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Press release from Business Wire

Chesapeake Energy Corporation Reports Financial and Operational Results for the 2012 First Quarter

<p class='bwalignc'> <i><b>Company Reports 2012 First Quarter Net Loss to Common Stockholders of $71 Million, or $0.11 per Fully Diluted Common Share, on Revenue of $2.4 Billion; Company Reports Adjusted Net Income Available to Common Stockholders of $94 Million, or $0.18 per Fully Diluted Common Share, Adjusted Ebitda of $838 Million and Operating Cash Flow of $910 Million</b></i> </p> <p class='bwalignc'> <i><b>2012 First Quarter Average Daily Total Production of 3.658 Bcfe per Day Increases 18% Year over Year and 2% Sequentially, Despite Voluntary Net Natural Gas Curtailments of 30 Bcf (54 Bcf Gross) during February and March; 2012 First Quarter Daily Liquids Production Increases 69% Year over Year and 7% Sequentially to 113,600 Bbls per Day; Liquids Production Reaches 19% of Total Production and 61% of Unhedged Natural Gas and Liquids Revenue</b></i> </p> <p class='bwalignc'> <i><b>Company Adds New Net Proved Reserves of Approximately 1.8 Tcfe, or 300 Mmboe, through the Drillbit in the 2012 First Quarter at a Drilling and Completion Cost of Only $1.19 per Mcfe, or $7.14 per Boe</b></i> </p> <p class='bwalignc'> <i><b>Company Has Completed $2.6 Billion of Asset Monetizations Year to Date and Is on Track to Complete an Expected $11.5-14.0 Billion of Total Asset Monetizations in 2012; Proceeds Expected to Fully Fund 2012 Capital Expenditure Budget and Reduce Long-Term Debt to the 25/25 Plan Goal of $9.5 Billion by Year-End 2012</b></i> </p> <p class='bwalignc'> <i><b>Company Plans to Significantly Reduce Capital Expenditures for Drilling, Completion and Leasehold from First Quarter 2012 Levels during Remainder of 2012 and in 2013</b></i> </p>

Tuesday, May 01, 2012

Chesapeake Energy Corporation Reports Financial and Operational Results for the 2012 First Quarter16:07 EDT Tuesday, May 01, 2012 OKLAHOMA CITY (Business Wire) -- Chesapeake Energy Corporation (NYSE:CHK) today announced financial and operational results for the 2012 first quarter. For the 2012 first quarter, Chesapeake reported a net loss to common stockholders of $71 million ($0.11 per fully diluted common share), ebitda of $597 million (defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization) and operating cash flow of $910 million (defined as cash flow from operating activities before changes in assets and liabilities) on revenue of $2.419 billion and production of 333 billion cubic feet of natural gas equivalent (bcfe). The company's 2012 first quarter results include various items that are typically not included in published estimates of the company's financial results by certain securities analysts. Excluding such items for the 2012 first quarter, Chesapeake reported adjusted net income to common stockholders of $94 million ($0.18 per fully diluted common share) and adjusted ebitda of $838 million. The primary excluded item from the 2012 first quarter reported results is a net unrealized noncash after-tax mark-to-market loss of $167 million resulting from the company's natural gas, liquids and interest rate hedging programs. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 18 – 20 of this release. Key Operational and Financial Statistics Summarized The table below summarizes Chesapeake's key results during the 2012 first quarter and compares them to results during the 2011 fourth quarter and the 2011 first quarter.   Three Months Ended3/31/12     12/31/11     3/31/11 Average daily production (in mmcfe)(a) 3,658 3,596 3,107 Natural gas equivalent production (in bcfe) 333 331 280 Natural gas equivalent realized price ($/mcfe)(b) 4.02 5.08 5.99 Oil and NGL (liquids) production (in mbbls) 10,334 9,767 6,048 Liquids as % of total production 19 18 13 Average realized liquids price ($/bbl)(b) 67.92 64.12 63.20 Liquids as % of realized revenue 52 37 23 Liquids as % of unhedged revenue 61 47 34 Natural gas production (in bcf) 271 272 243 Natural gas as % of total production 81 82 87 Average realized natural gas price ($/mcf)(b) 2.35 3.87 5.31 Natural gas as % of realized revenue 48 63 77 Natural gas as % of unhedged revenue 39 53 66 Marketing, gathering and compression net margin ($/mcfe)(c) 0.06 0.07 0.11 Oilfield services net margin ($/mcfe) (c) 0.12 0.09 0.09 Production expenses ($/mcfe) (d) (1.05 ) (0.88 ) (0.85 ) Production taxes ($/mcfe) (0.14 ) (0.15 ) (0.16 ) General and administrative costs ($/mcfe)(e) (0.35 ) (0.35 ) (0.38 ) Stock-based compensation ($/mcfe) (0.06 ) (0.06 ) (0.08 ) DD&A of natural gas and liquids properties ($/mcfe) (1.52 ) (1.46 ) (1.28 ) D&A of other assets ($/mcfe) (0.25 ) (0.26 ) (0.24 ) Interest expense ($/mcfe)(b) (0.02 ) (0.04 ) 0.00 Operating cash flow ($ in millions)(f) 910 1,311 1,381 Operating cash flow ($/mcfe) 2.73 3.96 4.94 Adjusted ebitda ($ in millions)(g) 838 1,308 1,346 Adjusted ebitda ($/mcfe) 2.52 3.95 4.81 Net income (loss) to common stockholders ($ in millions) (71 ) 429 (205 ) Earnings (loss) per share – diluted ($) (0.11 ) 0.63 (0.32 ) Adjusted net income to common stockholders ($ in millions)(h) 94 394 518 Adjusted earnings per share – diluted ($) 0.18 0.58 0.75   (a)   Includes effect of the Fayetteville Shale asset sale to BHP Billiton on March 31, 2011 (which had an average production loss impact of approximately 400 mmcfe per day in both the 2012 first and 2011 fourth quarters), VPP #9 sale in May 2011 (which had an average production loss impact of approximately 70 mmcfe per day in both the 2012 first and 2011 fourth quarters) and VPP #10 sale in March 2012 (which had an average production loss impact of approximately 32 mmcfe per day in the 2012 first quarter). Also includes the effect of voluntary net natural gas production curtailments of 30 bcf, or an average of approximately 330 mmcf per day in the 2012 first quarter. (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) Includes one-time retroactive Pennsylvania natural gas impact fee in the 2012 first quarter of $0.04 per mcfe. (e) Excludes expenses associated with noncash stock-based compensation. (f) Defined as cash flow provided by operating activities before changes in assets and liabilities. (g) Defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 19. (h) Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 20.   Management Comments Aubrey K. McClendon, Chesapeake's Chairman and Chief Executive Officer, said, “We are focused on executing our transformation to a more balanced asset base between liquids and natural gas and believe our business has strong momentum despite a challenging environment with natural gas prices at 10-year lows. This quarter continued to see strong liquids production growth as we accelerate our ongoing shift to liquids, continuing success in keeping finding costs low, and the addition of a substantial amount of new proved reserves. This year's capital expenditures will be front-end loaded, and for the remainder of the year we expect a significant decrease from the first quarter's peak capital expenditure levels as we further reduce drilling activity in dry natural gas plays and reduce spending on new leasehold. We will continue to implement our 25/25 Plan, including reducing overall debt to $9.5 billion by year-end 2012, monetizing the portions of our asset base where we are not a #1 or #2 producer, and continuing to increase our exposure to liquids. We believe Chesapeake has built the nation's best collection of resource-rich E&P assets, and we remain focused on realizing their growth and value for our shareholders.” 2012 First Quarter Average Daily Total Production of 3.658 Bcfe per Day Increases 18% Year over Year and 2% Sequentially, Despite Voluntary Net Natural Gas Curtailments of 30 Bcf (54 Bcf Gross) during February and March; 2012 First Quarter Daily Liquids Production Increases 69% Year over Year and Reaches 19% of Total Production and 61% of Unhedged Natural Gas and Liquids Revenue Chesapeake's daily production for the 2012 first quarter averaged 3.658 bcfe, an increase of 2% from the average 3.596 bcfe produced per day in the 2011 fourth quarter and an increase of 18% from the average 3.107 bcfe produced per day in the 2011 first quarter. Chesapeake's average daily production of 3.658 bcfe for the 2012 first quarter consisted of approximately 2.976 billion cubic feet of natural gas (bcf) (81% on a natural gas equivalent basis) and approximately 113,600 barrels (bbls) of oil and natural gas liquids (collectively “liquids”) (19% on a natural gas equivalent basis). During February and March, the company voluntarily curtailed 54 bcf of gross natural gas production, or an average of approximately 900 million cubic feet (mmcf) per day, resulting in net curtailments to Chesapeake of 30 bcf, or approximately 330 mmcf per day of natural gas production spread across the entire quarter. For the 2012 first quarter, the company's year-over-year growth rate of natural gas production was 10%, or approximately 272 mmcf per day, and its year-over-year growth rate of liquids production was 69%, or approximately 46,400 bbls per day. The company's percentage of revenue from liquids in the 2012 first quarter was 61% of total unhedged natural gas and liquids revenue, compared to 47% in the 2011 fourth quarter and 34% in the 2011 first quarter. As a result of reduced drilling activity in 2012 and 2013 on its dry natural gas plays, Chesapeake is projecting a decline in its natural gas productive capacity in 2013 of approximately 12% after adjusting for estimated net voluntary production curtailments of approximately 80 bcf in 2012. Average Realized Prices and Hedging Results Detailed Average prices realized during the 2012 first quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $2.35 per thousand cubic feet of natural gas (mcf) and $67.92 per bbl, for a realized natural gas equivalent price of $4.02 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas and liquids hedging activities during the 2012 first quarter generated a $0.58 gain per mcf and a $3.99 loss per bbl, respectively, for a 2012 first quarter realized hedging gain of $117 million, or $0.35 per mcfe. By comparison, average prices realized during the 2011 first quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.31 per mcf and $63.20 per bbl, for a realized natural gas equivalent price of $5.99 per mcfe. Realized gains from natural gas and liquids hedging activities during the 2011 first quarter generated a $2.07 gain per mcf and a $2.88 loss per bbl, respectively, for a 2011 first quarter realized hedging gain of $488 million, or $1.74 per mcfe. The company's realized cash hedging gains since January 1, 2006 have been $8.5 billion, or $1.52 per mcfe. Company Provides Update on Hedging Positions The following table summarizes Chesapeake's 2012 and 2013 open swap positions as of May 1, 2012. 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       LiquidsYear% of ForecastedProduction     $ NYMEXNatural Gas% of ForecastedProduction     $ NYMEXOil WTI 2Q - 4Q 2012 0% — 60% $103.02   2013 0% — 9% $102.86   In addition to the open hedging positions disclosed above, as of May 1, 2012, the company had an additional $48 million and $44 million of net hedging gains on closed contracts and premiums for call options that will be realized in 2012 and 2013, respectively, as set forth below.   Natural Gas       LiquidsYearForecastedProduction(bcf)     Gains/Premiums($ in millions)     ($/mcf)ForecastedProduction(mbbls)     Gains (Losses)/Premiums($ in millions)     ($/bbl) 2Q - 4Q 2012 779 $242 $0.31 31,666 $(194) $(6.14) 2013 990 $20 $0.02 57,000 $24 $0.41   Details of the company's quarter-end hedging positions will be provided in the company's Form 10-Q filing with the Securities and Exchange Commission (SEC), and current positions are disclosed in summary format in the company's Outlook dated May 1, 2012, which is attached to this release as Schedule “A,” beginning on page 21. The Outlook has been changed from the Outlook dated February 21, 2012, attached as Schedule “B,” which begins on page 25, to reflect various updated information. Proved Natural Gas and Oil Reserves Increase by Approximately 1.0 Tcfe, or 5%, in the 2012 First Quarter to 19.8 Tcfe; Proved Reserves on a Boe Basis Now Reach 3.3 Billion Boe; Company Adds New Proved Reserves of Approximately 1.8 Tcfe, or 300 Mmboe, through the Drillbit in the 2012 First Quarter at a Drilling and Completion Cost of Only $1.19 per Mcfe, or $7.14 per Boe The following table compares Chesapeake's March 31, 2012 proved reserves, the increase over its year-end 2011 proved reserves, reserve replacement ratio, estimated future net cash flows from proved reserves (discounted at an annual rate of 10% before income taxes (PV-10)), percentage of proved developed reserves and 2012 first quarter proved well costs based on the trailing 12-month average price required under SEC rules and the 10-year average NYMEX strip prices as of March 31, 2012. Additional information regarding the data in the table below is presented on pages 14 and 15. Pricing Method   NaturalGasPrice($/mcf)     OilPrice($/bbl)   ProvedReserves(tcfe)(a)   Proved ReservesGrowth(tcfe)(b)   Proved ReservesGrowth%(b)   ReserveReplacementRatio   PV-10(billions)   ProvedDevelopedPercentage   ProvedWellCosts($/mcf)(c) Trailing 12-month avg (SEC)(d)   $3.73   $98.25   19.8   1.0   5%   410%   $20.6   54%   $1.19 3/31/12 10-year avg NYMEX strip(e) $4.65 $94.54 20.9 1.0 5% 402% $24.7 54% $1.28   (a)   After sales of proved reserves of approximately 160 bcfe during the 2012 first quarter. (b) Compares proved reserves and growth for the 2012 first quarter under comparable pricing methods. At year-end 2011, Chesapeake's proved reserves were 18.8 tcfe using trailing 12-month average prices, which are required by SEC reporting rules, and 19.9 tcfe using the 10-year average NYMEX strip prices as of December 31, 2011. (c) Includes performance-related reserve revisions and excludes price-related revisions. Costs are net of $448 million of well cost carries paid by the company's joint venture partners. (d) 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 March 31, 2012. This pricing yields estimated "proved reserves" for SEC reporting purposes. Natural gas and oil volumes estimated under the 10-year average NYMEX strip reflect an alternative pricing scenario that illustrates the sensitivity of proved reserves to a different pricing assumption. (e) 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.   Additionally, the net book value of the company's other long-term assets was $8.1 billion as of March 31, 2012, compared to $7.5 billion as of December 31, 2011. Chesapeake's Leasehold and 3-D Seismic Inventories Total 15.6 Million Net Acres and 31.8 Million Acres, Respectively; Risked Unproved Resources in the Company's Inventory Total 112 Tcfe; Unrisked Unproved Resources Total 348 Tcfe Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (15.6 million net acres) and 3-D seismic (31.8 million acres) in the U.S. The company has also accumulated the largest inventory of U.S. natural gas shale play leasehold (2.2 million net acres) and owns a leading position in 11 of what Chesapeake believes are the Top 15 unconventional liquids-rich plays in the U.S. – the Eagle Ford Shale in South Texas; the Utica Shale in the Appalachian Basin; 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; and the Niobrara Shale in the Powder River Basin. In addition, Chesapeake also owns a #1 position in three of the best unconventional natural gas plays in the U.S. – the Marcellus, Haynesville and Bossier shales – and a #2 position in the Barnett Shale. On its leasehold inventory, Chesapeake has identified an estimated 20.9 trillion cubic feet of natural gas equivalent (tcfe) of proved reserves (using volume estimates based on the 10-year average NYMEX strip prices as of March 31, 2012 as compared to 19.8 tcfe using SEC pricing), 112 tcfe of risked unproved resources and 348 tcfe of unrisked unproved resources. The company is currently using 154 operated drilling rigs to further develop its inventory of approximately 39,400 net risked drillsites. Of Chesapeake's 154 operated rigs, 131 are drilling wells primarily focused on developing unconventional liquids-rich plays and 23 are drilling wells primarily focused on unconventional natural gas plays. To reduce capital expenditures during the remainder of 2012 and in 2013 by a combined $750 million at the midpoint, the company is reducing its drilling activity from a peak in the 2011 fourth quarter of 172 operated rigs to less than 125 operated rigs by the third quarter of 2012 and plans to average approximately 130 operated rigs in 2013 assuming natural gas prices remain at depressed levels. The following table summarizes Chesapeake's ownership and activity in its unconventional natural gas plays, its unconventional liquids-rich plays and other plays. Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and unproved resources associated with such drillsites.     Risked   Total   Risked   Unrisked   1Q2012 Avg   May 2012CHKNetProvedUnprovedUnprovedDaily NetOperatedNetUndrilledReservesResourcesResourcesProductionRigPlay Type   Acreage(a)   Wells   (bcfe)(a)(b)   (bcfe)(a)   (bcfe)(a)   (mmcfe)   Count   Unconventional Natural Gas Plays 2,175,000 13,250 10,473 56,400 129,100 2,060 23   Unconventional Liquids-Rich Plays 6,770,000 16,350 6,062 48,500 184,600 998 131   Other Plays 6,675,000 9,800 4,357 7,300 34,500 600 0                               Totals   15,620,000   39,400   20,892   112,200   348,200   3,658   154 (a)   As of March 31, 2012, pro forma for recent leasehold transactions. (b) Based on 10-year average NYMEX strip prices at March 31, 2012.   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 unconventional liquids-rich plays on approximately 6.8 million net leasehold acres with 1.0 billion bbls of oil equivalent (bboe) (or 6 tcfe) of proved reserves, 8.1 bboe (or 49 tcfe) of risked unproved resources and 30.8 bboe (or 185 tcfe) of unrisked unproved resources based on the company's internal estimates. Company Has Completed $2.6 Billion of Asset Monetizations Year to Date and is on Track to Complete an Expected $11.5-14.0 Billion of Total Asset Monetizations in 2012; Proceeds Expected to Fully Fund 2012 Capital Expenditure Budget and Reduce Long-Term Debt to the 25/25 Plan Goal of $9.5 Billion by Year-End 2012 Chesapeake has completed $2.6 billion of asset monetizations in the first four months of 2012. In March 2012, the company completed the sale of preferred shares of a newly formed unrestricted, non-guarantor consolidated subsidiary, CHK Cleveland Tonkawa, L.L.C. (CHK C-T), and a 3.75% overriding royalty interest in the first 1,000 new net wells to be drilled on CHK C-T leasehold and certain wells contributed at closing, for gross proceeds of $1.25 billion. Also in March 2012, Chesapeake completed the sale of a 10-year volumetric production payment (VPP) for proceeds of approximately $745 million, or approximately $4.68 per mcfe, for certain producing assets in its Anadarko Basin Granite Wash play. The transaction included approximately 160 bcfe of proved reserves and current net production of an estimated 125 million cubic feet of natural gas equivalent (mmcfe) per day. Including this transaction, the company has completed 10 VPP transactions since December 2007 and, in doing so, has sold approximately 1.37 tcfe of proved reserves for combined proceeds of approximately $6.4 billion, or approximately $4.65 per mcfe, which is nearly 300% more than the company's current drilling and completion cost per mcfe. In addition, in April 2012, Chesapeake closed the sale of approximately 58,400 net acres of leasehold and current daily production of approximately 25 mmcfe per day in the Texoma Woodford play to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation (NYSE:XOM), for approximately $572 million after certain deductions and closing costs. The company remains on track to complete additional asset monetizations of $9-11.5 billion during 2012. The planned asset monetizations include the sale of the company's Permian Basin assets, a joint venture in the Mississippi Lime, a VPP in the Eagle Ford Shale and the sale of various non-core oil and gas assets, as well as partial monetizations of the company's oilfield services, midstream and/or other assets. The company's monetization program is designed to fully fund the company's 2012 capital expenditure program and reduce the company's long-term debt to the 25/25 Plan goal of $9.5 billion by year-end 2012. Operational Update In response to stronger U.S. oil prices than natural gas prices, during the past four years Chesapeake has substantially shifted its drilling and completion activity to liquids-rich plays. During 2012 and 2013, the company projects that only approximately 16% and 8%, respectively, of its total drilling and completion capital expenditures will be invested in dry natural gas plays. The company continues to achieve strong operational results in its liquids-rich plays, particularly in the key plays highlighted below. Eagle Ford Shale (South Texas):Chesapeake's activities in the Eagle Ford Shale continue to generate strong results as the company further delineates its 475,000 net acre leasehold position. Approximately 30% and 40% of the company's 2012 and 2013 drilling budgets, respectively, have been allocated to the Eagle Ford Shale. The company's production from the play is growing steadily and substantially. Production for the 2012 first quarter averaged approximately 23,000 barrels of oil equivalent (boe) per day, up 35% sequentially compared to the 2011 fourth quarter. Approximately 55% of total Eagle Ford production during the 2012 first quarter was oil, 20% was natural gas liquids (NGL) and 25% was natural gas. Year to date, Chesapeake's gross operated oil production in the Eagle Ford Shale has more than doubled from 25,000 bbls per day at the beginning of 2012 to approximately 55,000 bbls per day at the end of April 2012. The growth has been achieved as a result of increased infrastructure and takeaway capacity as well as improved lateral steering, enhanced stimulation optimization and increased operational efficiencies. During the 2012 first quarter, the company brought on line more than 60 wells, including eight wells with peak rates of more than 1,000 bbls per day of oil. The company has secured pipeline transportation capacity for all of its projected Eagle Ford shale oil production with pipeline projects scheduled to become operational between May 2012 and January 2013 which will enable significant transportation cost savings relative to truck transportation alternatives. During the 2012 first quarter, approximately $150 million of Chesapeake's drilling costs in the Eagle Ford were paid for by its JV partner, CNOOC. Chesapeake is currently operating 35 rigs in the play and plans to average 30 rigs in 2012. Three notable recent wells completed by Chesapeake in the Eagle Ford during the quarter are as follows: The McKenzie D 3H in McMullen County, TX achieved a peak rate of 1,390 bbls of oil, 60 bbls of NGL and 0.6 mmcf of natural gas per day, or approximately 1,540 boe per day; Blakeway Unit B Dim 1H in Dimmit County, TX achieved a peak rate of 1,200 bbls of oil, 90 bbls of NGL and 0.8 mmcf of natural gas per day, or approximately 1,420 boe per day; and The Lazy A Cotulla M 3H in Dimmit County, TX achieved a peak rate of 1,020 bbls of oil, 35 bbls of NGL and 0.3 mmcf of natural gas per day, or approximately 1,115 boe per day. Mississippi Lime (northern Oklahoma, southern Kansas):Chesapeake's approximate 2.0 million net acres of leasehold is the largest position in the Mississippi Lime play. Production for the 2012 first quarter averaged 12,800 boe per day, up 22% sequentially compared to the 2011 fourth quarter. Approximately 40% of total Mississippi Lime production during the 2012 first quarter was oil, 15% was NGL and 45% was natural gas. The company has drilled 130 horizontal producing wells since 2009 with results that have been attractive and consistent. Well costs in the Mississippi Lime play are more than 50% less than typical wells in the Bakken play, resulting in very strong rates of return for the Mississippi Lime Play. The company is currently operating 22 rigs in the play and will maintain that level throughout the remainder of 2012. Chesapeake is currently pursuing a joint venture transaction on its leasehold and expects to announce a transaction in the next few months. Three notable recent wells completed by Chesapeake in the Mississippi Lime during the quarter are as follows: The Rudy 20-26-13 1H in Woods County, OK achieved a peak rate of 325 bbls of oil, 150 bbls of NGL and 2.8 mmcf of natural gas per day, or approximately 950 boe per day; The Leeper Trust 9-25-12 1H in Alfalfa County, OK achieved a peak rate of 525 bbls of oil, 70 bbls of NGL and 2.0 mmcf of natural gas per day, or approximately 930 boe per day; and H J Davis 24-29-10 1H in Alfalfa County, OK achieved a peak rate of 640 bbls of oil, 40 bbls of NGL and 1.2 mmcf of natural gas per day, or approximately 880 boe per day. Utica Shale (eastern Ohio, western Pennsylvania and northwestern West Virginia):Chesapeake's activity level is expected to continue rising as the company develops its most recent large-scale liquids-rich play discovery. The company has approximately 1.3 million acres of leasehold in the play, is currently operating 10 rigs and plans to average 13 rigs in 2012 and 22 rigs in 2013. The company's initial development focus in the play has been in the wet gas window. Chesapeake has drilled a total of 59 wells in the play, of which nine are currently producing, 15 are currently being completed, 15 are waiting on completion and 20 are waiting on pipeline infrastructure. Of the nine producing wells, eight are in the wet gas window of the play. On a post-processing basis, peak rates from the wet gas window of the play have averaged approximately 415 bbls of oil, 260 bbls of NGL and 3.9 mmcf of natural gas per day, or approximately 1,325 boe per day. The company's best Utica well, the Buell 8H in Harrison County, OH had an initial peak rate of more than 3,000 boe per day in September 2011, with roughly half the production from liquids. The Buell well is currently producing at a rate of 1,040 boe per day, and the company believes the well will have an estimated ultimate recovery (EUR) of at least 575,000 bbls of liquids and 13 bcf of natural gas. Three notable recent wells completed by Chesapeake in the Utica are as follows: The Shaw 5H in Carroll County, OH achieved a peak rate of 770 bbls of oil, 180 bbls of NGL and 2.9 mmcf of natural gas per day, or approximately 1,440 boe per day; The Burgett 8H in Carroll County, OH achieved a peak rate of 720 bbls of oil, 140 bbls of NGL and 2.1 mmcf of natural gas per day, or approximately 1,210 boe per day; and The Coniglio 6H in Carroll County, OH in a limited flow test before being shut-in to wait on a pipeline connection achieved a peak rate of 290 bbls of oil and 5.0 mmcf of wet natural gas per day, or approximately 1,125 boe per day at the end of the test. The company has a significant number of wells planned for the Utica oil window during the remainder of 2012 and is confident that it will have strong results based on its successful results in the oilier portion of the wet gas window, preliminary results from oil window testing and the results of certain of its competitors in the oil window. Cleveland and Tonkawa Tight Sand (western Oklahoma, Texas Panhandle):Chesapeake owns approximately 520,000 net acres of leasehold in the Cleveland play and 285,000 net acres in the Tonkawa play. Production for the 2012 first quarter averaged 18,500 boe per day, up 17% sequentially compared to 2011 fourth quarter. Approximately 50% of total Cleveland and Tonkawa production during the quarter was oil, 15% was NGL and 35% was natural gas. The company is currently operating 15 rigs in the area and plans to reduce its activity to 13 rigs in the second half of 2012. Three notable recent wells completed by Chesapeake in the Cleveland Sand during the quarter are as follows: The Lohr 701H in Hemphill County, TX achieved a peak rate of 580 bbls of oil, 850 bbls of NGL and 8.3 mmcf of natural gas per day, or approximately 2,811 boe per day; The Letha 10-19-25 1H in Ellis County, OK achieved a peak rate of 1,460 bbls of oil, 145 bbls of NGL and 1.6 mmcf of natural gas per day, or approximately 1,870 boe per day; and The Shill 3-18-25 1H in Ellis County, OK achieved a peak rate of 1,070 bbls of oil, 130 bbls of NGL and 1.3 mmcf of natural gas per day, or approximately 1,415 boe per day. Three notable recent wells completed by Chesapeake in the Tonkawa Sand during the quarter are as follows: The Roberts 32-16-22 1H in Roger Mills County, OK achieved a peak rate of 1,070 bbls of oil, 130 bbls of NGL and 1.3 mmcf of natural gas per day, or approximately 1,415 boe per day; The Thomas 20-16-23 1H in Ellis County, TX achieved a peak rate of 655 bbls of oil, 80 bbls of NGL and 0.9 mmcf of natural gas per day, or approximately 880 boe per day; and The Washita River USA 15-15-26 1H in Roger Mills County, OK achieved a peak rate of 600 bbls of oil, 21 bbls of NGL and 0.2 mmcf of natural gas per day, or approximately 650 boe per day. Drilling, Completion and Leasehold Capital Expenditures Peak in the 2012 First Quarter, Will Significantly Decline in Remaining Three Quarters of 2012 Chesapeake's 2012 first quarter capital expenditures on proved and unproved drilling and completion activities for operated and non-operated wells totaled $2.5 billion, an increase of approximately $350 million from the 2011 fourth quarter. The 2012 first quarter's capital expenditures were front-end loaded and were primarily attributable to increased and more expensive liquids-rich drilling, the timing lag of oilfield service cost reductions, higher than expected expenditures on non-operated wells and costs associated with ramping down in dry gas plays. The company believes that its drilling and completion expenditures have peaked and projects substantially lower quarterly capital expenditures for the remainder of 2012 and 2013, primarily as a result of the following factors: Substantial reduction of its drilling activity in dry natural gas plays from 50 operated rigs at the beginning of 2012 to an average of 38 rigs in the 2012 first quarter to an average 12 dry natural gas rigs in the second half of 2012, including approximately only two rigs each in the Barnett and Haynesville Shale plays. More aggressively electing out of (nonconsenting) non-operated wells in dry gas plays; Modest reduction of its drilling activity in liquids-rich plays from an average of 123 operated rigs in the 2012 first quarter to an average of approximately 115 rigs in the second half of 2012; Further optimizing drilling programs to achieve more efficient use of drilling capital and fewer wells waiting on completion and pipelines; Completing a joint venture in the Mississippi Lime play in the 2012 third quarter, which will reduce the company's net capital expenditures as a result of an anticipated drilling carry; Selling the company's Permian Basin assets in the 2012 third quarter, which will result in future capital expenditure savings; and Working more aggressively to lower oilfield service costs. As a result of the changes above, the company has revised its capital expenditure budget for drilling and completion costs from $7.0-7.5 billion to $7.5-8.0 billion in 2012 and from $7.5-8.5 billion to $6.5-7.0 billion in 2013, for two-year total drilling capital expenditure savings of $750 million at the midpoint. Of these 2012-2013 capital expenditures, approximately 90% will be directed to liquids-rich plays. During the 2012 first quarter, the company invested approximately $900 million in net leasehold and unproved properties, primarily in the Utica Shale and Mississippi Lime plays. The company has now largely completed its leasing objectives in those two areas and anticipates substantially reduced leasehold investment going forward. The company projects investing approximately $700 million in net leasehold and unproved properties for the balance of 2012 and approximately $500 million in 2013, for two-year total leasehold capital expenditure savings of approximately $425 million at the midpoint. Combined drilling and leasehold capital expenditure savings for 2012-2013 should therefore be approximately $1.175 billion relative to the company's previous Outlook dated February 21, 2012. 2012 First Quarter Financial and Operational Results Conference Call Information A conference call to discuss this release has been scheduled for Wednesday, May 2, 2012 at 9:00 am EDT. The telephone number to access the conference call is 913-312-0640 or toll-free 888-278-8476. The passcode for the call is 4138928. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EDT. For those unable to participate in the conference call, a replay will be available for audio playback at 1:00 pm EDT on Wednesday, May 2, 2012 and will run through midnight Wednesday, May 16, 2012. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 4138928. 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. This news release and the accompanying Outlooks include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.Forward-looking statements are statements other than statements of historical fact and give our current expectations or forecasts of future events.They include estimates of natural gas and oil reserves and resources, projected production and operating costs, projected drilling and completion expenditures and leasehold investment, anticipated asset sales and related proceeds, projected cash flow and liquidity, business strategy and other plans and objectives for future operations.Disclosures concerning the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date.These market prices 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 Item 1A of our 2011 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 29, 2012.These risk factors include the volatility of natural gas and oil prices and the adverse effect of lower prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including through 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 oil 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 oil 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; general economic conditions negatively impacting us and our business counterparties; oilfield services shortages and transportation capacity constraints and interruptions that could adversely affect our cash flow; and losses possible from 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 oil 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 oil 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.Chesapeake Energy Corporation (NYSE:CHK) 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 Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime, Bone Spring, Avalon, Wolfcamp, Wolfberry and Niobrara unconventional liquids plays. The company has also vertically integrated its operations and owns substantial marketing, midstream and oilfield services businesses directly and indirectly through its subsidiaries Chesapeake Energy Marketing, Inc., Chesapeake Midstream Development, L.P. and Chesapeake Oilfield Services, L.L.C. and its affiliate Chesapeake Midstream Partners, L.P. (NYSE:CHKM). Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.         CHESAPEAKE ENERGY CORPORATIONCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS($ in millions, except per-share and unit data)(unaudited)               THREE MONTHS ENDED:March 31,March 31,   2012       2011$     $/mcfe$     $/mcfeREVENUES:Natural gas and liquids 1,068 3.21 494 1.77 Marketing, gathering and compression 1,216 3.65 1,017 3.64 Oilfield services   135   0.41     101   0.36   Total Revenues   2,419   7.27     1,612   5.77     OPERATING EXPENSES:Natural gas and oil production 349 1.05 238 0.85 Production taxes 47 0.14 45 0.16 Marketing, gathering and compression 1,197 3.60 985 3.53 Oilfield services 96 0.29 77 0.28 General and administrative 136 0.41 130 0.46 Natural gas and liquids depreciation, depletion and amortization 506 1.52 358 1.28 Depreciation and amortization of other assets 84 0.25 68 0.24 (Gains) losses on sales of fixed assets   (2 ) (0.01 )   (5 ) (0.02 ) Total Operating Expenses   2,413   7.25     1,896   6.78     INCOME (LOSS) FROM OPERATIONS   6   0.02     (284 ) (1.01 )   OTHER INCOME (EXPENSE):Interest expense (12 ) (0.04 ) (7 ) (0.03 ) Earnings (losses) on investments (5 ) (0.02 ) 25 0.09 Losses on purchases or exchanges of debt — — (2 ) (0.01 ) Other income   6   0.02     2   0.01   Total Other Income (Expense)   (11 ) (0.04 )   18   0.06     INCOME (LOSS) BEFORE INCOME TAXES (5 ) (0.02 ) (266 ) (0.95 )   INCOME TAX EXPENSE (BENEFIT):Current income taxes — — 6 0.02 Deferred income taxes   (2 ) (0.01 )   (110 ) (0.39 ) Total Income Tax Expense (Benefit)   (2 ) (0.01 )   (104 ) (0.37 )   NET INCOME (LOSS) (3 ) (0.01 ) (162 ) (0.58 )   Net income attributable to noncontrolling interests   (25 ) (0.07 )   —   —     NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE   (28 ) (0.08 )   (162 ) (0.58 )   Preferred stock dividends   (43 ) (0.13 )   (43 ) (0.15 )   NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS   (71 ) (0.21 )   (205 ) (0.73 )   EARNINGS (LOSS) PER COMMON SHARE:Basic $ (0.11 ) $ (0.32 ) Diluted $ (0.11 ) $ (0.32 )   WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):Basic   642     634   Diluted   642     634           CHESAPEAKE ENERGY CORPORATIONCONDENSED CONSOLIDATED BALANCE SHEETS($ in millions)(unaudited)             March 31,December 31,     2012     2011   Cash and cash equivalents $ 438 $ 351 Other current assets   3,486   2,826 Total Current Assets   3,924   3,177   Property and equipment (net) 39,616 36,739 Other assets   2,049   1,919 Total Assets $ 45,589 $ 41,835   Current liabilities $ 6,664 $ 7,082 Long-term debt, net of discounts 13,082 10,626 Other long-term liabilities 2,965 2,682 Deferred tax liability   3,984   3,484 Total Liabilities   26,695   23,874   Chesapeake stockholders' equity 16,521 16,624 Noncontrolling interests   2,373   1,337 Total Equity   18,894   17,961   Total Liabilities and Equity $ 45,589 $ 41,835   Common Shares Outstanding (in millions)   662   659         CHESAPEAKE ENERGY CORPORATIONCAPITALIZATION($ in millions)(unaudited)             March 31,December 31,     2012     2011   Total debt, net of unrestricted cash $ 12,644 $ 10,275 Chesapeake stockholders' equity 16,521 16,624 Noncontrolling interests(a)   2,373     1,337   Total $ 31,538   $ 28,236     Debt to capitalization ratio 40 % 36 %   (a) Includes third-party ownership as follows:   CHK C-T, L.L.C. $ 1,025 $ — CHK Utica, L.L.C. 950 950 Chesapeake Granite Wash Trust 367 380 Cardinal Gas Services, L.L.C.   31     7   Total $ 2,373   $ 1,337         CHESAPEAKE ENERGY CORPORATIONRECONCILIATION OF 2012 FIRST QUARTER ADDITIONS TO NATURAL GAS AND OIL PROPERTIESBASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT MARCH 31, 2012($ in millions, except per-unit data)(unaudited)                 Proved ReservesCost     Bcfe(a)$/McfePROVED PROPERTIES:Well costs on proved properties(b) $ 2,159 1,816 (c) 1.19 Acquisition of proved properties 5 8 0.61 Sale of proved properties   (783 ) (159 ) 4.92 Total net proved properties   1,381   1,665   0.83   Revisions – price — (300 ) —   UNPROVED PROPERTIES:Well costs on unproved properties 321 — — Acquisition of unproved properties, net 919 — — Sale of unproved properties   (56 ) —   — Total net unproved properties   1,184   —   —   OTHER:Capitalized interest on unproved properties 186 — — Geological and geophysical costs 67 — — Asset retirement obligations   7   —   — Total other   260   —   —   Total $ 2,825   1,365   2.07     CHESAPEAKE ENERGY CORPORATIONROLL-FORWARD OF PROVED RESERVESTHREE MONTHS ENDED MARCH 31, 2012BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT MARCH 31, 2012(unaudited)           Bcfe(a)Beginning balance, January 1, 2012 18,789 Production (333 ) Acquisitions 8 Divestitures (159 ) Revisions – changes to previous estimates 342 Revisions – price (300 ) Extensions and discoveries   1,474   Ending balance, March 31, 2012   19,821     Proved reserves growth rate before acquisitions and divestitures 6.3 % Proved reserves growth rate after acquisitions and divestitures 5.5 %   Proved developed reserves 10,621 Proved developed reserves percentage 53.6 %   PV-10 ($ in billions)(a) $ 20,634   (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 March 31, 2012 of $3.73 per mcf of natural gas and $98.25 per bbl of oil, before field differential adjustments. (b) Net of well cost carries of $448 million associated with the Statoil-Marcellus, CNOOC-Eagle Ford, CNOOC-Niobrara and Total-Utica joint ventures. (c) Includes 342 bcfe of positive revisions resulting from changes to previous estimates and excludes downward revisions of 300 bcfe resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended March 31, 2012, compared to the twelve months ended December 31, 2011.       CHESAPEAKE ENERGY CORPORATIONRECONCILIATION OF 2012 FIRST QUARTER ADDITIONS TO NATURAL GAS AND OIL PROPERTIESBASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT MARCH 31, 2012($ in millions, except per-unit data)(unaudited)                 Proved ReservesCost     Bcfe(a)$/McfePROVED PROPERTIES:Well costs on proved properties(b) $ 2,159 1,692 (c) 1.28 Acquisition of proved properties 5 8 0.61 Sale of proved properties   (783 ) (159 ) 4.92 Total net proved properties   1,381   1,541   0.90   Revisions – price — (204 ) —   UNPROVED PROPERTIES:Well costs on unproved properties 321 — — Acquisition of unproved properties, net 919 — — Sale of unproved properties   (56 ) —   — Total net unproved properties   1,184   —   —   OTHER:Capitalized interest on unproved properties 186 — — Geological and geophysical costs 67 — — Asset retirement obligations   7   —   — Total other   260   —   —   Total $ 2,825   1,337   2.11     CHESAPEAKE ENERGY CORPORATIONROLL-FORWARD OF PROVED RESERVESTHREE MONTHS ENDED MARCH 31, 2012BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT MARCH 31, 2012(unaudited)       Bcfe(a)Beginning balance, January 1, 2012 19,887 Production (333 ) Acquisitions 8 Divestitures (159 ) Revisions – changes to previous estimates (233 ) Revisions – price (204 ) Extensions and discoveries   1,926   Ending balance, March 31, 2012   20,892     Proved reserves growth rate before acquisitions and divestitures 5.8 % Proved reserves growth rate after acquisitions and divestitures 5.1 %   Proved developed reserves 11,187 Proved developed reserves percentage 53.5 %   PV-10 ($ in billions)(a) $ 24,699   (a)   Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and 10-year average NYMEX strip prices as of March 31, 2012 of $4.65 per mcf of natural gas and $94.54 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 $448 million associated with the Statoil-Marcellus, CNOOC-Eagle Ford, CNOOC-Niobrara and Total-Utica joint ventures. (c) Includes 233 bcfe of downward revisions resulting from changes to previous estimates and excludes downward revisions of 204 bcfe resulting from lower natural gas prices using 10-year average NYMEX strip prices as of March 31, 2012, compared to December 31, 2011.         CHESAPEAKE ENERGY CORPORATIONSUPPLEMENTAL DATA – NATURAL GAS AND LIQUIDS SALES AND INTEREST EXPENSE(unaudited)             March 31,March 31,THREE MONTHS ENDED:   2012     2011   Natural Gas and Liquids Sales ($ in millions): Natural gas sales $ 478 $ 788 Natural gas derivatives – realized gains (losses) 158 505 Natural gas derivatives – unrealized gains (losses)   (147 )   (549 )   Total Natural Gas Sales   489     744     Liquids sales 743 400 Oil derivatives – realized gains (losses) (41 ) (17 ) Oil derivatives – unrealized gains (losses)   (123 )   (633 )   Total Liquids Sales   579     (250 )   Total Natural Gas and Liquids Sales $ 1,068   $ 494     Average Sales Price – excluding gains (losses) on derivatives: Natural gas ($ per mcf) $ 1.77 $ 3.24 Liquids ($ per bbl) $ 71.91 $ 66.08 Natural gas equivalent ($ per mcfe) $ 3.67 $ 4.25   Average Sales Price – excluding unrealized gains (losses) on derivatives: Natural gas ($ per mcf) $ 2.35 $ 5.31 Liquids ($ per bbl) $ 67.92 $ 63.20 Natural gas equivalent ($ per mcfe) $ 4.02 $ 5.99   Interest Expense (Income) ($ in millions): Interest (a) $ 8 $ 8 Derivatives – realized (gains) losses — (7 ) Derivatives – unrealized (gains) losses   4     6   Total Interest Expense $ 12   $ 7     (a)   Net of amounts capitalized.         CHESAPEAKE ENERGY CORPORATIONCONDENSED CONSOLIDATED CASH FLOW DATA($ in millions)(unaudited)             THREE MONTHS ENDED:March 31,March 31,   2012     2011   Beginning cash $ 351   $ 102     Cash provided by operating activities   251     718     Cash flows from investing activities:Well costs on proved properties (2,182 ) (1,593 ) Well costs on unproved properties (321 ) (28 ) Acquisition of proved properties (5 ) (18 ) Acquisition of unproved properties, net (1,079 ) (1,016 ) Sale of proved properties 744 1,774 Sale of unproved properties 59 3,184 Geological and geophysical costs (71 ) (71 ) Investments, net (73 ) 4 Other property and equipment, net (642 ) (3 ) Other   (47 )   (7 ) Total cash provided by (used in) investing activities   (3,617 )   2,226     Cash provided by (used in) financing activities   3,453     (2,197 )   Ending cash $ 438   $ 849               CHESAPEAKE ENERGY CORPORATIONRECONCILIATION OF OPERATING CASH FLOW AND EBITDA($ in millions)(unaudited)                   THREE MONTHS ENDED:March 31,December 31,March 31,   2012     2011     2011   CASH PROVIDED BY OPERATING ACTIVITIES $ 251 $ 2,179 $ 718   Changes in assets and liabilities   659     (868 )   663     OPERATING CASH FLOW(a) $ 910   $ 1,311   $ 1,381                       THREE MONTHS ENDED:March 31,December 31,March 31,   2012     2011     2011   NET INCOME (LOSS) $ (3 ) $ 487 $ (162 )   Income tax expense (benefit) (2 ) 312 (104 ) Interest expense 12 7 7 Depreciation and amortization of other assets 84 85 68 Natural gas and liquids depreciation, depletion and amortization   506     484     358     EBITDA(b) $ 597   $ 1,375   $ 167                       THREE MONTHS ENDED:March 31,December 31,March 31,   2012     2011     2011   CASH PROVIDED BY OPERATING ACTIVITIES $ 251 $ 2,179 $ 718   Changes in assets and liabilities 659 (868 ) 663 Interest expense 12 7 7 Unrealized gains (losses) on natural gas and oil derivatives (270 ) (345 ) (1,182 ) Gains (losses) on sales and impairments of fixed assets 2 397 5 Gains (losses) on investments (33 ) 22 5 Stock-based compensation (32 ) (34 ) (40 ) Other items   8     17     (9 )   EBITDA(b) $ 597   $ 1,375   $ 167     (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 CORPORATIONRECONCILIATION OF ADJUSTED EBITDA($ in millions)(unaudited)                   March 31,December 31,March 31,THREE MONTHS ENDED:   2012     2011     2011   EBITDA $ 597 $ 1,375 $ 167   Adjustments:Unrealized (gains) losses on natural gas and oil derivatives 270 345 1,182 (Gains) losses on sales and impairments of fixed assets (2 ) (397 ) (5 ) Net income attributable to noncontrolling interests (25 ) (15 ) — Losses on purchases or exchanges of debt — — 2 Other   (2 )   —     —     Adjusted EBITDA(a) $ 838   $ 1,308   $ 1,346     (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 CORPORATIONRECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS($ in millions, except per-share data)(unaudited)                   March 31,December 31,March 31,THREE MONTHS ENDED:   2012     2011     2011   Net income (loss) available to common stockholders $ (71 ) $ 429 $ (205 )   Adjustments, net of tax:Unrealized (gains) losses on derivatives 167 207 725 (Gains) losses on sales and impairments of fixed assets (1 ) (242 ) (3 ) Losses on purchases or exchanges of debt — — 1 Other   (1 )   —     —     Adjusted net income available to common stockholders(a) 94 394 518 Preferred stock dividends   43     43     43   Total adjusted net income $ 137   $ 437   $ 561     Weighted average fully diluted shares outstanding(b) 752 750 750   Adjusted earnings per share assuming dilution(a) $ 0.18   $ 0.58   $ 0.75     (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 May 1, 2012 Our policy is to periodically provide guidance on certain factors that affect our future financial performance. The primary changes from our February 21, 2012 Outlook are in italicized bold and reflect projected voluntary natural gas curtailments of 60-100 bcf in 2012 and includes the estimated production decreases of approximately 60 bcfe in 2012 and 90 bcfe in 2013 associated with potential Permian Basin, Mississippi Lime, VPP and other monetization transactions. Chesapeake Energy Corporation Consolidated ProjectionsFor Years Ending December 31, 2012 and 2013         Year Ending12/31/12Year Ending12/31/13 Estimated Production: Natural gas – bcf 1,040 – 1,060970 – 1,010 Liquids – mbbls 41,000 – 43,00055,000 – 59,000 Natural gas equivalent – bcfe 1,286 – 1,3181,300 – 1,364   Daily natural gas equivalent midpoint – mmcfe 3,5553,650   Year over year (YOY) estimated production increase excluding asset sales 17%7% YOY estimated production increase 9%2%   NYMEX Price(a) (for calculation of realized hedging effects only): Natural gas - $/mcf $2.50$3.50 Oil - $/bbl $100.73 $100.00   Estimated Realized Hedging Effects (based on assumed NYMEX prices above): Natural gas - $/mcf $0.35 $0.02 Liquids - $/bbl ($4.69)($1.03)   Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: Natural gas - $/mcf $0.90 – $1.00 $0.90 – $1.00 Liquids - $/bbl(b)$30.00 – $35.00$25.00 – $30.00   Operating Costs per Mcfe of Projected Production: Production expense $0.95 – 1.05$0.95 – 1.05 Production taxes (~ 5% of O&G revenues) $0.15 – 0.20$0.25 – 0.30 General and administrative(c) $0.39 – 0.44 $0.39 – 0.44 Stock-based compensation (noncash) $0.04 – 0.06 $0.04 – 0.06 DD&A of natural gas and liquids assets $1.40 – 1.60 $1.50 – 1.70 Depreciation of other assets $0.25 – 0.30 $0.30 – 0.35 Interest expense(d) $0.05 – 0.10 $0.05 – 0.10   Other ($ millions): Marketing, gathering and compression net margin(e)$70 – 80$85 – 95 Oilfield services net margin(e) $200 – 250 $300 – 400 Other income (including certain equity investments) $75 – 100 $125 – 175 Net income attributable to noncontrolling interest(f) ($180) – (200) ($200) – (240)   Book Tax Rate 39% 39%   Weighted average shares outstanding (in millions): Basic 640 – 645 645 – 650 Diluted 753 – 758 758 – 763       Year Ending12/31/12Year Ending12/31/13($ millions) Operating cash flow before changes in assets and liabilities(g)(h)$2,700 – 3,000$4,400 – 5,300   Well costs on proved properties ($6,500 – 7,000)($5,500 – 6,000) Well costs on unproved properties ($1,000) ($1,000) Acquisition of unproved properties, net ($1,600)($500) Sale of proved and unproved properties $9,500 – 11,000$4,500 – 5,000 Subtotal of net investment in proved and unproved properties $400 – 1,400($2,500)   Investment in oilfield services, midstream and other ($2,500 – 3,500) ($2,000 – 2,500) Monetization of oilfield services, midstream and other assets $2,000 – 3,000 $1,000 – 1,500 Subtotal of net investment in oilfield services, midstream and other ($500) ($1,000)   Interest, dividends and cash taxes ($1,000 – 1,250) ($1,000 – 1,250)     Total budgeted cash flow surplus (deficit) $1,600 – 2,650($100) – $550   (a)   NYMEX natural gas prices have been updated for actual contract prices through May 2012 and NYMEX oil prices have been updated for actual contract prices through March 2012. (b) Differentials include effects of natural gas liquids. (c) Excludes expenses associated with noncash 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 interests of Chesapeake Granite Wash Trust, CHK Utica Preferred Interest and Cleveland/Tonkawa Preferred Interest. (g) A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities. (h) Assumes NYMEX prices on open contracts of $2.25 to $2.75 per mcf and $100.00 per bbl in 2012 and $3.00 to $4.00 per mcf and $100.00 per bbl in 2013.   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 commodity 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 May 1, 2012, the company does not have any open natural gas swaps in place. The company currently has $13 million of net hedging losses related to closed natural gas contracts and premiums for call options for future production periods.     Open Swaps(bcf)   Avg. NYMEXPrice ofOpen Swaps   ForecastedNatural GasProduction(bcf)   Open SwapPositionsas a % ofForecastedNatural GasProduction   Total Gains(Losses) fromClosed Tradesand Premiumsfor Call Options($ in millions)   Total Gains fromClosed Tradesand Premiumsfor Call Optionsper mcf ofForecastedNatural GasProduction Q2 2012           $ 195   Q3 2012 32 Q4 2012                     15       Q2-Q4 2012   0   $ 0.00   779   0 %   $242     $0.31                           Total 2013   0   $ 0.00   990   0 %   $20     $ 0.02 Total 2014   0               $(34)     Total 2015   0               $(110)     Total 2016 – 2022   0               $(131)       The company currently has the following natural gas written call options in place for 2012 through 2020:     Call Options(bcf)   Avg. NYMEX Strike Price   Forecasted Natural Gas Production (bcf)   Call Options as a % of Forecasted Natural Gas Production Q2 2012   13   $ 6.54     Q3 2012 40 6.54 Q4 2012   41     6.54         Q2-Q4 2012   94   $ 6.54   779   12% Total 2013   415   $ 6.44   990   42% Total 2014   330   $ 6.43         Total 2015   116   $ 6.45         Total 2016 – 2020   349   $ 8.18           The company has the following natural gas basis protection swaps in place for 2012 through 2022:     Volume (Bcf)     Avg. NYMEX less 2012 49$0.79 2013 44 $ 0.21 2014 - 2022 67 $ 0.42 Totals 160 $ 0.47   At May 1, 2012, the company has the following open crude oil swaps in place for 2012 and through 2015. In addition, the company has $105 million of net hedging gains related to closed crude oil contracts and premiums for call options for future production periods.     Open Swaps (mbbls)   Avg. NYMEX Price of Open Swaps   Forecasted Liquids Production (mbbls)   Open Swap Positions as a % of Forecasted Liquids Production   Total Gains (Losses) from Closed Trades and Premiumsfor Call Options($millions)   Total Gains(Losses) fromClosed Tradesand Premiums forCall Options perbbl of ForecastedLiquidsProduction Q2 2012   7,285   $102.58       $(52)   Q3 2012 6,178103.45(67) Q4 2012   5,680     103.13             (75)     Q2-Q4 2012(a)   19,143   $103.02   31,666   60%   $(194)   $(6.14)                           Total 2013   4,947   $102.86   57,000   9%   $24     $0.41   Total 2014   902   $90.72           $(106)     Total 2015   500   $ 88.75           $265       Total 2016 – 2021                   $116         (a)   Certain hedging contracts include knockout swaps with provisions limiting the counterparty's exposure below prices of $60.00 covering 550 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 Q2 2012   -   -     Q3 2012 1,840 $ 106.38 Q4 2012   2,300     106.45         Q2-Q4 2012   4,140   $106.42   31,666   13%                   Total 2013   24,953   $ 96.88   57,000   44% Total 2014   23,620   $ 98.62         Total 2015   27,048   $ 100.99         Total 2016 – 2017   24,220   $ 100.07         SCHEDULE “B”CHESAPEAKE'S OUTLOOK AS OF FEBRUARY 21, 2012(PROVIDED FOR REFERENCE ONLY)NOW SUPERSEDED BY OUTLOOK AS OF MAY 1, 2012 Our policy is to periodically provide guidance on certain factors that affect our future financial performance. The primary changes from our November 3, 2011 Outlook are in italicized bold and reflect projected natural gas curtailments of approximately 130 bcf in 2012 and exclude the production effects of potential Mississippi Lime and Permian Basin transactions. Chesapeake Energy Corporation Consolidated ProjectionsFor Years Ending December 31, 2012 and 2013         Year Ending12/31/12Year Ending12/31/13 Estimated Production: Natural gas – bcf 950 – 990 1,020 – 1,060 Liquids – mbbls 53,000 – 57,000 74,000 – 78,000 Natural gas equivalent – bcfe 1,268 – 1,3321,464 – 1,528   Daily natural gas equivalent midpoint – mmcfe 3,5504,100   Year over year (YOY) estimated production increase excluding asset sales 12%20% YOY estimated production increase 9%15%   NYMEX Price(a) (for calculation of realized hedging effects only): Natural gas - $/mcf $3.40$5.00 Oil - $/bbl $100.03 $100.00   Estimated Realized Hedging Effects (based on assumed NYMEX prices above): Natural gas - $/mcf $0.37 $0.02 Liquids - $/bbl $(2.99)$(0.76)   Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: Natural gas - $/mcf $0.90 – $1.00$0.90 – $1.00 Liquids - $/bbl(b) $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 Production taxes (~ 5% of O&G revenues) $0.20 – 0.25 $0.30 – 0.35 General and administrative(c) $0.39 – 0.44 $0.39 – 0.44 Stock-based compensation (noncash) $0.04 – 0.06 $0.04 – 0.06 DD&A of natural gas and liquids assets $1.40 – 1.60 $1.50 – 1.70 Depreciation of other assets $0.25 – 0.30 $0.30 – 0.35 Interest expense(d) $0.05 – 0.10 $0.05 – 0.10   Other ($ millions): Marketing, gathering and compression net margin(e)$100 – 110$125 – 135 Oilfield services net margin(e)$200 – 250$300 – 400 Other income (including equity investments) $125 – 175$125 – 175 Net income attributable to noncontrolling interest(f)($180) – (200)($200) – (240)   Book Tax Rate 39% 39%   Weighted average shares outstanding (in millions): Basic 640 – 645 645 – 650 Diluted 753 – 758 758 – 763       Year Ending12/31/12Year Ending12/31/13($ millions) Operating cash flow before changes in assets and liabilities(g)(h)$4,500 – 5,200$7,500 – 8,500   Well costs on proved properties ($6,000 – 6,500)($6,500 – 7,500) Well costs on unproved properties ($1,000)($1,000) Acquisition of unproved properties, net ($1,400)($1,000 – 1,250) Sale of proved and unproved properties $8,000 – 10,000$3,000 – 4,000 Subtotal of net investment in proved and unproved properties ($400) – 1,100($5,500 – 5,750)   Investment in oilfield services, midstream and other ($2,500 – 3,500)($2,000 – 2,500) Monetization of oilfield services, midstream and other assets $2,000$1,000 – 1,500 Subtotal of net investment in oilfield services, midstream and other ($500 – 1,500)($1,000)   Interest and dividends ($1,000 –1,250)($1,000 – 1,250)     Total budgeted cash flow surplus (deficit) $2,600 – 3,550$0 – 500   (a)   NYMEX natural gas prices have been updated for actual contract prices through February 2012 and NYMEX oil prices have been updated for actual contract prices through January 2012. (b) Differentials include effects of natural gas liquids. (c) Excludes expenses associated with noncash 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 interests of Chesapeake Granite Wash Trust, CHK Utica Preferred Interest and potential Cleveland/Tonkawa Preferred Interest. (g) A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities. (h) Assumes NYMEX prices on open contracts of $3.00 to $4.00 per mcf and $100.00 per bbl in 2012 and $4.50 to $5.50 per mcf and $100.00 per bbl in 2013.   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 February 21, 2012, the company does not have any open natural gas swaps in place. The company currently has $176 million of net hedging gains related to closed natural gas contracts and premiums for call options for future production periods.     Open Swaps(bcf)   Avg. NYMEX Price of Open Swaps   Forecasted Natural Gas Production (bcf)   Open Swap Positions as a % of Forecasted Natural Gas Production   Total Gains(Losses) fromClosed Tradesand Premiumsfor Call Options($ in millions)   Total Gains fromClosed Tradesand Premiumsfor Call Optionsper mcf ofForecastedNatural GasProduction Q1 2012           158   Q2 2012 195 Q3 2012 32 Q4 2012                     15       Total 2012   0   $ 0.00   970   0 %   $ 400     $0.41                           Total 2013   0   $ 0.00   1,040   0 %   $ 21     $ 0.02 Total 2014   0               $ (32 )     Total 2015   0               $(103)     Total 2016 – 2022   0               $(110)       The company currently has the following natural gas written call options in place for 2012 through 2020:     Call Options(bcf)   Avg. NYMEX Strike Price   Forecasted Natural Gas Production (bcf)   Call Options as a % of Forecasted Natural Gas Production 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   970   17% Total 2013   415   $ 6.44   1,040   40 % Total 2014   330   $ 6.43         Total 2015   116   $6.45         Total 2016 – 2020   349   $8.18           The company has the following natural gas basis protection swaps in place for 2012 through 2022:     Volume (Bcf)     Avg. NYMEX less 2012 51$0.78 2013 44$0.21 2014 - 2022 67$0.42 Totals 162$0.47   At February 21, 2012, the company has the following open crude oil swaps in place for 2012 and through 2015. In addition, the company has $105 million of net hedging gains related to closed crude oil contracts and premiums for call options for future production periods.     Open Swaps (mbbls)   Avg. NYMEX Price of Open Swaps   Forecasted Liquids Production (mbbls)   Open Swap Positions as a % of Forecasted Liquids Production   Total Gains(Losses) fromClosed Tradesand Premiumsfor Call Options($millions)   Total Gains(Losses) fromClosed Tradesand Premiums forCall Options perbbl of ForecastedLiquidsProduction Q1 2012   5,829   101.70       (26)   Q2 2012 6,871102.27(51) Q3 2012 5,835103.16(65) Q4 2012   5,383     102.85             (74)     Total 2012(a)   23,918   $102.48   55,000   43%   $(216)   $ (3.93 )                           Total 2013   4,024   $102.59   76,000   5%   $ 26     $0.35   Total 2014   713   $ 88.27           $(104)     Total 2015   500   $ 88.75           $267       Total 2016 – 2021                   $ 132         (a)   Certain hedging contracts include knockout swaps with provisions limiting the counterparty's exposure below prices of $60.00 covering 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 Q1 2012   1,224   100.00     Q2 2012 - - Q3 2012 1,840106.38 Q4 2012   2,300     106.45         Total 2012   5,364   $104.95   55,000   10%                   Total 2013   24,953   $96.88   76,000   33% Total 2014   23,620   $98.62         Total 2015   27,048   $100.99         Total 2016 – 2017   24,220   $ 100.07         Chesapeake Energy CorporationInvestor Contacts:Jeffrey L. Mobley, CFA, 405-767-4763jeff.mobley@chk.comorJohn J. Kilgallon, 405-935-4441john.kilgallon@chk.comorMedia Contacts:Michael Kehs, 405-935-2560michael.kehs@chk.comorJim Gipson, 405-935-1310jim.gipson@chk.com