News Column

CHESAPEAKE ENERGY CORP - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

May 7, 2014

Financial Data The following table sets forth certain information regarding our production volumes, natural gas, oil and natural gas liquids (NGL) sales, average sales prices received, other operating income and expenses for the periods indicated: Three Months Ended March 31, 2014 2013 Net Production: Natural gas (bcf) 260.0 273.1 Oil (mmbbl) 9.9 9.3 NGL (mmbbl) 7.6 4.9 Oil equivalent (mmboe)(a) 60.8 59.7 Natural Gas, Oil and NGL Sales ($ in millions): Natural gas sales $ 1,005$ 573 Natural gas derivatives - realized gains (losses)(b) (154 ) 8 Natural gas derivatives - unrealized gains (losses)(b) (154 ) (278 ) Total natural gas sales 697 303 Oil sales 922 884 Oil derivatives - realized gains (losses)(b) (84 ) (4 ) Oil derivatives - unrealized gains (losses)(b) 10 132 Total oil sales 848 1,012 NGL sales 221 138 NGL derivatives - realized gains (losses)(b) - - NGL derivatives - unrealized gains (losses)(b) - - Total NGL sales 221 138 Total natural gas, oil and NGL sales $ 1,766



$ 1,453

Average Sales Price (excluding gains (losses) on derivatives): Natural gas ($ per mcf) $ 3.86$ 2.10 Oil ($ per bbl) $ 93.60$ 95.23 NGL ($ per bbl) $ 29.23$ 28.25 Oil equivalent ($ per boe) $ 35.35$ 26.71 Average Sales Price (including realized gains (losses) on derivatives): Natural gas ($ per mcf) $ 3.27$ 2.13 Oil ($ per bbl) $ 85.08$ 94.85 NGL ($ per bbl) $ 29.23$ 28.25 Oil equivalent ($ per boe) $ 31.44$ 26.79 53

--------------------------------------------------------------------------------

Three Months Ended March 31, 2014 2013 Other Operating Income(c) ($ in millions): Marketing, gathering and compression net margin $ 35$ 36 Oilfield services net margin $ 45$ 35 Expenses ($ per boe): Natural gas, oil and NGL production $ 4.73$ 5.14 Production taxes $ 0.83$ 0.89 General and administrative(d) $ 1.30



$ 1.84 Natural gas, oil and NGL depreciation, depletion and amortization

$ 10.33$ 10.86 Depreciation and amortization of other assets $ 1.29$ 1.31 Interest expense(e) $ 0.90$ 0.25 Interest Expense ($ in millions): Interest expense $ 58$ 17 Interest rate derivatives - realized (gains) losses(f) (3 ) (2 ) Interest rate derivatives - unrealized (gains) losses(f) (16 ) 6 Total interest expense $ 39$ 21



___________________________________________

(a) Oil equivalent is based on six mcf of natural gas to one barrel of oil or one

barrel of NGL. This ratio reflects an energy content equivalency and not a

price or revenue equivalency. In recent years, the price for a bbl of oil and

NGL has been significantly higher than the price for six mcf of natural gas.

(b) Realized gains and losses include the following items: (i) settlements of

non-designated derivatives related to current period production revenues,

(ii) prior period settlements for option premiums and for early-terminated

derivatives originally scheduled to settle against current period production

revenues, and (iii) gains and losses related to de-designated cash flow

hedges originally designated to settle against current period production

revenues. Unrealized gains and losses include the change in fair value of

open derivatives scheduled to settle against future period production

revenues offset by amounts reclassified as realized gains and losses during

the period.

(c) Includes revenue and operating costs. See Depreciation and Amortization of

Other Assets under Results of Operations for details of the depreciation and

amortization associated with our marketing, gathering, and compression and

oilfield services operating segments.

(d) Includes stock-based compensation but excludes restructuring and other

termination costs.

(e) Includes the effects of realized (gains) losses from interest rate

derivatives, excludes the effects of unrealized (gains) losses from interest

rate derivatives and is net of amounts capitalized.

(f) Realized (gains) losses include settlements related to the current period

interest accrual and the effect of (gains) losses on early terminated trades.

Settlements of early-terminated trades are reflected in realized (gains)

losses over the original life of the hedged item. Unrealized (gains) losses

include changes in the fair value of open interest rate derivatives offset by

amounts reclassified to realized (gains) losses during the period. 54

--------------------------------------------------------------------------------



Overview

Chesapeake is currently the second-largest producer of natural gas and the tenth-largest producer of liquids in the United States. We own interests in approximately 47,400 natural gas and oil wells that produced an average of approximately 675 mboe per day in the Current Quarter, net to our interest. We have a large and geographically diverse resource base of onshore U.S. unconventional natural gas and liquids assets. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas; the Utica Shale in Ohio and Pennsylvania; the Granite Wash/Hogshooter, Cleveland, Tonkawa and Mississippi Lime plays in the Anadarko Basin in northwestern Oklahoma, the Texas Panhandle and southern Kansas; and the Niobrara Shale in the Powder River Basin in Wyoming. Our core natural gas resource plays are the Haynesville/Bossier Shales in northwestern Louisiana and East Texas; the Marcellus Shale in the northern Appalachian Basin of West Virginia and Pennsylvania; and the Barnett Shale in the Fort Worth Basin of north-central Texas. We also own substantial marketing, compression and oilfield services businesses. Our Strategy With substantial leasehold positions in most of the premier U.S. onshore resource plays, Chesapeake is focused on finding and producing hydrocarbons in a responsible and efficient manner that seeks to maximize shareholder returns. We are committed to increasing our profitability and decreasing our financial complexity through the execution of our business strategy, which consists of two fundamental tenets: financial discipline and profitable and efficient growth from captured resources. We are applying financial discipline to all aspects of our business, with the primary goals of balancing capital expenditures with cash flow from operations, divesting noncore assets and affiliates, achieving investment grade metrics, lowering our per unit costs, and reducing financial and operational risk and complexity while we continue responsible environmental stewardship. As a result of our focus on financial discipline, average per unit production expenses during the Current Quarter decreased 8% from the Prior Quarter, while general and administrative expenses (excluding stock-based compensation and restructuring and other termination costs) decreased 27%. The Company's substantial inventory of hydrocarbon resources provides a strong foundation for future growth. We believe that focusing on profitable and efficient growth from our captured resources will allow us to deliver attractive financial returns through all phases of the commodity price cycle. We have seen and continue to see increased efficiencies through our leveraging of first-well investments made in prior periods, including drilling on pre-existing pads. We also have a competitive capital allocation process designed to optimize our asset portfolio and identify the highest quality projects for future investment. To better understand our opportunities for continuous improvement, we benchmark our performance against that of our peers and evaluate the performance of completed projects. We also pay careful attention to safety, regulatory compliance and environmental stewardship measures while executing our business strategy. 55 -------------------------------------------------------------------------------- Operating Results Our Current Quarter production of 61 mmboe consisted of 260 bcf of natural gas (71% on an oil equivalent basis), 10 mmbbls of oil (16% on an oil equivalent basis) and 8 mmbbls of NGL (13% on an oil equivalent basis). Liquids represented 29% of total production for the Current Quarter, up from 24% in the Prior Quarter. Our daily production for the Current Quarter averaged approximately 675 mboe, an increase of 2% from the Prior Quarter and 11% when adjusted for 2013 asset sales. Compared to the Prior Quarter, our natural gas production in the Current Quarter decreased by 5%, or 145 mmcf per day; our oil production increased by 6%, or approximately 6 mbbls per day; and our NGL production increased by 55%, or approximately 30 mbbls per day. In addition, the price we received for our natural gas, oil and NGL production increased approximately 32%, from $26.71 per boe in the Prior Quarter to $35.35 per boe in the Current Quarter (excluding gains or losses on natural gas and oil derivatives). Coupled with our liquids production increases, our revenues (excluding gains or losses on natural gas and oil derivatives) increased approximately $553 million in the Current Quarter compared to the Prior Quarter. See Results of Operations below for additional details. In the Current Quarter, our total capital expenditures were approximately $850 million, of which drilling and completion costs were approximately $729 million. We invested $882 million of cash during the Current Quarter in drilling and completion activities. This was partially offset by lower-than-expected drilling and completion costs and other adjustments, related to prior periods, of approximately $153 million, for net drilling and completion costs of approximately $729 million. This level of drilling and completion expenditures represents a decrease of approximately $735 million, or 50%, compared to the Prior Quarter. In the Current Quarter, we operated an average of 62 rigs, a decrease of 22 rigs compared to the Prior Quarter. In addition to a decreased rig count, drilling and completion costs were lower in the Current Quarter than in the Prior Quarter as a result of improving capital efficiencies and approximately 35% fewer well completions. Net expenditures for the acquisition of unproved properties were approximately $24 million during the Current Quarter compared to approximately $44 million in the Prior Quarter. Other capital expenditures were approximately $97 million during the Current Quarter compared to approximately $330 million during the Prior Quarter. The reduction in other capital expenditures in the Current Quarter from the Prior Quarter is primarily the result of a reduction in capital expenditures for construction of our corporate headquarters and field offices and for our oilfield services business and the sale of substantially all of our midstream business and most of our gathering assets in 2012 and 2013. In addition, in the Current Quarter, we also purchased rigs and compressors previously sold under long-term lease arrangements for approximately $340 million to facilitate asset sales and a possible spin-off or sale of Chesapeake Oilfield Services as discussed below under Divestitures - Chesapeake Oilfield Services. Based on planned activity levels for 2014 and 2015, we project that 2014 total capital expenditures will be $5.2 - $5.6 billion, an approximate 20% decrease from $6.8 billion of total capital expenditures in 2013. Divestitures We will continue to pursue opportunities to high-grade our portfolio so we can focus on existing assets that best fit our strategy of profitable growth from captured resources. We seek divestitures that are value-accretive and enable us to further reduce financial complexity and lower overall leverage. Our 2014 capital budget is expected to approximate our operating cash flow and is not dependent on divestitures. Sale of Investments In January 2014, we received $209 million of net proceeds from the sale of our common equity ownership in Chaparral Energy, Inc. We recorded a $73 million gain related to the sale. In March 2014, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction. Sale of Buildings and Land In the Current Quarter, we sold buildings and land noncore to our operations, primarily in the Oklahoma City area, for proceeds of approximately $55 million. Midstream Compression Asset Sales In March 2014, we sold 102 compressors and related equipment to Access Midstream Partners, L.P. for approximately $159 million. In April 2014, we sold 337 compressors and related equipment to Exterran Partners, L.P. for approximately $362 million. 56 -------------------------------------------------------------------------------- Chesapeake Oilfield Services In February 2014, we announced that we are pursuing strategic alternatives for our oilfield services business, Chesapeake Oilfield Services (COS), including a potential spin-off to Chesapeake shareholders or an outright sale (any such transaction, a "Separation Transaction"). COS services include drilling, hydraulic fracturing, oilfield rentals, rig relocation, and fluid handling and disposal. On March 17, 2014, our wholly owned subsidiary, Chesapeake Oilfield Operating, LLC (COO), filed a Registration Statement on Form 10 with the SEC. The Form 10 contains a preliminary information statement about the potential terms and conditions of a spin-off of COO to Chesapeake shareholders. It also provides initial information regarding COO as a stand-alone company, including financial, business, risk factor and management information. Immediately prior to completion of the possible spin-off, COO would convert into a corporation and change its name to Seventy Seven Energy Inc.Chesapeake intends for the potential spin-off to be tax-free to its shareholders for U.S. federal income tax purposes and, to that end, has obtained a private letter ruling from the Internal Revenue Service. Shareholders who want more complete information regarding the possible spin-off of COO, including the potential benefits and risks associated with the transaction, should consult the Form 10, which may be revised or updated in the future. As of March 31, 2014, COS had approximately 5,200 employees and owned or leased 114 land drilling rigs, including 10 proprietary, fit-for-purpose PeakeRigsTM that utilize advanced electronic drilling technology. Also, as of March 31, 2014, COS owned nine hydraulic fracturing fleets with an aggregate of 360,000 horsepower; a diversified oilfield tool rental business; an oilfield trucking fleet consisting of 260 rig relocation trucks; 67 cranes and forklifts used to move drilling rigs and other heavy equipment; and 247 fluid hauling trucks. As described under Liquidity and Capital Resources below, COO had $1.114 billion in aggregate principal amount of long-term debt outstanding as of March 31, 2014, including $650 million of 6.825% Senior Notes due 2019 and $464 million outstanding under a revolving bank credit facility that matures in November 2016. See Note 16 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for financial information about COS, which is one of our reportable operating segments, and Results of Operations below for further discussion of the results of our oilfield services business for the Current Quarter and the Prior Quarter. No agreement as to a Separation Transaction currently exists, no decision regarding a Separation Transaction has been made by our Board of Directors, and we can offer no assurance regarding the form, terms, timing or conditions of a Separation Transaction or that a Separation Transaction will ultimately occur or be consummated. Liquidity and Capital Resources Liquidity Overview As of March 31, 2014, we had approximately $5.017 billion in cash availability (defined as unrestricted cash on hand plus borrowing capacity under our revolving bank credit facilities) compared to $4.909 billion as of December 31, 2013. As of March 31, 2014, we had full availability under our $4.0 billion corporate revolving bank credit facility. During the Current Quarter, we decreased our debt, net of unrestricted cash, by approximately $92 million, to $11.957 billion. As of March 31, 2014, we had negative working capital of approximately $1.683 billion compared to negative working capital of approximately $1.859 billion as of December 31, 2013. Historically, working capital deficits have existed primarily because our capital spending has exceeded our cash flow from operations. For 2014, we are projecting that our capital expenditures will approximate our operating cash flow. Proceeds from any asset sales completed in 2014 and beyond may be used to reduce financial leverage and complexity and further enhance our liquidity. While furthering our strategic priorities, certain actions that would reduce financial leverage and complexity could negatively impact our future cash flows. We may incur various cash charges including but not limited to lease termination charges, financing extinguishment costs and charges for unused transportation and gathering capacity. To add more certainty to our future estimated cash flows, we currently have downside price protection, in the form of over-the-counter derivative contracts, on approximately 64% of our remaining 2014 estimated natural gas production at an average price of $4.10 per mcf and 70% of our remaining 2014 estimated oil production at an average price of $94.32 per bbl. See Quantitative and Qualitative Disclosures about Market Risk in Item 3 of Part I in this report. Our use of derivative contracts allows us to reduce the effect of price volatility on our cash flows and EBITDA (defined as earnings before interest, taxes, depreciation, depletion and amortization), but the amount of estimated production subject to derivative contracts for any period depends on our outlook on future prices and risk assessment. Based upon our 2014 capital expenditure budget, our forecasted operating cash flow and projected levels of indebtedness, we are projecting that we will be in compliance with the financial maintenance covenants of our corporate revolving bank credit facility. Further, we expect to meet in the ordinary course of business other contractual cash commitments to third parties pursuant to various agreements described in Contractual Obligations and Off-Balance Sheet Arrangements below and in Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report, recognizing that we may be required to meet such commitments even if our business plan assumptions were to change. We believe the assumptions underlying our budget for this period are reasonable and that we have adequate flexibility, including the ability to adjust discretionary capital expenditures and other spending to adapt to potential negative developments if needed. Recent Refinancing In the 2014 second quarter, we have taken a series of steps to reduce our interest costs and to lengthen the maturity profile of our outstanding indebtedness. On April 24, 2014, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our term loan credit facility. We will use the remaining proceeds along with cash on hand to redeem approximately $97 million aggregate principal amount of 6.875% Senior Notes due 2018 and to purchase outstanding 9.5% Senior Notes due 2015 through a tender offer that we commenced concurrently with the senior notes offering. On April 24, 2014, we purchased approximately $946 million aggregate principal amount of the 9.5% Senior Notes due 2015 that were tendered by the early tender date. The tender offer will expire on May 7, 2014, unless extended, and the redemption of the 6.875% Senior Notes due 2018 is expected to occur on May 12, 2014. 57 -------------------------------------------------------------------------------- Sources of Funds The following table presents the sources of our cash and cash equivalents for the Current Quarter and the Prior Quarter. See Notes 9, 10 and 12 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of sales of natural gas and oil assets, other assets and investments. Three Months Ended March 31, 2014 2013 ($ in millions) Cash provided by operating activities $ 1,291$ 924 Sales of natural gas and oil assets: Joint venture leasehold 7



25

Other natural gas and oil properties 42



165

Total sales of natural gas, oil and other assets 49



190

Sales of other assets: Sale of compressors to ACMP 159



-

Sales of other property and equipment 80



201

Total proceeds from sales of other property and equipment 239

201

Other sources of cash and cash equivalents: Proceeds from sales of other investments 239



-

Proceeds from credit facility borrowings, net 59



821

Other -



56

Total other sources of cash and cash equivalents 298



877

Total sources of cash and cash equivalents $ 1,877



$ 2,192

Cash provided by operating activities was $1.291 billion in the Current Quarter compared to $924 million in the Prior Quarter. The increase in cash provided by operating activities from the Prior Quarter to the Current Quarter is primarily the result of an increase in prices received for natural gas sold (excluding the effect of gains or losses on derivatives) from $2.10 per mcf in the Prior Quarter to $3.86 per mcf in the Current Quarter, an increase in oil and NGL sales volumes and decreases in certain of our operating expenses per unit. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, depletion and amortization, impairments of other assets, deferred income taxes and mark-to-market changes in our derivative instruments. See the discussion below under Results of Operations. Our $4.0 billion corporate revolving bank credit facility, our $500 million oilfield services revolving bank credit facility and cash and cash equivalents are other sources of liquidity. We use these revolving bank credit facilities and cash on hand to fund daily operating activities and capital expenditures as needed. We borrowed $421 million and repaid $362 million in the Current Quarter and borrowed $3.632 billion and repaid $2.811 billion in the Prior Quarter under our revolving bank credit facilities. As of March 31, 2014, we had no borrowings outstanding under our corporate revolving bank credit facility and had utilized approximately $23 million of the facility for various letters of credit. As of March 31, 2014, we had $464 million of outstanding borrowings under our oilfield services credit facility. Our corporate facility is secured by natural gas and oil proved reserves. A significant portion of our natural gas and oil reserves is currently unencumbered and therefore available to be pledged as additional collateral if needed to respond to borrowing base and collateral redeterminations that our lenders might make in the future. We believe our borrowing capacity under our corporate facility will not be reduced as a result of any such future redeterminations. Our oilfield services facility is secured by substantially all of our wholly owned oilfield services assets and is not subject to periodic borrowing base redeterminations. 58 -------------------------------------------------------------------------------- Uses of Funds The following table presents the uses of our cash and cash equivalents for the Current Quarter and the Prior Quarter: Three Months Ended March 31, 2014 2013 ($ in millions) Natural Gas and Oil Expenditures: Drilling and completion costs(a) $ (893 )$ (1,566 ) Acquisitions of proved and unproved properties (29 ) (73 ) Geological and geophysical costs (4 ) (13 ) Interest capitalized on unproved properties (158 ) (207 ) Total natural gas and oil expenditures (1,084 ) (1,859 )



Other Uses of Cash and Cash Equivalents: Cash paid to purchase leased rigs and compressors (340 ) - Additions to other property and equipment

(97 ) (330 ) Cash paid for prepayment of mortgage - (55 ) Dividends paid (101 ) (101 ) Distributions to noncontrolling interest owners (53 ) (57 ) Cash paid for financing derivatives(b) (15 ) (11 ) Additions to investments (3 ) (3 ) Other (17 ) (30 ) Total other uses of cash and cash equivalents (626 ) (587 ) Total uses of cash and cash equivalents $ (1,710 )$ (2,446 )



___________________________________________

(a) Net of $188 million and $180 million in drilling and completion carries

received from our joint venture partners during the Current Quarter and the

Prior Quarter, respectively.

(b) Reflects derivatives deemed to contain, for accounting purposes, a

significant financing element at contract inception.

Our primary use of funds is for capital expenditures related to exploration and development of natural gas and oil properties. Historically, a significant use was also for the acquisition of leasehold and construction and acquisition of other property and equipment. During the Current Quarter, our average operated rig count was 62 rigs compared to an average rig count of 84 operated rigs in the Prior Quarter. Our Prior Quarter drilling and completion expenditures also reflected significant well completion costs for natural gas wells that had been drilled, but not completed, in prior periods. These completions were delayed as we awaited the construction of infrastructure necessary to transport the natural gas produced to market. Capital expenditures related to our midstream, oilfield services and other fixed assets were $97 million and $330 million during the Current Quarter and the Prior Quarter, respectively. The reduction of such expenditures in the Current Quarter from the Prior Quarter is primarily the result of a reduction in capital expenditures for construction of our corporate headquarters, field offices and our oilfield services business and the sale of substantially all of our midstream business and most of our gathering assets in 2012 and 2013. In the Current Quarter, we also purchased rigs and compressors previously sold under long-term lease arrangements for approximately $340 million as part of a strategic initiative to reduce complexity and future commitments as well as to facilitate asset sales and a possible spin-off or sale of COS. We paid dividends on our common stock of $58 million in both the Current Quarter and the Prior Quarter. We paid dividends on our preferred stock of $43 million in both the Current Quarter and the Prior Quarter. 59 --------------------------------------------------------------------------------



Bank Credit Facilities During the Current Quarter, we had the following two revolving bank credit facilities as sources of liquidity:

Corporate Oilfield Services Credit Facility(a) Credit Facility(b) ($ in millions) Senior secured Senior secured Facility structure revolving revolving Maturity date December 2015 November 2016 Borrowing capacity $ 4,000 $ 500 Amount outstanding as of March 31, 2014 $ - $ 464 Letters of credit outstanding as of March 31, 2014 $ 23 $ -



___________________________________________

(a) Co-borrowers are Chesapeake Exploration, L.L.C., Chesapeake Appalachia,

L.L.C. and Chesapeake Louisiana, L.P.

(b) Borrower is Chesapeake Oilfield Operating, L.L.C. (COO).

Although the applicable interest rates under our corporate credit facility fluctuate based on our long-term senior unsecured credit ratings, our credit facilities do not contain provisions which would trigger an acceleration of amounts due under the respective facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings. Corporate Credit Facility. Our $4.0 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the facility are secured by proved reserves and bear interest at a variable rate. We were in compliance with all covenants under the credit facility agreement as of March 31, 2014, including the financial covenant requiring us to maintain an indebtedness to EBITDA ratio of 4.0 to 1.0. As of March 31, 2014, our indebtedness to EBITDA ratio was approximately 2.44 to 1.00. The ratio compares consolidated indebtedness to consolidated EBITDA, both non-GAAP financial measures that are defined in the credit facility agreement, for the 12-month period ending on the measurement date. Consolidated indebtedness consists of outstanding indebtedness, less the cash and cash equivalents of Chesapeake and certain of our subsidiaries. Consolidated EBITDA consists of the net income of Chesapeake and certain of our subsidiaries, excluding income from investments and non-cash income plus interest expense, taxes, depreciation, amortization expense and other non-cash or non-recurring expenses, and is calculated on a pro forma basis to give effect to any acquisitions, divestitures or other adjustments. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the terms of our corporate credit facility. Oilfield Services Credit Facility. Our $500 million syndicated oilfield services revolving bank credit facility is used to fund capital expenditures and for general corporate purposes associated with our oilfield services operations. The facility may be expanded from $500 million to $900 million at COO's option, subject to additional bank participation. Borrowings under the credit facility bear interest at a variable interest rate and are secured by all of the equity interests and assets of COO and its wholly owned subsidiaries (the restricted subsidiaries for this facility, which are unrestricted subsidiaries under Chesapeake's senior notes, contingent convertible senior notes, corporate revolving bank credit facility, secured hedging facility and equipment master lease agreements). COO was in compliance with all covenants under the credit facility agreement as of March 31, 2014. For further discussion of the terms of our oilfield services credit facility, see Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report. Hedging Facility We have a multi-counterparty secured hedging facility with 17 counterparties that have committed to provide approximately 1.063 bboe of hedging capacity for natural gas, oil and NGL price derivatives and 1.063 bboe for basis derivatives with an aggregate mark-to-market capacity of $17.0 billion under the terms of the facility. For further discussion of the terms of our hedging facility, see Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report. 60 -------------------------------------------------------------------------------- Term Loan Prior to April 24, 2014, we had a $2.0 billion unsecured term loan credit facility. We used a portion of the proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes that closed on April 24, 2014 to repay the borrowings under the term loan. See Recent Refinancing above for further discussion of the refinancing transactions. Our obligations under the facility ranked equally with our outstanding senior notes and contingent convertible senior notes and were unconditionally guaranteed on a joint and several basis by our direct and indirect wholly owned subsidiaries that are subsidiary guarantors under the indentures for such notes. Amounts borrowed under the facility bore interest at a variable rate. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the term loan. Senior Note Obligations Our senior note obligations consisted of the following as of March 31, 2014: March 31, 2014 ($ in millions) 9.5% senior notes due 2015(a) $ 1,265 3.25% senior notes due 2016 500 6.25% euro-denominated senior notes due 2017(b) 473 6.5% senior notes due 2017 660 6.875% senior notes due 2018(c) 97 7.25% senior notes due 2018 669 6.625% senior notes due 2019(d) 650 6.625% senior notes due 2020 1,300 6.875% senior notes due 2020 500 6.125% senior notes due 2021 1,000 5.375% senior notes due 2021 700 5.75% senior notes due 2023 1,100 2.75% contingent convertible senior notes due 2035(e) 396 2.5% contingent convertible senior notes due 2037(e) 1,168 2.25% contingent convertible senior notes due 2038(e) 347 Discount on senior notes(f) (303 ) Interest rate derivatives(g) 13 Total senior notes, net 10,535 Less current maturities of long-term debt(a) (316 ) Total long-term senior notes, net $ 10,219



___________________________________________

(a) On April 10, 2014, we commenced a tender offer for the 9.5% Senior Notes due

2015 concurrently with an offering of senior notes. On April 24, 2014, we

purchased approximately $946 million aggregate principal amount of notes that

were tendered by the early tender date. The tender offer will expire on May

7, 2014, unless extended. See Recent Refinancing above for further discussion

of the refinancing transactions. The remaining $319 million in aggregate

principal amount not tendered by the early tender date and the associated $3

million of discount are reflected as a current liability on our March 31,

2014 condensed consolidated balance sheet.

(b) The principal amount shown is based on the exchange rate of $1.3769 to 1.00

as of March 31, 2014. See Note 8 of the notes to our condensed consolidated

financial statements included in Item 1 of Part I of this report for

information on our related foreign currency derivatives.

(c) On April 10, 2014, we called the 6.875% Senior Notes due 2018 for redemption

on May 12, 2014. See Recent Refinancing above for further discussion of the

refinancing transactions.

(d) Issuers are COO, an indirect wholly owned subsidiary of the Company, and

Chesapeake Oilfield Finance, Inc. (COF), a wholly owned subsidiary of COO

formed solely to facilitate the offering of the 6.625% Senior Notes due 2019.

COF is nominally capitalized and has no operations or revenues. Chesapeake

Energy Corporation is the issuer of all other senior notes and the contingent

convertible senior notes. 61

--------------------------------------------------------------------------------



(e) The holders of our contingent convertible senior notes may require us to

repurchase, in cash, all or a portion of their notes at 100% of the principal

amount of the notes on any of four dates that are five, ten, fifteen and

twenty years before the maturity date. The notes are convertible, at the

holder's option, prior to maturity under certain circumstances into cash and,

if applicable, shares of our common stock using a net share settlement

process.

(f) Included in this discount was $284 million as of March 31, 2014 associated

with the equity component of our contingent convertible senior notes. This

discount is amortized based on an effective yield method.

(g) See Note 8 of the notes to our condensed consolidated financial statements

included in Item 1 of Part I of this report for discussion related to these

instruments.

For further discussion and details regarding our senior notes, contingent convertible senior notes and COO senior notes, see Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report. Credit Risk Derivative instruments that enable us to manage our exposure to natural gas, oil and NGL prices, interest rate and foreign currency volatility expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of March 31, 2014, our natural gas, oil and interest rate derivative instruments were spread among 16 counterparties. Additionally, the counterparties under our multi-counterparty secured hedging facility are required to secure their obligations in excess of defined thresholds. We use this facility for substantially all of our natural gas, oil and NGL derivatives. Our accounts receivable are primarily from purchasers of natural gas, oil and NGL ($1.940 billion as of March 31, 2014) and exploration and production companies that own interests in properties we operate ($472 million as of March 31, 2014). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During the Current Quarter and the Prior Quarter, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables. Contractual Obligations and Off-Balance Sheet Arrangements From time to time, we enter into arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 2014, these arrangements and transactions included (i) operating lease agreements, (ii) VPPs (to purchase production and pay related production expenses and taxes in the future), (iii) open purchase commitments, (iv) open delivery commitments, (v) open drilling commitments, (vi) undrawn letters of credit, (vii) open gathering and transportation commitments and (viii) various other commitments we enter into in the ordinary course of business that could result in a future cash obligation. As the operator of the properties from which VPP volumes have been sold, we bear the cost of producing the reserves attributable to such interests, which we include as a component of production expenses and production taxes in our condensed consolidated statements of operations in the periods such costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. The costs that will apply in the future will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which such production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all. We have committed to purchase natural gas and liquids produced that are associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices. See Notes 4 and 9 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of commitments and VPPs, respectively. 62 -------------------------------------------------------------------------------- Results of Operations - Three Months Ended March 31, 2014 vs. March 31, 2013 General. For the Current Quarter, Chesapeake had net income of $466 million, or $0.54 per diluted common share, on total revenues of $5.046 billion. This compares to net income of $102 million, or $0.02 per diluted common share, on total revenues of $3.424 billion during the Prior Quarter. The increase in the Current Quarter was primarily driven by an increase in our natural gas, oil and NGL sales as discussed below. Natural Gas, Oil and NGL Sales. During the Current Quarter, natural gas, oil and NGL sales were $1.766 billion compared to $1.453 billion in the Prior Quarter. In the Current Quarter, Chesapeake produced and sold 61 mmboe for $2.148 billion at a weighted average price of $35.35 per boe, compared to 60 mmboe produced and sold in the Prior Quarter for $1.595 billion at a weighted average price of $26.71 per boe. The increase in the price received per boe in the Current Quarter compared to the Prior Quarter resulted in an increase in revenues of $525 million, and increased sales volumes resulted in a $28 million increase in revenues, for a total increase in revenues of $553 million (excluding the effect of derivatives). For the Current Quarter, our average price received per mcf of natural gas was $3.86 compared to $2.10 in the Prior Quarter (excluding the effect of derivatives). Oil prices received per barrel (excluding the effect of derivatives) were $93.60 and $95.23 in the Current Quarter and the Prior Quarter, respectively. NGL prices received per barrel (excluding the effect of derivatives) were $29.23 and $28.25 in the Current Quarter and the Prior Quarter, respectively. Gains and losses from our natural gas, oil and NGL derivatives resulted in a net decrease in natural gas, oil and NGL revenues of $382 million in the Current Quarter and a net decrease of $142 million in the Prior Quarter. See Item 3 of Part I of this report for a complete listing of all of our derivative instruments as of March 31, 2014. A change in natural gas, oil and NGL prices has a significant impact on our revenues and cash flows. Assuming our Current Quarter production levels and without considering the effect of derivatives, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in the Current Quarter revenues and cash flows of approximately $26 million, and an increase or decrease of $1.00 per barrel of liquids sold would result in an increase or decrease in the Current Quarter revenues and cash flows of approximately $17 million. 63 --------------------------------------------------------------------------------



The following tables show our production and average sales prices received by operating division for the Current Quarter and the Prior Quarter:

Three Months



Ended March 31, 2014

Natural Gas Oil NGL Total (bcf) ($/mcf)(a) (mmbbl) ($/bbl)(a) (mmbbl) ($/bbl)(a) (mmboe) % ($/boe)(a) Southern(b) 139.8 3.18 8.5 94.77 4.3 29.77 36.0 59 38.08 Northern(c) 120.2 4.66 1.4 86.66 3.3 28.53 24.8 41 31.38 Total(d) 260.0 3.86 9.9 93.60 7.6 29.23 60.8 100 % 35.35 Three Months Ended March 31, 2013 Natural Gas Oil NGL Total (bcf) ($/mcf)(a) (mmbbl) ($/bbl)(a) (mmbbl) ($/bbl)(a) (mmboe) % ($/boe)(a) Southern(b) 192.5 1.94 8.8 95.69 4.2 26.28 45.1 76 29.47 Northern(c) 80.6 2.48 0.5 85.85 0.7 39.64 14.6 24 18.19 Total(d) 273.1 2.10 9.3 95.23 4.9 28.25 59.7 100 % 26.71



___________________________________________

(a) The average sales price excludes gains (losses) on derivatives.

(b) Our Southern Division includes the Eagle Ford, Granite Wash/Hogshooter,

Cleveland, Tonkawa and Mississippi Lime unconventional liquids plays and the

Haynesville/Bossier and Barnett unconventional natural gas shale plays. The

Eagle Ford Shale accounted for approximately 19% of our estimated proved

reserves by volume as of December 31, 2013. Production for the Eagle Ford

Shale for the Current Quarter and the Prior Quarter was 7.9 mmboe and 6.8

mmboe, respectively. The Barnett Shale accounted for approximately 16% of our

estimated proved reserves by volume as of December 31, 2013. Production for

the Barnett Shale for the Current Quarter and the Prior Quarter was 6.4 mmboe

and 7.2 mmboe, respectively.

(c) Our Northern Division includes the Utica and Niobrara unconventional liquids

plays and the Marcellus unconventional natural gas play. The Marcellus Shale

accounted for approximately 25% of our estimated proved reserves by volume as

of December 31, 2013. Production for the Marcellus Shale for the Current

Quarter and the Prior Quarter was 18.8 mmboe and 12.8 mmboe, respectively.

(d) Current Quarter and Prior Quarter production levels reflect the impact of

various asset sales and joint ventures. See Note 8 of the notes to our

condensed consolidated financial statements included in Item 1 of Part I of

this report for information on our natural gas and oil property divestitures

and joint ventures.

Our average daily production of 675 mboe for the Current Quarter consisted of approximately 2.9 bcf of natural gas (71% on an oil equivalent basis) and approximately 193,700 bbls of liquids, consisting of approximately 109,500 bbls of oil (16% on an oil equivalent basis) and approximately 84,200 bbls of NGL (13% on an oil equivalent basis). Our year-over-year growth rate of oil production was 6% and our year-over-year growth rate of NGL production was 55%. Natural gas production declined 5% year over year primarily as a result of asset sales. Excluding the impact of derivatives, our percentage of revenues from natural gas, oil and NGL is shown in the following table. Three Months Ended March 31, 2014 2013 Natural gas 47% 36% Oil 43% 55% NGL 10% 9% Total 100% 100% 64

-------------------------------------------------------------------------------- We are defending against claims by royalty owners alleging that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. Adverse results in these matters would cause our obligations to royalty owners to increase, which would result in a decrease in our future revenues. Marketing, Gathering and Compression Revenues and Expenses. Marketing, gathering and compression revenues and expenses consist of third-party revenues and expenses related to our marketing, gathering and compression operations and exclude depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See Depreciation and Amortization of Other Assets below for the depreciation and amortization recorded on our marketing, gathering and compression assets. Chesapeake recognized $3.015 billion in marketing, gathering and compression revenues in the Current Quarter with corresponding expenses of $2.980 billion, for a net margin before depreciation of $35 million. This compares to revenues of $1.781 billion, expenses of $1.745 billion and a net margin before depreciation of $36 million in the Prior Quarter. Our revenues and operating expenses from our marketing business increased substantially in the Current Quarter compared to the Prior Quarter. In the Current Quarter, the prices received for marketing natural gas and NGL were significantly higher than in the Prior Quarter. In addition, in the Current Quarter we marketed significantly more oil and NGL from both Chesapeake-operated wells and for third parties. Our marketing revenues and operating expenses also increased because of a variety of purchase and sales contracts we entered into with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In addition, compression services increased in the Current Quarter compared to the Prior Quarter. Oilfield Services Revenues and Expenses. Oilfield services consists of third-party revenues and expenses related to our oilfield services operations and excludes depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See Depreciation and Amortization of Other Assets below for the depreciation and amortization recorded on our oilfield services assets. Chesapeake recognized $265 million in oilfield services revenues in the Current Quarter with corresponding expenses of $220 million, for a net margin before depreciation of $45 million. This compares to revenues of $190 million, expenses of $155 million and a net margin before depreciation of $35 million in the Prior Quarter. Oilfield services revenues and expenses increased in the Current Quarter compared to the Prior Quarter primarily as a result of increased third-party utilization for all of our oilfield services. Natural Gas, Oil and NGL Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $288 million in the Current Quarter, compared to $307 million in the Prior Quarter. On a unit-of-production basis, production expenses were $4.73 per boe in the Current Quarter compared to $5.14 in the Prior Quarter. The per unit expense decrease in the Current Quarter was primarily the result of a general improvement in operating efficiencies across most of our operating areas. Production expenses in the Current Quarter and the Prior Quarter included approximately $41 million and $45 million, or $0.68 and $0.75 per boe, respectively, associated with VPP production volumes. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our VPP agreements decrease and as operating efficiencies generally improve. Production Taxes. Production taxes were $50 million in the Current Quarter compared to $53 million in the Prior Quarter. On a unit-of-production basis, production taxes were $0.83 per boe in the Current Quarter compared to $0.89 per boe in the Prior Quarter. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when natural gas, oil and NGL prices are higher. Even with the increase in prices in the Current Quarter compared to the Prior Quarter, total production taxes declined as a result of production tax credits received in both Oklahoma and Texas. Production taxes in the Current Quarter and the Prior Quarter included approximately $4 million and $7 million, or $0.07 and $0.11 per boe, respectively, associated with VPP production volumes. General and Administrative Expenses. General and administrative expenses were $79 million in the Current Quarter and $110 million in the Prior Quarter, or $1.30 and $1.84 per boe, respectively. The absolute and per unit expense decrease in the Current Quarter was primarily due to our efforts to reduce costs and increased emphasis on operational efficiencies. In addition, the workforce reduction described in Restructuring and Other Termination Costs below resulted in cost savings and is expected to contribute to more profitable and efficient growth. Included in general and administrative expenses is stock-based compensation of $12 million in the Current Quarter and $20 million in the Prior Quarter. See Note 7 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of our stock-based compensation. 65 -------------------------------------------------------------------------------- Chesapeake follows the full cost method of accounting under which all costs associated with natural gas and oil property acquisition, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with acquisition of leasehold and drilling and completion activities and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $57 million and $92 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our natural gas and oil property acquisition and drilling and completion efforts. The decrease was primarily due to lower costs and increased emphasis on operational efficiencies in support of our current business strategy. Restructuring and Other Termination Costs. We recorded $7 million of income in the Current Quarter and $133 million of restructuring and other termination costs in the Prior Quarter. The Current Quarter amount primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. The Prior Quarter amount primarily related to our voluntary separation plan and senior management separations. See Note 14 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion. Natural Gas, Oil and NGL Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (DD&A) of natural gas, oil and NGL properties was $628 million and $648 million in the Current Quarter and the Prior Quarter, respectively. The $20 million decrease in the Current Quarter is primarily driven by efficiencies in our drilling program as a result of lower development costs and higher estimated reserve recoveries in addition to upward price revisions to our estimated proved reserves. The average DD&A rate per boe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $10.33 and $10.86 in the Current Quarter and the Prior Quarter, respectively. Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $78 million in both the Current Quarter and the Prior Quarter. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. To the extent company-owned oilfield services equipment is used to drill and complete our wells, a substantial portion of the depreciation (i.e., the portion related to our utilization of the equipment) is capitalized in natural gas and oil properties as drilling and completion costs. The following table shows depreciation expense by asset class for the Current Quarter and the Prior Quarter and the estimated useful lives of these assets. Three Months Ended March 31, Estimated Useful 2014 2013 Life ($ in millions) (in years) Oilfield services equipment(a) $ 37 $ 26 3 - 15 Buildings and improvements 11 13 10 - 39 Natural gas compressors(b) 8 9 3 - 20 Computers and office equipment 9 12 3 - 7 Vehicles 7 11 0 - 7 Natural gas gathering systems and treating plants(b) 4 3 20 Other 2 4 2 - 20 Total depreciation and amortization of other assets $ 78 $



78

___________________________________________

(a) Included in our oilfield services operating segment.

(b) Included in our marketing, gathering and compression operating segment.

Impairments of Fixed Assets and Other. In the Current Quarter and the Prior Quarter, we recognized $20 million and $27 million, respectively, of fixed asset impairment losses and other charges. The Current Quarter losses primarily related to drilling rigs and equipment. The Prior Quarter losses primarily related to buildings and land. See Note 13 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of our impairments of fixed assets and other. Net Gains on Sales of Fixed Assets. In the Current Quarter, net gains on sales of fixed assets were $23 million compared to $49 million in the Prior Quarter. The Current Quarter amount primarily related to the sale of natural gas compressors. The Prior Quarter amount primarily consisted of gains on sales of gathering assets partially offset by losses on the sales of buildings and land. See Note 12 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of our net gains on sales of fixed assets. 66 --------------------------------------------------------------------------------



Interest Expense. Interest expense was $39 million in the Current Quarter compared to $21 million in the Prior Quarter as follows:

Three Months Ended March 31, 2014 2013 ($ in millions) Interest expense on senior notes $ 180 $



186

Interest expense on term loans 29



29

Amortization of loan discount, issuance costs and other 19



19

Interest expense on credit facilities 8



12

Realized (gains) losses on interest rate derivatives(a) (3 ) (2 ) Unrealized (gains) losses on interest rate derivatives(b) (16 ) 6 Capitalized interest (178 ) (229 ) Total interest expense $ 39$ 21 Average senior notes borrowings $ 10,809 $



10,283

Average term loan borrowings $ 2,000 $



2,000

Average credit facilities borrowings $ 440 $



1,095

___________________________________________

(a) Includes settlements related to the current period interest accrual and the

effect of gains (losses) on early terminated trades. Settlements of

early-terminated trades are reflected in realized (gains) losses over the

original life of the hedged item.

(b) Includes changes in the fair value of open interest rate derivatives offset

by amounts reclassified to realized (gains) losses during the period.

Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $0.90 per boe in the Current Quarter compared to $0.25 per boe in the Prior Quarter. The increase in Current Quarter interest expense is primarily due to a decrease in the amount of interest capitalized as a result of a lower average balance of unevaluated natural gas and oil properties, the primary asset on which interest is capitalized. Losses on Investments. Losses on investments were $21 million in the Current Quarter compared to losses of $37 million in the Prior Quarter. The Current Quarter and the Prior Quarter losses primarily related to our equity in the net loss of FTS International, Inc. Net Gain on Sales of Investments. We recorded net gains on sales of investments of $67 million in the Current Quarter. We sold all of our interest in Chaparral Energy, Inc. for cash proceeds of $215 million and recorded a $73 million gain related to the sale. We also sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction. Other Income. Other income was $6 million in both the Current Quarter and the Prior Quarter. The Current Quarter other income consisted of $1 million of interest income and $5 million of miscellaneous income. The Prior Quarter other income consisted of $6 million of miscellaneous income. Income Tax Expense. Chesapeake recorded income tax expense of $280 million and $63 million in the Current Quarter and the Prior Quarter, respectively. Our effective income tax rate was 37.5% in the Current Quarter and 38% in the Prior Quarter. Our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences. Net Income Attributable to Noncontrolling Interests. Chesapeake recorded net income attributable to noncontrolling interests of $41 million and $44 million in the Current Quarter and the Prior Quarter, respectively. Net income attributable to noncontrolling interests is primarily driven by the dividends paid on our CHK Utica and CHK C-T preferred stock in addition to income or loss related to the Chesapeake Granite Wash Trust. See Note 6 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of these entities. 67 -------------------------------------------------------------------------------- Recently Issued Accounting Standards In February 2013, the Financial Accounting Standards Board issued guidance on the recognition, measurement and disclosure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. We adopted this standard on January 1, 2014, and it did not have a material impact on our financial statements. Forward-Looking Statements This report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). Forward-looking statements give our current expectations or forecasts of future events. They include expected natural gas, oil and NGL production and future expenses, estimated operating costs, assumptions regarding future natural gas, oil and NGL prices, planned drilling activity, estimates of future drilling and completion and other capital expenditures (including the use of joint venture drilling carries), and anticipated sales, as well as statements concerning anticipated cash flow and liquidity, covenant compliance, debt reduction, operating and capital efficiencies, business strategy and other plans and objectives for future operations. Our ability to generate sufficient operating cash flow to fund future capital expenditures is subject to all the risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time. Further, asset dispositions we are evaluating as we focus on our strategic priorities are subject to market conditions and other factors beyond our control. Our plans to reduce financial leverage and complexity may take longer to implement if such dispositions are delayed or do not occur as expected. Disclosures concerning the fair values 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. Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under Risk Factors in Item 1A of our 2013 Form 10-K and include: the volatility of natural gas, oil and NGL prices;



the limitations our level of indebtedness may have on our financial

flexibility; the availability of capital on an economic basis to fund reserve replacement costs;



our ability to replace reserves and sustain production;

uncertainties inherent in estimating quantities of natural gas, oil and

NGL reserves and projecting future rates of production and the amount and

timing of development expenditures;

declines in the prices of natural gas and oil potentially resulting in a

write-down of our asset carrying values;

our ability to generate profits or achieve targeted results in drilling

and well operations;

leasehold terms expiring before production can be established;

commodity derivative activities resulting in lower prices realized on

natural gas, oil and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations;



charges incurred in connection with actions to reduce financial leverage

and complexity;

competition in the oil and gas exploration and production industry;

drilling and operating risks, including potential environmental liabilities;

our need to acquire adequate supplies of water for our drilling operations and to dispose of or recycle the water used;



legislative and regulatory changes adversely affecting our industry and

our business, including initiatives related to hydraulic fracturing, air

emissions and endangered species;

a deterioration in general economic, business or industry conditions;

68 --------------------------------------------------------------------------------



oilfield services shortages, gathering system and transportation capacity

constraints and various transportation interruptions that could adversely

affect our revenues and cash flow; adverse developments or losses from pending or future litigation and regulatory investigations;



cyber attacks adversely impacting our operations; and

an interruption in operations at our headquarters due to a catastrophic event.

We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information except as required by applicable law. We urge you to carefully review and consider the disclosures made in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business. ITEM 3. Quantitative and Qualitative Disclosures About Market Risk Natural Gas, Oil and NGL Derivatives Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. These instruments allow us to predict with greater certainty the effective prices to be received for our share of production. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives. Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas and oil futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, natural gas and oil storage inventory levels, industry decline rates for base production and weather trends. We use a wide range of derivative instruments to achieve our risk management objectives, including swaps, collars and options. All of these are described in more detail below. We typically use collars, three-way collars and swaps for a large portion of the natural gas and oil price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility. In the second half of 2011 and in 2012 and 2013, we bought natural gas and oil calls to, in effect, lock in sold call positions. Due to lower natural gas, oil and NGL prices, we were able to achieve this at a low cost to us. In some cases, we deferred the payment of the premium on these trades to the related month of production. Some of our derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception and the cash settlements associated with these instruments are classified as financing cash flows in the accompanying condensed consolidated statements of cash flows. We determine the volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production (risked) from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for more volumes than our forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price payment, resulting in a net amount due to or from the counterparty. We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate such risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original derivative position. Gains or losses related to closed positions will be recognized in the month of related production based on the terms specified in the original contract. We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. Such non- 69 -------------------------------------------------------------------------------- performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our multi-counterparty secured hedging facility which requires counterparties to post collateral if their obligations to Chesapeake are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the fair value measurements associated with our derivatives. As of March 31, 2014, our natural gas and oil derivative instruments consisted of the following: Swaps: Chesapeake receives a fixed price and pays a floating market price



to the counterparty for the hedged commodity.

Collars: These instruments contain a fixed floor price (put) and ceiling

price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call



strike prices, no payments are due from either party. Three-way collars

include an additional put option in exchange for a more favorable strike

price on the call option. This eliminates the counterparty's downside

exposure below the second put option. Options: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the



counterparty such excess on sold call options, and Chesapeake receives

such excess on bought call options. If the market price settles below the

fixed price of the call options, no payment is due from either party.



Basis Protection Swaps: These instruments are arrangements that guarantee

a price differential to NYMEX from a specified delivery point. Our

current natural gas basis protection swaps 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. Our current oil basis protection swaps 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.

As of March 31, 2014, we had the following open natural gas and oil derivative instruments: Weighted Average Price Fair Value Volume Fixed Call Put



Differential Asset (Liability)

(tbtu) ($ per mmbtu) ($ in millions) Natural Gas: Swaps: Short-term 394 4.17 - - - $ (125 ) 3-Way Collars: Short-term 280 - 4.47 3.47 / 4.21 - (56 ) Long-term 107 - 4.37 3.38 / 4.17 - 8 Call Options (sold): Short-term 305 - 6.41 - - (15 ) Long-term 563 - 7.44 - - (26 ) Call Options (bought)(a): Short-term (305 ) - 6.41 - - (36 ) Long-term (370 ) - 6.15 - - (125 ) Basis Protection Swaps: Short-term 119 - - - (0.51 ) (10 ) Long-term 32 - - - (0.52 ) (4 ) Total Natural Gas $ (389 ) 70

--------------------------------------------------------------------------------

Weighted Average Price Fair Value Asset Volume Fixed Call Put Differential (Liability) (mmbbl) ($ per bbl) ($ in millions) Oil: Swaps: Short-term 22.4 94.23 - - - $ (81 ) Long-term 0.4 89.15 - - - - Call Options (sold): Short-term 16.2 - 97.74 - - (84 ) Long-term 42.8 - 100.23 - - (162 )

Call Options (bought)(b): Short-term (10.4 ) - 102.02 - - (7 ) Long-term (6.7 ) - 113.54 - - (4 ) Basis Protection Swaps: Short-term 0.3 - - - 6.00 1

Total Oil $ (337 ) Total Natural Gas and Oil $ (726 )



___________________________________________

(a) Included in the fair value are deferred premiums of $31 million, $82 million

and $85 million which will be included in natural gas, oil and NGL sales as

realized gains (losses) in 2014, 2015 and 2016, respectively.

(b) Included in the fair value are deferred premiums of $35 million and $13

million which will be included in natural gas, oil and NGL sales as realized

gains (losses) in 2014 and 2015, respectively.

In addition to the open derivative positions disclosed above, as of March 31, 2014 we had $107 million of net derivative gains related to settled contracts for future production periods that will be recorded within natural gas, oil and NGL sales as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive income or unrealized gains (losses) on derivatives in the month of related production, based on the terms specified in the original contract as noted below. March 31, 2014 ($ in millions) Short-term $ (79 ) Long-term 186 Total $ 107 The table below reconciles the changes in fair value of our natural gas and oil derivatives during the Current Quarter. Of the $726 million fair value liability as of March 31, 2014, $412 million related to contracts maturing in the next 12 months and $314 million related to contracts maturing after 12 months. All open derivative instruments as of March 31, 2014 are expected to mature by December 31, 2022. 2014 ($ in millions)



Fair value of contracts outstanding, as of January 1 $ (551 ) Change in fair value of contracts

(364 ) Fair value of new contracts when entered into - Contracts realized or otherwise settled 189 Fair value of contracts when closed -



Fair value of contracts outstanding, as of March 31 $ (726 )

71 -------------------------------------------------------------------------------- The change in natural gas and oil prices during the Current Quarter increased the liability related to our derivative instruments by $364 million. This unrealized gain is recorded in natural gas, oil and NGL sales. We settled contracts in the Current Quarter that were in a liability position for $189 million. The realized losses will be recorded in natural gas, oil and NGL sales in the month of related production. Interest Rate Derivatives The table below presents principal cash flows and related weighted average interest rates by expected maturity dates. Years of Maturity 2014 2015 2016 2017 2018 Thereafter Total ($ in millions) Liabilities:



Debt - fixed rate(a) $ - $ 1,661$ 500$ 2,302$ 1,112

$ 5,250$ 10,825 Average interest rate - % 7.89 % 3.25 % 4.42 % 5.66 % 6.20 % 5.89 % Debt - variable rate(b) $ - $ - $ 464$ 2,000 $ -



$ - $ 2,464 Average interest rate - % - % 2.90 % 5.75 % - %

- % 5.21 %



___________________________________________

(a) This amount does not include the discount included in debt of $303 million

and interest rate derivatives of $13 million.

(b) This amount does not include the discount included in debt of $30 million.

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving bank credit facilities. All of our other indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest rates. However, changes in interest rates do affect the fair value of our fixed-rate debt. We enter into interest rate derivatives, including fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes and floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our bank credit facility borrowings. As of March 31, 2014, the following interest rate derivatives were outstanding: Weighted Average Rate Fair Value Notional Fair Value Asset Amount Fixed Floating(a) Hedge (Liability) ($ in millions) ($ in millions)

Fixed to Floating: Swaps Mature 2020 - 2023 $ 1,200 6.06 % 1 - 3 mL No $ (66 ) 430 bp Floating to Fixed: Swaps Mature 2014 - 2015 $ 1,050 2.13 % 1 - 6 mL No (14 ) $ (80 )



___________________________________________

(a) Month LIBOR has been abbreviated "mL" and basis points has been abbreviated

"bp". 72



--------------------------------------------------------------------------------

In addition to the open derivative positions disclosed above, as of March 31, 2014 we had $62 million of net gains related to settled derivative contracts that will be recorded within interest expense as realized gains (losses) once they are transferred from our senior note liability or within interest expense as unrealized gains (losses) over the remaining seven-year term of our related senior notes. Realized and unrealized gains or losses from interest rate derivative transactions are reflected as adjustments to interest expense on the condensed consolidated statements of operations. Foreign Currency Derivatives In December 2006, we issued 600 million of 6.25% Euro-denominated Senior Notes due 2017. Concurrent with the issuance of the euro-denominated senior notes, we entered into cross currency swaps to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. In May 2011, we purchased and subsequently retired 256 million in aggregate principal amount of these senior notes following a tender offer, and we simultaneously unwound the cross currency swaps for the same principal amount. Under the terms of the remaining cross currency swaps, on each semi-annual interest payment date, the counterparties pay us 11 million and we pay the counterparties $17 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay us 344 million and we will pay the counterparties $459 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to 1.00. Through the cross currency swaps, we have eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates and therefore the swaps are designated as cash flow hedges. The fair values of the cross currency swaps are recorded on the condensed consolidated balance sheet as an asset of $7 million as of March 31, 2014. The euro-denominated debt in long-term debt has been adjusted to $473 million as of March 31, 2014 using an exchange rate of $1.3769 to 1.00. ITEM 4. Controls and Procedures Evaluation of Disclosure Controls and Procedures We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Chesapeake's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2014. Changes in Internal Control Over Financial Reporting There was no change in our internal control over financial reporting during the period ended March 31, 2014 which materially affected, or was reasonably likely to materially affect, our internal control over financial reporting.


For more stories on investments and markets, please see HispanicBusiness' Finance Channel



Source: Edgar Glimpses


Story Tools






HispanicBusiness.com Facebook Linkedin Twitter RSS Feed Email Alerts & Newsletters