | 43 | | | 43 | |
Total adjusted net income | | $ | 226 | | $ | 196 | | $ | 137 | |
| | | | | | | | | | | |
Weighted average fully diluted shares outstanding(b) | | | 758 | | | 754 | | | 752 | |
| | | | | | | | | | | |
Adjusted earnings per share assuming dilution(a) | | $ | 0.30 | | $ | 0.26 | | $ | 0.18 | |
| (a) | Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to GAAP earnings because: |
| | (i) | Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. |
| | (ii) | Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. |
| | (iii) | Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. |
| (b) | Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. |
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
| | March 31, | | December 31, | | March 31, | |
| THREE MONTHS ENDED: | 2013 | | 2012 | | 2012 | |
| | | | | | | | | | |
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 924 | | $ | 858 | | $ | 274 | |
| | | | | | | | | | |
| Changes in assets and liabilities | | 252 | | | 271 | | | 636 | |
| | | | | | | | | | |
OPERATING CASH FLOW(a) | $ | 1,176 | | $ | 1,129 | | $ | 910 | |
| | March 31, | | December 31, | | March 31, | |
| THREE MONTHS ENDED: | 2013 | | 2012 | | 2012 | |
| | | | | | | | | | |
| NET INCOME (LOSS) | $ | 102 | | $ | 344 | | $ | (3 | ) |
| | | | | | | | | | |
| Interest expense | | 21 | | | 14 | | | 12 | |
| Income tax expense (benefit) | | 63 | | | 219 | | | (2 | ) |
| Depreciation and amortization of other assets | | 78 | | | 71 | | | 84 | |
Natural gas, oil and NGL depreciation, depletion and amortization | | 648 | | | 651 | | | 506 | |
| | | | | | | | | | |
EBITDA(b) | $ | 912 | | $ | 1,299 | | $ | 597 | |
| | March 31, | | December 31, | | March 31, | |
| THREE MONTHS ENDED: | 2013 | | 2012 | | 2012 | |
| | | | | | | | | | |
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 924 | | $ | 858 | | $ | 274 | |
| | | | | | | | | | |
| Changes in assets and liabilities | | 252 | | | 271 | | | 636 | |
| Interest expense | | 21 | | | 14 | | | 12 | |
Unrealized gains (losses) on natural gas, oil and NGL derivatives | | (146 | ) | | 125 | | | (270 | ) |
| Net gains on sales of fixed assets | | 49 | | | 272 | | | 2 | |
| Impairments of fixed assets and other | | (27 | ) | | (59 | ) | | — | |
| Employee retirement and other termination benefits | | (105 | ) | | (3 | ) | | — | |
| Gain on sale of investment | | — | | | 31 | | | — | |
| Losses on investments | | (29 | ) | | (18 | ) | | (33 | ) |
| Impairment of investment | | (10 | ) | | — | | | — | |
| Stock-based compensation | | (32 | ) | | (27 | ) | | (37 | ) |
| Losses on purchases of debt | | — | | | (200 | ) | | — | |
| Other items | | 15 | | | 35 | | | 13 | |
| | | | | | | | | | |
EBITDA(b) | $ | 912 | | $ | 1,299 | | $ | 597 | |
| (a) | Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. |
| (b) | Ebitda represents net income (loss) before 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)
| | March 31, | | December 31, | | March 31, | |
| THREE MONTHS ENDED: | 2013 | | 2012 | | 2012 | |
| | | | | | | | | | |
| EBITDA | $ | 912 | | $ | 1,299 | | $ | 597 | |
| | | | | | | | | | |
| Adjustments: | | | | | | | | | |
Unrealized (gains) losses on natural gas, oil and NGL derivatives | | 146 | | | (125 | ) | | 270 | |
Impairment of investment | | 10 | | | — | | | — | |
| Net gains on sales of fixed assets | | (49 | ) | | (272 | ) | | (2 | ) |
Impairments of fixed assets and other | | 27 | | | 59 | | | — | |
Net income attributable to noncontrolling interests | | (44 | ) | | (44 | ) | | (25 | ) |
Gain on sale of investment | | — | | | (31 | ) | | — | |
| Losses on purchases of debt | | — | | | 200 | | | — | |
| | | | | | | | | | |
Employee retirement expense and other termination benefits | | 133 | | | 3 | | | — | |
Other | | (1 | ) | | — | | | (2 | ) |
| | | | | | | | | | |
Adjusted EBITDA(a) | $ | 1,134 | | $ | 1,089 | | $ | 838 | |
| (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 1, 2013
Chesapeake periodically provides management guidance on certain factors that affect its future financial performance. The primary changes from the company’s February 21, 2013 Outlook are in italicized bold below. The production guidance provided assumes Chesapeake closes asset sales for proceeds of approximately $4 billion during 2013. Estimated production decreases of approximately 42 bcfe in 2013 are associated with these sales and are reflected in the production guidance set forth below. To the extent the company completes asset sales in excess of $4 billion during 2013, production guidance may need to be reduced to reflect such incremental sales.
Chesapeake Energy Corporation Consolidated Projections
| | | Year Ending 12/31/13 |
| Estimated Production: | | |
Natural gas – bcf | | 1,060 – 1,090 |
Oil – mbbls | | 37,000 – 39,000 |
NGL – mbbls(a) | | 23,000 – 25,000 |
Natural gas equivalent – bcfe | | 1,420 – 1,474 |
| | | |
| Daily natural gas equivalent midpoint – mmcfe | | 3,965 |
| | | |
| YOY estimated production increase (adjusted for planned asset sales) | | 2% |
| | | |
NYMEX Price(b) (for calculation of realized hedging effects only): | | |
Natural gas - $/mcf | | $4.00 |
Oil - $/bbl | | $91.11 |
| | | |
| Estimated Realized Hedging Effects (based on assumed NYMEX prices above): above): | | |
Natural gas - $/mcf | | ($0.25) |
Oil - $/bbl | | $3.32 |
| | | |
| Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: | | |
Natural gas - $/mcf | | $1.15 – 1.25 |
Oil - $/bbl | | $0.00 – 2.00 |
NGL - $/bbl | | $62.00 – 66.00 |
| | | |
| Operating Costs per Mcfe of Projected Production: | | |
Production expense | | $0.85 – 0.90 |
| Production taxes | | $0.20 – 0.25 |
General and administrative(c) | | $0.30 – 0.35 |
Stock-based compensation (noncash) | | $0.04 – 0.06 |
DD&A of natural gas and liquids assets | | $1.65 – 1.85 |
Depreciation of other assets | | $0.25 – 0.30 |
Interest expense(d) | | $0.05 – 0.10 |
| | | |
| Other ($ millions): | | |
Marketing, gathering and compression net margin(e) | | $100 – 125 |
Oilfield services net margin(e) | | $150 – 200 |
Net income attributable to noncontrolling interests and other(f) | | ($180) – (220) |
| | | |
| Book Tax Rate | | 38% |
| | | |
| Weighted average shares outstanding (in millions): | | |
Basic | | 645 – 655 |
Diluted | | 758 – 763 |
| | | |
Operating cash flow before changes in assets and liabilities(g)(h) | | $5,200 – 5,300 |
| Well costs on proved and unproved properties | | ($5,750 – 6,250) |
| Acquisition of unproved properties, net | | ($400) |
| a) | Assumes no ethane rejection. |
| b) | NYMEX natural gas and oil prices have been updated for actual contract prices through April and March, respectively. |
| c) | Excludes expenses associated with noncash stock-based compensation. |
| 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 a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities. |
| h) | Assumes NYMEX prices on open contracts of $4.00 to $4.50 per mcf and $90.00 per bbl in 2013. |
Natural Gas, Oil and NGL Hedging Activities
Chesapeake enters into natural gas, oil and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end derivative positions and the accounting for natural gas, oil and NGL derivatives.
As of April 30, 2013, the company had the following open natural gas swaps in place and gains (losses) related to closed natural gas trades and premiums for call options for future production periods.
| | | Open Swaps (bcf) | | Avg. NYMEX Price of Open Swaps | | Forecasted Natural Gas Production (bcf) | | Open Swap Positions as a % of Forecasted Natural Gas Production | | Total Gains (Losses) from Closed Trades and Premiums for Call Options ($ in millions) | | Total Gains (Losses) from Closed Trades and Premiums for Call Options per mcf of Forecasted Natural Gas Production |
| Q2 2013 | | 185 | | | $ | 3.77 | | | | | | | | | $ | 11 | | | | | |
| Q3 2013 | | 197 | | | | 3.73 | | | | | | | | | | 7 | | | | | |
| Q4 2013 | | 190 | | | | 3.71 | | | | | | | | | | (3 | ) | | | | |
| Total Q2-Q4 2013 | | 572 | | | $ | 3.73 | | | 802 | | | 71 | % | | $ | 15 | | | $ | 0.02 | |
| Total 2014 | | 128 | | | $ | 4.38 | | | | | | | | | $ | (74 | ) | | | | |
| Total 2015 | | 0 | | | | - | | | | | | | | | $ | (131 | ) | | | | |
| Total 2016 – 2022 | | 0 | | | | - | | | | | | | | | $ | (187 | ) | | | | |
The company currently has the following purchased natural gas three-way collars in place:
| | | 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 |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Q2 2013 | | 18 | | | $ | 3.03 | | | $ | 3.55 | | | $ | 4.03 | | | | | | | | | |
| Q3 2013 | | 18 | | | | 3.03 | | | | 3.55 | | | | 4.03 | | | | | | | | | |
| Q4 2013 | | 18 | | | | 3.03 | | | | 3.55 | | | | 4.03 | | | | | | | | | |
| Total Q2-Q4 2013 | | 54 | | | $ | 3.03 | | | $ | 3.55 | | | $ | 4.03 | | | | 802 | | | | 7% | |
| Total 2014 | | 18 | | | $ | 3.50 | | | $ | 4.00 | | | $ | 4.70 | | | | | | | | | |
The company currently has the following natural gas swaptions in place:
| | | Swaptions (bcf) | | Avg. NYMEX Strike Price | | Forecasted Natural Gas Production (bcf) | | Swaptions as a % of Forecasted Natural Gas Production |
| | | | | | | | | | | | | | |
| Total Q2-Q4 2013 | | 0 | | | $ | - | | | 802 | | | 0 | % |
| Total 2014 | | 12 | | | $ | 4.80 | | | | | | | |
The company currently has the following natural gas written call options in place:
| | | Call Options (bcf) | | Avg. NYMEX Strike Price | | Forecasted Natural Gas Production (bcf) | | Call Options as a % of Forecasted Natural Gas Production |
| | | | | | | | | | | | | | |
| Total Q2-Q4 2013 | | 0 | | | $ | - | | | 802 | | | 0 | % |
| Total 2016 – 2020 | | 193 | | | $ | 9.92 | | | | | | | |
The company has the following natural gas basis protection swaps in place:
| | | Volume (bcf) | | Avg. NYMEX less |
| | | | | | | |
| Q2 2013 | | 11 | | | $ | 0.21 |
| Q3 2013 | | 11 | | | | 0.21 |
| Q4 2013 | | 11 | | | | 0.21 |
| Total Q2-Q4 2013 | | 33 | | | $ | 0.21 |
| Total 2014 | | 28 | | | $ | 0.32 |
| Total 2015 | | 31 | | | $ | 0.34 |
| Total 2016-2022 | | 8 | | | $ | 1.02 |
| | | |
As of April 30, 2013, the company had the following open crude oil swaps in place and gains (losses) related to closed crude oil contracts and premiums for call options for future production:
| | | 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 |
| | | | | | | | | | | | | | | | | | | | | | |
| Q2 2013 | | 7,947 | | | $ | 95.56 | | | | | | | | | $ | 1 | | | | | |
| Q3 2013 | | 8,456 | | | | 95.42 | | | | | | | | | | 2 | | | | | |
| Q4 2013 | | 8,796 | | | | 95.33 | | | | | | | | | | 2 | | | | | |
| Total Q2-Q4 2013 | | 25,199 | | | $ | 95.43 | | | 28,717 | | | 88 | % | | $ | 5 | | | $ | 0.17 | |
| Total 2014 | | 18,451 | | | $ | 93.63 | | | | | | | | | $ | (151 | ) | | | | |
| Total 2015 | | 645 | | | $ | 89.42 | | | | | | | | | $ | 265 | | | | | |
| Total 2016 – 2022 | | 0 | | | $ | - | | | | | | | | | $ | 117 | | | | | |
The company currently has the following crude oil written call options in place:
| | | Call Options (mbbls) | | Avg. NYMEX Strike Price | | Forecasted Oil Production (mbbls) | | Call Options as a % of Forecasted Oil Production |
| | | | | | | | | | | | | | |
| Q2 2013 | | 1,954 | | | $ | 97.90 | | | | | | | |
| Q3 2013 | | 1,975 | | | | 97.90 | | | | | | | |
| Q4 2013 | | 1,975 | | | | 97.90 | | | | | | | |
| Total Q2-Q4 2013 | | 5,904 | | | $ | 97.90 | | | 28,717 | | | 21 | % |
| Total 2014 | | 17,612 | | | $ | 98.79 | | | | | | | |
| Total 2015 | | 27,048 | | | $ | 100.99 | | | | | | | |
| Total 2016 – 2017 | | 24,220 | | | $ | 100.07 | | | | | | | |
The company has the following oil basis protection swaps in place:
| | | Volume (mbbls) | | Avg. NYMEX plus |
| | | | | | | |
| Q2 2013 | | 2,457 | | | $ | 12.34 |
| Q3 2013 | | 736 | | | | 10.07 |
| Q4 2013 | | 0 | | | | - |
| Total Q2-Q4 2013 | | 3,193 | | | $ | 11.82 |
SCHEDULE “B”
MANAGEMENT’S OUTLOOK AS OF FEBRUARY 21, 2013
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF MAY 1, 2013
Chesapeake periodically provides management guidance on certain factors that affect its future financial performance. The primary changes from the company’s November 1, 2012 Outlook are in italicized bold and reflect estimated future production decreases of approximately 35 bcfe in 2013 associated with the company’s planned asset sales.
Chesapeake Energy Corporation Consolidated Projections
| | | Year Ending 12/31/13 |
| Estimated Production: | | |
Natural gas – bcf | | 1,030 – 1,070 |
Oil – mbbls | | 36,000 – 38,000 |
NGL – mbbls | | 24,000 – 26,000 |
Natural gas equivalent – bcfe | | 1,390 – 1,454 |
| | | |
| Daily natural gas equivalent midpoint – mmcfe | | 3,895 |
| | | |
| YOY estimated production increase (adjusted for planned asset sales) | | 0% |
| | | |
NYMEX Price (b) (for calculation of realized heading effects only): | | |
Natural gas - $/mcf | | $3.67 |
Oil - $/bbl | | $95.00 |
| | | |
| Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | | |
Natural gas - $/mcf | | ($0.05) |
Oil - $/bbl | | $0.30 |
| | | |
| Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: | | |
Natural gas - $/mcf | | $1.15 – 1.25 |
Oil - $/bbl | | $0.00 – 2.00 |
NGL - $/bbl | | $66.00 – 70.00 |
| | | |
| Operating Costs per Mcfe of Projected Production: | | |
Production expense | | $0.90 – 0.95 |
| Production taxes | | $0.20 – 0.25 |
General and administrative(c) | | $0.34 – 0.39 |
Stock-based compensation (noncash) | | $0.04 – 0.06 |
DD&A of natural gas and liquids assets | | $1.65 – 1.85 |
Depreciation of other assets | | $0.25 – 0.30 |
Interest expense(d) | | $0.05 – 0.10 |
| | | |
| | | |
| Other ($ millions): | | |
Marketing, gathering and compression net margin(e) | | $90 – 100 |
Oilfield services net margin(e) | | $175 – 225 |
Net income attributable to noncontrolling interest(f) | | ($180) – (220) |
| | | |
| Book Tax Rate | | 39% |
| | | |
| Weighted average shares outstanding (in millions): | | |
Basic | | 645 – 650 |
Diluted | | 758 – 763 |
| | | |
Operating cash flow before changes in assets and liabilities(g)(h) | | $4,850 – 5,150 |
| Well costs on proved and unproved properties | | ($5,750 – 6,250) |
| Acquisition of unproved properties, net | | ($400) |
| a) | Assumes no ethane rejection. |
| b) | NYMEX natural gas and oil prices have been updated for actual contract prices through February and January, respectively. |
| c) | Excludes expenses associated with noncash stock-based compensation. |
| 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 a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities. |
| h) | Assumes NYMEX prices on open contracts of $3.50 to $4.00 per mcf and $95.00 per bbl in 2013. |
Natural Gas, Oil and NGL Hedging Activities
Chesapeake enters into natural gas, oil and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end derivative positions and the accounting for natural gas, oil and NGL derivatives.
As of February 21, 2013, the company has the following open natural gas swaps in place and gains (losses) related to closed natural gas trades and premiums for call options for future production periods.
| | | Open Swaps (bcf) | | Avg. NYMEX Price of Open Swaps | | Forecasted Natural Gas Production (bcf) | | Open Swap Positions as a % of Forecasted Natural Gas Production | | Total Gains (Losses) from Closed Trades and Premiums for Call Options ($ in millions) | | Total Gains (Losses) from Closed Trades and Premiums for Call Options per mcf of Forecasted Natural Gas Production | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Q1 2013 | | 53 | | | $ | 3.72 | | | | | | | | | $ | (9 | ) | | | | | |
| Q2 2013 | | 137 | | | | 3.66 | | | | | | | | | | 11 | | | | | | |
| Q3 2013 | | 141 | | | | 3.59 | | | | | | | | | | 7 | | | | | | |
| Q4 2013 | | 141 | | | | 3.59 | | | | | | | | | | (3 | ) | | | | | |
| Total 2013 | | 472 | | | $ | 3.63 | | | 1,050 | | | 45 | % | | $ | 6 | | | $ | 0.00 | | |
| Total 2014 | | 0 | | | | - | | | | | | | | | $ | (74 | ) | | | | | |
| Total 2015 | | 0 | | | | - | | | | | | | | | $ | (131 | ) | | | | | |
| Total 2016 – 2022 | | 0 | | | | - | | | | | | | | | $ | (187 | ) | | | | | |
The company currently has the following purchased natural gas three-way collars in place:
| | | 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 |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Q1 2013 | | 0 | | | $ | - | | | $ | - | | | $ | - | | | | | | | | | |
| Q2 2013 | | 18 | | | | 3.03 | | | | 3.55 | | | | 4.03 | | | | | | | | | |
| Q3 2013 | | 18 | | | | 3.03 | | | | 3.55 | | | | 4.03 | | | | | | | | | |
| Q4 2013 | | 18 | | | | 3.03 | | | | 3.55 | | | | 4.03 | | | | | | | | | |
| Total 2013 | | 54 | | | $ | 3.03 | | | $ | 3.55 | | | $ | 4.03 | | | | 1,050 | | | | 5% | |
The company currently has the following purchased natural gas written call options in place:
| | | Call Options (bcf) | | Avg. NYMEX Strike Price | | Forecasted Natural Gas Production (bcf) | | Call Options as a % of Forecasted Natural Gas Production |
| | | | | | | | | | | | | | |
| Q1 2013 | | 0 | | | $ | - | | | | | | | |
| Q2 2013 | | 0 | | | | - | | | | | | | |
| Q3 2013 | | 0 | | | | - | | | | | | | |
| Q4 2013 | | 0 | | | | - | | | | | | | |
| Total 2013 | | 0 | | | $ | - | | | 1,050 | | | 0 | % |
| Total 2014 | | 0 | | | $ | - | | | | | | | |
| Total 2015 | | 0 | | | $ | - | | | | | | | |
| Total 2016 – 2020 | | 193 | | | $ | 9.92 | | | | | | | |
The company has the following natural gas basis protection swaps in place:
| | | Volume (bcf) | | Avg. NYMEX less |
| | | | | | | |
| Q1 2013 | | 11 | | | $ | 0.21 |
| Q2 2013 | | 11 | | | | 0.21 |
| Q3 2013 | | 11 | | | | 0.21 |
| Q4 2013 | | 11 | | | | 0.21 |
| Total 2013 | | 44 | | | $ | 0.21 |
| Total 2014 | | 28 | | | $ | 0.32 |
| Total 2015 | | 31 | | | $ | 0.34 |
| Total 2016-2022 | | 8 | | | $ | 1.02 |
| | | |
As of February 21, 2013, the company has the following open crude oil swaps in place and gains (losses) related to closed crude oil contracts and premiums for call options for future production:
| | | 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 |
| | | | | | | | | | | | | | | | | | | | | | |
| Q1 2013 | | 6,401 | | | $ | 95.52 | | | | | | | | | $ | 1 | | | | | |
| Q2 2013 | | 7,935 | | | | 95.56 | | | | | | | | | | 1 | | | | | |
| Q3 2013 | | 8,451 | | | | 95.42 | | | | | | | | | | 2 | | | | | |
| Q4 2013 | | 8,796 | | | | 95.33 | | | | | | | | | | 2 | | | | | |
| Total 2013 | | 31,583 | | | $ | 95.45 | | | 37,000 | | | 85 | % | | $ | 6 | | | $ | 0.17 | |
| Total 2014 | | 18,073 | | | $ | 93.67 | | | | | | | | | $ | (151 | ) | | | | |
| Total 2015 | | 500 | | | $ | 88.75 | | | | | | | | | $ | 265 | | | | | |
| Total 2016 – 2022 | | 0 | | | $ | - | | | | | | | | | $ | 117 | | | | | |
The company currently has the following crude oil written call options in place:
| | | Call Options (mbbls) | | Avg. NYMEX Strike Price | | Forecasted Oil Production (mbbls) | | Call Options as a % of Forecasted Oil Production |
| | | | | | | | | | | | | | |
| Q1 2013 | | 2,125 | | | $ | 98.09 | | | | | | | |
| Q2 2013 | | 1,954 | | | | 97.90 | | | | | | | |
| Q3 2013 | | 1,975 | | | | 97.90 | | | | | | | |
| Q4 2013 | | 1,975 | | | | 97.90 | | | | | | | |
| Total 2013 | | 8,029 | | | $ | 97.95 | | | 37,000 | | | 22 | % |
| Total 2014 | | 17,612 | | | $ | 98.79 | | | | | | | |
| Total 2015 | | 27,048 | | | $ | 100.99 | | | | | | | |
| Total 2016 – 2017 | | 24,220 | | | $ | 100.07 | | | | | | | |
The company has the following oil basis protection swaps in place:
| | | Volume (mbbls) | | Avg. NYMEX plus |
| | | | | | | |
| Q1 2013 | | 2,340 | | | $ | 15.09 |
| Q2 2013 | | 2,457 | | | | 12.34 |
| Q3 2013 | | 736 | | | | 10.07 |
| Q4 2013 | | 0 | | | | - |
| Total 2013 | | 5,533 | | | $ | 13.20 |
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