| News Release | |
| | |
| FOR IMMEDIATE RELEASE | |
| NOVEMBER 3, 2011 | |
CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL AND
OPERATIONAL RESULTS FOR THE 2011 THIRD QUARTER
Company Reports 2011 Third Quarter Net Income to Common Stockholders of
$879 Million, or $1.23 per Fully Diluted Common Share, on Revenue of $4.0 Billion;
Company Reports Adjusted Net Income Available to Common Stockholders of
$496 Million, or $0.72 per Fully Diluted Common Share, Adjusted Ebitda
of $1.4 Billion and Operating Cash Flow of $1.4 Billion
2011 Third Quarter Average Daily Total Production of 3.329 Bcfe per Day Increases 9%
Year over Year and 9% Sequentially; 2011 Third Quarter Liquids Production
Increases 91% Year over Year and 21% Sequentially; 2011 Third Quarter
Liquids Production Delivers 17% of Total Production and
40% of Unhedged Natural Gas and Liquids Revenue
Company Adds New Net Proved Reserves of 4.2 Tcfe Through the Drillbit in the
First Three Quarters of 2011 at a Cost of $1.08 per Proved Mcfe; Proved Reserves
Total 17.7 Tcfe, or Almost 3 Billion Barrels of Oil Equivalent
OKLAHOMA CITY, OKLAHOMA, NOVEMBER 3, 2011 – Chesapeake Energy Corporation (NYSE:CHK) today announced its 2011 third quarter financial and operational results. For the quarter, Chesapeake reported net income to common stockholders of $879 million ($1.23 per fully diluted common share), operating cash flow of $1.409 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $2.013 billion (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization) on revenue of $3.977 billion and production of 306 billion cubic feet of natural gas equivalent (bcfe).
The company’s 2011 third quarter results include various items that are typically not included in published estimates of the company’s financial results by certain securities analysts. For the 2011 third quarter, Chesapeake reported adjusted net income to common stockholders of $496 million ($0.72 per fully diluted common share) and adjusted ebitda of $1.385 billion. The primary excluded item was a net unrealized after-tax mark-to-market gain of $385 million resulting from the company’s natural gas, liquids and interest rate hedging programs.
A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 16 – 20 of this release.
| INVESTOR CONTACTS: | | MEDIA CONTACTS: | | CHESAPEAKE ENERGY CORPORATION |
| Jeffrey L. Mobley, CFA | | John J. Kilgallon | | Michael Kehs | | Jim Gipson | | 6100 North Western Avenue |
| (405) 767-4763 | | (405) 935-4441 | | (405) 935-2560 | | (405) 935-1310 | | P.O. Box 18496 |
| jeff.mobley@chk.com | | john.kilgallon@chk.com | | michael.kehs@chk.com | | jim.gipson@chk.com | | Oklahoma City, OK 73154 |
Key Operational and Financial Statistics Summarized
The table below summarizes Chesapeake’s key results during the 2011 third quarter and compares them to results during the 2011 second quarter and the 2010 third quarter.
| | | Three Months Ended | | | |
| | | 9/30/11 | | 6/30/11 | | 9/30/10 | | | |
Average daily production (in mmcfe)(a) | | | 3,329 | | | 3,049 | | | 3,043 | | | |
| Natural gas equivalent production (in bcfe) | | | 306 | | | 277 | | | 280 | | | |
Natural gas equivalent realized price ($/mcfe)(b) | | | 5.78 | | | 6.07 | | | 5.67 | | | |
| Oil and NGL (liquids) production (in mbbls) | | | 8,669 | | | 7,192 | | | 4,533 | | | |
| Liquids as % of total production | | | 17 | | | 16 | | | 10 | | | |
Average realized liquids price ($/bbl)(b) | | | 63.03 | | | 65.23 | | | 59.81 | | | |
| Liquids as % of realized revenue | | | 31 | | | 28 | | | 17 | | | |
| Liquids as % of unhedged revenue | | | 40 | | | 40 | | | 23 | | | |
| Natural gas production (in bcf) | | | 254 | | | 234 | | | 253 | | | |
| Natural gas as % of total production | | | 83 | | | 84 | | | 90 | | | |
Average realized natural gas price ($/mcf)(b) | | | 4.82 | | | 5.19 | | | 5.20 | | | |
| Natural gas as % of realized revenue | | | 69 | | | 72 | | | 83 | | | |
| Natural gas as % of unhedged revenue | | | 60 | | | 60 | | | 77 | | | |
Marketing, gathering and compression net margin ($/mcfe)(c) | | | .10 | | | .14 | | | .12 | | | |
Oilfield services net margin ($/mcfe) (c) | | | .11 | | | .11 | | | .03 | | | |
| Production expenses ($/mcfe) | | | (.92) | | | (.94) | | | (.83) | | | |
| Production taxes ($/mcfe) | | | (.16) | | | (.17) | | | (.12) | | | |
General and administrative costs ($/mcfe)(d) | | | (.41) | | | (.38) | | | (.37) | | | |
| Stock-based compensation ($/mcfe) | | | (.08) | | | (.08) | | | (.07) | | | |
| DD&A of natural gas and liquids properties ($/mcfe) | | | (1.38) | | | (1.32) | | | (1.35) | | | |
| D&A of other assets ($/mcfe) | | | (.24) | | | (.23) | | | (.20) | | | |
Interest expense ($/mcfe)(b) | | | (.01) | | | (.07) | | | (.00) | | | |
Operating cash flow ($ in millions)(e) | | | 1,409 | | | 1,207 | | | 1,234 | | | |
| Operating cash flow ($/mcfe) | | | 4.60 | | | 4.35 | | | 4.41 | | | |
Adjusted ebitda ($ in millions)(f) | | | 1,385 | | | 1,365 | | | 1,282 | | | |
| Adjusted ebitda ($/mcfe) | | | 4.52 | | | 4.92 | | | 4.58 | | | |
| Net income to common stockholders ($ in millions) | | | 879 | | | 467 | | | 515 | | | |
| Earnings per share – diluted ($) | | | 1.23 | | | .68 | | | .75 | | | |
Adjusted net income to common stockholders ($ in millions)(g) | | | 496 | | | 528 | | | 478 | | | |
| Adjusted earnings per share – diluted ($) | | | .72 | | | .76 | | | .70 | | | |
| | | |
(a) | Includes effect of Fayetteville Shale asset sale (which had an average production loss impact of approximately 400 mmcfe per day in both the 2011 third and second quarters) to BHP Billiton on March 31, 2011 and VPP #9 sale (which had an average production loss impact of approximately 75 and 40 mmcfe per day in the 2011 third quarter and 2011 second quarter, respectively) on May 12, 2011. |
| (b) | Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging. |
| (c) | Includes revenue and operating costs and excludes depreciation and amortization of other assets. |
| (d) | Excludes expenses associated with noncash stock-based compensation. |
| (e) | Defined as cash flow provided by operating activities before changes in assets and liabilities. |
| (f) | Defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 18. |
| (g) | Defined as net income available to common stockholders, as adjusted to remove the effects of certain items detailed on page 19. |
2011 Third Quarter Average Daily Total Production of 3.329 Bcfe per Day Increases 9%
Year over Year and 9% Sequentially; 2011 Third Quarter Liquids Production
Increases 91% Year over Year and 21% Sequentially; 2011 Third Quarter
Liquids Production Delivers 17% of Total Production and
40% of Unhedged Natural Gas and Liquids Revenue
Chesapeake’s daily production for the 2011 third quarter averaged 3.329 bcfe, an increase of 286 million cubic feet of natural gas equivalent (mmcfe), or 9%, over the 3.043 bcfe produced per day in the 2010 third quarter and an increase of 280 mmcfe, or 9%, from the 3.049 bcfe produced per day in the 2011 second quarter.
Chesapeake’s average daily production of 3.329 bcfe for the 2011 third quarter consisted of 2.763 billion cubic feet of natural gas (bcf) and 94,228 barrels (bbls) of oil and natural gas liquids (collectively, “liquids”). The company’s 2011 third quarter production of 306.2 bcfe was comprised of 254.2 bcf of natural gas (83% on a natural gas equivalent basis) and 8.7 million barrels of liquids (mmbbls) (17% on a natural gas equivalent basis). The company’s year-over-year growth rate of natural gas production was 1% while its year-over-year growth rate of liquids production was 91%. The company’s percentage of revenue from liquids in the 2011 third quarter was 40% of total unhedged natural gas and liquids revenue compared to 23% in the 2010 third quarter and 40% in the 2011 second quarter.
2011 Third Quarter Average Realized Prices Benefit from Realized
Hedging Gains of $344 Million, or $1.12 per Mcfe
Average prices realized during the 2011 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $4.82 per thousand cubic feet (mcf) and $63.03 per bbl, for a realized natural gas equivalent price of $5.78 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas hedging activities during the 2011 third quarter generated a $1.43 gain per mcf, while realized losses from liquids hedging activities generated a $2.26 loss per bbl, resulting in 2011 third quarter net realized hedging gains of $344 million, or $1.12 per mcfe.
By comparison, average prices realized during the 2010 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.20 per mcf and $59.81 per bbl, for a realized natural gas equivalent price of $5.67 per mcfe. Realized gains from natural gas and liquids hedging activities during the 2010 third quarter generated a $1.92 gain per mcf and a $5.56 gain per bbl, respectively, for 2010 third quarter realized hedging gains of $512 million, or $1.83 per mcfe.
The company’s realized cash hedging gains since January 1, 2006 have been $8.1 billion, or $1.64 on average for every mcfe produced.
Company Provides Update on Hedging Positions
The following table summarizes Chesapeake’s 2011 and 2012 open swap positions as of November 3, 2011. Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and liquids supply and demand trends, Chesapeake may increase or decrease some or all of its hedging positions at any time in the future without notice.
| | | Natural Gas | | Liquids |
| Year | | % of Forecasted Production | | $ NYMEX Natural Gas | | % of Forecasted Production | | $ NYMEX Oil WTI |
| 4Q 2011 | | 0 | % | | — | | | 4 | % | | $97.17 | |
| 2012 | | 0 | % | | — | | | 3 | % | | $98.10 | |
| 2013 | | 0 | % | | — | | | 1 | % | | $87.69 | |
In addition to the open hedging positions disclosed above, as of November 3, 2011, the company had an additional $358 million, $294 million and $47 million of net hedging gains on closed contracts and premiums collected on call options that will be realized in 2011, 2012 and 2013, respectively, as set forth below.
| | Natural Gas | | Liquids |
| Year | | Forecasted Production (bcf) | | Gains ($ in millions) | | Gains ($/mcf) | | Forecasted Production (mbbls) | | Gains (Losses) ($ in millions) | | Gains (Losses) ($/bbl) |
| 4Q 2011 | | 250 | | $369 | | $1.48 | | 10,000 | | $(11) | | $(1.11) |
| 2012 | | 1,020 | | $400 | | $0.39 | | 55,000 | | $(106) | | $(1.92) |
| 2013 | | 1,040 | | $21 | | $0.02 | | 74,000 | | $26 | | $0.36 |
Proved Natural Gas and Liquids Reserves Increased by 581 Bcfe, or 3%, in the First
Three Quarters of 2011 to 17.7 Tcfe Despite the Sale of 2.8 Tcfe of Proved Reserves;
Also in the First Three Quarters of 2011, Company Adds New Net Proved Reserves
Before Sales of 4.2 Tcfe Through the Drillbit at a Cost of $1.08 per Proved Mcfe
The following table compares Chesapeake’s September 30, 2011 proved reserves, the increase versus its year-end 2010 proved reserves, estimated future net cash flows from proved reserves (discounted at an annual rate of 10% before income taxes (PV-10)), and proved developed percentage based on the trailing 12-month average price required by the reserve reporting rules of the SEC and the 10-year average NYMEX strip prices at September 30, 2011.
| Pricing Method | Natural Gas Price ($/mcf) | Oil Price ($/bbl) | Proved Reserves (tcfe)(a) | Proved Reserves Increase (bcfe)(b) | Proved Reserves Increase %(b) | PV-10 (billions) | Proved Developed % |
Trailing 12-month average (SEC)(c) | $4.16 | $94.32 | 17.7 | 581 | 3% | $18.2 | 56% |
9/30/11 10-year average NYMEX strip(d) | $5.36 | $85.94 | 18.5 | 872 | 5% | $25.0 | 56% |
| (a) | After sales of proved reserves of approximately 2.8 tcfe during the first three quarters of 2011. |
| (b) | Compares proved reserve increase for the first three quarters of 2011 under comparable pricing methods. At year-end 2010, Chesapeake’s proved reserves were 17.1 tcfe using trailing 12-month average prices, which are required by SEC reporting rules, and 17.6 tcfe using 10-year average NYMEX strip prices at December 31, 2010. |
| (c) | Reserve volumes estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of September 30, 2011. This pricing yields estimated "proved reserves" for SEC reporting purposes. Natural gas and liquids volumes estimated under any alternative pricing scenario reflect the sensitivity of proved reserves to a different pricing assumption. |
| (d) | Futures prices represent an unbiased consensus estimate by market participants about the likely prices to be received for future production. Management believes that 10-year average NYMEX strip prices provide a better indicator of the likely economic producibility of the company’s proved reserves than the historical 12-month average price. |
The following table summarizes Chesapeake’s proved well costs for the first three quarters of 2011 using the two pricing methods described above.
| | Trailing 12-Month Average (SEC) Pricing ($/mcfe) | 9/30/11 10-year Average NYMEX Strip Pricing ($/mcfe) |
Proved well costs(a) | $1.08 | $1.04 |
| | | |
| (a) | Includes performance-related revisions and excludes price-related revisions. Costs are net of $1.868 billion of well cost carries paid by the company’s joint venture partners. |
A complete reconciliation of proved reserves based on these two alternative pricing methods, along with total costs, is presented on pages 12 and 13 of this release.
In addition to the PV-10 value of its proved reserves, the company also has significant value in its unevaluated properties, which had a book value of $16.4 billion as of September 30, 2011 and a likely value substantially in excess of book value. Furthermore, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments and other non-current assets) was $7.0 billion as of September 30, 2011, an increase of approximately $0.9 billion from December 31, 2010.
Chesapeake’s Leasehold and 3-D Seismic Inventories Total 15.0 Million Net Acres
and 30.1 Million Acres, Respectively; Risked Unproved and Unrisked Unproved
Resources in the Company’s Inventory Total 111 Tcfe and 338 Tcfe, Respectively
Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (15.0 million net acres) and 3-D seismic (30.1 million acres) in the U.S. The company has also accumulated the largest inventory of U.S. natural gas shale play leasehold (2.5 million net acres) and now owns a leading position in 12 of what Chesapeake believes are the Top 15 unconventional liquids-rich plays in the U.S. – the Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the Anadarko Basin; the Avalon, Bone Spring, Wolfcamp and Wolfberry plays in the Permian Basin; the Eagle Ford Shale in South Texas; the Niobrara Shale in the Powder River and DJ Basins; the Bakken/Three Forks in the Williston Basin; and the Utica Shale in the Appalachian Basin.
On its leasehold inventory, Chesapeake has identified an estimated 18.5 trillion cubic feet of natural gas equivalent (tcfe) of proved reserves (using volume estimates based on the 10-year average NYMEX strip prices at September 30, 2011), 111 tcfe of risked unproved resources and 338 tcfe of unrisked unproved resources. The company is currently using 171 operated drilling rigs to further develop its inventory of approximately 38,700 net risked drillsites. Of Chesapeake’s 171 operated rigs, 105 are drilling wells primarily focused on unconventional liquids-rich plays, 63 are drilling wells primarily focused on unconventional natural gas plays and three are drilling conventional natural gas plays. The company has reduced its natural gas-directed activity by 18 rigs from July 2011 and by 31 rigs from January 2011. In addition, 165 of Chesapeake’s 171 operated rigs are drilling horizontal wells.
In recognition of the value gap between liquids and natural gas prices, Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise during the past three years to identify, secure and commercialize new unconventional liquids-rich plays. To date, Chesapeake has built leasehold positions and established production in multiple liquids-rich plays on approximately 6.2 million net leasehold acres with 7.0 billion bbls of oil equivalent (bboe) (or 42 tcfe) of risked unproved resources and 27.0 bboe (or 162 tcfe) of unrisked unproved resources based on the company’s internal estimates. As a result of its success to date, Chesapeake expects to increase its liquids production through its drilling activities to an average of approximately 150,000 bbls per day in 2012, 200,000 bbls per day in 2013 and 250,000 bbls per day in 2015. Previously, these volume estimates were for year-end exit rates and have been recently revised to full-year averages because of the company’s ongoing success in increasing its liquids production rates.
The following table summarizes Chesapeake’s ownership and activity in its unconventional natural gas plays, unconventional liquids-rich plays and other conventional and unconventional plays. Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and unproved resources associated with such drillsites.
| | | Est. | | Risked | Total | Risked | Unrisked | Oct 2011 | Oct 2011 |
| | CHK | Drilling | | Net | Proved | Unproved | Unproved | Daily Net | Operated |
| | Net | Density | Risk | Undrilled | Reserves | Resources | Resources | Production | Rig |
| Play Type/Area | Acreage(1) | (Acres) | Factor | Wells | (bcfe)(1)(2) | (bcfe)(1) | (bcfe)(1) | (mmcfe) | Count |
| Unconventional Natural Gas Plays: | | | | | | | | | |
| Marcellus | 1,780,000 | 90 | 60% | 7,850 | 1,204 | 37,800 | 95,300 | 370 | 29 |
| Haynesville | 460,000 | 80 | 30% | 3,710 | 4,293 | 15,300 | 23,100 | 1,195 | 19 |
Bossier(3) | 190,000 | 80 | 60% | 950 | 21 | 3,900 | 9,800 | 10 | 0 |
| Barnett | 220,000 | 60 | 25% | 1,610 | 4,169 | 2,700 | 3,600 | 485 | 15 |
Pearsall(4) | 350,000 | 160 | 75% | 550 | 6 | 2,500 | 9,800 | ND | 0 |
| Subtotal | 2,460,000 | | | 14,670 | 9,693 | 62,200 | 141,600 | 2,060 | 63 |
| | | | | | | | | | |
| Unconventional Liquids Plays: | | | | | | | | | |
Anadarko Basin(5) | 2,385,000 | 155 | 70% | 4,890 | 2,862 | 13,300 | 37,200 | 540 | 44 |
| Eagle Ford | 460,000 | 80 | 50% | 2,830 | 559 | 8,000 | 16,500 | 85 | 30 |
Permian Basin(6) | 830,000 | 160 | 64% | 1,810 | 332 | 2,700 | 8,800 | 120 | 13 |
Powder River and DJ basins(7) | 640,000 | ND | ND | ND | ND | ND | ND | ND | 11 |
| Utica | 1,500,000 | ND | ND | ND | ND | ND | ND | ND | 5 |
| Other | 400,000 | ND | ND | ND | ND | ND | ND | ND | 2 |
| Subtotal | 6,215,000 | | | 14,880 | 3,779 | 41,900 | 162,000 | 780 | 105 |
| | | | | | | | | | |
| Other Conventional and | | | | | | | | | |
| Unconventional Plays: | 6,325,000 | Various | Various | 9,150 | 5,005 | 6,600 | 34,000 | 630 | 3 |
| Total | 15,000,000 | | | 38,700 | 18,477 | 110,700 | 337,600 | 3,470 | 171 |
| Note: ND denotes “not disclosed” |
| (1) | As of September 30, 2011, pro forma for recent leasehold transactions. |
| (2) | Based on 10-year average NYMEX strip prices at September 30, 2011. |
| (3) | Bossier Shale acreage overlaps with Haynesville Shale acreage and is excluded from the sub-totals to avoid double counting of acreage. |
| (4) | Pearsall Shale acreage overlaps with Eagle Ford Shale acreage and is excluded from the sub-totals to avoid double counting of acreage. |
| (5) | Includes Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays. |
| (6) | Includes various Delaware and Midland basin plays, including Wolfcamp, Avalon, Bone Spring and Wolfberry. |
| (7) | Includes Niobrara, Frontier, Codell and Greenhorn plays. |
Conference Call Information
A conference call to discuss this release has been scheduled for Friday, November 4, 2011 at 9:00 a.m. EDT. The telephone number to access the conference call is 913-312-1463 or toll-free 888-778-8861. The passcode for the call is 5544489. We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EDT. For those unable to participate in the conference call, a replay will be available for audio playback from 1:00 p.m. EDT on Friday, November 4, 2011 through midnight on November 18, 2011. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 5544489. 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. The webcast of the conference call will be available on Chesapeake’s website for one year.
Chesapeake Energy Corporation is the second-largest producer of natural gas, a Top 15 producer of oil and natural gas liquids and the most active driller of new wells in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S. Chesapeake owns leading positions in the Barnett, Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays and in the Granite Wash, Cleveland, Tonkawa, Mississippi Lime, Bone Spring, Avalon, Wolfcamp, Wolfberry, Eagle Ford, Niobrara, Three Forks/Bakken and Utica unconventional liquids plays. The company has also vertically integrated its operations and owns substantial midstream, compression, drilling, trucking, pressure pumping and other oilfield service assets directly and indirectly through its subsidiaries Chesapeake Midstream Development, L.P. and Chesapeake Oilfield Services, L.L.C. and its affiliate Chesapeake Midstream Partners, L.P. (NYSE:CHKM). Chesapeake’s stock is listed on the New York Stock Exchange under the symbol CHK. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and press releases.
This news release and the accompanying Outlooks include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of natural gas and liquids reserves and resources, expected natural gas and liquids production and future expenses, assumptions regarding future natural gas and oil prices, planned drilling activity and well costs, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures of the estimated realized effects of our current hedging positions on future natural gas and liquids sales are based upon market prices that are subject to significant volatility. 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.
Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in our 2010 Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, 2011. These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the values of our natural gas and liquids properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and liquids reserves and projecting future rates of production and the amount and timing of development expenditures; inability 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 and liquids sales, the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; a reduced ability to borrow or raise additional capital as a result of lower natural gas and oil prices; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business; general economic conditions negatively impacting us and our business counterparties; transportation capacity constraints and interruptions that could adversely affect our revenues and cash flow; and adverse results in pending or future litigation.
Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the expectations and forecasts reflected in these and other 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.
The SEC requires natural gas and oil companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of natural gas and liquids that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. In this news release, we use the terms “risked and unrisked unproved resources” to describe Chesapeake’s internal estimates of volumes of natural gas and liquids that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. These are broader descriptions of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company. We believe our estimates of unproved resources are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates. The company calculates the standardized measure of future net cash flows of proved reserves only at year end because applicable income tax information on properties, including recently acquired natural gas and liquids interests, is not readily available at other times during the year. As a result, the company is not able to reconcile interim period-end PV-10 values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects. Year-end standardized measure calculations are provided in the financial statement notes in our annual reports on Form 10-K.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per-share and unit data)
(unaudited)
| THREE MONTHS ENDED: | September 30, | | September 30, |
| 2011 | | 2010 |
| | $ | | $/mcfe | | $ | | $/mcfe |
| REVENUES: | | | | | | | | | |
Natural gas and liquids sales | | 2,402 | | 7.84 | | | 1,639 | | 5.86 |
Marketing, gathering and compression sales | | 1,422 | | 4.64 | | | 883 | | 3.15 |
Oilfield services revenue | | 153 | | 0.50 | | | 59 | | 0.21 |
Total Revenues | | 3,977 | | 12.98 | | | 2,581 | | 9.22 |
| | | | | | | | | | |
| OPERATING COSTS: | | | | | | | | | |
Production expenses | | 282 | | 0.92 | | | 231 | | 0.83 |
Production taxes | | 50 | | 0.16 | | | 34 | | 0.12 |
General and administrative expenses | | 151 | | 0.49 | | | 125 | | 0.45 |
Marketing, gathering and compression expenses | | 1,392 | | 4.55 | | | 851 | | 3.04 |
Oilfield services expense | | 118 | | 0.39 | | | 52 | | 0.18 |
Natural gas and liquids depreciation, depletion and amortization | | 423 | | 1.38 | | | 378 | | 1.35 |
Depreciation and amortization of other assets | | 75 | | 0.24 | | | 56 | | 0.20 |
Losses on sales of other property and equipment | | 3 | | 0.01 | | | 17 | | 0.06 |
Other impairments | | — | | — | | | 20 | | 0.07 |
Total Operating Costs | | 2,494 | | 8.14 | | | 1,764 | | 6.30 |
| | | | | | | | | | |
| INCOME FROM OPERATIONS | | 1,483 | | 4.84 | | | 817 | | 2.92 |
| | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | |
Interest expense | | (4) | | (0.01) | | | (3) | | (0.01) |
Earnings on investments | | 28 | | 0.09 | | | 151 | | 0.54 |
Losses on purchases or exchanges of debt | | — | | — | | | (59) | | (0.21) |
Impairment of investments | | — | | — | | | (16) | | (0.06) |
Other income | | 4 | | 0.01 | | | 17 | | 0.06 |
Total Other Income | | 28 | | 0.09 | | | 90 | | 0.32 |
| | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 1,511 | | 4.93 | | | 907 | | 3.24 |
| | | | | | | | | | |
| INCOME TAX EXPENSE (BENEFIT): | | | | | | | | | |
Current income taxes | | (1) | | — | | | (1) | | — |
Deferred income taxes | | 590 | | 1.92 | | | 350 | | 1.25 |
Total Income Tax Expense | | 589 | | 1.92 | | | 349 | | 1.25 |
| | | | | | | | | | |
| NET INCOME | | 922 | | 3.01 | | | 558 | | 1.99 |
| | | | | | | | | | |
Preferred stock dividends | | (43) | | (0.14) | | | (43) | | (0.15) |
| | | | | | | | | | |
| NET INCOME AVAILABLE TO COMMON STOCKHOLDERS | | 879 | | 2.87 | | | 515 | | 1.84 |
| | | | | | | | | | |
| EARNINGS PER COMMON SHARE: | | | | | | | | | |
Basic | $ | 1.38 | | | | $ | 0.81 | | |
Diluted | $ | 1.23 | | | | $ | 0.75 | | |
| | | | | | | | | | |
| WEIGHTED AVERAGE COMMON AND COMMON | | | | | | | | | |
| EQUIVALENT SHARES OUTSTANDING (in millions) | | | | | | | | | |
Basic | | 638 | | | | | 632 | | |
Diluted | | 753 | | | | | 744 | | |
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per-share and unit data)
(unaudited)
| NINE MONTHS ENDED: | September 30, | | September 30, |
| 2011 | | 2010 |
| | $ | | $/mcfe | | $ | | $/mcfe |
| REVENUES: | | | | | | | | | |
Natural gas and liquids sales | | 4,688 | | 5.43 | | | 4,698 | | 6.13 |
Marketing, gathering and compression sales | | 3,844 | | 4.45 | | | 2,520 | | 3.29 |
Oilfield services revenue | | 376 | | 0.44 | | | 173 | | 0.22 |
Total Revenues | | 8,908 | | 10.32 | | | 7,391 | | 9.64 |
| | | | | | | | | | |
| OPERATING COSTS: | | | | | | | | | |
Production expenses | | 782 | | 0.91 | | | 652 | | 0.85 |
Production taxes | | 140 | | 0.16 | | | 119 | | 0.16 |
General and administrative expenses | | 410 | | 0.47 | | | 340 | | 0.44 |
Marketing, gathering and compression expenses | | 3,744 | | 4.34 | | | 2,429 | | 3.17 |
Oilfield services expense | | 287 | | 0.33 | | | 154 | | 0.19 |
Natural gas and liquids depreciation, depletion and amortization | | 1,147 | | 1.33 | | | 1,025 | | 1.34 |
Depreciation and amortization of other assets | | 206 | | 0.24 | | | 159 | | 0.21 |
Losses on sales of other property and equipment | | 3 | | — | | | 17 | | 0.02 |
Other impairments | | 4 | | 0.01 | | | 20 | | 0.03 |
Total Operating Costs | | 6,723 | | 7.79 | | | 4,915 | | 6.41 |
| | | | | | | | | | |
| INCOME FROM OPERATIONS | | 2,185 | | 2.53 | | | 2,476 | | 3.23 |
| | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | |
Interest expense | | (37) | | (0.04) | | | (12) | | (0.01) |
Earnings on investments | | 100 | | 0.11 | | | 190 | | 0.25 |
Losses on purchases or exchanges of debt | | (176) | | (0.20) | | | (130) | | (0.17) |
Impairment of investments | | — | | — | | | (16) | | (0.02) |
Other income | | 9 | | 0.01 | | | 12 | | 0.01 |
Total Other Income (Expense) | | (104) | | (0.12) | | | 44 | | 0.06 |
| | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 2,081 | | 2.41 | | | 2,520 | | 3.29 |
| | | | | | | | | | |
| INCOME TAX EXPENSE: | | | | | | | | | |
Current income taxes | | 11 | | 0.01 | | | 4 | | 0.01 |
Deferred income taxes | | 801 | | 0.93 | | | 966 | | 1.26 |
Total Income Tax Expense | | 812 | | 0.94 | | | 970 | | 1.27 |
| | | | | | | | | | |
| NET INCOME | | 1,269 | | 1.47 | | | 1,550 | | 2.02 |
| | | | | | | | | | |
Preferred stock dividends | | (128) | | (0.15) | | | (68) | | (0.09) |
| | | | | | | | | | |
| NET INCOME AVAILABLE TO COMMON STOCKHOLDERS | | 1,141 | | 1.32 | | | 1,482 | | 1.93 |
| | | | | | | | | | |
| EARNINGS PER COMMON SHARE: | | | | | | | | | |
Basic | $ | 1.79 | | | | $ | 2.35 | | |
Diluted | $ | 1.69 | | | | $ | 2.24 | | |
| | | | | | | | | | |
| WEIGHTED AVERAGE COMMON AND COMMON | | | | | | | | | |
| EQUIVALENT SHARES OUTSTANDING (in millions) | | | | | | | | | |
Basic | | 636 | | | | | 631 | | |
Diluted | | 752 | | | | | 692 | | |
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
| | September 30, | | December 31, | |
| | 2011 | | 2010 | |
| | | | | |
| Cash and cash equivalents | $ | 111 | | $ | 102 | |
| Other current assets | | 3,359 | | | 3,164 | |
Total Current Assets | | 3,470 | | | 3,266 | |
| | | | | | | |
| Property and equipment (net) | | 35,138 | | | 32,378 | |
| Other assets | | 1,514 | | | 1,535 | |
Total Assets | $ | 40,122 | | $ | 37,179 | |
| | | | | | | |
| Current liabilities | $ | 6,195 | | $ | 4,490 | |
Long-term debt, net of discounts (a) | | 11,789 | | | 12,640 | |
| Asset retirement obligations | | 313 | | | 301 | |
| Other long-term liabilities | | 2,003 | | | 2,100 | |
| Deferred tax liability | | 3,524 | | | 2,384 | |
Total Liabilities | | 23,824 | | | 21,915 | |
| | | | | | | |
| Stockholders’ Equity | | 16,298 | | | 15,264 | |
| | | | | | | |
| Total Liabilities & Stockholders' Equity | $ | 40,122 | | $ | 37,179 | |
| | | | | | | |
| Common Shares Outstanding (in millions) | | 660 | | | 654 | |
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
| | September 30, | | % of Total Book | | December 31, | | % of Total Book |
| | 2011 | | Capitalization | | 2010 | | Capitalization |
| | | | | | | | |
Total debt, net of cash (a) | | $ | 11,678 | | | | 42 | % | | | | $ | 12,538 | | | | 45 | % | |
| Stockholders' equity | | | 16,298 | | | | 58 | % | | | | | 15,264 | | | | 55 | % | |
Total | | $ | 27,976 | | | | 100 | % | | | | $ | 27,802 | | | | 100 | % | |
| (a) | At September 30, 2011, the company had $3.236 billion of borrowings under its $4.0 billion corporate revolving bank credit facility and $327 million of borrowings under its $600 million midstream revolving bank credit facility. |
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2011 ADDITIONS TO NATURAL GAS AND LIQUIDS PROPERTIES
BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT SEPTEMBER 30, 2011
($ in millions, except per-unit data)
(unaudited)
| | Proved Reserves | |
| | Cost | | Bcfe (a) | | $/Mcfe | |
| Proved Properties: | | | | | | | | |
Well costs on proved properties(b) | $ | 4,537 | | | 4,188 | (c) | 1.08 | |
| Acquisition of proved properties | | 47 | | | 29 | | 1.60 | |
| Sale of proved properties | | (2,614) | | | (2,760) | | 0.95 | |
| Total net proved properties | | 1,970 | | | 1,457 | | 1.35 | |
| | | | | | | | | |
| Revisions – price | | — | | | (13) | | — | |
| | | | | | | | | |
| Unproved Properties: | | | | | | | | |
| Well costs on unproved properties | | 875 | | | — | | — | |
| Acquisition of unproved properties | | 3,062 | | | — | | — | |
| Sale of unproved properties | | (3,656) | | | — | | — | |
| Total net unproved properties | | 281 | | | — | | — | |
| | | | | | | | | |
Other: | | | | | | | | |
| Capitalized interest on unproved properties | | 552 | | | — | | — | |
| Geological and geophysical costs | | 154 | | | — | | — | |
| Asset retirement obligations | | (2) | | | — | | — | |
| Total other | | 704 | | | — | | — | |
| | | | | | | | | |
| Total | $ | 2,955 | | | 1,444 | | 2.05 | |
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
NINE MONTHS ENDED SEPTEMBER 30, 2011
BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT SEPTEMBER 30, 2011
(unaudited)
| | Bcfe(a) | |
| Beginning balance, 1/1/11 | 17,096 | |
| Production | (863) | |
| Acquisitions | 29 | |
| Divestitures | (2,760) | |
| Revisions – changes to previous estimates | 471 | |
| Revisions – price | (13) | |
| Extensions and discoveries | 3,717 | |
| Ending balance, 9/30/11 | 17,677 | |
| | | |
| Proved reserves growth rate | 3 | % |
| | | |
| Proved developed reserves | 9,852 | |
| Proved developed reserves percentage | 56 | % |
| | | |
PV-10 ($ in billions) (a) | $ | 18.2 | |
| (a) | Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of September 30, 2011, of $4.16 per mcf of natural gas and $94.32 per bbl of oil, before field differential adjustments. |
| (b) | Net of well cost carries of $1.868 billion associated with the Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara joint venture agreements. |
| (c) | Includes 471 bcfe of positive revisions resulting from changes to previous estimates and excludes downward revisions of 13 bcfe resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended September 30, 2011, compared to the twelve months ended December 31, 2010. |
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2011 ADDITIONS TO NATURAL GAS AND LIQUIDS PROPERTIES
BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT SEPTEMBER 30, 2011
($ in millions, except per-unit data)
(unaudited)
| | Proved Reserves | |
| | Cost | | | Bcfe (a) | | | $/Mcfe | |
| Proved Properties: | | | | | | | | | |
Well costs on proved properties(b) | $ | 4,537 | | | | 4,359 | (c) | 1.04 | |
| Acquisition of proved properties | | 47 | | | | 29 | | | 1.60 | |
| Sale of proved properties | | (2,614) | | | | (2,760) | | | 0.95 | |
| Total net proved properties | | 1,970 | | | | 1,628 | | | 1.21 | |
| | | | | | | | | | | |
| Revisions – price | | — | | | | 107 | | | — | |
| | | | | | | | | | | |
| Unproved Properties: | | | | | | | | | | |
| Well costs on unproved properties | | 875 | | | | — | | | — | |
| Acquisition of unproved properties | | 3,062 | | | | — | | | — | |
| Sale of unproved properties | | (3,656) | | | | — | | | — | |
Total net unproved properties | | 281 | | | | — | | | — | |
| | | | | | | | | | | |
| Other: | | | | | | | | | | |
| Capitalized interest on unproved properties | | 552 | | | | — | | | — | |
| Geological and geophysical costs | | 154 | | | | — | | | — | |
| Asset retirement obligations | | (2) | | | | — | | | — | |
Total other | | 704 | | | | — | | | — | |
| | | | | | | | | | | |
Total | $ | 2,955 | | | | 1,735 | | | 1.70 | |
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
NINE MONTHS ENDED SEPTEMBER 30, 2011
BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT SEPTEMBER 30, 2011
(unaudited)
| | Bcfe(a) |
| Beginning balance, 1/1/11 | 17,605 | |
| Production | (863) | |
| Acquisitions | 29 | |
| Divestitures | (2,760) | |
| Revisions – changes to previous estimates | 471 | |
| Revisions – price | 107 | |
| Extensions and discoveries | 3,888 | |
| Ending balance, 9/30/11 | 18,477 | |
| | | |
| Proved reserves growth rate | 5 | % |
| | | |
| Proved developed reserves | 10,282 | |
| Proved developed reserves percentage | 56 | % |
| | | |
PV-10 ($ in billions) (a) | $ | 25.0 | |
| (a) | Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and 10-year average NYMEX strip prices as of September 30, 2011 of $5.36 per mcf of natural gas and $85.94 per bbl of oil, before field differential adjustments. Futures prices, such as the 10-year average NYMEX strip prices, represent an unbiased consensus estimate by market participants about the likely prices to be received for our future production. Chesapeake uses such forward-looking market-based data in developing its drilling plans, assessing its capital expenditure needs and projecting future cash flows. Chesapeake believes these prices are better indicators of the likely economic producibility of proved reserves than the trailing 12-month average price required by the SEC's reporting rule. |
| (b) | Net of well cost carries of $1.868 billion associated with the Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara joint venture agreements. |
| (c) | Includes 471 bcfe of positive revisions resulting from changes to previous estimates and excludes positive revisions of 107 bcfe resulting from higher natural gas prices as of September 30, 2011, compared to December 31, 2010. |
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA – NATURAL GAS AND LIQUIDS SALES AND INTEREST EXPENSE
(unaudited)
| | THREE MONTHS ENDED | | NINE MONTHS ENDED | |
| | SEPTEMBER 30, | | SEPTEMBER 30, | |
| | 2011 | | 2010 | | 2011 | | 2010 | |
| | | | | | | | | |
| Natural Gas and Liquids Sales ($ in millions): | | | | | | | | |
Natural gas sales | $ | 861 | | $ | 828 | | $ | 2,412 | | $ | 2,504 | |
Natural gas derivatives – realized gains (losses) | | 364 | | | 487 | | | 1,322 | | | 1,418 | |
Natural gas derivatives – unrealized gains (losses) | | (28) | | | 315 | | | (693) | | | 534 | |
| | | | | | | | | | | | | |
Total Natural Gas Sales | | 1,197 | | | 1,630 | | | 3,041 | | | 4,456 | |
| | | | | | | | | | | | | |
Liquids sales | | 566 | | | 246 | | | 1,480 | | | 739 | |
Oil derivatives – realized gains (losses) | | (20) | | | 25 | | | (82) | | | 66 | |
Oil derivatives – unrealized gains (losses) | | 659 | | | (262) | | | 249 | | | (563) | |
| | | | | | | | | | | | | |
Total Liquids Sales | | 1,205 | | | 9 | | | 1,647 | | | 242 | |
| | | | | | | | | | | | | |
Total Natural Gas and Liquids Sales | $ | 2,402 | | $ | 1,639 | | $ | 4,688 | | $ | 4,698 | |
| | | | | | | | | | | | | |
| Average Sales Price – excluding gains (losses) on derivatives: | | | | | | | | | | |
Natural gas ($ per mcf) | $ | 3.39 | | $ | 3.28 | | $ | 3.30 | | $ | 3.63 | |
Liquids ($ per bbl) | $ | 65.29 | | $ | 54.25 | | $ | 67.53 | | $ | 57.57 | |
Natural gas equivalent ($ per mcfe) | $ | 4.66 | | $ | 3.84 | | $ | 4.51 | | $ | 4.23 | |
| | | | | | | | | | | | | |
| Average Sales Price – excluding unrealized gains (losses) on derivatives: | | | | | | | | | | |
Natural gas ($ per mcf) | $ | 4.82 | | $ | 5.20 | | $ | 5.10 | | $ | 5.69 | |
Liquids ($ per bbl) | $ | 63.03 | | $ | 59.81 | | $ | 63.80 | | $ | 62.75 | |
Natural gas equivalent ($ per mcfe) | $ | 5.78 | | $ | 5.67 | | $ | 5.94 | | $ | 6.17 | |
| | | | | | | | | | | | | |
| Interest Expense (Income) ($ in millions): | | | | | | | | | | | | |
Interest (a) | $ | 4 | | $ | 3 | | $ | 18 | | $ | 93 | |
Derivatives – realized (gains) losses | | — | | | (2) | | | 6 | | | (6) | |
Derivatives – unrealized (gains) losses | | — | | | 2 | | | 13 | | | (75) | |
Total Interest Expense | $ | 4 | | $ | 3 | | $ | 37 | | $ | 12 | |
| (a) | Net of amounts capitalized. |
| | |
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
| | September 30, | | September 30, | |
| THREE MONTHS ENDED: | 2011 | | 2010 | |
| | | | | |
| Beginning cash | $ | 109 | | $ | 601 | |
| | | | | | | |
| Cash provided by operating activities | $ | 1,631 | | $ | 993 | |
| | | | | | | |
| Cash flows from investing activities: | | | | | | |
| Well costs on proved properties | | (1,149) | | | (1,364) | |
| Well costs on unproved properties | | (801) | | | (23) | |
| Acquisitions of proved and unproved properties | | (1,244) | | | (1,362) | |
| Divestitures of proved and unproved properties | | 184 | | | 1,174 | |
| Investments, net | | (86) | | | (4) | |
| Other property and equipment, net | | (397) | | | (267) | |
| Other | | 18 | | | (87) | |
Total cash used in investing activities | $ | (3,475) | | $ | (1,933) | |
| | | | | | | |
| Cash provided by financing activities | $ | 1,846 | | $ | 948 | |
| | | | | | | |
| Ending cash | $ | 111 | | $ | 609 | |
| | September 30, | | September 30, | |
| NINE MONTHS ENDED: | 2011 | | 2010 | |
| | | | | |
| Beginning cash | $ | 102 | | $ | 307 | |
| | | | | | | |
| Cash provided by operating activities | $ | 3,724 | | $ | 3,971 | |
| | | | | | | |
| Cash flows from investing activities: | | | | | | |
| Well costs on proved properties | | (4,470) | | | (3,615) | |
| Well costs on unproved properties | | (875) | | | (103) | |
| Acquisitions of proved and unproved properties | | (3,773) | | | (4,217) | |
| Divestitures of proved and unproved properties | | 6,357 | | | 3,107 | |
| Investments, net | | 126 | | | (113) | |
| Other property and equipment, net | | (1,073) | | | (640) | |
| Other | | (7) | | | (84) | |
Total cash used in investing activities | $ | (3,715) | | $ | (5,665) | |
| | | | | | | |
| Cash provided by financing activities | $ | — | | $ | 1,996 | |
| | | | | | | |
| Ending cash | $ | 111 | | $ | 609 | |
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
| THREE MONTHS ENDED: | September 30, | | June 30, | | September 30, | |
| 2011 | | 2011 | | 2010 | |
| | | | | | | | | | |
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 1,631 | | $ | 1,375 | | $ | 993 | |
| | | | | | | | | | |
Changes in assets and liabilities | | (222) | | | (168) | | | 241 | |
| | | | | | | | | | |
OPERATING CASH FLOW (a) | $ | 1,409 | | $ | 1,207 | | $ | 1,234 | |
| THREE MONTHS ENDED: | September 30, | | June 30, | | September 30, | |
| 2011 | | 2011 | | 2010 | |
| | | | | | | | | | |
| NET INCOME | $ | 922 | | $ | 510 | | $ | 558 | |
| | | | | | | | | | |
| Income tax expense | | 589 | | | 325 | | | 349 | |
| Interest expense | | 4 | | | 25 | | | 3 | |
| Depreciation and amortization of other assets | | 75 | | | 63 | | | 56 | |
| Natural gas and liquids depreciation, depletion and amortization | | 423 | | | 366 | | | 378 | |
| | | | | | | | | | |
EBITDA (b) | $ | 2,013 | | $ | 1,289 | | $ | 1,344 | |
| THREE MONTHS ENDED: | September 30, | | June 30, | | September 30, | |
| 2011 | | 2011 | | 2010 | |
| | | | | | | | | | |
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 1,631 | | $ | 1,375 | | $ | 993 | |
| | | | | | | | | | |
| Changes in assets and liabilities | | (222) | | | (168) | | | 241 | |
| Interest expense | | 4 | | | 25 | | | 3 | |
| Unrealized gains (losses) on natural gas and oil derivatives | | 631 | | | 106 | | | 53 | |
| Gains (losses) on investments | | (4) | | | 19 | | | 155 | |
| Stock-based compensation | | (40) | | | (39) | | | (44) | |
| Other items | | 13 | | | (29) | | | (57) | |
| | | | | | | | | | |
EBITDA (b) | $ | 2,013 | | $ | 1,289 | | $ | 1,344 | |
| (a) | Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. |
| (b) | Ebitda represents net income before income tax expense, interest expense 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)
| NINE MONTHS ENDED: | September 30, | | September 30, | |
| 2011 | | 2010 | |
| | | | | | | |
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 3,724 | | $ | 3,971 | |
| | | | | | | |
Changes in assets and liabilities | | 274 | | | (173) | |
| | | | | | | |
OPERATING CASH FLOW (a) | $ | 3,998 | | $ | 3,798 | |
| NINE MONTHS ENDED: | September 30, | | September 30, | |
| 2011 | | 2010 | |
| | | | | | | |
| NET INCOME | $ | 1,269 | | $ | 1,550 | |
| | | | | | | |
| Income tax expense | | 812 | | | 970 | |
| Interest expense | | 37 | | | 12 | |
| Depreciation and amortization of other assets | | 206 | | | 159 | |
| Natural gas and liquids depreciation, depletion and amortization | | 1,147 | | | 1,025 | |
| | | | | | | |
EBITDA (b) | $ | 3,471 | | $ | 3,716 | |
| NINE MONTHS ENDED: | September 30, | | September 30, | |
| 2011 | | 2010 | |
| | | | | | | |
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 3,724 | | $ | 3,971 | |
| | | | | | | |
| Changes in assets and liabilities | | 274 | | | (173) | |
| Interest expense | | 37 | | | 12 | |
| Unrealized gains (losses) on natural gas and oil derivatives | | (444) | | | (29) | |
| Gains on investments | | 19 | | | 120 | |
| Stock-based compensation | | (119) | | | (111) | |
| Other items | | (20) | | | (74) | |
| | | | | | | |
EBITDA (b) | $ | 3,471 | | $ | 3,716 | |
| (a) | Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. |
| (b) | Ebitda represents net income before income tax expense, interest expense 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)
| | September 30, | | June 30, | | September 30, | |
| THREE MONTHS ENDED: | 2011 | | 2011 | | 2010 | |
| | | | | | | | | | |
| EBITDA | $ | 2,013 | | $ | 1,289 | | $ | 1,344 | |
| | | | | | | | | | |
| Adjustments: | | | | | | | | | |
| Unrealized (gains) losses on natural gas and oil derivatives | | (631) | | | (106) | | | (53) | |
| Losses on purchases or exchanges of debt | | — | | | 174 | | | 59 | |
| Gains on investments | | — | | | — | | | (121) | |
| Impairment of investments | | — | | | — | | | 16 | |
| Losses on sales of other property and equipment | | 3 | | | 4 | | | 17 | |
| Other impairments | | — | | | 4 | | | 20 | |
| | | | | | | | | | |
Adjusted EBITDA (a) | $ | 1,385 | | $ | 1,365 | | $ | 1,282 | |
| | September 30, | | September 30, | |
| NINE MONTHS ENDED: | 2011 | | 2010 | |
| | | | | | | |
| EBITDA | $ | 3,471 | | $ | 3,716 | |
| | | | | | | |
| Adjustments: | | | | | | |
Unrealized (gains) losses on natural gas and oil derivatives | | 444 | | | 29 | |
Losses on purchases or exchanges of debt | | 176 | | | 130 | |
Gains on investments | | — | | | (121) | |
Impairment of investments | | — | | | 16 | |
Losses on sales of other property and equipment | | 3 | | | 17 | |
Other impairments | | 4 | | | 20 | |
| | | | | | | |
Adjusted EBITDA (a) | $ | 4,098 | | $ | 3,807 | |
| (a) | Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as 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. |
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per-share data)
(unaudited)
| | September 30, | | June 30, | | September 30, | |
| THREE MONTHS ENDED: | 2011 | | 2011 | | 2010 | |
| | | | | | | | | | |
| Net income available to common stockholders | $ | 879 | | $ | 467 | | $ | 515 | |
| | | | | | | | | | |
| Adjustments: | | | | | | | | | |
| Unrealized (gains) losses on derivatives, net of tax | | (385) | | | (61) | | | (31) | |
| Losses on purchases or exchanges of debt, net of tax | | — | | | 106 | | | 36 | |
| Gains on investment activity, net of tax | | — | | | — | | | (74) | |
| Impairment of investments, net of tax | | — | | | — | | | 9 | |
| Losses on sales of other property and equipment, net of tax | | 2 | | | 3 | | | 11 | |
| Other impairments, net of tax | | — | | | 2 | | | 12 | |
| (Gain) loss on foreign currency derivatives, net of tax | | — | | | 11 | | | — | |
| | | | | | | | | | |
Adjusted net income available to common stockholders (a) | | 496 | | | 528 | | | 478 | |
| Preferred stock dividends | | 43 | | | 43 | | | 43 | |
Total adjusted net income | $ | 539 | | $ | 571 | | $ | 521 | |
| | | | | | | | | | |
Weighted average fully diluted shares outstanding (b) | | 753 | | | 751 | | | 744 | |
| | | | | | | | | | |
Adjusted earnings per share assuming dilution (a) | $ | 0.72 | | $ | 0.76 | | $ | 0.70 | |
| (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 discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because: |
| | i. | Management uses adjusted net income available to common stockholders to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies. |
| | ii. | Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. |
| | iii. | Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. |
(b) | Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. |
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per-share data)
(unaudited)
| | September 30, | | September 30, | |
| NINE MONTHS ENDED: | 2011 | | 2010 | |
| | | | | | | |
| Net income available to common stockholders | $ | 1,141 | | $ | 1,482 | |
| | | | | | | |
| Adjustments: | | | | | | |
| Unrealized (gains) losses on derivatives, net of tax | | 279 | | | (28) | |
| Losses on purchases or exchanges of debt, net of tax | | 107 | | | 80 | |
| Gains on investment activity, net of tax | | — | | | (74) | |
| Impairment of investments, net of tax | | — | | | 9 | |
| Losses on sales of other property and equipment, net of tax | | 2 | | | 11 | |
| Other impairments, net of tax | | 2 | | | 12 | |
| (Gain) loss on foreign currency derivatives, net of tax | | 11 | | | — | |
| | | | | | | |
Adjusted net income available to common stockholders (a) | | 1,542 | | | 1,492 | |
| Preferred stock dividends | | 128 | | | 68 | |
Total adjusted net income | $ | 1,670 | | $ | 1,560 | |
| | | | | | | |
Weighted average fully diluted shares outstanding (b) | | 752 | | | 692 | |
| | | | | | | |
Adjusted earnings per share assuming dilution (a) | $ | 2.22 | | $ | 2.26 | |
| (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 discloses these non-GAAP financial measures as 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. |
SCHEDULE “A”
CHESAPEAKE’S OUTLOOK AS OF NOVEMBER 3, 2011
Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of November 3, 2011, we are using the following key assumptions in our projections for 2011, 2012 and 2013.
The primary changes from our July 28, 2011 Outlook are in italicized bold and are explained as follows:
| 1) | First projections for full-year 2013 have been provided; |
| 2) | Projected effects of changes in our hedging positions have been updated; |
| 3) | Certain cost assumptions have been updated; |
| 4) | Cash flow and proved well costs projections have been updated; and |
| 5) | Stand-alone Outlooks prior to consolidation eliminations are being provided for the first time for wholly owned subsidiaries Chesapeake Oilfield Services, L.L.C. and Chesapeake Midstream Development, L.P. |
Chesapeake Energy Corporation Consolidated Projections
For Years Ending December 31, 2011, 2012 and 2013
| | | Year Ending 12/31/11 | | Year Ending 12/31/12 | | Year Ending 12/31/13 |
| Estimated Production: | | | | | | |
Natural gas – bcf | | 970 – 990 | | 1,000 – 1,040 | | 1,020 – 1,060 |
Liquids – mbbls | | 31,000 – 33,000 | | 53,000 – 57,000 | | 72,000 – 76,000 |
Natural gas equivalent – bcfe | | 1,156 – 1,188 | | 1,318 – 1,382 | | 1,452 – 1,516 |
| | | | | | | |
| Daily natural gas equivalent midpoint – mmcfe | | 3,200 | | 3,700 | | 4,060 |
| | | | | | | |
| Year over year (YOY) estimated production increase | | 13% | | 15% | | 10% |
| YOY estimated production increase excluding asset sales | | 24% | | 16% | | 11% |
| | | | | | | |
NYMEX Price(a) (for calculation of realized hedging effects only): | | |
Natural gas - $/mcf | | $4.14 | | $5.00 | | $6.00 |
Oil - $/bbl | | $92.84 | | $100.00 | | $100.00 |
| | | | | | | |
| Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | | |
Natural gas - $/mcf | | $1.68 | | $0.37 | | $0.02 |
Liquids - $/bbl | | $(3.07) | | $(2.60) | | $(1.05) |
| | | | | | | |
| Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: | | |
Natural gas - $/mcf | | $0.90 – $1.10 | | $0.90 – $1.10 | | $0.90 – $1.10 |
Liquids - $/bbl(b) | | $30.00 – $35.00 | | $25.00 – $30.00 | | $20.00 – $25.00 |
| | | | | | | |
| Operating Costs per Mcfe of Projected Production: | | | | | | |
Production expense | | $0.90 – 1.00 | | $0.90 – 1.00 | | $0.90 – 1.00 |
| Production taxes (~ 5% of O&G revenues) | | $0.25 – 0.30 | | $0.25 – 0.30 | | $0.30 – 0.35 |
General and administrative(c) | | $0.36 – 0.41 | | $0.39 – 0.44 | | $0.39 – 0.44 |
Stock-based compensation (non-cash) | | $0.07 – 0.09 | | $0.04 – 0.06 | | $0.04 – 0.06 |
DD&A of natural gas and liquids assets | | $1.25 – 1.40 | | $1.40 – 1.60 | | $1.40 – 1.60 |
Depreciation of other assets | | $0.20 – 0.25 | | $0.25 – 0.30 | | $0.25 – 0.30 |
Interest expense(d) | | $0.05 – 0.10 | | $0.05 – 0.10 | | $0.05 – 0.10 |
| | | | | | | |
| Other ($ millions): | | | | |
Marketing, gathering and compression net margin(e) | | $120 – 130 | | $130 – 140 | | $140 – 150 |
Oilfield services net margin(e) | | $120 – 140 | | $250 – 300 | | $350 – 450 |
Other income (including equity investments) | | $100 – 150 | | $100 – 150 | | $100 – 150 |
Net income attributable to noncontrolling interest(f) | | $(3) – (5) | | $(35) – (40) | | $(40) – (45) |
| | | | | | | |
| Book Tax Rate | | 39% | | 39% | | 39% |
| | | | | | | |
| Weighted average shares outstanding (in millions): | | | | | | |
Basic | | 635 – 640 | | 640 – 645 | | 645 – 650 |
Diluted | | 748 – 753 | | 753 – 758 | | 758 – 763 |
| | | | | | | |
Operating cash flow before changes in assets and liabilities(g)(h) ($ millions) | | $5,100 – 5,200 | | $6,000 – 6,800 | | $8,000 – 9,000 |
| Proved well costs, net of JV carries ($ millions) | | ($6,000 – 6,500) | | ($6,200 – 6,800) | | ($7,000 – 8,000) |
Chesapeake Oilfield Services, L.L.C. Projections(i)
Prior to Consolidation Eliminations For Years Ending December 31, 2011, 2012 and 2013
($ in millions)
| | | Year Ending 12/31/11 | | Year Ending 12/31/12 | | Year Ending 12/31/13 |
| | | | | | | |
Revenue | | $1,200 – 1,300 | | $2,000 – 2,500 | | $3,100 – 3,600 |
Operating expense | | $900 – 1,000 | | $1,400 – 1,700 | | $2,100 – 2,500 |
Depreciation and amortization | | $155 – 165 | | $210 – 270 | | $330 – 390 |
Interest expense | | $40 – 50 | | $60 – 70 | | $50 – 60 |
| | | | | | | |
Operating cash flow before changes in assets and liabilities(g) | | $200 – 250 | | $600 – 700 | | $900 – 1,000 |
Capital expenditures | | ($800 – 900) | | ($800 – 900) | | ($800 – 900) |
Chesapeake Midstream Development, L.P. Projections
Prior to Consolidation Eliminations For Years Ending December 31, 2011, 2012 and 2013
($ in millions)
| | | Year Ending 12/31/11 | | Year Ending 12/31/12 | | Year Ending 12/31/13 |
| | | | | | | |
Revenue | | $200 – 220 | | $250 – 300 | | $350 – 400 |
Operating expense | | $150 – 160 | | $140 – 170 | | $170 – 200 |
Depreciation and amortization | | $50 – 60 | | $100 – 120 | | $150 – 170 |
Interest expense | | $10 – 15 | | $10 – 15 | | $15 – 25 |
Earnings from equity investments | | $75 – 100 | | $75 – 100 | | $75 – 100 |
| | | | | | | |
Operating cash flow before changes in assets and liabilities(g) | | $130 – 150 | | $175 – 225 | | $225 – 275 |
Capital expenditures (net of dropdowns) | | ($50 – 100) | | ($800 – 900) | | ($800 – 900) |
| a) | NYMEX natural gas prices have been updated for actual contract prices through November 2011 and NYMEX oil prices have been updated for actual contract prices through September 2011. |
| b) | Differentials include effects of natural gas liquids. |
| c) | Excludes expenses associated with non-cash stock-based compensation. |
| d) | Does not include 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 interest of Chesapeake Granite Wash Trust. |
| g) | A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities. |
| h) | Assumes NYMEX prices of $4.00 to $5.00 per mcf and $85.00 per bbl in 2011, $4.50 to $5.50 per mcf and $100.00 per bbl in 2012, and $5.50 to $6.50 per mcf and $100.00 per bbl in 2013. |
| i) | Excludes investment in FTS International, LLC. |
Commodity Hedging Activities
Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the Securities and Exchange Commission for detailed information about derivative instruments the company uses, its quarter-end natural gas and oil derivative positions and the accounting for commodity derivatives.
At November 3, 2011, the company does not have any open natural gas swaps in place. The company currently has $616 million of net hedging gains related to closed natural gas contracts and premiums collected on call options for future production periods.
| | Open Swaps (bcf) | | Avg. NYMEX Price of Open Swaps | | Forecasted Natural Gas Production (bcf) | | Open Swap Positions as a % of Forecasted Natural Gas Production | | Total Gains (Losses) from Closed Trades and Collected Call Premiums ($ in millions) | | Total Gains from Closed Trades and Collected Call Premiums per mcf of Forecasted Natural Gas Production |
| Q4 2011 | | 0 | | | $ | 0.00 | | | 250 | | | 0 | % | | $ | 369 | | | $ | 1.48 | |
| Q1 2012 | | | | | | | | | | | | | | | | 158 | | | | | |
| Q2 2012 | | | | | | | | | | | | | | | | 195 | | | | | |
| Q3 2012 | | | | | | | | | | | | | | | | 32 | | | | | |
| Q4 2012 | | | | | | | | | | | | | | | | 15 | | | | | |
| Total 2012 | | 0 | | | $ | 0.00 | | | 1,020 | | | 0 | % | | $ | 400 | | | $ | 0.39 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Total 2013 | | 0 | | | $ | 0.00 | | | 1,040 | | | 0 | % | | $ | 21 | | | $ | 0.02 | |
| Total 2014 | | 0 | | | | | | | | | | | | | $ | (32) | | | | | |
| Total 2015 | | 0 | | | | | | | | | | | | | $ | (46) | | | | | |
| Total 2016 – 2022 | | 0 | | | | | | | | | | | | | $ | (96) | | | | | |
The company currently has the following natural gas written call options in place for 2011 through 2020:
| | | Call Options (bcf) | | Avg. NYMEX Strike Price | | Forecasted Natural Gas Production (bcf) | | Call Options as a % of Forecasted Natural Gas Production |
| Q4 2011 | | 11 | | | | 4.13 | | | 250 | | | 4 | % |
| | | | | | | | | | | | | | |
| Q1 2012 | | 40 | | | | 6.54 | | | | | | | |
| Q2 2012 | | 40 | | | | 6.54 | | | | | | | |
| Q3 2012 | | 40 | | | | 6.54 | | | | | | | |
| Q4 2012 | | 41 | | | | 6.54 | | | | | | | |
| Total 2012 | | 161 | | | $ | 6.54 | | | 1,020 | | | 16 | % |
| | | | | | | | | | | | | | |
| Total 2013 | | 415 | | | $ | 6.44 | | | 1,040 | | | 40 | % |
| Total 2014 | | 330 | | | $ | 6.43 | | | | | | | |
| Total 2015 | | 138 | | | $ | 6.41 | | | | | | | |
| Total 2016 – 2020 | | 393 | | | $ | 7.93 | | | | | | | |
The company has the following natural gas basis protection swaps in place for 2011 through 2022:
| | | Non-Appalachia | | Appalachia |
| | | Volume (Bcf) | | Avg. NYMEX less | | Volume (Bcf) | | Avg. NYMEX plus |
| 2011 | | 7 | | | $ | 0.82 | | | 12 | | | $ | 0.14 | |
| 2012 | | 51 | | | $ | 0.78 | | | — | | | $ | — | |
| 2013 - 2022 | | 29 | | | $ | 0.69 | | | — | | | $ | — | |
| Totals | | 87 | | | $ | 0.75 | | | 12 | | | $ | 0.14 | |
At November 3, 2011, the company has the following open crude oil swaps in place for 2011 and through 2015. In addition, the company has $93 million of net hedging gains related to closed crude oil contracts and premiums collected on call options for future production periods.
| | | Open Swaps (mbbls) | | Avg. NYMEX Price of Open Swaps | | Forecasted Liquids Production (mbbls) | | Open Swap Positions as a % of Forecasted Liquids Production | | Total Gains (Losses) from Closed Trades and Collected Call Premiums ($millions) | | Total Gains (Losses) from Closed Trades and Collected Call Premiums per bbl of Forecasted Liquids Production |
Q4 2011(a) | | 440 | | | $ | 97.17 | | | 10,000 | | | 4 | % | | $ | (11) | | | $ | (1.11) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Q1 2012 | | 346 | | | | 97.89 | | | | | | | | | | (19) | | | | | |
| Q2 2012 | | 349 | | | | 98.12 | | | | | | | | | | (25) | | | | | |
| Q3 2012 | | 361 | | | | 98.19 | | | | | | | | | | (29) | | | | | |
| Q4 2012 | | 369 | | | | 98.20 | | | | | | | | | | (33) | | | | | |
Total 2012(a) | | 1,425 | | | $ | 98.10 | | | 55,000 | | | 3 | % | | $ | (106) | | | $ | (1.92) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Total 2013 | | 739 | | | $ | 87.69 | | | 74,000 | | | 1 | % | | $ | 26 | | | $ | 0.36 | |
| Total 2014 | | 713 | | | $ | 88.27 | | | | | | | | | $ | (159) | | | | | |
| Total 2015 | | 500 | | | $ | 88.75 | | | | | | | | | $ | 211 | | | | | |
| Total 2016 – 2021 | | | | | | | | | | | | | | | $ | 132 | | | | | |
| (a) | Certain hedging contracts include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 276 mbbls in 2011 and 732 mbbls in 2012. |
The company currently has the following crude oil written call options in place for 2011 through 2017:
| | | Call Options (mbbls) | | Avg. NYMEX Strike Price | | Forecasted Liquids Production (mbbls) | | Call Options as a % of Forecasted Liquids Production |
| Q4 2011 | | 1,840 | | | $ | 110.00 | | | 10,000 | | | 18 | % |
| | | | | | | | | | | | | | |
| Q1 2012 | | 4,047 | | | | 100.00 | | | | | | | |
| Q2 2012 | | 4,047 | | | | 100.00 | | | | | | | |
| Q3 2012 | | 4,091 | | | | 100.00 | | | | | | | |
| Q4 2012 | | 4,092 | | | | 100.00 | | | | | | | |
| Total 2012 | | 16,277 | | | $ | 100.00 | | | 55,000 | | | 30 | % |
| | | | | | | | | | | | | | |
| Total 2013 | | 21,245 | | | $ | 95.19 | | | 74,000 | | | 29 | % |
| Total 2014 | | 15,379 | | | $ | 96.61 | | | | | | | |
| Total 2015 | | 19,360 | | | $ | 100.57 | | | | | | | |
| Total 2016 – 2017 | | 24,220 | | | $ | 100.07 | | | | | | | |
SCHEDULE “B”
CHESAPEAKE’S OUTLOOK AS OF JULY 28, 2011
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF NOVEMBER 3, 2011
CHESAPEAKE’S OUTLOOK AS OF JULY 28, 2011
Years Ending December 31, 2011 and 2012
Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of July 28, 2011, we are using the following key assumptions in our projections for 2011 and 2012.
The primary changes from our May 2, 2011 Outlook are in italicized bold and are explained as follows:
| 1) | Our production guidance has been updated; |
| 2) | Projected effects of changes in our hedging positions have been updated; |
| 3) | Certain cost assumptions have been updated; and |
| 4) | Our cash flow projections have been updated, including increased drilling and completion costs. |
| | | Year Ending 12/31/2011 | | Year Ending 12/31/2012 |
| Estimated Production: | | | | |
Natural gas – bcf | | 970 – 990 | | 1,000 – 1,040 |
Liquids – mbbls | | 31,000 – 33,000 | | 53,000 – 57,000 |
Natural gas equivalent – bcfe | | 1,156 – 1,188 | | 1,318 – 1,382 |
| | | | | |
| Daily natural gas equivalent midpoint – mmcfe | | 3,200 | | 3,700 |
| | | | | |
| Year over year (YOY) estimated production increase | | 12 – 15% | | 12 - 18% |
| YOY estimated production increase excluding asset sales | | 23 – 26% | | 13 - 19% |
| | | | | |
NYMEX Price(a) (for calculation of realized hedging effects only): |
Natural gas - $/mcf | | $4.34 | | $5.50 |
Oil - $/bbl | | $99.15 | | $100.00 |
| | | | | |
| Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | | |
Natural gas - $/mcf | | $1.60 | | $0.28 |
Liquids - $/bbl | | $(3.65) | | $(3.93) |
| | | | | |
| Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: | | |
Natural gas - $/mcf | | $0.90 – $1.10 | | $0.90 – $1.10 |
Liquids - $/bbl(b) | | $30.00 – $35.00 | | $30.00 – $35.00 |
| | | | | |
| Operating Costs per Mcfe of Projected Production: | | | | |
Production expense | | $0.90 – 1.00 | | $0.90 – 1.00 |
| Production taxes (~ 5% of O&G revenues) | | $0.25 – 0.30 | | $0.25 – 0.30 |
General and administrative(c) | | $0.36 – 0.41 | | $0.36 – 0.41 |
Stock-based compensation (non-cash) | | $0.07 – 0.09 | | $0.07 – 0.09 |
DD&A of natural gas and liquids assets | | $1.25 – 1.40 | | $1.25 – 1.40 |
Depreciation of other assets | | $0.20 – 0.25 | | $0.20 – 0.25 |
Interest expense(d) | | $0.05 – 0.10 | | $0.05 – 0.10 |
| | | | | |
| Other Income per Mcfe: | | |
| Marketing, gathering and compression net margin | | $0.12 – 0.14 | | $0.12 – 0.14 |
Service operations net margin | | $0.09 – 0.11 | | $0.15 – 0.20 |
Other income (including equity investments) | | $0.06 – 0.08 | | $0.06 – 0.08 |
| | | | | |
| Book Tax Rate | | 39% | | 39% |
| | | | | |
| Equivalent Shares Outstanding (in millions): | | | | |
Basic | | 640 – 645 | | 647 – 652 |
Diluted | | 750 – 755 | | 760 – 765 |
| | | | | |
Operating cash flow before changes in assets and liabilities(e)(f) | | $5,100 – 5,200 | | $6,000 – 6,800 |
| Drilling and completion costs, net of joint venture carries | | ($6,000 – 6,500) | | ($6,000 – 6,500) |
| | Note: please refer to footnotes on following page |
| a) | NYMEX natural gas prices have been updated for actual contract prices through July 2011 and NYMEX oil prices have been updated for actual contract prices through June 2011. |
| b) | Differentials include effects of natural gas liquids. |
| c) | Excludes expenses associated with noncash stock compensation. |
| d) | Does not include gains or losses on interest rate derivatives. |
| e) | A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities. |
| f) | Assumes NYMEX prices of $4.00 to $5.00 per mcf and $100.00 per bbl in 2011 and $5.00 to $6.00 per mcf and $100.00 per bbl in 2012. |
Commodity Hedging Activities
Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices. The company utilizes the following types of natural gas and oil derivative instruments:
| 1) | Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity. |
| 2) | Call options: Chesapeake sells call options in exchange for a premium from the counterparty. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party. |
| 3) | Put options: Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. At the time of settlement, if the market prices falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party. |
| 4) | Knockout swaps: Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout price. |
| 5) | Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract. |
All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.
Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction. Since the latter half of 2009 through June 2011, the company has taken advantage of attractive strip prices in 2012 through 2017 and sold natural gas and oil call options to its counterparties in exchange for 2010, 2011 and 2012 natural gas swaps with strike prices above the then current market price. This effectively allowed the company to sell out-year volatility through call options at terms acceptable to Chesapeake in exchange for natural gas swaps with fixed prices in excess of the market price at the time.
Gains or losses from commodity derivative transactions are reflected as adjustments to natural gas and liquids sales. All realized gains (losses) from natural gas and oil derivatives are included in natural gas and liquids sales in the month of related production. In accordance with generally accepted accounting principles, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and liquids sales as unrealized gains (losses). Realized gains (losses) are comprised of settled trades related to the production periods being reported. Unrealized gains (losses) are comprised of both temporary fluctuations in the mark-to-market values of nonqualifying trades and settled values of nonqualifying derivatives related to future production periods.
At July 28, 2011, the company has the following open natural gas swaps in place for 2011 and 2012. In addition, the company currently has $630 million of net hedging gains related to closed natural gas contracts and premiums collected on call options for future production periods.
| | Open Swaps (Bcf) | | Avg. NYMEX Price of Open Swaps | | Forecasted Natural Gas Production (Bcf) | | Open Swap Positions as a % of Forecasted Natural Gas Production | Total Gains (Losses) from Closed Trades and Collected Call Premiums ($millions) | Total Gains from Closed Trades and Collected Call Premiums per mcf of Forecasted Natural Gas Production |
| Q3 2011 | | 200 | | | $ | 4.81 | | | | | | | | $ | 285 | | | | |
| Q4 2011 | | 197 | | | $ | 4.78 | | | | | | | | $ | 250 | | | | |
| Total 2011 | | 397 | | | $ | 4.79 | | | 500 | | | 79 | % | $ | 535 | | $ | 1.07 | |
| | | | | | | | | | | | | | | | | | | | |
| Total 2012 | | 94 | | | $ | 6.12 | | | 1,020 | | | 9 | % | $ | 248 | | $ | 0.24 | |
| Total 2013 | | | | | | | | | | | | | | $ | 21 | | | | |
| Total 2014 | | | | | | | | | | | | | | $ | (32) | | | | |
| Total 2015 | | | | | | | | | | | | | | $ | (46) | | | | |
| Total 2016 – 2020 | | | | | | | | | | | | | | $ | (96) | | | | |
The company currently has the following natural gas written call options in place for 2011 through 2020:
| | | Call Options (Bcf) | | Avg. NYMEX Strike Price | | Forecasted Natural Gas Production (Bcf) | | Call Options as a % of Forecasted Natural Gas Production |
| Total 2012 | | 161 | | | $ | 6.54 | | | 1,020 | | | 16 | % |
| Total 2013 | | 415 | | | $ | 6.44 | | | | | | | |
| Total 2014 | | 330 | | | $ | 6.43 | | | | | | | |
| Total 2015 | | 226 | | | $ | 6.31 | | | | | | | |
| Total 2016 – 2020 | | 393 | | | $ | 7.93 | | | | | | | |
The company has the following natural gas basis protection swaps in place for 2011 through 2022:
| | | Non-Appalachia | | Appalachia |
| | | Volume (Bcf) | | Avg. NYMEX less | | Volume (Bcf) | | Avg. NYMEX plus |
| 2011 | | 26 | | | $ | 0.82 | | | 25 | | | $ | 0.14 | |
| 2012 | | 51 | | | $ | 0.78 | | | — | | | $ | — | |
| 2013 - 2022 | | 29 | | | $ | 0.69 | | | — | | | $ | — | |
| Totals | | 106 | | | $ | 0.77 | | | 25 | | | $ | 0.14 | |
At July 28, 2011, the company has the following open crude oil swaps in place for 2011 and 2012. In addition, the company has $60 million of net hedging gains related to closed crude oil contracts and premiums collected on call options for future production periods.
| | Open Swaps (mbbls) | | Avg. NYMEX Price of Open Swaps | | Forecasted Liquids Production (mbbls) | | Open Swap Positions as a % of Forecasted Liquids Production | Total Gains (Losses) from Closed Trades and Collected Call Premiums ($millions) | Total Gains (Losses) from Closed Trades and Collected Call Premiums per bbl of Forecasted Liquids Production |
| Q3 2011 | 828 | | | $ | 100.90 | | | — | | — | | $ | (17) | | | | |
| Q4 2011 | 828 | | | $ | 100.90 | | | — | | — | | $ | (17) | | | | |
Total 2011(a) | 1,656 | | | $ | 100.90 | | | 19,000 | | 9 | % | $ | (34) | | $ | (1.80) | |
| | | | | | | | | | | | | | | | | | |
Total 2012(a) | 1,830 | | | $ | 105.03 | | | 55,000 | | 3 | % | $ | 82 | | $ | 1.48 | |
| Total 2013 | | | | | | | | | | | | $ | 6 | | | | |
| Total 2014 | | | | | | | | | | | | $ | (197) | | | | |
| Total 2015 | | | | | | | | | | | | $ | 145 | | | | |
| Total 2016 – 2020 | | | | | | | | | | | | $ | 58 | | | | |
| (a) | Certain hedging contracts include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 0.6 mmbbls in 2011 and 0.7 mmbbls in 2012. |
The company currently has the following crude oil written call options in place for 2011 through 2017:
| | | Call Options (mbbls) | | Avg. NYMEX Strike Price | | Forecasted Liquids Production (mbbls) | | Call Options as a % of Forecasted Liquids Production |
| Q3 2011 | | 1,840 | | | $ | 110.00 | | | | | | | |
| Q4 2011 | | 1,840 | | | $ | 110.00 | | | | | | | |
| Total 2011 | | 3,680 | | | $ | 110.00 | | | 19,000 | | | 19 | % |
| | | | | | | | | | | | | | |
| Total 2012 | | 22,139 | | | $ | 87.93 | | | 55,000 | | | 40 | % |
| Total 2013 | | 14,564 | | | $ | 87.20 | | | | | | | |
| Total 2014 | | 8,707 | | | $ | 87.72 | | | | | | | |
| Total 2015 | | 11,226 | | | $ | 92.00 | | | | | | | |
| Total 2016 – 2017 | | 14,424 | | | $ | 89.75 | | | | | | | |
