Attached files
| file | filename |
|---|---|
| 8-K - CURRENT REPORT - CHESAPEAKE ENERGY CORP | chk_8-kx093013.htm |
News Release |  | |
NOT FOR IMMEDIATE RELEASE - DRAFT 6
NOVEMBER 6, 2013
CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL AND
OPERATIONAL RESULTS FOR THE 2013 THIRD QUARTER
OKLAHOMA CITY, NOVEMBER 6, 2013 – Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2013 third quarter. Key information related to the quarter and Chesapeake's updated Outlook is as follows:
• | Adjusted net income per fully diluted share of $0.43, compared to $0.10 in the 2012 third quarter |
• | Adjusted ebitda of $1.325 billion increases 29% year over year |
• | Net daily oil production rises 23% year over year to 120,000 bbls per day |
• | Full-year 2013 oil production outlook increases by 2 million barrels to 40 – 42 million barrels, a 28 – 34% increase year over year |
• | Full-year 2013 drilling, completion and leasehold capital expenditure outlook decreases by $300 million to $5.700 – $6.050 billion |
• | Conference call at 9:00 am EST today; dial-in 913-312-0713, passcode 5588965 |
Chesapeake reported net income available to common stockholders of $156 million or $0.24 per fully diluted share. These results include the effects of the following after-tax items:
◦ | noncash unrealized mark-to-market losses of $118 million from the company’s derivative instruments; |
◦ | a charge of $55 million for the impairment of certain of the company’s property and equipment and other assets; |
◦ | a net gain of $82 million on sales of certain of the company’s property and equipment, consisting primarily of midstream assets; and |
◦ | a $39 million charge for restructuring and other termination benefits. |
Adjusting for these and other items not typically included in earnings estimates by securities analysts, Chesapeake reported adjusted net income available to common stockholders of $282 million, or $0.43 per fully diluted share, which compares to adjusted net income available to common stockholders of $35 million, or $0.10 per fully diluted share, in the 2012 third quarter.
The company reported adjusted ebitda of $1.325 billion, an increase of 29% year over year. Operating cash flow, which is cash flow provided by operating activities before changes in assets and liabilities, was $1.368 billion, an increase of 22% year over year. Additional definitions and reconciliations to comparable financial measures calculated in accordance with generally accepted accounting principles of adjusted net income available to common stockholders, operating cash flow, ebitda and adjusted ebitda are provided on pages 12 – 16 of this release.
Doug Lawler, Chesapeake’s Chief Executive Officer, said, "We are pleased with our operational performance during the third quarter. Our strong results compared to the 2012 third quarter were driven by a substantial increase in oil and natural gas liquids production, higher realized natural gas prices and significantly lower per-unit production, overhead and DD&A expenses. Additionally, our focus on financial discipline and operational efficiencies generated lower-than-expected capital expenditures during the 2013 third quarter, and we have reduced our full-year 2013 capital spending outlook accordingly. I am particularly impressed by the strong performance of the company while
INVESTOR CONTACTS: | MEDIA CONTACT: | CHESAPEAKE ENERGY CORPORATION | ||
Jeffrey L. Mobley, CFA Gary T. Clark, CFA (405) 935-8870 ir@chk.com | Gordon Pennoyer (405) 935-8878 media@chk.com | 6100 North Western Avenue P.O. Box 18496 Oklahoma City, OK 73154 | ||
we implemented significant transformational initiatives over the past few months. We look forward to achieving further efficiency gains and improvements in returns on capital in 2014."
2013 Third Quarter Oil Production Increases 23% Year over Year to 120,000 Bbls per Day; Total Production Decreases 2% Year over Year to 4.0 Bcfe per Day, Primarily Due to Asset Sales
Chesapeake’s daily production for the 2013 third quarter averaged approximately 4.0 billion cubic feet of natural gas equivalent (bcfe), a decrease of 2% from the 2012 third quarter and a nominal decrease from the 2013 second quarter. This decrease is primarily due to production losses associated with recent asset sales in the Mississippi Lime, northern Eagle Ford Shale and Haynesville Shale, as well as the sale of Permian Basin assets in September and October of 2012. Adjusted for asset sales, the company's production increased approximately 8% year over year and 5% sequentially.
The company’s average daily production consisted of approximately 3.0 billion cubic feet (bcf) of natural gas and 178,500 barrels (bbls) of liquids, comprised of approximately 120,000 bbls of oil and 58,500 bbls of natural gas liquids (NGL).
During the 2013 third quarter, average daily oil production increased 23% year over year and 4% sequentially, and average daily NGL production increased 31% year over year and 12% sequentially. Natural gas production in the third quarter decreased 10% year over year and 3% sequentially. Liquids accounted for 27% of total production during the 2013 third quarter, up from 21% during the 2012 third quarter and 25% during the 2013 second quarter.
Mr. Lawler added, "Our oil assets in the Eagle Ford Shale continue to deliver strong results, prompting us to raise our full-year 2013 oil production guidance by 2 million barrels (mmbbls) to 40 – 42 mmbbls. We are also reducing the midpoint of our 2013 NGL production guidance range by 1.5 mmbbls, primarily reflecting continued high levels of ethane rejection as well as a slower production ramp in the Utica Shale, resulting from unexpected downtime at a third-party gas processing facility. "
Capital Spending and Cost Overview
During the 2013 third quarter, Chesapeake operated an average of 67 rigs and invested approximately $1.2 billion in drilling and completion activities. This represents a decrease of approximately $350 million compared to the 2013 second quarter. Chesapeake spud a total of 253 gross wells and completed 321 gross wells during the 2013 third quarter, compared to 312 gross wells spud and 410 gross wells completed during the 2013 second quarter.
Mr. Lawler noted, "Although we have reduced our drilling and completion activities in the second half of 2013 and we are planning for a lower capital expenditure budget next year, we expect to continue delivering organic production growth in 2014. We anticipate our growth will be led by an increase in oil production from the Eagle Ford Shale and an increase in natural gas and NGL production from the Utica and Marcellus shales, which will benefit from new gas processing and pipeline takeaway capacity."
During the 2013 fourth quarter, Chesapeake plans to operate an average of 59 rigs and to complete approximately 14% fewer gross wells compared to the 2013 third quarter. Based on this planned
2
activity level, the company is reducing its 2013 full-year guidance for drilling and completion costs from a range of $5.7 – $6.0 billion to $5.5 – $5.8 billion.
Net expenditures for the acquisition of unproved properties were approximately $45 million during the 2013 third quarter. The company continues to track below its budgeted leasehold expenditures for the year and is lowering its 2013 full-year leasehold expenditure guidance from $300 – $350 million to $200 – $250 million. Other capital expenditures were approximately $170 million during the 2013 third quarter.
Average production expenses during the 2013 third quarter were $0.76 per thousand cubic feet of natural gas equivalent (mcfe), a decrease of 10% year over year. General and administrative (G&A) expenses (excluding stock-based compensation and restructuring and other termination benefits) were $0.29 per mcfe, a decrease of 12% year over year.
A complete summary of the company’s guidance for 2013 is provided in the Outlook dated November 6, 2013 which is attached to this release as Schedule "A” beginning on Page 17. This updates information previously provided in the Outlook dated August 1, 2013.
Asset Sales Update
As of September 30, 2013, Chesapeake had completed asset sales of approximately $3.6 billion in 2013. During the 2013 fourth quarter, the company anticipates completing additional asset sales for net proceeds of approximately $600 million. Chesapeake continues to pursue other asset sale transactions that may close in the first half of 2014. The proceeds from such sales are anticipated to be directed toward reducing financial leverage and complexity and further enhancing liquidity.
Operational Update
The company continues to achieve strong operational results in its most active plays.
Eagle Ford Shale (South Texas): Eagle Ford Shale net production averaged approximately 95,000 barrels of oil equivalent (boe) per day (211,000 gross operated boe per day) during the 2013 third quarter. This production is net of approximately 6,300 boe per day of production associated with assets sold in the northern Eagle Ford on July 31, 2013, and represents an increase of 82% year over year and 11% sequentially. Approximately 68% of the company’s Eagle Ford production consisted of oil, 12% was NGL and 20% was natural gas.
Chesapeake operated an average of 13 rigs and connected 100 gross wells to sales during the 2013 third quarter, compared to 14 average operated rigs and 140 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 100 wells that commenced first production during the 2013 third quarter was approximately 930 boe per day.
As of September 30, 2013, net of recent asset sales, Chesapeake had 788 producing wells and 117 wells waiting on pipeline or in various stages of completion in the Eagle Ford Shale.
Utica Shale (eastern Ohio, Pennsylvania, West Virginia): Utica Shale net production averaged approximately 164 million cubic feet of natural gas equivalent (mmcfe) per day (312 gross operated mmcfe per day) during the 2013 third quarter, an increase of 91% sequentially from the 2013 second quarter.
During the 2013 third quarter, Chesapeake operated an average of 11 rigs and connected 63 gross wells to sales, compared to 12 average operated rigs and 42 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 63 wells that commenced first production in the Utica during the 2013 third quarter was approximately 6.6 mmcfe per day.
As of September 30, 2013, Chesapeake had drilled a total of 377 wells in the Utica, which included 169 producing wells and 208 wells waiting on pipeline connection or in various stages of completion.
3
Greater Anadarko Basin (Oklahoma, Texas Panhandle, southern Kansas): Chesapeake's production in the Greater Anadarko Basin comes primarily from five plays: the Mississippi Lime, Granite Wash, Cleveland, Tonkawa and Hogshooter. Aggregate net production from these plays during the 2013 third quarter averaged 109,000 boe per day (196,000 gross operated boe per day), an increase of 12% year over year and a decrease of 14% sequentially. The sequential production decrease is primarily driven by the sale of assets in the Mississippi Lime at the end of June 2013 that produced approximately 22,200 boe per day during the 2013 second quarter. Approximately 34% of the company’s Greater Anadarko Basin production during the 2013 third quarter was oil, 21% was NGL and 45% was natural gas.
During the 2013 third quarter, Chesapeake operated an average of 22 rigs and connected 89 gross wells to sales, compared to 28 operated rigs and 123 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 89 wells that commenced first production in the Greater Anadarko Basin during the 2013 third quarter was approximately 830 boe per day.
As of September 30, 2013, the company had 44 wells waiting on pipeline connection or in various stages of completion in the Greater Anadarko Basin.
Northern Marcellus Shale (Pennsylvania): The company’s production from the northern Marcellus continued to grow during the 2013 third quarter, despite certain temporary downstream takeaway constraints. The company expects that these constraints will be significantly or completely relieved in the 2013 fourth quarter as new capacity expansion projects are placed in-service on several key pipelines. Chesapeake has contracted for approximately one-third of the estimated 1.4 bcf per day of new pipeline capacity expected to be placed on-line in the 2013 fourth quarter, which the company believes will benefit both its production volumes and gas price realizations.
Average daily net production in this play was approximately 825 mmcfe per day (1,900 gross operated mmcfe per day), an increase of 53% year over year and 6% sequentially. All of Chesapeake's production in the northern Marcellus consists of natural gas.
During the 2013 third quarter, Chesapeake operated an average of five rigs and connected 37 gross wells to sales, compared to five operated rigs and 79 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 37 wells that commenced first production during the 2013 third quarter was approximately 9.3 mmcfe per day.
As of September 30, 2013, Chesapeake had 128 wells waiting on pipeline connection or in various stages of completion in the northern Marcellus.
Southern Marcellus Shale (Pennsylvania, West Virginia): Chesapeake’s average daily net production in the southern wet-gas portion of the Marcellus was approximately 275 mmcfe per day (470 gross operated mmcfe per day), an increase of 123% year over year and 33% sequentially. Approximately 13% of the company’s southern Marcellus production was oil, 17% was NGL and 70% was natural gas.
During the 2013 third quarter, Chesapeake operated an average of three rigs and connected 30 gross wells to sales, compared to three operated rigs and 52 gross wells connected to sales during the 2013 second quarter. The average peak daily production rate of the 30 wells that commenced first production during the 2013 third quarter was approximately 6.7 mmcfe per day.
As of September 30, 2013, Chesapeake had 62 wells waiting on pipeline connection or in various stages of completion in the southern Marcellus.
4
Key Financial and Operational Results
The table below summarizes Chesapeake’s key financial and operational results during the 2013 third quarter and compares them to results during the 2013 second quarter and the 2012 third quarter.
Three Months Ended | |||||||||
9/30/2013 | 6/30/2013 | 9/30/2012 | |||||||
Natural gas equivalent production (in bcfe) | 372 | 369 | 381 | ||||||
Natural gas equivalent realized price ($/mcfe)(a) | 4.78 | 4.96 | 4.04 | ||||||
Oil production (in mmbbls) | 11.0 | 10.5 | 9.0 | ||||||
Average realized oil price ($/bbl)(a) | 92.09 | 93.81 | 90.79 | ||||||
Oil as % of total production | 18 | 17 | 14 | ||||||
NGL production (in mmbbls) | 5.4 | 4.8 | 4.1 | ||||||
Average realized NGL price ($/bbl)(a) | 26.52 | 24.22 | 31.22 | ||||||
NGL as % of total production | 9 | 8 | 7 | ||||||
Liquids as % of realized revenue(b) | 65 | 60 | 61 | ||||||
Liquids as % of unhedged revenue(b) | 69 | 58 | 63 | ||||||
Natural gas production (in bcf) | 273 | 278 | 302 | ||||||
Average realized natural gas price ($/mcf)(a) | 2.26 | 2.62 | 1.97 | ||||||
Natural gas as % of total production | 73 | 75 | 79 | ||||||
Natural gas as % of realized revenue | 35 | 40 | 39 | ||||||
Natural gas as % of unhedged revenue | 31 | 42 | 37 | ||||||
Production expenses ($/mcfe) | (0.76 | ) | (0.78 | ) | (0.84 | ) | |||
Production taxes ($/mcfe) | (0.17 | ) | (0.16 | ) | (0.14 | ) | |||
General and administrative costs ($/mcfe)(c) | (0.29 | ) | (0.25 | ) | (0.33 | ) | |||
Stock-based compensation ($/mcfe) | (0.04 | ) | (0.04 | ) | (0.05 | ) | |||
DD&A of natural gas and liquids properties ($/mcfe) | (1.75 | ) | (1.75 | ) | (2.00 | ) | |||
D&A of other assets ($/mcfe) | (0.21 | ) | (0.21 | ) | (0.17 | ) | |||
Interest expense ($/mcfe)(a) | (0.11 | ) | (0.14 | ) | (0.10 | ) | |||
Marketing, gathering and compression net margin ($ in millions)(d) | 23 | 29 | 42 | ||||||
Oilfield services net margin ($ in millions)(d) | 38 | 35 | 36 | ||||||
Operating cash flow ($ in millions)(e) | 1,368 | 1,370 | 1,118 | ||||||
Operating cash flow ($/mcfe) | 3.68 | 3.71 | 2.93 | ||||||
Adjusted ebitda ($ in millions)(f) | 1,325 | 1,424 | 1,024 | ||||||
Adjusted ebitda ($/mcfe) | 3.56 | 3.86 | 2.69 | ||||||
Net income available to common stockholders ($ in millions) | 156 | 457 | (2,055 | ) | |||||
Earnings per share – diluted ($) | 0.24 | 0.66 | (3.19 | ) | |||||
Adjusted net income available to common stockholders ($ in millions)(g) | 282 | 334 | 35 | ||||||
Adjusted earnings per share – diluted ($) | 0.43 | 0.51 | 0.10 | ||||||
(a) | Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging. |
(b) | "Liquids” includes both oil and NGL. |
(c) | Excludes expenses associated with stock-based compensation and restructuring and other termination benefits. |
(d) | Includes revenue and operating costs and excludes depreciation and amortization of other assets, impairments of fixed assets and other, and gains or losses on sales of fixed assets. |
(e) | Defined as cash flow provided by operating activities before changes in assets and liabilities. |
(f) | Defined as net income before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on Page 16. |
(g) | Defined as net income available to common stockholders, as adjusted to remove the effects of certain items detailed on Page 12. |
5
2013 Third Quarter Financial and Operational Results Conference Call Information
A conference call to discuss this release has been scheduled for Wednesday, November 6, 2013, at 9:00 am EST. The telephone number to access the conference call is 913-312-0713 or toll-free 888-778-9069. The passcode for the call is 5588965. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EST. For those unable to participate in the conference call, a replay will be available for audio playback at 2:00 pm EST on Wednesday, November 6, 2013, and will run through 2:00 pm EST on Wednesday, November 20, 2013. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 5588965. The conference call will also be webcast live on Chesapeake’s website at www.chk.com in the "Events” subsection of the "Investors” section of the company’s website. The webcast of the conference will be available on the company’s website for one year.
Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas and the 11th largest producer of oil and natural gas liquids in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing its large and geographically diverse resource base of unconventional natural gas and oil assets onshore in the U.S. The company also owns substantial marketing, compression and oilfield services businesses. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.
This news release and the accompanying Outlook includes "forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact that give our current expectations or forecasts of future events. They include production forecasts, estimates of operating costs, planned development drilling, expected capital expenditures, expected efficiency gains, anticipated asset sales, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.
Factors that could cause actual results to differ materially from expected results are described under "Risk Factors” in Item 1A of our 2012 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, 2013. These risk factors include the volatility of natural gas, oil and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the prices of natural gas and oil potentially resulting in a write-down of our asset carrying values; the availability of capital on an economic basis, including through planned asset sales, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas, oil and NGL sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing, air emissions and endangered species; current worldwide economic uncertainty which may have a material adverse effect on our results of operations, liquidity and financial condition; oilfield services shortages, gathering system and transportation capacity constraints and various transportation interruptions that could adversely affect our revenues and cash flow; losses possible from pending or future litigation and regulatory investigations; cyber attacks adversely impacting our operations; and the loss of key operational personnel or inability to maintain our corporate culture. In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Further, 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 reduce financial leverage and complexity and enhance our liquidity. 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.
6
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per share and unit data)
(unaudited)
THREE MONTHS ENDED: | September 30, 2013 | September 30, 2012 | ||||||||||||
$ | $/mcfe | $ | $/mcfe | |||||||||||
REVENUES: | ||||||||||||||
Natural gas, oil and NGL | 1,586 | 4.26 | 1,437 | 3.77 | ||||||||||
Marketing, gathering and compression | 3,032 | 8.15 | 1,381 | 3.62 | ||||||||||
Oilfield services | 249 | 0.67 | 152 | 0.40 | ||||||||||
Total Revenues | 4,867 | 13.08 | 2,970 | 7.79 | ||||||||||
OPERATING EXPENSES: | ||||||||||||||
Natural gas, oil and NGL production | 282 | 0.76 | 320 | 0.84 | ||||||||||
Production taxes | 62 | 0.17 | 53 | 0.14 | ||||||||||
Marketing, gathering and compression | 3,009 | 8.09 | 1,339 | 3.51 | ||||||||||
Oilfield services | 211 | 0.57 | 116 | 0.30 | ||||||||||
General and administrative | 120 | 0.31 | 145 | 0.38 | ||||||||||
Restructuring and other termination benefits | 63 | 0.18 | 3 | 0.01 | ||||||||||
Natural gas, oil and NGL depreciation, depletion and amortization | 652 | 1.75 | 762 | 2.00 | ||||||||||
Depreciation and amortization of other assets | 79 | 0.21 | 66 | 0.17 | ||||||||||
Impairment of natural gas and oil properties | — | — | 3,315 | 8.70 | ||||||||||
Impairments of fixed assets and other | 85 | (0.36 | ) | 38 | 0.10 | |||||||||
Net (gains) losses on sales of fixed assets | (132 | ) | 0.23 | 7 | 0.02 | |||||||||
Total Operating Expenses | 4,431 | 11.91 | 6,164 | 16.17 | ||||||||||
INCOME (LOSS) FROM OPERATIONS | 436 | 1.17 | (3,194 | ) | (8.38 | ) | ||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (40 | ) | (0.11 | ) | (36 | ) | (0.10 | ) | ||||||
Losses on investments | (22 | ) | (0.06 | ) | (23 | ) | (0.06 | ) | ||||||
Gains (losses) on sales of investments | 3 | 0.01 | 31 | 0.08 | ||||||||||
Other income (expense) | 10 | 0.03 | (9 | ) | (0.02 | ) | ||||||||
Total Other Income (Expense) | (49 | ) | (0.13 | ) | (37 | ) | (0.10 | ) | ||||||
INCOME (LOSS) BEFORE INCOME TAXES | 387 | 1.04 | (3,231 | ) | (8.48 | ) | ||||||||
INCOME TAX EXPENSE (BENEFIT): | ||||||||||||||
Current income taxes | 7 | 0.02 | 22 | 0.05 | ||||||||||
Deferred income taxes | 140 | 0.38 | (1,282 | ) | (3.36 | ) | ||||||||
Total Income Tax Expense (Benefit) | 147 | 0.40 | (1,260 | ) | (3.31 | ) | ||||||||
NET INCOME (LOSS) | 240 | 0.64 | (1,971 | ) | (5.17 | ) | ||||||||
Net income attributable to noncontrolling interests | (38 | ) | (0.10 | ) | (41 | ) | (0.11 | ) | ||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | 202 | 0.54 | (2,012 | ) | (5.28 | ) | ||||||||
Preferred stock dividends | (43 | ) | (0.11 | ) | (43 | ) | (0.11 | ) | ||||||
Earnings allocated to participating securities | (3 | ) | (0.01 | ) | — | — | ||||||||
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS | 156 | 0.42 | (2,055 | ) | (5.39 | ) | ||||||||
EARNINGS (LOSS) PER COMMON SHARE: | ||||||||||||||
Basic | $ | 0.24 | $ | (3.19 | ) | |||||||||
Diluted | $ | 0.24 | $ | (3.19 | ) | |||||||||
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): | ||||||||||||||
Basic | 656 | 644 | ||||||||||||
Diluted | 656 | 644 | ||||||||||||
7
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per share and unit data)
(unaudited)
NINE MONTHS ENDED: | September 30, 2013 | September 30, 2012 | ||||||||||||
$ | $/mcfe | $ | $/mcfe | |||||||||||
REVENUES: | ||||||||||||||
Natural gas, oil and NGL | 5,444 | 4.95 | 4,622 | 4.36 | ||||||||||
Marketing, gathering and compression | 6,871 | 6.25 | 3,710 | 3.50 | ||||||||||
Oilfield services | 650 | 0.59 | 446 | 0.42 | ||||||||||
Total Revenues | 12,965 | 11.79 | 8,778 | 8.28 | ||||||||||
OPERATING EXPENSES: | ||||||||||||||
Natural gas, oil and NGL production | 877 | 0.80 | 1,005 | 0.95 | ||||||||||
Production taxes | 173 | 0.16 | 141 | 0.13 | ||||||||||
Marketing, gathering and compression | 6,781 | 6.17 | 3,631 | 3.43 | ||||||||||
Oilfield services | 543 | 0.49 | 321 | 0.30 | ||||||||||
General and administrative | 336 | 0.30 | 436 | 0.41 | ||||||||||
Restructuring and other termination benefits | 203 | 0.19 | 4 | — | ||||||||||
Natural gas, oil and NGL depreciation, depletion and amortization | 1,945 | 1.77 | 1,856 | 1.75 | ||||||||||
Depreciation and amortization of other assets | 234 | 0.21 | 233 | 0.22 | ||||||||||
Impairment of natural gas and oil properties | — | — | 3,315 | 3.13 | ||||||||||
Impairments of fixed assets and other | 343 | (0.26 | ) | 281 | 0.27 | |||||||||
Net (gains) losses on sales of fixed assets | (290 | ) | 0.31 | 5 | — | |||||||||
Total Operating Expenses | 11,145 | 10.14 | 11,228 | 10.59 | ||||||||||
INCOME (LOSS) FROM OPERATIONS | 1,820 | 1.65 | (2,450 | ) | (2.31 | ) | ||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (164 | ) | (0.15 | ) | (63 | ) | (0.06 | ) | ||||||
Losses on investments | (26 | ) | (0.02 | ) | (87 | ) | (0.08 | ) | ||||||
Impairment of investment | (10 | ) | (0.01 | ) | — | — | ||||||||
Gains (losses) on sales of investments | (7 | ) | (0.01 | ) | 1,061 | 1.00 | ||||||||
Losses on purchases of debt | (70 | ) | (0.06 | ) | — | — | ||||||||
Other income (expense) | 18 | 0.02 | 2 | — | ||||||||||
Total Other Income (Expense) | (259 | ) | (0.23 | ) | 913 | 0.86 | ||||||||
INCOME (LOSS) BEFORE INCOME TAXES | 1,561 | 1.42 | (1,537 | ) | (1.45 | ) | ||||||||
INCOME TAX EXPENSE (BENEFIT): | ||||||||||||||
Current income taxes | 9 | 0.01 | 24 | 0.02 | ||||||||||
Deferred income taxes | 585 | 0.53 | (623 | ) | (0.59 | ) | ||||||||
Total Income Tax Expense (Benefit) | 594 | 0.54 | (599 | ) | (0.57 | ) | ||||||||
NET INCOME (LOSS) | 967 | 0.88 | (938 | ) | (0.88 | ) | ||||||||
Net income attributable to noncontrolling interests | (127 | ) | (0.12 | ) | (131 | ) | (0.13 | ) | ||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | 840 | 0.76 | (1,069 | ) | (1.01 | ) | ||||||||
Preferred stock dividends | (128 | ) | (0.12 | ) | (128 | ) | (0.12 | ) | ||||||
Premium on purchase of preferred shares of a subsidiary | (69 | ) | (0.06 | ) | — | — | ||||||||
Earnings allocated to participating securities | (14 | ) | (0.01 | ) | — | — | ||||||||
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS | 629 | 0.57 | (1,197 | ) | (1.13 | ) | ||||||||
EARNINGS (LOSS) PER COMMON SHARE: | ||||||||||||||
Basic | $ | 0.96 | $ | (1.86 | ) | |||||||||
Diluted | $ | 0.96 | $ | (1.86 | ) | |||||||||
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): | ||||||||||||||
Basic | 654 | 643 | ||||||||||||
Diluted | 654 | 643 | ||||||||||||
8
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
September 30, 2013 | December 31, 2012 | ||||||
Cash and cash equivalents | $ | 987 | $ | 287 | |||
Other current assets | 3,007 | 2,661 | |||||
Total Current Assets | 3,994 | 2,948 | |||||
Property and equipment (net) | 37,121 | 37,167 | |||||
Other assets | 1,173 | 1,496 | |||||
Total Assets | $ | 42,288 | $ | 41,611 | |||
Current liabilities | $ | 5,678 | $ | 6,266 | |||
Long-term debt, net of discounts | 12,736 | 12,157 | |||||
Other long-term liabilities | 2,103 | 2,485 | |||||
Deferred income tax liabilities | 3,423 | 2,807 | |||||
Total Liabilities | 23,940 | 23,715 | |||||
Preferred stock | 3,062 | 3,062 | |||||
Noncontrolling interests | 2,152 | 2,327 | |||||
Common stock and other stockholders’ equity | 13,134 | 12,507 | |||||
Total Equity | 18,348 | 17,896 | |||||
Total Liabilities and Equity | $ | 42,288 | $ | 41,611 | |||
Common Shares Outstanding (in millions) | 665 | 664 | |||||
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
September 30, 2013 | December 31, 2012 | ||||||
Total debt, net of unrestricted cash | $ | 11,749 | $ | 12,333 | |||
Preferred stock | 3,062 | 3,062 | |||||
Noncontrolling interests(a) | 2,152 | 2,327 | |||||
Common stock and other stockholders’ equity | 13,134 | 12,507 | |||||
Total | $ | 30,097 | $ | 30,229 | |||
Total debt to capitalization ratio | 39 | % | 41 | % | |||
(a) | Includes third-party ownership as follows: |
CHK Cleveland Tonkawa, L.L.C. | $ | 1,015 | $ | 1,015 | |||
CHK Utica, L.L.C. | 807 | 950 | |||||
Chesapeake Granite Wash Trust | 323 | 356 | |||||
Other | 7 | 6 | |||||
Total | $ | 2,152 | $ | 2,327 | |||
9
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - NATURAL GAS, OIL AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Net Production: | ||||||||||||||||
Natural gas (bcf) | 273.3 | 302.3 | 824.1 | 848.6 | ||||||||||||
Oil (mmbbl) | 11.0 | 9.0 | 30.9 | 22.3 | ||||||||||||
NGL (mmbbl) | 5.4 | 4.1 | 15.0 | 13.0 | ||||||||||||
Natural gas equivalent (bcfe) | 371.9 | 381.1 | 1,099.4 | 1,060.5 | ||||||||||||
Natural Gas, Oil and NGL Sales ($ in millions): | ||||||||||||||||
Natural gas sales | $ | 581 | $ | 543 | $ | 1,932 | $ | 1,359 | ||||||||
Natural gas derivatives – realized gains (losses)(a) | 37 | 52 | (7 | ) | 391 | |||||||||||
Natural gas derivatives – unrealized gains (losses) | 6 | (90 | ) | 74 | (401 | ) | ||||||||||
Total Natural Gas Sales | 624 | 505 | 1,999 | 1,349 | ||||||||||||
Oil sales | 1,115 | 792 | 2,975 | 2,038 | ||||||||||||
Oil derivatives – realized gains (losses)(a) | (99 | ) | 25 | (89 | ) | 6 | ||||||||||
Oil derivatives – unrealized gains (losses) | (197 | ) | (14 | ) | 163 | 803 | ||||||||||
Total Oil Sales | 819 | 803 | 3,049 | 2,847 | ||||||||||||
NGL sales | 143 | 129 | 396 | 401 | ||||||||||||
NGL derivatives – realized gains (losses)(a) | — | — | — | (9 | ) | |||||||||||
NGL derivatives – unrealized gains (losses) | — | — | — | 34 | ||||||||||||
Total NGL Sales | 143 | 129 | 396 | 426 | ||||||||||||
Total Natural Gas, Oil and NGL Sales | $ | 1,586 | $ | 1,437 | $ | 5,444 | $ | 4,622 | ||||||||
Average Sales Price – excluding gains (losses) on derivatives: | ||||||||||||||||
Natural gas ($ per mcf) | $ | 2.12 | $ | 1.80 | $ | 2.34 | $ | 1.60 | ||||||||
Oil ($ per bbl) | $ | 101.08 | $ | 88.07 | $ | 96.40 | $ | 91.31 | ||||||||
NGL ($ per bbl) | $ | 26.52 | $ | 31.22 | $ | 26.35 | $ | 30.86 | ||||||||
Natural gas equivalent ($ per mcfe) | $ | 4.94 | $ | 3.84 | $ | 4.82 | $ | 3.58 | ||||||||
Average Sales Price – excluding unrealized gains (losses) on derivatives(a): | ||||||||||||||||
Natural gas ($ per mcf) | $ | 2.26 | $ | 1.97 | $ | 2.34 | $ | 2.06 | ||||||||
Oil ($ per bbl) | $ | 92.09 | $ | 90.79 | $ | 93.51 | $ | 91.55 | ||||||||
NGL ($ per bbl) | $ | 26.52 | $ | 31.22 | $ | 26.35 | $ | 30.17 | ||||||||
Natural gas equivalent ($ per mcfe) | $ | 4.78 | $ | 4.04 | $ | 4.74 | $ | 3.95 | ||||||||
Interest Expense (Income) ($ in millions): | ||||||||||||||||
Interest(b) | $ | 43 | $ | 38 | $ | 113 | $ | 67 | ||||||||
Derivatives – realized (gains) losses | (3 | ) | — | (6 | ) | — | ||||||||||
Derivatives – unrealized (gains) losses | — | (2 | ) | 57 | (4 | ) | ||||||||||
Total Interest Expense | $ | 40 | $ | 36 | $ | 164 | $ | 63 | ||||||||
(a) | Includes settlements for commodity derivatives adjusted for option premiums. For derivatives closed early, settlements are reflected in the period of original contract expiration. |
(b) | Net of amounts capitalized. |
10
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
THREE MONTHS ENDED: | September 30, 2013 | September 30, 2012 | ||||||
Beginning cash | $ | 677 | $ | 1,024 | ||||
Cash provided by operating activities | 1,356 | 949 | ||||||
Cash flows from investing activities: | ||||||||
Drilling and completion costs on proved and unproved properties(a) | (1,303 | ) | (2,353 | ) | ||||
Acquisition of proved and unproved properties(b) | (266 | ) | (936 | ) | ||||
Sale of proved and unproved properties | 885 | 808 | ||||||
Geological and geophysical costs | (8 | ) | (52 | ) | ||||
Additions to other property and equipment | (133 | ) | (605 | ) | ||||
Proceeds from sales of other assets | 337 | 140 | ||||||
Investments, net | 9 | (133 | ) | |||||
Other | 7 | (102 | ) | |||||
Total cash used in investing activities | (472 | ) | (3,233 | ) | ||||
Cash provided by (used in) financing activities | (574 | ) | 1,409 | |||||
Change in cash and cash equivalents classified as current assets held for sale | — | (7 | ) | |||||
Change in cash and cash equivalents | 310 | (882 | ) | |||||
Ending cash | $ | 987 | $ | 142 | ||||
(a) | Includes capitalized interest of $1 million and $18 million for the three months ended September 30, 2013 and 2012, respectively. |
(b) | Includes capitalized interest of $205 million and $309 million for the three months ended September 30, 2013 and 2012, respectively. |
NINE MONTHS ENDED: | September 30, 2013 | September 30, 2012 | ||||||
Beginning cash | $ | 287 | $ | 351 | ||||
Cash provided by operating activities | 3,561 | 1,978 | ||||||
Cash flows from investing activities: | ||||||||
Drilling and completion costs on proved and unproved properties(c) | (4,435 | ) | (7,360 | ) | ||||
Acquisition of proved and unproved properties(d) | (763 | ) | (2,594 | ) | ||||
Sale of proved and unproved properties | 2,742 | 2,226 | ||||||
Geological and geophysical costs | (36 | ) | (165 | ) | ||||
Additions to other property and equipment | (639 | ) | (1,916 | ) | ||||
Proceeds from sales of other assets | 796 | 219 | ||||||
Investments, net | 107 | 1,739 | ||||||
Other | 181 | (303 | ) | |||||
Total cash used in investing activities | (2,047 | ) | (8,154 | ) | ||||
Cash provided by (used in) financing activities | (814 | ) | 5,981 | |||||
Change in cash and cash equivalents classified as current assets held for sale | — | (14 | ) | |||||
Change in cash and cash equivalents | 700 | (209 | ) | |||||
Ending cash | $ | 987 | $ | 142 | ||||
(c) | Includes capitalized interest of $47 million and $30 million for the nine months ended September 30, 2013 and 2012, respectively. |
(d) | Includes capitalized interest of $571 million and $623 million for the nine months ended September 30, 2013 and 2012, respectively. |
11
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per share data)
(unaudited)
THREE MONTHS ENDED: | September 30, 2013 | June 30, 2013 | September 30, 2012 | |||||||||
Net income (loss) available to common stockholders | $ | 156 | $ | 457 | $ | (2,055 | ) | |||||
Adjustments, net of tax: | ||||||||||||
Unrealized (gains) losses on derivatives | 118 | (325 | ) | 63 | ||||||||
Net (gains) losses on sales of fixed assets | (82 | ) | (68 | ) | 4 | |||||||
Impairment of natural gas and oil properties | — | — | 2,022 | |||||||||
Impairments of fixed assets and other | 55 | 143 | 23 | |||||||||
Restructuring and other termination benefits | 39 | 5 | 2 | |||||||||
(Gains) losses on sales of investments | (2 | ) | 6 | (19 | ) | |||||||
Losses on purchases of debt | — | 44 | — | |||||||||
Premium on purchase of preferred shares of a subsidiary | — | 69 | — | |||||||||
Other | (2 | ) | 3 | (5 | ) | |||||||
Adjusted net income available to common stockholders(a) | 282 | 334 | 35 | |||||||||
Preferred stock dividends | 43 | 43 | 43 | |||||||||
Earnings allocated to participating securities | 3 | 11 | — | |||||||||
Total adjusted net income | $ | 328 | $ | 388 | $ | 78 | ||||||
Weighted average fully diluted shares outstanding (in millions)(b) | 765 | 763 | 754 | |||||||||
Adjusted earnings per share assuming dilution(a) | $ | 0.43 | $ | 0.51 | $ | 0.10 | ||||||
(a) | Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with accounting principles generally accepted in the United States (GAAP) because: |
(i) | Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. |
(ii) | Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. |
(iii) | Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. |
(b) | Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. |
12
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per share data)
(unaudited)
NINE MONTHS ENDED: | September 30, 2013 | September 30, 2012 | ||||||
Net income (loss) available to common stockholders | $ | 629 | $ | (1,197 | ) | |||
Adjustments, net of tax: | ||||||||
Unrealized gains on derivatives | (112 | ) | (268 | ) | ||||
Net (gains) losses on sales of fixed assets | (180 | ) | 3 | |||||
Impairment of natural gas and oil properties | — | 2,022 | ||||||
Impairments of fixed assets and other | 215 | 171 | ||||||
Restructuring and other termination benefits | 126 | 2 | ||||||
Impairment of investments | 6 | — | ||||||
(Gains) losses on sales of investments | 4 | (603 | ) | |||||
Losses on purchases of debt | 44 | — | ||||||
Premium on purchase of preferred shares of a subsidiary | 69 | — | ||||||
Other | (2 | ) | 2 | |||||
Adjusted net income available to common stockholders(a) | 799 | 132 | ||||||
Preferred stock dividends | 128 | 128 | ||||||
Earnings allocated to participating securities | 14 | — | ||||||
Total adjusted net income | $ | 941 | $ | 260 | ||||
Weighted average fully diluted shares outstanding (in millions)(b) | 763 | 753 | ||||||
Adjusted earnings per share assuming dilution(a) | $ | 1.23 | $ | 0.35 | ||||
(a) | Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to GAAP earnings because: |
(i) | Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. |
(ii) | Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. |
(iii) | Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. |
(b) | Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. |
13
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
THREE MONTHS ENDED: | September 30, 2013 | June 30, 2013 | September 30, 2012 | |||||||||
CASH PROVIDED BY OPERATING ACTIVITIES | $ | 1,356 | $ | 1,281 | $ | 949 | ||||||
Changes in assets and liabilities | 12 | 89 | 169 | |||||||||
OPERATING CASH FLOW(a) | $ | 1,368 | $ | 1,370 | $ | 1,118 | ||||||
THREE MONTHS ENDED: | September 30, 2013 | June 30, 2013 | September 30, 2012 | |||||||||
NET INCOME | $ | 240 | $ | 625 | $ | (1,971 | ) | |||||
Interest expense | 40 | 104 | 36 | |||||||||
Income tax expense (benefit) | 147 | 384 | (1,260 | ) | ||||||||
Depreciation and amortization of other assets | 79 | 76 | 66 | |||||||||
Natural gas, oil and NGL depreciation, depletion and amortization | 652 | 645 | 762 | |||||||||
EBITDA(b) | $ | 1,158 | $ | 1,834 | $ | (2,367 | ) | |||||
THREE MONTHS ENDED: | September 30, 2013 | June 30, 2013 | September 30, 2012 | |||||||||
CASH PROVIDED BY OPERATING ACTIVITIES | $ | 1,356 | $ | 1,281 | $ | 949 | ||||||
Changes in assets and liabilities | 12 | 89 | 169 | |||||||||
Interest expense, net of unrealized gains (losses) on derivatives | 40 | 53 | 36 | |||||||||
Unrealized gains (losses) on natural gas, oil and NGL derivatives | (191 | ) | 576 | (104 | ) | |||||||
Net gains (losses) on sales of fixed assets | 132 | 109 | (7 | ) | ||||||||
Impairment of natural gas and oil properties | — | — | (3,315 | ) | ||||||||
Impairments of fixed assets and other | (59 | ) | (231 | ) | (14 | ) | ||||||
Restructuring and other termination benefits | (60 | ) | 1 | (4 | ) | |||||||
Gains (losses) on sales of investments | 3 | (10 | ) | 31 | ||||||||
Earnings (losses) on investments | (23 | ) | 22 | (27 | ) | |||||||
Stock-based compensation | (22 | ) | (24 | ) | (30 | ) | ||||||
Losses on purchases of debt | — | (17 | ) | — | ||||||||
Other items | (30 | ) | (15 | ) | (51 | ) | ||||||
EBITDA(b) | $ | 1,158 | $ | 1,834 | $ | (2,367 | ) | |||||
(a) | Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. |
(b) | Ebitda represents net income (loss) before interest expense, income taxes, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP. |
14
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
NINE MONTHS ENDED: | September 30, 2013 | September 30, 2012 | ||||||
CASH PROVIDED BY OPERATING ACTIVITIES | $ | 3,561 | $ | 1,978 | ||||
Changes in assets and liabilities | 352 | 946 | ||||||
OPERATING CASH FLOW(a) | $ | 3,913 | $ | 2,924 | ||||
NINE MONTHS ENDED: | September 30, 2013 | September 30, 2012 | ||||||
NET INCOME (LOSS) | $ | 967 | $ | (938 | ) | |||
Interest expense, net of unrealized gains | 164 | 63 | ||||||
Income tax expense (benefit) | 594 | (599 | ) | |||||
Depreciation and amortization of other assets | 234 | 233 | ||||||
Natural gas, oil and NGL depreciation, depletion and amortization | 1,945 | 1,856 | ||||||
EBITDA(b) | $ | 3,904 | $ | 615 | ||||
NINE MONTHS ENDED: | September 30, 2013 | September 30, 2012 | ||||||
CASH PROVIDED BY OPERATING ACTIVITIES | $ | 3,561 | $ | 1,978 | ||||
Changes in assets and liabilities | 352 | 946 | ||||||
Interest expense, net of unrealized gains on derivatives | 107 | 63 | ||||||
Unrealized gains on natural gas, oil and NGL derivatives | 238 | 436 | ||||||
Net gains (losses) on sales of fixed assets | 290 | (6 | ) | |||||
Impairment of natural gas and oil properties | — | (3,315 | ) | |||||
Impairments of fixed assets and other | (317 | ) | (256 | ) | ||||
Restructuring and other termination benefits | (164 | ) | (4 | ) | ||||
Gains (losses) on sales of investments | (7 | ) | 1,061 | |||||
Losses on investments | (30 | ) | (147 | ) | ||||
Impairment of investment | (10 | ) | — | |||||
Stock-based compensation | (78 | ) | (93 | ) | ||||
Losses on purchases of debt | (12 | ) | — | |||||
Other items | (26 | ) | (48 | ) | ||||
EBITDA(b) | $ | 3,904 | $ | 615 | ||||
(a) | Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. |
(b) | Ebitda represents net income (loss) before interest expense, income taxes, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP. |
15
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
THREE MONTHS ENDED: | September 30, 2013 | June 30, 2013 | September 30, 2012 | |||||||||
EBITDA | $ | 1,158 | $ | 1,834 | $ | (2,367 | ) | |||||
Adjustments: | ||||||||||||
Unrealized (gains) losses on natural gas, oil and NGL derivatives | 191 | (576 | ) | 104 | ||||||||
Impairment of natural gas and oil properties | — | — | 3,315 | |||||||||
Net (gains) losses on sales of fixed assets | (132 | ) | (109 | ) | 7 | |||||||
Impairments of fixed assets and other | 89 | 231 | 38 | |||||||||
Net income attributable to noncontrolling interests | (38 | ) | (45 | ) | (41 | ) | ||||||
(Gains) losses on sales of investments | (3 | ) | 10 | (31 | ) | |||||||
Losses on purchases of debt | — | 70 | — | |||||||||
Restructuring and other termination benefits | 63 | 7 | 3 | |||||||||
Other | (3 | ) | 2 | (4 | ) | |||||||
Adjusted EBITDA(a) | $ | 1,325 | $ | 1,424 | $ | 1,024 | ||||||
NINE MONTHS ENDED: | September 30, 2013 | September 30, 2012 | ||||||
EBITDA | $ | 3,904 | $ | 615 | ||||
Adjustments: | ||||||||
Unrealized gains on natural gas, oil and NGL derivatives | (238 | ) | (436 | ) | ||||
Impairment of natural gas and oil properties | — | 3,315 | ||||||
Impairment of investment | 10 | — | ||||||
Net (gains) losses on sales of fixed assets | (290 | ) | 5 | |||||
Impairments of fixed assets and other | 347 | 281 | ||||||
Net income attributable to noncontrolling interests | (127 | ) | (131 | ) | ||||
(Gains) losses on sales of investments | 7 | (988 | ) | |||||
Losses on purchases of debt | 70 | — | ||||||
Restructuring and other termination benefits | 203 | 4 | ||||||
Other | (3 | ) | (3 | ) | ||||
Adjusted EBITDA(a) | $ | 3,883 | $ | 2,662 | ||||
(a) | Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to ebitda because: |
(i) | Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. |
(ii) | Adjusted ebitda is more comparable to estimates provided by securities analysts. |
(iii) | Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. |
16
SCHEDULE "A”
MANAGEMENT’S OUTLOOK AS OF NOVEMBER 6, 2013
Chesapeake periodically provides management guidance on certain factors that affect its future financial performance. The primary changes from the company’s August 1, 2013 Outlook are in italicized bold below.
Chesapeake Energy Corporation Consolidated Projections
Year Ending 12/31/13 | |
Estimated Production: | |
Natural gas – bcf | 1,080 – 1,090 |
Oil – mbbls | 40,000 – 42,000 |
NGL – mbbls(a) | 20,000 – 21,000 |
Natural gas equivalent – bcfe | 1,440 – 1,468 |
Daily natural gas equivalent midpoint – mmcfe | 3,985 |
YOY estimated production increase (adjusted for planned asset sales) | 3% |
NYMEX Price(b) (for calculation of realized hedging effects only): | |
Natural gas - $/mcf | $3.67 |
Oil - $/bbl | $98.60 |
Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | |
Natural gas - $/mcf | $0.00 |
Oil - $/bbl | ($3.17) |
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: | |
Natural gas - $/mcf | $1.30 – 1.50 |
Oil - $/bbl | $1.00 – 3.00 |
NGL - $/bbl | $70.50 – 74.50 |
Operating Costs per Mcfe of Projected Production: | |
Production expense | $0.80 – 0.85 |
Production taxes | $0.15 – 0.20 |
General and administrative(c) | $0.25 – 0.30 |
Stock-based compensation (noncash) | $0.04 – 0.06 |
DD&A of natural gas and liquids assets | $1.65 – 1.85 |
Depreciation of other assets | $0.20 – 0.25 |
Interest expense(d) | $0.10 – 0.15 |
Other ($ millions): | |
Marketing, gathering and compression net margin(e) | $100 – 125 |
Oilfield services net margin(e) | $125 – 175 |
Net income attributable to noncontrolling interests and other(f) | ($160 – 200) |
Book Tax Rate | 38% |
Weighted average shares outstanding (in millions): | |
Basic | 650 – 655 |
Diluted | 760 – 765 |
Operating cash flow before changes in assets and liabilities(g)(h)(i) | $5,050 – 5,100 |
Drilling and completion costs on proved and unproved properties | ($5,500 – 5,800) |
Acquisition of unproved properties, net | ($200 – 250) |
a) | Reflects actual and assumed ethane rejection in the 2013 second quarter through 2013 fourth quarter. |
b) | NYMEX natural gas and oil prices have been updated for actual contract prices through October and September, respectively. |
c) | Excludes expenses associated with stock-based compensation and restructuring and other termination benefits. |
d) | Does not include unrealized gains or losses on interest rate derivatives. |
e) | Includes revenue and operating costs and excludes depreciation and amortization of other assets. |
f) | Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica, L.L.C. and CHK Cleveland Tonkawa, L.L.C. |
g) | A non-GAAP financial measure. We are unable to provide reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities. |
h) | Assumes NYMEX prices on open contracts of $3.50 to $3.75 per mcf and $100.00 per bbl in 2013. |
i) | Excludes the expected impact of fourth quarter cash charges related to lease termination and financing extinguishment costs |
17
Natural Gas, Oil and NGL Hedging Activities
Chesapeake enters into natural gas, oil and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end and year-end derivative positions and accounting for natural gas, oil and NGL derivatives.
The company’s natural gas hedging positions as of November 5, 2013 were as follows:
Open Natural Gas Swaps; Gains (Losses) from Closed
Natural Gas Trades and Call Option Premiums
Open Swaps (bcf) | Avg. NYMEX Price of Open Swaps | Forecasted Natural Gas Production (bcf) | Open Swap Positions as a % of Forecasted Natural Gas Production | Total Gains (Losses) from Closed Trades and Premiums for Call Options ($ in millions) | Total Gains (Losses) from Closed Trades and Premiums for Call Options per mcf of Forecasted Natural Gas Production | |||||||||
Q4 2013 | 190 | $ | 3.71 | 260 | 73% | $ | (3 | ) | $ | (0.01 | ) | |||
Total 2014 | 233 | $ | 4.23 | $ | (74 | ) | ||||||||
Total 2015 | 0 | - | $ | (131 | ) | |||||||||
Total 2016 – 2022 | 0 | - | $ | (187 | ) | |||||||||
Natural Gas Three-Way Collars
Open Collars (bcf) | Avg. NYMEX Sold Put Price | Avg. NYMEX Bought Put Price | Avg. NYMEX Ceiling Price | Forecasted Natural Gas Production (bcf) | Open Collars as a % of Forecasted Natural Gas Production | ||||||||
Q4 2013 | 18 | $ | 3.03 | $ | 3.55 | $ | 4.03 | 260 | 7% | ||||
Total 2014 | 18 | $ | 3.50 | $ | 4.00 | $ | 4.70 | ||||||
Natural Gas Swaptions
Swaptions (bcf) | Avg. NYMEX Strike Price | Forecasted Natural Gas Production (bcf) | Swaptions as a % of Forecasted Natural Gas Production | ||||
Q4 2013 | 0 | $ | — | 260 | 0% | ||
Total 2014 | 12 | $ | 4.80 | ||||
Natural Gas Written Call Options
Call Options (bcf) | Avg. NYMEX Strike Price | Forecasted Natural Gas Production (bcf) | Call Options as a % of Forecasted Natural Gas Production | ||||
Q4 2013 | 0 | $ | — | 260 | 0% | ||
Total 2016 – 2020 | 193 | $ | 9.92 | ||||
18
Natural Gas Basis Protection Swaps
Volume (bcf) | Avg. NYMEX less | |||
Q4 2013 | 11 | $ | 0.21 | |
Total 2014 | 28 | $ | 0.32 | |
Total 2015 | 31 | $ | 0.34 | |
Total 2016 - 2022 | 8 | $ | 1.02 | |
The company’s crude oil hedging positions as of November 5, 2013 were as follows:
Open Crude Oil Swaps; Gains (Losses) from Closed
Crude Oil Trades and Call Option Premiums
Open Swaps (mbbls) | Avg. NYMEX Price of Open Swaps | Forecasted Oil Production (mbbls) | Open Swap Positions as a % of Forecasted Oil Production | Total Gains (Losses) from Closed Trades and Premiums for Call Options ($ in millions) | Total Gains (Losses) from Closed Trades and Premiums for Call Options per bbl of Forecasted Oil Production | |||||||
Q4 2013 | 9,181 | $ | 95.59 | 10,140 | 91% | $ | 2 | $0.18 | ||||
Total 2014 | 21,750 | $ | 93.79 | $ | (176 | ) | ||||||
Total 2015 | 693 | $ | 89.48 | $ | 252 | |||||||
Total 2016 – 2022 | 0 | $ | — | $ | 117 | |||||||
Crude Oil Swaptions
Swaptions (mbbls) | Avg. NYMEX Strike Price | Forecasted Natural Gas Production (mbbls) | Swaptions as a % of Forecasted Natural Gas Production | ||||
Q4 2013 | 0 | $ | — | 10,140 | 0% | ||
Total 2014 | 2,920 | $ | 106.69 | ||||
Total 2015 | 2,368 | $ | 106.61 | ||||
Crude Oil Written Call Options
Call Options (mbbls) | Avg. NYMEX Strike Price | Forecasted Oil Production (mbbls) | Call Options as a % of Forecasted Oil Production | ||||
Q4 2013 | 1,975 | $ | 97.90 | 10,140 | 19% | ||
Total 2014 | 6,697 | $ | 93.90 | ||||
Total 2015 | 15,823 | $ | 93.12 | ||||
Total 2016 – 2017 | 24,220 | $ | 100.07 | ||||
Crude Oil Basis Protection Swaps
Volume (mbbls) | Avg. NYMEX plus | |||
Q4 2013 | 92 | $ | 6.00 | |
Total 2014 | 365 | $ | 6.00 | |
19