CHESAPEAKE ENERGY CORPORATION Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2014 second quarter. Key information related to the second quarter is as follows:
- Company reports adjusted net income of $0.36 per fully diluted share and adjusted ebitda of $1.277 billion
- Average production of approximately 695,000 boe per day increases 13% year over year, adjusted for asset sales
- Average oil production of approximately 113,400 bbls per day increases 12% year over year, adjusted for asset sales
- Total capital expenditures of $1.3 billion decrease 27% year over year
- Company increases midpoint of 2014 production outlook by 10,000 boe per day, reiterates 2014 total capex of $5.0 to $5.4 billion
- Spin-off of oilfield services business (NYSE:SSE) completed June 30, 2014
For the 2014 second quarter, Chesapeake reported net income available to common stockholders of $145 million, or $0.22 per fully diluted share. Items typically excluded by securities analysts in their earnings estimates reduced net income available to common stockholders for the 2014 second quarter by approximately $90 million on an after-tax basis and are presented on Page 13 of this release. The primary component of this reduction to net income was a loss on the repurchase of debt securities associated with our April 2014 debt refinancing, partially offset by net gains on sales of fixed assets. Adjusting for these items, 2014 second quarter net income available to common stockholders was $235 million, or $0.36 per fully diluted share, which compares to adjusted net income available to common stockholders of $265 million, or $0.51 per fully diluted share, in the 2013 second quarter.
Adjusted ebitda was $1.277 billion in the 2014 second quarter, compared to $1.424 billion in the 2013 second quarter. Operating cash flow, which is cash flow provided by operating activities before changes in assets and liabilities, was $1.269 billion in the 2014 second quarter, compared to $1.366 billion in the 2013 second quarter. The year-over-year decreases in adjusted ebitda and operating cash flow were primarily the result of higher production and lower per unit costs, which were more than offset by the effect of lower realized oil, natural gas and natural gas liquids (NGL) prices.
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 13 - 17 of this release.
Doug Lawler, Chesapeake’s Chief Executive Officer, commented, "Chesapeake delivered solid organic production growth in the quarter while continuing to demonstrate capital discipline and efficiency. As a result, we are increasing our 2014 production outlook while leaving our capital budget unchanged. In the 2014 second half, we plan to connect approximately 35% more wells to sales than we connected in the first half of the year. As our pace of well connections accelerates, we expect our production growth trajectory will increase accordingly and we anticipate our year-end 2014 exit rate will exceed 730,000 boe per day."
2014 Second Quarter Average Daily Production of Approximately 695,000 Boe Increases 13% Year over Year, Adjusted for Asset Sales
Chesapeake’s daily production for the 2014 second quarter averaged 694,650 barrels of oil equivalent (boe), a year-over-year increase of 13%, adjusted for asset sales. Average daily production consisted of approximately 113,400 barrels (bbls) of oil, 84,300 bbls of NGL and 3.0 billion cubic feet (bcf) of natural gas.
On an adjusted basis, 2014 second quarter average daily oil production increased 12% year over year, average daily NGL production increased 72% year over year and natural gas production increased 7% year over year.
Chesapeake is increasing the midpoint of its expected 2014 daily production rate outlook by 10,000 boe, or 1.5%, to between 685,000 and 705,000 boe per day. The increase in production is partially attributable to better production trends in the first half of 2014, coupled with an increase in forecasted well connections during the second half of 2014. A change in the timing of announced divestitures and the acreage swap with RKI Exploration & Production, LLC (RKI), as described below, also impacted the outlook increase.
Recent Strategic Transactions
On June 30, 2014, Chesapeake completed the spin-off of its oilfield services business into an independent publicly traded company, Seventy Seven Energy Inc. (NYSE:SSE). After the close of business on June 30, 2014, Chesapeake distributed to its shareholders one share of SSE common stock for every 14 shares of Chesapeake common stock held as of June 19, 2014, the record date. In conjunction with the spin-off, Chesapeake removed $1.1 billion of debt associated with SSE from its balance sheet, the effect of which was reflected as of June 30, 2014.
On July 29, 2014, Chesapeake repurchased all of the outstanding preferred shares of its unrestricted subsidiary CHK Utica, L.L.C. (CHK Utica) from third-party preferred shareholders. Chesapeake paid approximately $1.26 billion to repurchase 1,060,000 preferred shares of CHK Utica. The transaction retired Chesapeake’s highest cost leverage instrument and eliminated approximately $75 million in annual cash dividend payments to third-party preferred shareholders.
On July 29, 2014, Chesapeake announced that it had entered into an agreement with RKI to exchange Chesapeake's nonoperated northern Powder River Basin (PRB) acreage for RKI's southern PRB acreage that is operated by Chesapeake. The transaction is expected to increase Chesapeake's PRB holdings by 66,000 net acres and average working interest from 38% to 79%. In addition to the exchange of acreage, Chesapeake will pay RKI $450 million in cash. The transaction, which is subject to certain closing conditions including the receipt of third-party consents, is expected to close in August 2014.
Asset Sales Update
During the 2014 second quarter, the company received total proceeds of approximately $675 million from the sale of noncore assets, including $362 million of net proceeds from the sale of compression assets to Exterran Partners, L.P. (NASDAQ:EXLP).
In the 2014 second half, Chesapeake expects to receive more than $700 million in proceeds from various asset sales that have closed, or are underway. These transactions are expected to include noncore E&P assets in southwestern Pennsylvania, South Central Oklahoma, East Texas and South Texas, as well as additional compression assets and other miscellaneous real estate and equipment.
Chesapeake continues to pursue opportunities to high-grade its portfolio while focusing on assets that best align with 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.
Capital Spending and Cost Overview
Chesapeake's total capital expenditures in the 2014 second quarter were approximately $1.315 billion, of which drilling and completion capital expenditures were approximately $1.131 billion. This level of expenditures represents an increase of approximately $402 million, or 55%, compared to the 2014 first quarter. The sequential increase is primarily the result of higher drilling and completion activity during the 2014 second quarter, including a significant increase in nonoperated drilling and completion activity.
In the 2014 second quarter, net expenditures for the acquisition of unproved properties and geological and geophysical costs were approximately $54 million. Other capital expenditures were approximately $130 million, of which $79 million was attributable to capital spending in its former oilfield services business prior to the June 30, 2014 spin-off. In addition, the company purchased rigs and compressors previously sold under long-term lease arrangements for approximately $82 million as part of its strategic initiative to reduce complexity and future commitments as well as to facilitate asset sales and the SSE spin-off.
Chesapeake spud a total of 324 gross wells and connected 275 gross wells to sales during the 2014 second quarter, compared to 299 gross wells spud and 249 gross wells connected to sales during the 2014 first quarter. In the second half of 2014, the company plans to connect to sales approximately 35% more wells than were connected in the first half of 2014, and anticipates investing approximately 40% more capital on drilling and completions. The company reiterates its 2014 full-year total capital expenditure guidance of $5.0 - $5.4 billion, excluding capitalized interest.
Chesapeake's focus on cost discipline continued to generate reductions in production and general and administrative (G&A) expenses. Average production expenses during the 2014 second quarter were $4.46 per boe, a decrease of 5% from the 2013 second quarter. G&A expenses (including share-based compensation) during the 2014 second quarter were $1.43 per boe, a decrease of 17% from the 2013 second quarter. Interest expense (excluding unrealized gains or losses on interest rate derivatives) during the 2014 second quarter was $0.92 per boe, an 8% increase from the 2013 second quarter, as the company capitalized a smaller percentage of its interest cost due to a decrease in unevaluated natural gas and oil properties.
A summary of the company’s guidance for 2014 is provided in the Outlook dated August 6, 2014, attached to this release as Schedule "A” beginning on Page 18.
Operational Update - Southern Division
Eagle Ford Shale (South Texas): Eagle Ford net production averaged approximately 91,000 boe per day (200,000 gross operated boe per day) during the 2014 second quarter. Adjusted for asset sales, this represents an increase of 15% year over year and 4% sequentially. Approximately 64% of the company’s Eagle Ford production in the 2014 second quarter was oil, 14% was NGL and 22% was natural gas. Current field estimated production rates for the Eagle Ford are more than 101,000 boe per day during the final week of July as increased activity continues to drive higher production.
Chesapeake operated an average of 22 rigs (two of which were spudder rigs) and connected 104 gross wells to sales during the 2014 second quarter in the Eagle Ford, compared to 18 average operated rigs and 81 gross wells connected to sales during the 2014 first quarter. The average peak production rate of the 104 wells that commenced first production in the Eagle Ford during the 2014 second quarter was approximately 825 boe per day.
Mid-Continent (Oklahoma, Texas Panhandle, southern Kansas): Chesapeake's net production in the Mid-Continent during the 2014 second quarter averaged 98,000 boe per day (180,000 gross operated boe per day). Approximately 33% of the company’s Mid-Continent production during the 2014 second quarter was oil, 20% was NGL and 47% was natural gas.
During the 2014 second quarter, Chesapeake operated an average of 18 rigs (one of which was a spudder rig) and connected 56 gross wells to sales in the Mid-Continent, compared to 17 average operated rigs and 52 gross wells connected to sales during the 2014 first quarter. The average peak production rate of the 56 wells that commenced first production in the Mid-Continent during the 2014 second quarter was approximately 710 boe per day.
Haynesville Shale (Northwest Louisiana, East Texas): Chesapeake’s 2014 second quarter average net production in the Haynesville was approximately 508 million cubic feet of natural gas equivalent (mmcfe) per day (785 gross operated mmcfe per day). Adjusted for 2013 asset sales, this represents a decrease of 26% year over year and a 3% increase sequentially. All of the company's production in the Haynesville consists of natural gas.
During the 2014 second quarter, Chesapeake operated an average of eight rigs and connected 13 gross wells to sales in the Haynesville, compared to seven average operated rigs and seven gross wells connected to sales during the 2014 first quarter. The average peak production rate of the 13 wells that commenced first production in the Haynesville during the 2014 second quarter was approximately 12.6 mmcfe per day.
During the 2014 second quarter, Chesapeake brought on to production nine cross unit lateral tests, which enabled the company to increase lateral length by approximately 17% and access incremental resources that would have otherwise been left undeveloped. The company is encouraged by the initial results of these cross unit laterals and will continue to monitor performance.
Operational Update - Northern Division
Utica Shale (Ohio, Pennsylvania, West Virginia): Utica net production averaged approximately 67,000 boe per day (125,000 gross operated boe per day) during the 2014 second quarter, an increase of 373% year over year and 34% sequentially. Approximately 10% of the company’s Utica production during the 2014 second quarter was oil, 30% was NGL and 60% was natural gas.
During the 2014 second quarter, Chesapeake operated an average of eight rigs and connected 48 gross wells to sales in the Utica, compared to an average of nine operated rigs and 47 gross wells connected to sales during the 2014 first quarter. The average peak production rate of the 48 wells that commenced first production in the Utica during the 2014 second quarter was approximately 1,200 boe per day.
As of June 30, 2014, the company had 210 wells awaiting pipeline connection or in various stages of completion in the Utica. In June 2014, the third phase of the Kensington gas processing plant, located in Columbiana County, Ohio, was placed into service. This incremental capacity will enable the company to connect more Utica wells to sales during the 2014 second half and begin to reduce its inventory of nonproducing wells to a more normalized working level.
Northern Marcellus Shale (Pennsylvania): Average net production in the northern Marcellus was approximately 878 mmcfe per day (2,145 gross operated mmcfe per day), an increase of 12% year over year and a decrease of 3% sequentially. The sequential decrease was primarily the result of significant downtime at a large pipeline compressor station in June. All of the company's production in the northern Marcellus consists of natural gas.
During the 2014 second quarter, Chesapeake operated an average of six rigs and connected 21 gross wells to sales in the northern Marcellus, compared to five average operated rigs and 22 gross wells connected to sales during the 2014 first quarter. The average peak production rate of the 21 wells that commenced first production in the northern Marcellus during the 2014 second quarter was approximately 13.6 mmcfe per day.
As of June 30, 2014, the company had 120 wells awaiting pipeline connection or in various stages of completion in the northern Marcellus.
Southern Marcellus Shale (Pennsylvania, West Virginia): Average net production in the southern Marcellus was approximately 58,000 boe per day (95,400 gross operated boe per day), an increase of 67% year over year and an increase of 5% sequentially. Approximately 9% of the company’s southern Marcellus production during the 2014 second quarter was oil, 34% was NGL and 57% was natural gas.
During the 2014 second quarter, Chesapeake operated an average of one rig and connected nine gross wells to sales in the southern Marcellus, compared to two average operated rigs and 11 gross wells connected to sales during the 2014 first quarter. The average peak production rate of the nine wells that commenced first production in the southern Marcellus during the 2014 second quarter was approximately 1,875 boe per day. Chesapeake recently added a second rig in the southern Marcellus where its primary objective will be to delineate the dry Utica formation in the West Virginia Panhandle.
Powder River Basin (Wyoming): Average net production in the PRB was approximately 11,000 boe per day (19,150 gross operated boe per day), an increase of 479% year over year and an increase of 17% sequentially. Approximately 51% of the company’s Powder River Basin production during the 2014 second quarter was oil, 16% was NGL and 33% was natural gas.
During the 2014 second quarter, Chesapeake operated an average of three rigs and connected 11 gross wells to sales in the Powder River Basin, compared to four average operated rigs and 13 gross wells connected to sales during the 2014 first quarter. The average peak production rate of the 11 wells that commenced first production in the Powder River Basin during the 2014 second quarter was approximately 1,765 boe per day.
Chesapeake intends to begin adding more rigs in the Powder River Basin during the 2015 first quarter, and expects to average approximately seven to nine rigs drilling throughout 2015. The company expects that its production from the Powder River Basin will be relatively constrained until the Buckinghorse gas processing plant is placed into service during the 2014 fourth quarter.
As of June 30, 2014, the company had 47 wells awaiting pipeline connection or in various stages of completion in the Powder River Basin.
Key Financial and Operational Results | |||||||||
The table below summarizes Chesapeake’s key financial and operational results during the 2014 second quarter and compares them to results in prior periods. | |||||||||
| Three Months Ended | |||||||||
| 06/30/14 | 03/31/14 | 06/30/13 | |||||||
| Oil equivalent production (in mmboe) | 63.2 | 60.8 | 61.6 | ||||||
| Oil production (in mmbbls) | 10.3 | 9.9 | 10.5 | ||||||
| Average realized oil price ($/bbl)(a) | 85.23 | 85.08 | 93.81 | ||||||
| Oil as % of total production | 16 | 16 | 17 | ||||||
| NGL production (in mmbbls) | 7.7 | 7.6 | 4.8 | ||||||
| Average realized NGL price ($/bbl)(a) | 21.03 | 29.23 | 24.22 | ||||||
| NGL as % of total production | 12 | 13 | 8 | ||||||
| Natural gas production (in bcf) | 271 | 260 | 278 | ||||||
| Average realized natural gas price ($/mcf)(a) | 2.45 | 3.27 | 2.62 | ||||||
| Natural gas as % of total production | 72 | 71 | 75 | ||||||
| Production expenses ($/boe) | (4.46 | ) | (4.73 | ) | (4.68 | ) | |||
| Production taxes ($/boe) | (1.14 | ) | (0.83 | ) | (0.95 | ) | |||
| General and administrative costs ($/boe)(b) | (1.25 | ) | (1.09 | ) | (1.49 | ) | |||
| Share-based compensation ($/boe) | (0.18 | ) | (0.21 | ) | (0.24 | ) | |||
| DD&A of natural gas and liquids properties ($/boe) | (10.45 | ) | (10.33 | ) | (10.48 | ) | |||
| DD&A of other assets ($/boe) | (1.25 | ) | (1.29 | ) | (1.23 | ) | |||
| Interest expense ($/boe)(a) | (0.92 | ) | (0.90 | ) | (0.85 | ) | |||
|
Marketing, gathering and compression net margin
($ in millions)(c) | 1 | 35 | 29 | ||||||
| Oilfield services net margin ($ in millions)(c) | 69 | 45 | 35 | ||||||
| Operating cash flow ($ in millions)(d) | 1,269 | 1,614 | 1,366 | ||||||
| Operating cash flow ($/boe) | 20.07 | 26.55 | 22.19 | ||||||
| Adjusted ebitda ($ in millions)(e) | 1,277 | 1,515 | 1,424 | ||||||
| Adjusted ebitda ($/boe) | 20.20 | 24.94 | 23.14 | ||||||
|
Net income available to common stockholders
($ in millions) | 145 | 374 | 457 | ||||||
| Earnings per share – diluted ($) | 0.22 | 0.54 | 0.66 | ||||||
|
Adjusted net income available to common
stockholders ($ in millions)(f) | 235 | 405 | 265 | ||||||
| Adjusted earnings per share – diluted ($) | 0.36 | 0.59 | 0.51 | ||||||
| Total capital expenditures ($ in millions) | 1,315 | 851 | 1,810 | ||||||
| Capitalized interest ($ in millions) | 155 | 178 | 210 | ||||||
(a) Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging. | |||||||||
(b) Excludes expenses associated with share-based compensation and restructuring and other termination costs. | |||||||||
(c) Includes revenue and operating expenses and excludes depreciation and amortization of other assets. | |||||||||
(d) Defined as cash flow provided by operating activities before changes in assets and liabilities. | |||||||||
(e) 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 17. | |||||||||
(f) Defined as net income available to common stockholders, as adjusted to remove the effects of certain items detailed on Page 13. | |||||||||
2014 Second Quarter Financial and Operational Results Conference Call Information
A conference call to discuss this release has been scheduled for Wednesday, August 6, 2014, at 9:00 am EDT. The telephone number to access the conference call is 913-312-1469 or toll-free 888-778-8903. The passcode for the call is 3038618. 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, August 6, 2014, and will run through 2:00 pm EDT on Wednesday, August 20, 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 3038618. 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 and compression 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. They include statements that give our current expectations or forecasts of future events, production, production growth and well connection forecasts, estimates of operating costs, planned development drilling and expected drilling cost reductions, 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, and the assumptions on which such statements are based. 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 or changed 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. The transaction with RKI is subject to closing conditions, including third-party consents, and it may not be completed in the time frame anticipated or at all. Chesapeake's interest in the properties acquired in the RKI exchange will be reduced if applicable participation rights are exercised and other conditions, including payment to Chesapeake of consideration for such participation, are fulfilled. 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 | ||||||||
| 2014 | 2013 | |||||||
| REVENUES: | ||||||||
| Natural gas, oil and NGL | $ | 1,704 | $ | 2,406 | ||||
| Marketing, gathering and compression | 3,167 | 2,057 | ||||||
| Oilfield services | 281 | 212 | ||||||
| Total Revenues | 5,152 | 4,675 | ||||||
| OPERATING EXPENSES: | ||||||||
| Natural gas, oil and NGL production | 282 | 288 | ||||||
| Production taxes | 72 | 59 | ||||||
| Marketing, gathering and compression | 3,166 | 2,028 | ||||||
| Oilfield services | 212 | 177 | ||||||
| General and administrative | 90 | 106 | ||||||
| Restructuring and other termination costs | 33 | 7 | ||||||
Natural gas, oil and NGL depreciation, depletion and amortization | 661 | 645 | ||||||
| Depreciation and amortization of other assets | 79 | 76 | ||||||
| Impairments of fixed assets and other | 40 | 231 | ||||||
| Net gains on sales of fixed assets | (93 | ) | (109 | ) | ||||
| Total Operating Expenses | 4,542 | 3,508 | ||||||
| INCOME FROM OPERATIONS | 610 | 1,167 | ||||||
| OTHER INCOME (EXPENSE): | ||||||||
| Interest expense | (27 | ) | (104 | ) | ||||
| Earnings (losses) on investments | (24 | ) | 23 | |||||
| Net losses on sales of investments | — | (10 | ) | |||||
| Losses on purchases of debt | (195 | ) | (70 | ) | ||||
| Other income | 7 | 3 | ||||||
| Total Other Expense | (239 | ) | (158 | ) | ||||
| INCOME BEFORE INCOME TAXES | 371 | 1,009 | ||||||
| INCOME TAX EXPENSE: | ||||||||
| Current income taxes | 5 | 2 | ||||||
| Deferred income taxes | 136 | 382 | ||||||
| Total Income Tax Expense | 141 | 384 | ||||||
| NET INCOME | 230 | 625 | ||||||
| Net income attributable to noncontrolling interests | (39 | ) | (45 | ) | ||||
| NET INCOME ATTRIBUTABLE TO CHESAPEAKE | 191 | 580 | ||||||
| Preferred stock dividends | (43 | ) | (43 | ) | ||||
| Premium on purchase of preferred shares of a subsidiary | — | (69 | ) | |||||
| Earnings allocated to participating securities | (3 | ) | (11 | ) | ||||
| NET INCOME AVAILABLE TO COMMON STOCKHOLDERS | $ | 145 | $ | 457 | ||||
| EARNINGS PER COMMON SHARE: | ||||||||
| Basic | $ | 0.22 | $ | 0.70 | ||||
| Diluted | $ | 0.22 | $ | 0.66 | ||||
| WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): | ||||||||
| Basic | 659 | 653 | ||||||
| Diluted | 659 | 760 | ||||||
CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions, except per share data) (unaudited) | ||||||||
| Six Months Ended June 30, | ||||||||
| 2014 | 2013 | |||||||
| REVENUES: | ||||||||
| Natural gas, oil and NGL | $ | 3,471 | $ | 3,858 | ||||
| Marketing, gathering and compression | 6,182 | 3,838 | ||||||
| Oilfield services | 545 | 402 | ||||||
| Total Revenues | 10,198 | 8,098 | ||||||
| OPERATING EXPENSES: | ||||||||
| Natural gas, oil and NGL production | 570 | 595 | ||||||
| Production taxes | 122 | 112 | ||||||
| Marketing, gathering and compression | 6,147 | 3,772 | ||||||
| Oilfield services | 431 | 332 | ||||||
| General and administrative | 169 | 216 | ||||||
| Restructuring and other termination costs | 26 | 140 | ||||||
Natural gas, oil and NGL depreciation, depletion and amortization | 1,288 | 1,293 | ||||||
| Depreciation and amortization of other assets | 157 | 154 | ||||||
| Impairments of fixed assets and other | 60 | 258 | ||||||
| Net gains on sales of fixed assets | (115 | ) | (158 | ) | ||||
| Total Operating Expenses | 8,855 | 6,714 | ||||||
| INCOME FROM OPERATIONS | 1,343 | 1,384 | ||||||
| OTHER INCOME (EXPENSE): | ||||||||
| Interest expense | (66 | ) | (124 | ) | ||||
| Losses on investments | (45 | ) | (14 | ) | ||||
| Net gains (losses) on sales of investments | 67 | (10 | ) | |||||
| Losses on purchases of debt | (195 | ) | (70 | ) | ||||
| Other income | 13 | 8 | ||||||
| Total Other Expense | (226 | ) | (210 | ) | ||||
| INCOME BEFORE INCOME TAXES | 1,117 | 1,174 | ||||||
| INCOME TAX EXPENSE: | ||||||||
| Current income taxes | 8 | 3 | ||||||
| Deferred income taxes | 413 | 443 | ||||||
| Total Income Tax Expense | 421 | 446 | ||||||
| NET INCOME | 696 | 728 | ||||||
| Net income attributable to noncontrolling interests | (80 | ) | (89 | ) | ||||
| NET INCOME ATTRIBUTABLE TO CHESAPEAKE | 616 | 639 | ||||||
| Preferred stock dividends | (86 | ) | (86 | ) | ||||
| Premium on purchase of preferred shares of a subsidiary | — | (69 | ) | |||||
| Earnings allocated to participating securities | (12 | ) | (11 | ) | ||||
| NET INCOME AVAILABLE TO COMMON STOCKHOLDERS | $ | 518 | $ | 473 | ||||
| EARNINGS PER COMMON SHARE: | ||||||||
| Basic | $ | 0.79 | $ | 0.72 | ||||
| Diluted | $ | 0.78 | $ | 0.72 | ||||
| WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): | ||||||||
| Basic | 658 | 653 | ||||||
| Diluted | 760 | 653 | ||||||
CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ($ in millions) (unaudited) | |||||||
June 30, |
December 31, | ||||||
| Cash and cash equivalents | $ | 1,462 | $ | 837 | |||
| Other current assets | 2,908 | 2,819 | |||||
| Total Current Assets | 4,370 | 3,656 | |||||
| Property and equipment, (net) | 36,011 | 37,134 | |||||
| Other assets | 746 | 992 | |||||
| Total Assets | $ | 41,127 | $ | 41,782 | |||
| Current liabilities | $ | 5,792 | $ | 5,515 | |||
| Long-term debt, net of discounts | 11,549 | 12,886 | |||||
| Other long-term liabilities | 1,688 | 1,834 | |||||
| Deferred income tax liabilities | 3,773 | 3,407 | |||||
| Total Liabilities | 22,802 | 23,642 | |||||
| Preferred stock | 3,062 | 3,062 | |||||
| Noncontrolling interests | 2,123 | 2,145 | |||||
| Common stock and other stockholders’ equity | 13,140 | 12,933 | |||||
| Total Equity | 18,325 | 18,140 | |||||
| Total Liabilities and Equity | $ | 41,127 | $ | 41,782 | |||
| Common Shares Outstanding (in millions) | 664 | 664 | |||||
CHESAPEAKE ENERGY CORPORATION CAPITALIZATION ($ in millions) (unaudited) | ||||||||
June 30, |
December 31, | |||||||
| Total debt, net of unrestricted cash | $ | 10,087 | $ | 12,049 | ||||
| Preferred stock | 3,062 | 3,062 | ||||||
| Noncontrolling interests(a) | 2,123 | 2,145 | ||||||
| Common stock and other stockholders’ equity | 13,140 | 12,933 | ||||||
| Total | $ | 28,412 | $ | 30,189 | ||||
| Total debt to capitalization ratio | 36 | % | 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 | 294 | 314 | ||||||
| Other | 7 | 9 | ||||||
| Total | $ | 2,123 | $ | 2,145 | ||||
CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA - NATURAL GAS, OIL AND NGL PRODUCTION, SALES AND INTEREST EXPENSE (unaudited) | ||||||||||||||||
| Three Months Ended June 30, | Six Months Ended | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Net Production: | ||||||||||||||||
| Natural gas (bcf) | 271.3 | 277.6 | 531.4 | 550.8 | ||||||||||||
| Oil (mmbbl) | 10.3 | 10.5 | 20.2 | 19.8 | ||||||||||||
| NGL (mmbbl) | 7.7 | 4.8 | 15.2 | 9.6 | ||||||||||||
| Oil equivalent (mmboe) | 63.2 | 61.6 | 124.0 | 121.2 | ||||||||||||
| Natural Gas, Oil and NGL Sales ($ in millions): | ||||||||||||||||
| Natural gas sales | $ | 750 | $ | 779 | $ | 1,754 | $ | 1,352 | ||||||||
| Natural gas derivatives – realized gains (losses)(a) | (86 | ) | (53 | ) | (240 | ) | (45 | ) | ||||||||
| Natural gas derivatives – unrealized gains (losses)(a) | 113 | 347 | (41 | ) | 68 | |||||||||||
| Total Natural Gas Sales | 777 | 1,073 | 1,473 | 1,375 | ||||||||||||
| Oil sales | 1,006 | 975 | 1,928 | 1,859 | ||||||||||||
| Oil derivatives – realized gains (losses)(a) | (127 | ) | 14 | (210 | ) | 10 | ||||||||||
| Oil derivatives – unrealized gains (losses)(a) | (113 | ) | 229 | (103 | ) | 361 | ||||||||||
| Total Oil Sales | 766 | 1,218 | 1,615 | 2,230 | ||||||||||||
| NGL sales | 161 | 115 | 383 | 253 | ||||||||||||
| Total NGL Sales | 161 | 115 | 383 | 253 | ||||||||||||
| Total Natural Gas, Oil and NGL Sales | $ | 1,704 | $ | 2,406 | $ | 3,471 | $ | 3,858 | ||||||||
| Average Sales Price – excluding gains (losses) on derivatives: | ||||||||||||||||
| Natural gas ($ per mcf) | $ | 2.76 | $ | 2.81 | $ | 3.30 | $ | 2.45 | ||||||||
| Oil ($ per bbl) | $ | 97.49 | $ | 92.53 | $ | 95.59 | $ | 93.79 | ||||||||
| NGL ($ per bbl) | $ | 21.03 | $ | 24.22 | $ | 25.10 | $ | 26.26 | ||||||||
| Oil equivalent ($ per boe) | $ | 30.32 | $ | 30.36 | $ | 32.79 | $ | 28.57 | ||||||||
| Average Sales Price – including realized gains (losses) on derivatives: | ||||||||||||||||
| Natural gas ($ per mcf) | $ | 2.45 | $ | 2.62 | $ | 2.85 | $ | 2.37 | ||||||||
| Oil ($ per bbl) | $ | 85.23 | $ | 93.81 | $ | 85.16 | $ | 94.29 | ||||||||
| NGL ($ per bbl) | $ | 21.03 | $ | 24.22 | $ | 25.10 | $ | 26.26 | ||||||||
| Oil equivalent ($ per boe) | $ | 26.97 | $ | 29.73 | $ | 29.16 | $ | 28.28 | ||||||||
| Interest Expense (Income) ($ in millions): | ||||||||||||||||
| Interest(b) | $ | 61 | $ | 54 | $ | 119 | $ | 70 | ||||||||
| Derivatives – realized (gains) losses(c) | (3 | ) | (1 | ) | (6 | ) | (3 | ) | ||||||||
| Derivatives – unrealized (gains) losses(c) | (31 | ) | 51 | (47 | ) | 57 | ||||||||||
| Total Interest Expense | $ | 27 | $ | 104 | $ | 66 | $ | 124 | ||||||||
(a) Realized gains and losses include the following items: (i) settlements of nondesignated 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: |
June 30, |
June 30, | ||||||
| Beginning cash | $ | 1,004 | $ | 33 | ||||
| Cash provided by operating activities | 1,352 | 1,281 | ||||||
| Cash flows from investing activities: | ||||||||
Drilling and completion costs on proved and unproved properties(a) | (1,082 | ) | (1,551 | ) | ||||
| Acquisition of proved and unproved properties(b) | (169 | ) | (256 | ) | ||||
| Sale of proved and unproved properties | 198 | 1,691 | ||||||
| Geological and geophysical costs | (16 | ) | (15 | ) | ||||
| Cash paid to purchase leased rigs and compressors | (82 | ) | (3 | ) | ||||
| Additions to other property and equipment | (56 | ) | (152 | ) | ||||
| Property and equipment deposits | (45 | ) | (21 | ) | ||||
| Proceeds from sales of other assets | 474 | 258 | ||||||
| Additions to investments | (2 | ) | (1 | ) | ||||
| Proceeds from sales of investments | — | 102 | ||||||
| Other | (1 | ) | 118 | |||||
| Total cash provided by (used in) investing activities | (781 | ) | 170 | |||||
| Cash used in financing activities | (113 | ) | (807 | ) | ||||
| Change in cash and cash equivalents | 458 | 644 | ||||||
| Ending cash | $ | 1,462 | $ | 677 | ||||
(a) Includes capitalized interest of $9 million and $17 million for the three months ended June 30, 2014 and 2013, respectively. | ||||||||
(b) Includes capitalized interest of $140 million and $173 million for the three months ended June 30, 2014 and 2013, respectively. | ||||||||
| SIX MONTHS ENDED: | June 30, 2014 | June 30, 2013 | ||||||
| Beginning cash | $ | 837 | $ | 287 | ||||
| Cash provided by operating activities | 2,643 | 2,205 | ||||||
| Cash flows from investing activities: | ||||||||
Drilling and completion costs on proved and unproved properties(a) | (1,976 | ) | (3,117 | ) | ||||
| Acquisition of proved and unproved properties(b) | (348 | ) | (511 | ) | ||||
| Sale of proved and unproved properties | 240 | 1,856 | ||||||
| Geological and geophysical costs | (20 | ) | (28 | ) | ||||
| Cash paid to purchase leased rigs and compressors | (422 | ) | (3 | ) | ||||
| Additions to other property and equipment | (153 | ) | (482 | ) | ||||
| Property and equipment deposits | (45 | ) | (21 | ) | ||||
| Proceeds from sales of other assets | 713 | 459 | ||||||
| Additions to investments | (5 | ) | (4 | ) | ||||
| Proceeds from sales of investments | 239 | 102 | ||||||
| Other | (3 | ) | 174 | |||||
| Total cash used in investing activities | (1,780 | ) | (1,575 | ) | ||||
| Cash used in financing activities | (238 | ) | (240 | ) | ||||
| Change in cash and cash equivalents | 625 | 390 | ||||||
| Ending cash | $ | 1,462 | $ | 677 | ||||
(a) Includes capitalized interest of $21 million and $32 million for the six months ended June 30, 2014 and 2013, respectively. | ||||||||
(b) Includes capitalized interest of $298 million and $380 million for the six months ended June 30, 2014 and 2013, respectively. | ||||||||
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in millions, except per share data) (unaudited) | ||||||||||||
| THREE MONTHS ENDED: |
June 30, |
March 31, |
June 30, | |||||||||
Net income available to common stockholders | $ | 145 | $ | 374 | $ | 457 | ||||||
| Adjustments, net of tax: | ||||||||||||
| Unrealized (gains) losses on derivatives | (19 | ) | 80 | (325 | ) | |||||||
| Restructuring and other termination costs | 20 | (4 | ) | 5 | ||||||||
| Impairments of fixed assets and other | 25 | 12 | 143 | |||||||||
| Net gains on sales of fixed assets | (57 | ) | (14 | ) | (68 | ) | ||||||
| Impairments of investments | 3 | — | — | |||||||||
| Net (gains) losses on sales of investments | — | (42 | ) | 6 | ||||||||
| Losses on purchases of debt and extinguishment of other financing | 120 | — | 44 | |||||||||
| Other | (2 | ) | (1 | ) | 3 | |||||||
| Adjusted net income available to common stockholders(a) | 235 | 405 | 265 | |||||||||
| Preferred stock dividends | 43 | 43 | 43 | |||||||||
| Premium on purchase of preferred shares of a subsidiary | — | — | 69 | |||||||||
| Earnings allocated to participating securities | 3 | 8 | 11 | |||||||||
| Total adjusted net income attributable to Chesapeake | $ | 281 | $ | 456 | $ | 388 | ||||||
Weighted average fully diluted shares outstanding (in millions)(b) | 776 | 767 | 763 | |||||||||
| Adjusted earnings per share assuming dilution(a) | $ | 0.36 | $ | 0.59 | $ | 0.51 | ||||||
(a) Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with accounting principles generally accepted in the United States (GAAP) because: | ||||||||||||
(i) Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. | ||||||||||||
(ii) Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. | ||||||||||||
(iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. | ||||||||||||
(b) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. | ||||||||||||
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in millions, except per share data) (unaudited) | ||||||||
| SIX MONTHS ENDED: |
June 30, |
June 30, | ||||||
| Net income available to common stockholders | $ | 518 | $ | 473 | ||||
| Adjustments, net of tax: | ||||||||
| Unrealized (gains) losses on derivatives | 61 | (230 | ) | |||||
| Restructuring and other termination costs | 16 | 87 | ||||||
| Impairments of fixed assets and other | 37 | 160 | ||||||
| Net gains on sales of fixed assets | (72 | ) | (98 | ) | ||||
| Impairments of investments | 3 | 6 | ||||||
| Net (gains) losses on sales of investments | (42 | ) | 6 | |||||
| Losses on purchases of debt and extinguishment of other financing | 121 | 44 | ||||||
| Other | (3 | ) | — | |||||
| Adjusted net income available to common stockholders(a) | 639 | 448 | ||||||
| Preferred stock dividends | 86 | 86 | ||||||
| Premium on purchase of preferred shares of a subsidiary | — | 69 | ||||||
| Earnings allocated to participating securities | 12 | 11 | ||||||
| Total adjusted net income attributable to Chesapeake | $ | 737 | $ | 614 | ||||
| Weighted average fully diluted shares outstanding (in millions)(b) | 776 | 764 | ||||||
| Adjusted earnings per share assuming dilution(a) | $ | 0.95 | $ | 0.80 | ||||
(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: | June 30, 2014 | March 31, 2014 | June 30, 2013 | |||||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 1,352 | $ | 1,291 | $ | 1,281 | ||||||
| Changes in assets and liabilities | (83 | ) | 323 | 85 | ||||||||
| OPERATING CASH FLOW(a) | $ | 1,269 | $ | 1,614 | $ | 1,366 | ||||||
| THREE MONTHS ENDED: | June 30, 2014 | March 31, 2014 | June 30, 2013 | |||||||||
| NET INCOME | $ | 230 | $ | 466 | $ | 625 | ||||||
| Interest expense | 27 | 39 | 104 | |||||||||
| Income tax expense | 141 | 280 | 384 | |||||||||
| Depreciation and amortization of other assets | 79 | 78 | 76 | |||||||||
| Natural gas, oil and NGL depreciation, depletion and amortization | 661 | 628 | 645 | |||||||||
| EBITDA(b) | $ | 1,138 | $ | 1,491 | $ | 1,834 | ||||||
| THREE MONTHS ENDED: | June 30, 2014 | March 31, 2014 | June 30, 2013 | |||||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 1,352 | $ | 1,291 | $ | 1,281 | ||||||
| Changes in assets and liabilities | (83 | ) | 323 | 85 | ||||||||
| Interest expense, net of unrealized gains on derivatives | 58 | 55 | 53 | |||||||||
| Natural gas, oil and NGL derivative gains (losses), net | (213 | ) | (382 | ) | 598 | |||||||
| Cash payments on natural gas, oil and NGL derivative settlements, net | 150 | 168 | (22 | ) | ||||||||
| Share-based compensation | (20 | ) | (20 | ) | (24 | ) | ||||||
| Restructuring and other termination costs | (33 | ) | 9 | 1 | ||||||||
| Impairments of fixed assets and other | (39 | ) | (12 | ) | (231 | ) | ||||||
| Net gains on sales of fixed assets | 93 | 23 | 109 | |||||||||
| Earnings (losses) on investments | (24 | ) | (21 | ) | 22 | |||||||
| Net gains (losses) on sales of investments | — | 67 | (10 | ) | ||||||||
| Losses on purchases of debt and extinguishment of other financing | (61 | ) | — | (17 | ) | |||||||
| Other items | (42 | ) | (10 | ) | (11 | ) | ||||||
| EBITDA(b) | $ | 1,138 | $ | 1,491 | $ | 1,834 | ||||||
(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 that 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 before interest expense, income taxes, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP. | ||||||||||||
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA ($ in millions) (unaudited) | ||||||||
| SIX MONTHS ENDED: | June 30, 2014 | June 30, 2013 | ||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 2,643 | $ | 2,205 | ||||
| Changes in assets and liabilities | 240 | 341 | ||||||
| OPERATING CASH FLOW(a) | $ | 2,883 | $ | 2,546 | ||||
| SIX MONTHS ENDED: | June 30, 2014 | June 30, 2013 | ||||||
| NET INCOME | $ | 696 | $ | 728 | ||||
| Interest expense | 66 | 124 | ||||||
| Income tax expense | 421 | 446 | ||||||
| Depreciation and amortization of other assets | 157 | 154 | ||||||
| Natural gas, oil and NGL depreciation, depletion and amortization | 1,288 | 1,293 | ||||||
| EBITDA(b) | $ | 2,628 | $ | 2,745 | ||||
| SIX MONTHS ENDED: | June 30, 2014 | June 30, 2013 | ||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 2,643 | $ | 2,205 | ||||
| Changes in assets and liabilities | 240 | 341 | ||||||
| Interest expense, net of unrealized gains (losses) on derivatives | 113 | 67 | ||||||
| Natural gas, oil and NGL derivative gains (losses), net | (595 | ) | 470 | |||||
| Cash payments on natural gas, oil and NGL derivative settlements, net | 318 | (41 | ) | |||||
| Share-based compensation | (40 | ) | (56 | ) | ||||
| Restructuring and other termination costs | (24 | ) | (104 | ) | ||||
| Impairments of fixed assets and other | (51 | ) | (258 | ) | ||||
| Net gains on sales of fixed assets | 115 | 158 | ||||||
| Losses on investments | (45 | ) | (7 | ) | ||||
| Net gains (losses) on sales of investments | 67 | (10 | ) | |||||
| Losses on purchases of debt and extinguishment of other financing | (61 | ) | (17 | ) | ||||
| Other items | (52 | ) | (3 | ) | ||||
| EBITDA(b) | $ | 2,628 | $ | 2,745 | ||||
(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 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: | June 30, 2014 | March 31, 2014 | June 30, 2013 | |||||||||
| EBITDA | $ | 1,138 | $ | 1,491 | $ | 1,834 | ||||||
| Adjustments: | ||||||||||||
| Unrealized (gains) losses on natural gas, oil and NGL derivatives | — | 144 | (576 | ) | ||||||||
| Restructuring and other termination costs | 33 | (7 | ) | 7 | ||||||||
| Impairments of fixed assets and other | 40 | 20 | 231 | |||||||||
| Net gains on sales of fixed assets | (93 | ) | (23 | ) | (109 | ) | ||||||
| Impairments of investments | 5 | — | — | |||||||||
| Net (gains) losses on sales of investments | — | (67 | ) | 10 | ||||||||
| Losses on purchases of debt and extinguishment of other financing | 195 | — | 70 | |||||||||
|
Net income attributable to noncontrolling
interests | (39 | ) | (41 | ) | (45 | ) | ||||||
| Other | (2 | ) | (2 | ) | 2 | |||||||
| Adjusted EBITDA(a) | $ | 1,277 | $ | 1,515 | $ | 1,424 | ||||||
| SIX MONTHS ENDED: | June 30, 2014 | June 30, 2013 | ||||||||||
| EBITDA | $ | 2,628 | $ | 2,745 | ||||||||
| Adjustments: | ||||||||||||
| Unrealized (gains) losses on natural gas, oil and NGL derivatives | 144 | (429 | ) | |||||||||
| Restructuring and other termination costs | 26 | 140 | ||||||||||
| Impairments of fixed assets and other | 60 | 258 | ||||||||||
| Net gains on sales of fixed assets | (115 | ) | (158 | ) | ||||||||
| Impairment of investments | 5 | 10 | ||||||||||
| Net (gains) losses on sales of investments | (67 | ) | 10 | |||||||||
| Losses on purchases of debt and extinguishment of other financing | 195 | 70 | ||||||||||
|
Net income attributable to noncontrolling
interests | (80 | ) | (89 | ) | ||||||||
| Other | (4 | ) | 1 | |||||||||
| Adjusted EBITDA(a) | $ | 2,792 | $ | 2,558 | ||||||||
(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” CHESAPEAKE ENERGY CORPORATION MANAGEMENT’S OUTLOOK AS OF AUGUST 6, 2014 | |
Chesapeake periodically provides management guidance on certain factors that affect the company’s future financial performance. The primary changes from the company’s May 16, 2014 Outlook are in italicized bold below. | |
Year Ending | |
| Production Growth (adjusted for asset sales)(a): | |
| Liquids: | 29 – 33% |
| Oil | 11 – 15% |
| NGL(b) | 63 – 68% |
| Natural gas | 4 – 6% |
| Total Adjusted Production Growth | 9 – 12% |
| Daily Equivalent Rate - mboe | 685 – 705 |
| NYMEX Price(c) (for calculation of realized hedging effects only): | |
| Oil - $/bbl | $97.92 |
| Natural gas - $/mcf | $4.43 |
| Estimated Realized Hedging Effects(d) (based on assumed NYMEX prices above): | |
| Oil - $/bbl | ($7.84) |
| Natural gas - $/mcf | ($0.21) |
| Estimated Basis/Gathering/Marketing/Transportation Differentials to NYMEX Prices: | |
| Oil - $/bbl | $5.00 – 7.00 |
| NGL - $/bbl | $72.00 – 76.00 |
| Natural gas - $/mcf | $1.75 – 1.85 |
| Operating Costs per Boe of Projected Production: | |
| Production expense | $4.25 – 4.75 |
| Production taxes | $0.90 – 1.00 |
| 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 | $0.90 – 1.00 |
| Interest expense(f) | $0.65 – 0.75 |
| Other ($ millions): | |
| Marketing, gathering and compression net margin(g) | $50 – 75 |
| Net income attributable to noncontrolling interests and other(h) | ($100 – 130) |
| Book Tax Rate | 37.5% |
| Weighted Average Shares Outstanding (in millions): | |
| Basic | 657 – 661 |
| Diluted | 775 – 779 |
| Operating Cash Flow before Changes in Assets and Liabilities ($ in millions) (i)(j) | $5,350 – 5,550 |
| Total Capital Expenditures ($ in millions) | $5,000 – 5,400 |
| Capitalized interest, dividends and distributions ($ in millions) | $1,070 – 1,120 |
a) Growth ranges based on 2013 production of 604 mboe/day adjusted for asset sales in 2013 and 2014. | |
b) Assumes ethane recovery in the Utica and southern Marcellus to fulfill Chesapeake’s pipeline commitments, no ethane recovery in the Rockies and partial ethane recovery in the Mid-Continent and Eagle Ford. | |
c) NYMEX natural gas and oil prices have been updated for actual contract prices through July and June, 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, L.L.C. and CHK Cleveland Tonkawa, L.L.C. CHK Utica became wholly owned on July 29, 2014 when the company purchased CHK Utica preferred shares held by third parties. | |
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 $4.00 per mcf and production growth ranges as shown above. | |
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 July 31, 2014, the company had downside protection on approximately 69% of its remaining projected 2014 natural gas production at an average price of $4.12 per thousand cubic feet of natural gas. Approximately 65% of the company's remaining projected 2014 oil production had downside protection at an average price of $94.25 per bbl.
The company’s natural gas hedging positions as of July 31, 2014 were as follows:
Open Natural Gas Swaps; Gains (Losses) from Closed Natural Gas Trades and Call Option Premiums | ||||||||||
|
Open
Swaps (bcf) |
Avg. NYMEX
Price of Open Swaps |
Total Gains (Losses) from
Closed Trades and Premiums for Call Options ($ in millions) | ||||||||
| Q3 2014 | 112 | $ | 4.09 | $ | (15 | ) | ||||
| Q4 2014 | 112 | 4.09 | (21 | ) | ||||||
| Total Q3 - Q4 2014 | 224 | $ | 4.09 | $ | (36 | ) | ||||
| 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 | ||||||||||
| Q3 2014 | 57 | $ | 3.55 | $ | 4.09 | $ | 4.38 | ||||||
| Q4 2014 | 71 | 3.49 | 4.11 | 4.37 | |||||||||
| Total Q3 - Q4 2014 | 128 | $ | 3.52 | $ | 4.10 | $ | 4.37 | ||||||
| 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 | |||||||
| Q3 2014 | 11 | $ | 4.50 | $ | 5.24 | ||||
| Q4 2014 | 11 | 4.50 | 5.24 | ||||||
| Total Q3 - Q4 2014 | 22 | $ | 4.50 | $ | 5.24 | ||||
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 | |||||
| Q3 2014 | 46 | $ | (0.53 | ) | ||
| Q4 2014 | 25 | (0.62 | ) | |||
| Total Q3 - Q4 2014 | 71 | $ | (0.56 | ) | ||
| Total 2015 | 38 | $ | (0.48 | ) | ||
| Total 2016 - 2022 | 8 | $ | (1.02 | ) | ||
The company’s crude oil hedging positions as of July 31, 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) | ||||||||
| Q3 2014 | 7,241 | $ | 94.28 | $ | (48 | ) | ||||
| Q4 2014 | 7,197 | 94.22 | (49 | ) | ||||||
| Total Q3 - Q4 2014 | 14,438 | $ | 94.25 | $ | (97 | ) | ||||
| Total 2015 | 12,457 | $ | 94.58 | $ | 239 | |||||
| Total 2016 – 2022 | 0 | — | $ | 117 | ||||||
Crude Oil Written Call Options | |||||
|
Call Options
(mbbls) |
Avg. NYMEX
Strike Price | ||||
| Q3 2014 | 626 | $ | 83.53 | ||
| Q4 2014 | 626 | 83.53 | |||
| Total Q3 - Q4 2014 | 1,252 | $ | 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 | ||||
| Q3 2014 | 92 | $ | 6.00 | ||
| Q4 2014 | 92 | 6.00 | |||
| Total Q3 - Q4 2014 | 184 | $ | 6.00 | ||
