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CHESAPEAKE ENERGY CORP - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations(Edgar Glimpses Via Acquire Media NewsEdge) 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: Years Ended December 31, 2013 2012 2011 Net Production: Natural gas (bcf) 1,095 1,129 1,004 Oil (mmbbl) 41 31 17 NGL (mmbbl) 21 18 15 Oil equivalent (mmboe)(a) 244 237 199 Natural Gas, Oil and NGL Sales ($ in millions): Natural gas sales $ 2,430 $ 2,004 $ 3,133 Natural gas derivatives - realized gains (losses) 9 328 1,656 Natural gas derivatives - unrealized gains (losses) (52 ) (331 ) (669 ) Total natural gas sales 2,387 2,001 4,120 Oil sales 3,911 2,829 1,523 Oil derivatives - realized gains (losses) (108 ) 39 (60 ) Oil derivatives - unrealized gains (losses) 280 857 (128 ) Total oil sales 4,083 3,725 1,335 NGL sales 582 526 603 NGL derivatives - realized gains (losses) - (9 ) (42 ) NGL derivatives - unrealized gains (losses) - 35 8 Total NGL sales 582 552 569 Total natural gas, oil and NGL sales $ 7,052 $ 6,278 $ 6,024 Average Sales Price (excluding gains (losses) on derivatives): Natural gas ($ per mcf) $ 2.22 $ 1.77 $ 3.12 Oil ($ per bbl) $ 95.17 $ 90.49 $ 89.80 NGL ($ per bbl) $ 27.87 $ 29.89 $ 40.96 Oil equivalent ($ per boe) $ 28.33 $ 22.61 $ 26.42 Average Sales Price (including realized gains (losses) on derivatives): Natural gas ($ per mcf) $ 2.23 $ 2.07 $ 4.77 Oil ($ per bbl) $ 92.53 $ 91.74 $ 86.25 NGL ($ per bbl) $ 27.87 $ 29.37 $ 38.12 Oil equivalent ($ per boe) $ 27.92 $ 24.12 $ 34.23 Other Operating Income(b) ($ in millions): Marketing, gathering and compression net margin $ 98 $ 119 $ 123 Oilfield services net margin $ 159 $ 142 $ 119 Other Operating Income(b) ($ per boe): Marketing, gathering and compression net margin $ 0.40 $ 0.50 $ 0.62 Oilfield services net margin $ 0.65 $ 0.60 $ 0.60 37-------------------------------------------------------------------------------- Years Ended December 31, 2013 2012 2011 Expenses ($ per boe): Natural gas, oil and NGL production $ 4.74 $ 5.50 $ 5.39 Production taxes $ 0.94 $ 0.79 $ 0.96 General and administrative expenses(c) $ 1.86 $ 2.26 $ 2.75 Natural gas, oil and NGL depreciation, depletion and amortization $ 10.59 $ 10.58 $ 8.20 Depreciation and amortization of other assets $ 1.28 $ 1.28 $ 1.46 Interest expense(d) $ 0.65 $ 0.35 $ 0.18 Interest Expense ($ in millions): Interest expense $ 169 $ 84 $ 30 Interest rate derivatives - realized (gains) losses(e) (9 ) (1 ) 7 Interest rate derivatives - unrealized (gains) losses(f) 67 (6 ) 7 Total interest expense $ 227 $ 77 $ 44 ___________________________________________ (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) Includes revenue and operating costs 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, Impairments of Fixed Assets and Other and Net (Gains) Losses on Sales of Fixed Assets under Results of Operations for details of the depreciation and amortization and impairments of assets and net gains or losses on sales of fixed assets associated with our marketing, gathering and compression and oilfield services operating segments. (c) Includes stock-based compensation and excludes restructuring and other termination costs. (d) Includes the effects of realized (gains) losses from interest rate derivatives, but excludes the effects of unrealized (gains) losses from interest rate derivatives; amount is shown net of amounts capitalized. (e) 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. (f) 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. 38--------------------------------------------------------------------------------Overview For an overview of our business and strategy, please see Our Business and Business Strategy in Item 1 of this report. We own interests in approximately 46,800 natural gas and oil wells that produced approximately 665 mboe per day in the 2013 fourth quarter, net to our interest. Our 2013 production of 244 mmboe consisted of 1.095 tcf of natural gas (75% on an oil equivalent basis), 41 mmbbls of oil (17% on an oil equivalent basis) and 21 mmbbls of NGL (8% on an oil equivalent basis). Liquids represented 25% of total production for 2013, up from 20% in 2012. Our daily production for 2013 averaged approximately 670 mboe, an increase of 3% from 2012. Compared to 2012, our natural gas production in 2013 decreased by 3%, or 85 mmcf per day; our oil production increased by 32%, or approximately 27,200 bbls per day; and our NGL production increased by 19%, or approximately 9,100 bbls per day. In 2013, we operated an average of 71 rigs, a decrease of 60 rigs compared to 2012, and invested approximately $5.5 billion in drilling and completion costs compared to approximately $8.8 billion in 2012. Drilling and completion costs were lower in 2013 than in 2012 as Chesapeake drilled and completed fewer wells. In addition, our capital efficiency improvements in 2013 became more evident as we continued to drive well costs down. Net expenditures for the acquisition of unproved properties were approximately $205 million during 2013 compared to approximately $1.7 billion in 2012. Through 2012, the Company invested heavily in unproved properties and now holds a substantial inventory of resources that provides a foundation for future growth. Other capital expenditures were approximately $1.0 billion during 2013 compared to approximately $3.4 billion during 2012. The reduction in other capital expenditures in 2013 from 2012 is primarily the result of our sale of substantially all of our midstream business and most of our gathering assets in 2012 and 2013 and a reduction in capital expenditures for our oilfield services business. Based on planned activity levels for 2014, 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 An essential part of our business strategy in 2013 was using the proceeds from divestitures to fund the spending gap between cash flow from operations and our capital expenditures, to reduce financial leverage and complexity and further enhance our liquidity. In 2013, we generated aggregate net proceeds of approximately $4.4 billion from the sale of natural gas and oil properties, midstream and other assets that we deemed were noncore or did not fit in our long-term plans and through our entry into a strategic joint venture. We will continue to pursue opportunities to high-grade our portfolio to focus on assets that best fit our strategy of profitable growth from captured resources with sales that we believe will be value accretive and enable us to further reduce financial complexity and lower overall leverage, but our 2014 capital budget is not dependent on divestitures. On February 24, 2014, we announced that we are pursuing strategic alternatives for our oilfield services business, COS, including a potential spin-off to Chesapeake shareholders or an outright sale. See Oilfield Services in Item I of this report for a further description of our oilfield services business. In addition, in January 2014 we received $209 million of net proceeds from the sale of our common equity ownership in Chaparral Energy, Inc. Also, in connection with certain assets sales in 2012 and 2013, we believe that we will receive proceeds in excess of $150 million in 2014 that were held back for title review and other purposes at the time of closing (see Haynesville and Eagle Ford divestitures and Mississippi Lime joint venture below). Currently, we are marketing or currently have under contract certain real estate and other non-E&P assets, excluding COS, that are expected to generate proceeds of more than $650 million during 2014. Together, the items listed above and excluding any proceeds we may receive from a COS transaction, are expected to generate proceeds of approximately $1 billion, and we believe the sale of these assets will have minimal impact on our 2014 operating cash flow guidance. Major 2013 Natural Gas and Oil Property Sales In November 2013, we sold a wholly owned subsidiary, MKR Holdings, L.L.C. (MKR), to Chief Oil and Gas and two of its working interest partners, Enerplus and Tug Hill. Net proceeds from the transaction were approximately $490 million. MKR held producing wells and undeveloped acreage in the Marcellus Shale in Bradford, Lycoming, Sullivan, Susquehanna and Wyoming counties, Pennsylvania. 39 -------------------------------------------------------------------------------- In July 2013, we sold assets in the Haynesville Shale to EXCO Operating Company, LP (EXCO) for net proceeds of approximately $257 million. Subsequent to closing, we have received approximately $47 million of additional net proceeds for post-closing adjustments. The assets sold included our operated and non-operated interests in approximately 9,600 net acres in DeSoto and Caddo parishes, Louisiana. Also in July 2013, we sold assets in the northern Eagle Ford Shale to EXCO for net proceeds of approximately $617 million. Subsequent to closing, we have received approximately $32 million of additional net proceeds for post-closing adjustments and may receive up to $64 million of additional net proceeds for further post-closing adjustments. The assets sold included approximately 55,000 net acres in Zavala, Dimmit, La Salle and Frio counties, Texas. 2013 Natural Gas and Oil Property Joint Venture In June 2013, we completed a strategic joint venture with Sinopec International Petroleum Exploration and Production Corporation (Sinopec) in which Sinopec purchased a 50% undivided interest in approximately 850,000 acres (425,000 acres net to Sinopec) in the Mississippi Lime play in northern Oklahoma. Total consideration for the transaction was approximately $1.020 billion in cash, of which approximately $949 million of net proceeds was received upon closing. We also received an additional $90 million at closing related to closing adjustments for activity between the effective date and closing date of the transaction. We may receive up to an additional $71 million of net proceeds for post-closing adjustments. All future exploration and development costs in the joint venture will be shared proportionately between the parties with no drilling carries involved. Major 2013 Midstream Asset Sales In August 2013, our wholly owned subsidiary, Chesapeake Midstream Development, L.L.C. (CMD), sold its wholly owned midstream subsidiary, Mid-America Midstream Gas Services, L.L.C. (MAMGS), to SemGas, L.P. (SemGas), a wholly owned subsidiary of SemGroup Corporation, for net proceeds of approximately $306 million. We recorded a $141 million gain associated with the transaction. MAMGS owned certain gathering and processing assets located in the Mississippi Lime play, and the transaction with SemGas included a new long-term fixed-fee gathering and processing agreement covering acreage dedication areas in the Mississippi Lime play. In May 2013, CMD sold its wholly owned subsidiary, Granite Wash Midstream Gas Services, L.L.C. (GWMGS), to MarkWest Oklahoma Gas Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE), for net proceeds of approximately $252 million. We recorded a $105 million gain associated with this transaction. GWMGS owned certain midstream assets in the Anadarko Basin that service the Granite Wash and Hogshooter formations. The transaction with MWE included new long-term fixed-fee agreements for gas gathering, compression, treating and processing services. In March 2013, CMD sold its interest in certain gathering system assets in Pennsylvania to Western Gas Partners, LP (NYSE:WES) for net proceeds of approximately $134 million. We recorded a $55 million gain associated with this transaction. Liquidity and Capital Resources Liquidity Overview As of December 31, 2013, we had approximately $4.909 billion in cash availability (defined as unrestricted cash on hand plus borrowing capacity under our revolving bank credit facilities) compared to $4.338 billion as of December 31, 2012. During 2013, we decreased our debt, net of unrestricted cash, by approximately $284 million, to $12.049 billion. As of December 31, 2013, we had negative working capital of approximately $1.859 billion compared to negative working capital of approximately $2.854 billion (excluding current maturity of debt) as of December 31, 2012. Historically, working capital deficits have existed primarily because our capital spending has exceeded our cash flow from operations. Our business is capital intensive. During the year ended December 31, 2013, our capital expenditures exceeded cash flow from operations, and we filled this spending gap with borrowings and proceeds from our joint venture with Sinopec and from sales of assets that we determined were noncore or did not fit our long-term plans. In addition, as of December 31, 2013 we had full availability under our corporate revolving bank credit facility, providing significant additional liquidity if necessary. For 2014, we are projecting that our capital expenditures will approximate our cash flow from operations. 40 -------------------------------------------------------------------------------- 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 results of operations. 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 68% of our 2014 estimated natural gas production at an average price of $4.15 per mcf and 58% of our 2014 estimated oil production at an average price of $93.92 per bbl. See Quantitative and Qualitative Disclosures about Market Risk in Item 7A of 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. As part of our asset sales planning and capital expenditure budgeting process, we closely monitor the resulting effects on the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our corporate revolving bank credit facility. While asset sales enhance our ability to reduce debt, sales of producing natural gas and oil properties may adversely affect the amount of cash flow and EBITDA we generate in future periods and reduce the amount and value of collateral available to secure our obligations, both of which can be exacerbated by low prices for our production. In September 2012, we obtained an amendment to our corporate revolving bank credit facility agreement that increased the required 4.00 to 1.00 indebtedness to EBITDA ratio for the quarter ended September 30, 2012 and the four subsequent quarters. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for discussion of the terms of the amendment and the early termination of its provisions on June 28, 2013. For the quarter ended December 31, 2013 and the four previous quarters, our indebtedness to EBITDA ratio was less than 4.00 to 1.00, the ratio currently in effect and which existed prior to the amendment. Failure to maintain compliance with the covenants of our revolving bank credit facility agreement could result in the acceleration of outstanding indebtedness under the facility and lead to cross defaults under our senior note and contingent convertible senior note indentures, secured hedging facility, equipment master lease agreements and term loan. 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 consolidated financial statements included in Item 8 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. 41 -------------------------------------------------------------------------------- Sources of Funds The following table presents the sources of our cash and cash equivalents for the years ended December 31, 2013, 2012 and 2011. See Divestitures above and Notes 8, 12, 13 and 15 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of sales of natural gas and oil assets, other assets, investments, and preferred interests and noncontrolling interests in subsidiaries. Years Ended December 31, 2013 2012 2011 ($ in millions) Cash provided by operating activities $ 4,614 $ 2,837 $ 5,903 Sales of natural gas and oil assets: Eagle Ford 636 - - Marcellus 490 - - Haynesville 304 - - Permian Basin - 3,130 - Texoma - 572 - Chitwood Knox - 540 - Fayetteville Shale - - 4,270 SIPC (Mississippi Lime) joint venture 1,025 - - TOT (Utica) joint venture - - 610 CNOOC (Niobrara) joint venture - - 553 TOT (Barnett) joint venture - - 425 Volumetric production payments - 744 849 Joint venture leasehold 58 272 511 Other natural gas and oil properties 954 626 433 Total sales of natural gas, oil and other assets 3,467 5,884 7,651 Sales of other assets: Sale of Chesapeake Midstream Operating, L.L.C. (CMO) - 2,160 - Sale of Appalachia Midstream Services, L.L.C. (AMS) - - 879 Sale of Mid-America Midstream Gas Services, L.L.C. (MAMGS) 306 - - Sale of Granite Wash Midstream Gas Services, L.L.C. (GWMGS) 252 - - Sales of other property and equipment 364 332 433 Total proceeds from sales of other property and equipment 922 2,492 1,312 Other sources of cash and cash equivalents: Sale of investment in ACMP - 2,000 - Sale of preferred interest and ORRI in CHK C-T - 1,250 - Sale of preferred interest and ORRI in CHK Utica - - 1,250 Sale of noncontrolling interest in Chesapeake Granite Wash Trust - - 410 Proceeds from long-term debt, net 2,274 6,985 1,614 Proceeds from sales of other investments 115 - - Cash received from financing derivatives(a) - - 1,043 Other 187 84 442 Total other sources of cash and cash equivalents 2,576 10,319 4,759 Total sources of cash and cash equivalents $ 11,579 $ 21,532 $ 19,625 ___________________________________________ (a) Reflects derivatives deemed to contain, for accounting purposes, a significant financing element at contract inception. 42-------------------------------------------------------------------------------- Cash provided by operating activities was $4.614 billion in 2013 compared to $2.837 billion in 2012 and $5.903 billion in 2011. The increase in cash provided by operating activities from 2012 to 2013 is primarily the result of an increase in prices received for natural gas, oil and NGL sold (excluding the effect of gains or losses on derivatives) from $22.61 per boe in 2012 to $28.33 per boe in 2013, an increase in oil and NGL sales volumes and decreases in certain of our operating expenses per unit. The decline in cash provided by operating activities from 2011 to 2012 is primarily the result of a decrease in the natural gas price received for natural gas sold (excluding the effect of gains or losses on derivatives) from $3.12 per mcf in 2011 to $1.77 per mcf in 2012. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, depletion and amortization, impairments of natural gas and oil properties and other assets, deferred income taxes and mark-to-market changes in our derivative instruments. See the discussion below under Results of Operations. The following table reflects the proceeds received from issuances of debt in 2013, 2012 and 2011. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion. Years Ended December 31, 2013 2012 2011 Principal Principal Principal Amount of Net Amount of Net Amount of Net Debt Issued Proceeds Debt Issued Proceeds Debt Issued Proceeds ($ in millions) Senior notes $ 2,300 $ 2,274 $ 1,300 $ 1,263 $ 1,650 $ 1,614 Term loans - - 6,000 5,722 - - Total $ 2,300 $ 2,274 $ 7,300 $ 6,985 $ 1,650 $ 1,614 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 $7.669 billion and repaid $7.682 billion in 2013, borrowed $20.318 billion and repaid $21.650 billion in 2012 and borrowed $15.509 billion and repaid $17.466 billion in 2011 under our revolving bank credit facilities. 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 our lenders might make in the future. We believe our borrowing capacity under this 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. Prior to June 15, 2012, we also had a $600 million midstream revolving bank credit facility, which we terminated in June 2012. Our revolving bank credit facilities are described below under Bank Credit Facilities. 43 -------------------------------------------------------------------------------- Uses of Funds The following table presents the uses of our cash and cash equivalents for 2013, 2012 and 2011: Years Ended December 31, 2013 2012 2011 ($ in millions) Natural Gas and Oil Expenditures: Drilling and completion costs(a) $ (5,490 ) $ (8,707 ) $ (7,257 ) Acquisitions of proved properties (22 ) (342 ) (48 ) Acquisitions of unproved properties (280 ) (2,043 ) (4,296 ) Geological and geophysical costs (33 ) (170 ) (192 ) Interest capitalized on unproved properties (811 ) (829 ) (648 ) Total natural gas and oil expenditures (6,636 ) (12,091 ) (12,441 ) Other Uses of Cash and Cash Equivalents: Additions to other property and equipment(b) (972 ) (2,651 ) (2,009 ) Acquisition of drilling company - - (339 ) Payments on credit facility borrowings, net (13 ) (1,332 ) (1,957 ) Cash paid to purchase debt (2,141 ) (4,000 ) (2,015 ) Cash paid for prepayment of mortgage (55 ) - - Dividends paid (404 ) (398 ) (379 ) Cash paid to purchase preferred shares of subsidiary (212 ) - - Cash paid to extinguish other financing (141 ) - - Distributions to noncontrolling interest owners (215 ) (218 ) (9 ) Cash paid for financing derivatives(c) (91 ) (37 ) - Additions to investments (44 ) (395 ) - Other (105 ) (474 ) (227 ) Total other uses of cash and cash equivalents (4,393 ) (9,505 ) (6,935 ) Total uses of cash and cash equivalents $ (11,029 ) $ (21,596 ) $ (19,376 ) ___________________________________________ (a) Net of $884 million, $784 million and $2.570 billion in drilling and completion carries received from our joint venture partners during 2013, 2012 and 2011, respectively. (b) Includes approximately $240 million and $36 million (excluding lease termination costs) in 2013 and 2012, respectively, to purchase rigs and compressors subject to sale leaseback agreements, lowering our future operating lease commitments. See Notes 4 and 16 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of these transactions. (c) 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 2012, our average operated rig count was 131 rigs as we were quickly ramping up our liquids-focused drilling while gradually ramping down drilling of natural gas wells. During 2013, our average rig count was 71 operated rigs, and as of February 20, 2014, our rig count was 63 operated rigs. Our 2013 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 enabled us to hold by production the related leasehold according to the terms of our leases. Our unproved property leasehold acquisition costs were $280 million during 2013, a substantial decrease from prior years. Through 2012, the Company invested heavily in unproved properties and now holds a substantial inventory of resources that provides a foundation for future growth. We believe that focusing on profitable and efficient growth from captured resources will allow us to deliver attractive profit margins and financial returns in the future through all phases of the commodity price cycle. 44 -------------------------------------------------------------------------------- Capital expenditures related to additions to property and equipment associated with our midstream, oilfield services and other fixed assets of $972 million, $2.651 billion and $2.009 billion during 2013, 2012 and 2011, respectively, were primarily related to the expansion of our gathering systems and the growth of our oilfield services assets, in particular our hydraulic fracturing assets. The $1.679 billion reduction of such expenditures in 2013 from 2012 is primarily the result of our sale of substantially all of our midstream business and most of our gathering assets in 2012 and 2013 and a reduction in capital expenditures for our oilfield services business. In late 2012, we fully repaid the $4.0 billion term loan that we established in May 2012 with cash proceeds from asset sales and proceeds from the issuance of the $2.0 billion term loan that we established in November 2012. We recorded approximately $200 million of losses associated with this repayment, including the write-off of $86 million of deferred charges. In 2011, we completed and settled tender offers to purchase $2.044 billion in principal amount of our senior notes and contingent convertible senior notes for $2.186 billion in cash, including approximately $171 million in cash premiums, primarily funded with a portion of the net proceeds we received from the sale of our Fayetteville Shale assets. We paid dividends on our common stock of $233 million, $227 million and $207 million in 2013, 2012 and 2011, respectively. We paid dividends on our preferred stock of $171 million, $171 million and $172 million in 2013, 2012 and 2011, respectively. Bank Credit Facilities During 2013, we had two revolving bank credit facilities as sources of liquidity. Corporate Oilfield Services Credit Facility(a) Credit Facility(b) ($ 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 December 31, 2013 $ - $ 405 Letters of credit outstanding as of December 31, 2013 $ 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 December 31, 2013. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the terms of our corporate credit facility, including the terms of an amendment that increased the required indebtedness to EBITDA ratio as of September 30, 2012 and the subsequent two quarters. Our indebtedness to EBITDA ratio as of December 31, 2013 was approximately 2.70 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. 45 -------------------------------------------------------------------------------- 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, term loan, corporate revolving bank credit facility, secured hedging facility and equipment master lease agreements). For further discussion of the terms of our oilfield services credit facility, see Note 3 of the notes to our consolidated financial statements included in Item 8 of this report. Hedging Facility We have a multi-counterparty secured hedging facility with 16 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 11 of the notes to our consolidated financial statements included in Item 8 of this report. Term Loan In November 2012, we established an unsecured five-year term loan credit facility in an aggregate principal amount of $2.0 billion for net proceeds of $1.935 billion. We used the proceeds from the term loan, along with proceeds from assets sales, to repay our $4.0 billion term loan credit facility established in May 2012. Our obligations under the facility rank equally with our outstanding senior notes and contingent convertible senior notes and are unconditionally guaranteed on a joint and several basis by our direct and indirect wholly owned subsidiaries that are subsidiary guarantors under the indentures for such notes. Amounts borrowed under the facility bear interest at a variable rate and the facility may be voluntarily repaid at any time, subject to applicable premiums, as provided in the agreement. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion. 46 -------------------------------------------------------------------------------- Senior Note Obligations In addition to outstanding borrowings under our revolving bank credit facilities and the term loan discussed above, our long-term debt consisted of the following as of December 31, 2013: December 31, 2013 ($ 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 97 7.25% senior notes due 2018 669 6.625% senior notes due 2019(c) 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(d) 396 2.5% contingent convertible senior notes due 2037(d) 1,168 2.25% contingent convertible senior notes due 2038(d) 347 Discount on senior notes(e) (324 ) Interest rate derivatives(f) 13 Total senior notes, net $ 10,514 ___________________________________________ (a) Due February 2015. (b) The principal amount shown is based on the exchange rate of $1.3743 to €1.00 as of December 31, 2013. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for information on our related foreign currency derivatives. (c) 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. (d) 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. (e) Included in this discount was $303 million as of December 31, 2013 associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. (f) See Note 11 of the notes to our consolidated financial statements included in Item 8 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 consolidated financial statements included in Item 8 of this report. 47 -------------------------------------------------------------------------------- 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 December 31, 2013, 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 ($1.548 billion as of December 31, 2013) and exploration and production companies that own interests in properties we operate ($478 million as of December 31, 2013). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During 2013, 2012 and 2011, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables. Contractual Obligations and Off-Balance Sheet Arrangements From time to time, we enter into arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2013, these arrangements and transactions included (i) operating lease agreements, (ii) VPPs (to purchase production and pay related production expenses and taxes in the future), (iii) open purchase commitments, (iv) open delivery commitments, (v) open drilling commitments, (vi) undrawn letters of credit, (vii) open gathering and transportation commitments and (viii) various other commitments we enter into in the ordinary course of business that could result in a future cash obligation. The table below summarizes our contractual cash obligations for both recorded obligations and certain off-balance sheet arrangements and commitments as of December 31, 2013. Payments Due By Period Less Than More Than Total 1 Year 1-3 Years 3-5 Years 5 Years ($ in millions) Long-term debt: Principal $ 13,230 $ - $ 2,566 $ 5,414 $ 5,250 Interest 4,615 753 1,267 987 1,608 Operating lease obligations(a) 375 118 191 65 1 Purchase obligations(b) 17,261 2,069 3,755 3,710 7,727 Unrecognized tax benefits(c) 323 6 - 317 - Standby letters of credit 23 23 - - - Deferred premium on call options 268 83 185 - - Other 93 15 28 16 34 Total contractual cash obligations(d) $ 36,188 $ 3,067 $ 7,992 $ 10,509 $ 14,620 ___________________________________________ (a) See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease obligations. Also, see Note 23 for a description of operating lease obligations reduced subsequent to December 31, 2013. (b) See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of gathering, processing and transportation agreements, drilling contracts and property and equipment purchase commitments. 48--------------------------------------------------------------------------------(c) See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a description of unrecognized tax benefits. (d) This table does not include the estimated discounted liability for future dismantlement, abandonment and restoration costs of natural gas and oil properties or derivative liabilities. See Notes 19 and 11, respectively, of the notes to our consolidated financial statements included in Item 8 of this report for more information on our asset retirement obligations and derivatives. This table also does not include our costs to produce reserves attributable to non-expense-bearing royalty and other interests in our properties, including VPPs, which are discussed below. 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 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. The amount of these VPP-related production expenses and taxes, based on cost levels as of December 31, 2013 pursuant to SEC reporting requirements, was estimated to be approximately $799 million in total and $163 million for the next twelve months on an undiscounted basis and approximately $648 million and $155 million, respectively, on a discounted basis using an annual discount rate of 10%. 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 12 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of commitments and VPPs, respectively. Derivative Activities 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 the exposure to adverse market changes, we have entered into various derivative instruments. Executive management is involved in all risk management activities and the Board of Directors reviews the Company's derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading. As of December 31, 2013, our natural gas and oil derivative instruments consisted of swaps, collars, options, swaptions and basis protection swaps. Item 7A. Quantitative and Qualitative Disclosures About Market Risk contains a description of each of these instruments and gains and losses on natural gas, oil and NGL derivatives during 2013, 2012 and 2011. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving our risk management objectives. Our commodity derivative activities allow us to predict with greater certainty the effective prices we will receive for our hedged production. We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or minimize a loss. Commodity markets are volatile and Chesapeake's derivative activities are dynamic. Mark-to-market positions under commodity derivative contracts fluctuate with commodity prices. As described under Hedging Facility in Note 11 of the notes to our consolidated financial statements included in Item 8 of this report, our secured multi-counterparty hedging facility allows us to minimize the potential liquidity impact of significant mark-to-market fluctuations in the value of such derivatives by pledging our proved reserves. 49 -------------------------------------------------------------------------------- The estimated fair values of our natural gas and oil derivative contracts as of December 31, 2013 and 2012 are provided below. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information concerning the fair value of our natural gas and oil derivative instruments. December 31, 2013 2012 ($ in millions) Derivative assets (liabilities): Fixed-price natural gas swaps $ (23 ) $ 24 Natural gas three-way collars (7 ) - Natural gas call options (210 ) (240 ) Natural gas basis protection swaps 3 (15 ) Fixed-price oil swaps (50 ) 68 Oil call options (265 ) (748 ) Oil call swaptions - (13 ) Oil basis protection swaps 1 - Estimated fair value $ (551 ) $ (924 ) Changes in the fair value of natural gas and oil derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to the hedged commodities, and locked-in gains and losses of settled designated derivative contracts are recorded in accumulated other comprehensive income and are transferred to earnings in the month of related production. As of December 31, 2013, 2012 and 2011, accumulated other comprehensive income included unrealized losses, net of related tax effects, totaling $159 million, $179 million and $162 million, respectively, associated with commodity derivative contracts. Based upon the market prices at December 31, 2013, we expect to transfer to earnings approximately $23 million of net loss included in accumulated other comprehensive income during the next 12 months. A detailed explanation of accounting for natural gas, oil and NGL derivatives appears under Application of Critical Accounting Policies - Derivatives elsewhere in this Item 7. Interest Rate Derivatives To mitigate a portion of our exposure to volatility in interest rates related to our senior notes and credit facilities, we enter into interest rate derivatives. For interest rate derivative contracts designated as fair value hedges, changes in fair values of the derivatives are recorded on the consolidated balance sheets as assets or (liabilities), with corresponding offsetting adjustments to the debt's carrying value. Changes in the fair value of derivatives not designated as fair value hedges, which occur prior to their maturity (i.e., temporary fluctuations in mark-to-market values), are reported currently in the consolidated statements of operations as interest expense. Gains or losses from interest rate derivative contracts are reflected as adjustments to interest expense on the consolidated statements of operations. The components of interest expense for the years ended December 31, 2013, 2012 and 2011 are presented below in Results of Operations - Interest Expense, and a detailed explanation of accounting for interest rate derivatives appears under Application of Critical Accounting Policies - Derivatives elsewhere in this Item 7. Foreign Currency Derivatives On December 6, 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. A detailed explanation of accounting for foreign currency derivatives appears under Application of Critical Accounting Policies - Derivatives elsewhere in this Item 7. 50 -------------------------------------------------------------------------------- Results of Operations General. For the year ended December 31, 2013, Chesapeake had net income of $894 million, or $0.73 per diluted common share, on total revenues of $17.506 billion. This compares to a net loss of $594 million, or $1.46 per diluted common share, on total revenues of $12.316 billion during the year ended December 31, 2012 and net income of $1.757 billion, or $2.32 per diluted common share, on total revenues of $11.635 billion during the year ended December 31, 2011. The year ended December 31, 2013 includes charges of approximately $546 million for the impairment of buildings, land, drilling rigs, gathering systems and other assets and $248 million related to restructuring and other termination costs incurred in connection with a workforce reduction, executive officer separations and other employee terminations. The charges reflect actions taken as a result of the company-wide review of our operations, assets and organizational structure in the second half of 2013. Certain other actions we expect to take in the future to further our strategic priorities of reducing financial leverage and complexity could negatively impact our future results of operations and/or liquidity. Going forward, we expect to incur further cash and noncash charges, including but not limited to impairments of fixed assets, lease termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. The net loss in 2012 was primarily driven by a $2.022 billion after-tax impairment of natural gas and oil properties recorded in the 2012 third quarter. See Impairment of Natural Gas and Oil Properties below. Natural Gas, Oil and NGL Sales. During 2013, natural gas, oil and NGL sales were $7.052 billion compared to $6.278 billion in 2012 and $6.024 billion in 2011. In 2013, Chesapeake produced and sold 244 mmboe for $6.923 billion at a weighted average price of $28.33 per boe, compared to 237 mmboe produced and sold in 2012 for $5.359 billion at a weighted average price of $22.61 per boe and 199 mmboe produced and sold in 2011 for $5.259 billion at a weighted average price of $26.42 per boe. The increase in the price received per boe in 2013 compared to 2012 resulted in an increase in revenues of $1.397 billion, and increased sales volumes resulted in a $167 million increase in revenues, for a total increase in revenues of $1.564 billion. For 2013, our average price received per mcf of natural gas of $2.22 compared to $1.77 in 2012 and $3.12 in 2011 (excluding the effect of derivatives). Oil prices received per barrel (excluding the effect of derivatives) were $95.17, $90.49 and $89.80 in 2013, 2012 and 2011, respectively. NGL prices realized per barrel (excluding the effect of derivatives) were $27.87, $29.89 and $40.96 in 2013, 2012 and 2011, respectively. In 2013, realized prices for natural gas were negatively affected by higher year-over-year natural gas gathering and transportation costs, primarily as a result of construction of midstream systems being undertaken in certain of our less mature operating areas and a fee associated with a production shortfall below the minimum volume commitment under our Barnett gathering agreement. For 2014, we expect that we will continue to see increased gathering and transportation costs and those increases are reflected in our natural gas price differential forecast for 2014. Gains and losses from our natural gas, oil and NGL derivatives resulted in a net increase in natural gas, oil and NGL revenues of $129 million, $919 million and $765 million in 2013, 2012 and 2011, respectively. See Item 7A of this report for a complete listing of all of our derivative instruments as of December 31, 2013. A change in natural gas, oil and NGL prices has a significant impact on our revenues and cash flows. Assuming our 2013 production levels, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in 2013 revenues and cash flows of approximately $109 million and $107 million, respectively, and an increase or decrease of $1.00 per barrel of liquids sold would result in an increase or decrease in 2013 revenues and cash flows of approximately $62 million and $60 million, respectively, without considering the effect of derivatives. 51 -------------------------------------------------------------------------------- Our company-wide reorganization in the 2013 second half resulted in two operating divisions replacing the four operating divisions we previously reported. 2012 and 2011 have been revised to reflect our current organization. The following tables show our production and average sales prices received by operating division for 2013, 2012 and 2011: 2013 Natural Gas Oil NGL Total (bcf) ($/mcf)(a) (mmbbl) ($/bbl)(a) (mmbbl) ($/bbl)(a) (mmboe) % ($/boe)(a) Southern(b) 692.9 2.09 37.6 95.57 16.7 26.32 169.7 69 32.30 Northern(c) 401.7 2.44 3.5 90.82 4.2 33.95 74.7 31 19.28 Total(d) 1,094.6 2.22 41.1 95.17 20.9 27.87 244.4 100 % 28.33 2012 Natural Gas Oil NGL Total (bcf) ($/mcf)(a) (mmbbl) ($/bbl)(a) (mmbbl) ($/bbl)(a) (mmboe) % ($/boe)(a) Southern(b) 868.0 1.68 30.3 90.78 15.8 28.78 190.8 81 24.43 Northern(c) 260.8 2.10 1.0 81.60 1.8 39.73 46.2 19 15.11 Total(d) 1,128.8 1.77 31.3 90.49 17.6 29.89 237.0 100 % 22.61 2011 Natural Gas Oil NGL Total (bcf) ($/mcf)(a) (mmbbl) ($/bbl)(a) (mmbbl) ($/bbl)(a) (mmboe) % ($/boe)(a) Southern(b) 867.8 3.06 16.4 90.00 13.5 39.62 174.5 88 26.76 Northern(c) 136.3 3.48 0.6 83.60 1.2 55.34 24.5 12 24.03 Total(d) 1,004.1 3.12 17.0 89.80 14.7 40.96 199.0 100 % 26.42 ___________________________________________ (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 2013, 2012 and 2011 was 31.7 mmboe, 17.8 mmboe and 3.5 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 2013, 2012 and 2011 was 28.9 mmboe, 30.3 mmboe and 23.9 mmboe, respectively. Our gathering agreements for Barnett and Haynesville require us to pay the service provider a fee for any production shortfall below certain annual minimum gathering volume commitments. These fees amounted to $0.03 per mcf in 2013, and we anticipate incurring shortfall fees in 2014 based on current production estimates. (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 2013, 2012 and 2011 was 62.9 mmboe, 40.5 mmboe and 20.2 mmboe, respectively. (d) 2013, 2012 and 2011 production levels reflect the impact of various asset sales and joint ventures. See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for information on our natural gas and oil property divestitures and joint ventures. Our average daily production of 670 mboe for 2013 consisted of approximately 3.0 bcf of natural gas (75% on an oil equivalent basis), approximately 169,800 bbls of liquids, consisting of approximately 112,600 bbls of oil (17% on an oil equivalent basis) and approximately 57,200 bbls of NGL (8% on an oil equivalent basis). Our year-over-year growth rate of oil production was 32% and our year-over-year growth rate of NGL production was 19%. Natural gas production declined 3% year over year primarily as a result of asset sales. 52 --------------------------------------------------------------------------------Excluding the impact of derivatives, our percentage of revenues from natural gas, oil and NGL is shown in the following table. 2013 2012 2011 Natural gas 36% 37% 60% Oil 56% 53% 29% NGL 8% 10% 11% Total 100% 100% 100% Marketing, Gathering and Compression Sales 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 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 marketing, gathering and compression assets. Chesapeake recognized $9.559 billion in marketing, gathering and compression revenues in 2013 with corresponding expenses of $9.461 billion, for a net margin before depreciation of $98 million. This compares to revenues of $5.431 billion and $5.090 billion, expenses of $5.312 billion and $4.967 billion and a net margin before depreciation of $119 million and $123 million in 2012 and 2011, respectively. Our revenues and operating expenses from our marketing business increased substantially in 2013 compared to 2012 and 2011. In 2013, we marketed significantly more oil and NGL from both Chesapeake-operated wells and for third parties while our marketing of natural gas was virtually unchanged. Due to the relative high prices of oil and NGL compared to natural gas, our revenues and expenses increased substantially. In addition, we entered into a variety of purchase and sales contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. These transactions also increased our marketing revenues and operating expenses. In addition, compression services increased in 2013 compared to 2012 and 2011, offset by the loss of activity from the sale of substantially all of our gathering business and most of our gathering assets in the 2012 and 2013. Our gathering business provided approximately $16 million, $51 million and $44 million of the total marketing, gathering and compression net margin, or 16%, 43% and 36%, in 2013, 2012 and 2011, respectively. 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 $895 million in oilfield services revenues in 2013 with corresponding expenses of $736 million, for a net margin before depreciation of $159 million. This compares to revenues of $607 million and $521 million, expenses of $465 million and $402 million and a net margin before depreciation of $142 million and $119 million in 2012 and 2011, respectively. Oilfield services revenues and expenses increased from 2011 to 2013, primarily as a result of the increase in third-party utilization of our oilfield services. Natural Gas, Oil and NGL Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $1.159 billion in 2013, compared to $1.304 billion in 2012 and $1.073 billion in 2011. On a unit-of-production basis, production expenses were $4.74 per boe in 2013 compared to $5.50 and $5.39 per boe in 2012 and 2011, respectively. The per unit expense decrease in 2013 was primarily the result of a general improvement in operating efficiencies across most of our operating areas as well as lower saltwater disposal costs and the divestiture in 2012 of our Permian Basin assets, which had comparatively high operating costs per unit of production. Production expenses in 2013, 2012 and 2011 included approximately $170 million, $220 million and $234 million, or $0.70, $0.93 and $1.18 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 in addition to the general improvement in operating efficiencies noted above. 53 --------------------------------------------------------------------------------The following table shows our production expenses by operating division and our ad valorem tax expenses for 2013, 2012 and 2011: 2013 2012 2011 Production Production Production Expenses $/boe Expenses $/boe Expenses $/boe ($ in millions, except per unit) Southern $ 925 5.46 $ 1,087 5.70 $ 875 5.01 Northern 164 2.19 143 3.10 136 5.57 1,089 4.46 1,230 5.19 1,011 5.08 Ad valorem tax 70 0.28 74 0.31 62 0.31 Total $ 1,159 4.74 $ 1,304 5.50 $ 1,073 5.39 Production Taxes. Production taxes were $229 million in 2013 compared to $188 million in 2012 and $192 million in 2011. On a unit-of-production basis, production taxes were $0.94 per boe in 2013 compared to $0.79 per boe in 2012 and $0.96 per boe in 2011. 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. The $41 million increase in production taxes in 2013 was primarily due to the increase in the unhedged price of our production from $22.61 per boe to $28.33 per boe. Production taxes in 2013, 2012 and 2011 included approximately $21 million, $20 million and $34 million, respectively, or $0.08, $0.08 and $0.17 per boe, respectively, associated with VPP production volumes. General and Administrative Expenses. General and administrative expenses were $457 million in 2013, $535 million in 2012 and $548 million in 2011, or $1.86, $2.26 and $2.75 per boe, respectively. The absolute and per unit expense decrease in 2013 was primarily due to our efforts to reduce our cost structure and increased emphasis on operational efficiencies, partially offset by an increase in legal expenses relating to various corporate matters. In addition, we anticipate the workforce reduction described below will result in future cost savings and help the Company demonstrate more profitable and efficient growth. Included in general and administrative expenses is stock-based compensation of $60 million in 2013, $71 million in 2012 and $92 million in 2011. See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our stock-based compensation. 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 $317 million, $434 million and $432 million of internal costs in 2013, 2012 and 2011, respectively, directly related to our natural gas and oil property acquisition and drilling and completion efforts. The decrease was primarily due to our cost structure initiatives and increased emphasis on operational efficiencies in addition to a substantial decrease in our acquisition of unproved properties and lower drilling and completion expenditures. Restructuring and Other Termination Costs. We recorded $248 million and $7 million of restructuring and other termination costs in 2013 and 2012, respectively. The 2013 amount primarily related to workforce reductions, senior management separations and our voluntary separation plan. The 2012 amount related to other termination benefits. The Company committed to a workforce reduction plan in September 2013 that resulted in a reduction of approximately 900 employees. In connection with the workforce reduction plan, we incurred a total charge of $66 million. The acceleration of vesting of stock-based compensation accounted for approximately $45 million of this expense. We also incurred charges of approximately $182 million in 2013 related to the separation from the Company of certain other employees, including approximately $107 million related to our former CEO and other executive officers that were outside the workforce reduction plan. See Note 17 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion. 54 -------------------------------------------------------------------------------- Natural Gas, Oil and NGL Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (DD&A) of natural gas, oil and NGL properties was $2.589 billion, $2.507 billion and $1.632 billion in 2013, 2012 and 2011, respectively. The $82 million and $875 million increases in 2013 and 2012 are primarily the result of 3% and 19% increases in production in 2013 and 2012, respectively, the 2012 decrease in the Barnett Shale and Haynesville Shale proved undeveloped reserves primarily as a result of downward price revisions, and the higher costs of liquids-rich plays compared to natural gas plays as we shift to a more liquids-focused strategy. 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 $10.59, $10.58 and $8.20 in 2013, 2012 and 2011, respectively. Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $314 million in 2013, compared to $304 million in 2012 and $291 million in 2011. Depreciation and amortization of other assets was $1.28, $1.28 and $1.46 per boe in 2013, 2012 and 2011, respectively. The increase in 2013 is primarily due to increases in depreciation resulting from additions to our hydraulic fracturing equipment during 2013 compared to 2012 and 2011, partially offset by significant decreases in depreciation for natural gas gathering assets, most of which were sold in 2012 and 2013. See Note 15 of the notes to our consolidated financial statements included in Item 8 of this report for information regarding these sales. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. To the extent company-owned oilfield services equipment is used to drill and complete our wells, a substantial portion of the depreciation (i.e., the portion related to our utilization of the equipment) is capitalized in natural gas and oil properties as drilling and completion costs. The following table shows depreciation expense by asset class for 2013, 2012 and 2011 and the estimated useful lives of these assets. Years Ended December 31, Estimated Useful 2013 2012 2011 Life ($ in millions) (in years) Oilfield services equipment(a) $ 122 $ 61 $ 52 3 - 15 Natural gas gathering systems and treating plants(b) 13 46 58 20 Buildings and improvements 47 42 34 10 - 39 Natural gas compressors(b) 35 26 18 3 - 20 Computers and office equipment 44 45 40 3 - 7 Vehicles 38 52 46 0 - 7 Other 15 32 43 2 - 20 Total depreciation and amortization of other assets $ 314 $ 304 $ 291 ___________________________________________ (a) Included in our oilfield services operating segment. (b) Included in our marketing, gathering and compression operating segment. Impairment of Natural Gas and Oil Properties. In 2012, we reported a non-cash impairment charge on our natural gas and oil properties of $3.315 billion, primarily resulting from a 10% decrease in trailing 12-month average first-day-of-the-month natural gas prices as of September 30, 2012 compared to June 30, 2012, and the impairment of certain undeveloped leasehold, primarily in the Williston and DJ Basins. We account for our natural gas and oil properties using the full cost method of accounting, which limits the amount of costs we can capitalize and requires us to write off these costs if the carrying value of natural gas and oil assets in the evaluated portion of our full cost pool exceeds the sum of the present value of expected future net cash flows of proved reserves using a 10% pre-tax discount rate based on pricing and cost assumptions prescribed by the SEC and the present value of natural gas and oil derivative instruments designated as cash flow hedges. See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairment of natural gas and oil properties. Impairments of Fixed Assets and Other. In 2013, 2012 and 2011, we recognized $546 million, $340 million and $46 million, respectively, of impairment losses and other charges primarily related to buildings, land, gathering systems and drilling rigs. See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our impairments of fixed assets and other. 55 -------------------------------------------------------------------------------- Net Gains on Sales of Fixed Assets. In 2013, net gains on sales of fixed assets were $302 million compared to net gains of $267 million and $437 million in 2012 and 2011, respectively, primarily related to gathering systems sold. See Note 15 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our net gains on sales of fixed assets. Interest Expense. Interest expense was $227 million in 2013 compared to $77 million in 2012 and $44 million in 2011 as follows: Years Ended December 31, 2013 2012 2011 ($ in millions) Interest expense on senior notes $ 740 $ 732 $ 653 Interest expense on credit facilities 38 70 70 Interest expense on term loans 116 173 - Realized (gains) losses on interest rate derivatives(a) (9 ) (1 ) 7 Unrealized (gains) losses on interest rate derivatives(b) 67 (6 ) 7 Amortization of loan discount, issuance costs and other 91 89 39 Capitalized interest (816 ) (980 ) (732 ) Total interest expense $ 227 $ 77 $ 44 Average senior notes borrowings 10,991 10,487 9,373 Average term loan borrowings 2,000 2,096 - Average credit facilities borrowings 678 2,517 2,830 ___________________________________________ (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 $0.65 per boe in 2013 compared to $0.35 per boe in 2012 and $0.18 per boe in 2011. The increase in 2013 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. Earnings (Losses) on Investments. Losses on investments were $226 million in 2013, compared to losses of $103 million in 2012 and earnings of $156 million in 2011. The 2013 and 2012 losses primarily related to our equity in the net loss of FTS International, Inc. (FTS). The 2011 earnings primarily related to our equity in the net income of ACMP. See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our investments. Gains (Losses) on Sales of Investments. We recorded losses on sales of investments of $7 million in 2013 and gains on sales of investments of $1.092 billion in 2012. In 2013, we sold all of our shares of Clean Energy Fuels Corp. (Clean Energy) for cash proceeds of $13 million. We also sold our $100 million investment in Clean Energy convertible notes for cash proceeds of $85 million. We recorded a $15 million loss related to the sale of the Clean Energy convertible notes and a $3 million gain related to the sale of the Clean Energy common stock. In addition, in 2013 we sold a $1 million equity investment for cash proceeds of $6 million and recorded a $5 million gain. In 2012, we sold all of our common and subordinated units representing limited partner interests in ACMP and all of our limited liability company interests in the sole member of its general partner for cash proceeds of $2.0 billion. We recorded a $1.032 billion pre-tax gain associated with the transaction. Also in 2012, we sold our investment in Glass Mountain Pipeline, LLC for cash proceeds of $99 million. We recorded a $62 million gain associated with the transaction. Losses on Purchases of Debt and Extinguishment of Other Financing. We recorded losses on purchases of debt and extinguishment of other financing of $193 million in 2013, $200 million in 2012 and $176 million in 2011. In 2013, we terminated the financing master lease agreement on our real estate surface properties in the Fort Worth, Texas area for $258 million and recorded a loss of approximately $123 million associated with the extinguishment. Also, in 56 -------------------------------------------------------------------------------- 2013, we completed tender offers to purchase $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million. We recorded a loss of approximately $37 million associated with the tender offers, including $32 million in premiums and $5 million of unamortized deferred charges. In addition, we redeemed $1.3 billion in aggregate principal amount of our 6.775% Senior Notes due 2019 at par pursuant to a notice of special early redemption. We recorded a loss of approximately $33 million associated with the redemption, including $19 million of unamortized deferred charges and $14 million of discount. In 2012, we used proceeds from asset sales and our November 2012 term loan to fully repay our May 2012 term loans. We recorded $200 million of losses associated with the repayment, including $86 million of deferred charges and $114 million of debt discount. In 2011, we completed tender offers to purchase $1.373 billion in aggregate principal amount of certain of our senior notes and $531 million in aggregate principal amount of certain of our contingent convertible senior notes. Associated with the tender offers, we recorded losses of approximately $166 million related to the senior notes and $8 million related to the contingent convertible senior notes. Also during 2011, we purchased $140 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for approximately $128 million. Associated with these purchases, we recognized a loss of $2 million in 2011. Other Income. Other income was $26 million, $8 million and $23 million in 2013, 2012 and 2011, respectively. The 2013 other income consisted of $5 million of interest income and $21 million of miscellaneous income. The 2012 income consisted of $1 million of interest income and $7 million of miscellaneous income. The 2011 income consisted of $3 million of interest income and $20 million of miscellaneous income. Income Tax Expense (Benefit). Chesapeake recorded income tax expense of $548 million in 2013 compared to an income tax benefit of $380 million in 2012 and income tax expense of $1.123 billion in 2011. Our effective income tax rate was 38% in 2013 and 39% in both 2012 and 2011. 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 $170 million, $175 million and $15 million in 2013, 2012 and 2011, 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 8 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of these entities. Application of Critical Accounting Policies Readers of this report and users of the information contained in it should be aware that certain events may impact our financial results based on the accounting policies in place. The three policies we consider to be the most significant are discussed below. The Company's management has discussed each critical accounting policy with the Audit Committee of the Company's Board of Directors. The selection and application of accounting policies are an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment in the specific set of circumstances existing in our business. Natural Gas and Oil Properties. The accounting for our business is subject to special accounting rules that are unique to the natural gas and oil industry. There are two allowable methods of accounting for natural gas and oil business activities: the successful efforts method and the full cost method. Chesapeake follows the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not capitalize any costs related to production, general corporate overhead or similar activities. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of natural gas and oil properties are generally calculated on a well by well or lease or field basis versus the aggregated "full cost" pool basis. Additionally, gain or loss is generally recognized on all sales of natural gas and oil properties under the successful efforts method. As a result, our financial statements differ from those of companies that apply the successful efforts 57 -------------------------------------------------------------------------------- method since we generally reflect a higher level of capitalized costs as well as a higher natural gas and oil depreciation, depletion and amortization rate, and we do not have exploration expenses that successful efforts companies frequently have. Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved natural gas and oil reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred. Unevaluated properties are grouped by major producing area where individual property costs are not significant. We review the carrying value of our natural gas and oil properties under the SEC's full cost accounting rules on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for natural gas and oil cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating estimated future net revenues, current prices are calculated as the unweighted arithmetic average of natural gas and oil prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. Costs used are those as of the end of the applicable quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. Two primary factors impacting this test are reserve levels and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. See Natural Gas and Oil Properties in Note 1 of the notes to our consolidated financial statements included in Item 8 of this report for further information on the full cost method of accounting. Derivatives. Chesapeake uses commodity price and financial risk management instruments to mitigate a portion of our exposure to price fluctuations in natural gas and oil prices, changes in interest rates and foreign exchange rates. Gains and losses on derivative contracts are reported as a component of the related transaction. Results of commodity derivative contracts are reflected in natural gas, oil and NGL sales, and results of interest rate and foreign exchange rate derivative contracts are reflected in interest expense. The changes in the fair value of derivative instruments not qualifying, or not elected, for designation as either cash flow or fair value hedges that occur prior to maturity are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas, oil and NGL sales or interest expense. Cash settlements of our derivative arrangements are generally classified as operating cash flows unless the derivative is deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statements of cash flows. Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheets as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as natural gas, oil and NGL cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings as natural gas, oil and NGL sales. Any change in the fair value resulting from ineffectiveness is recognized immediately in natural gas, oil and NGL sales. For interest rate derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings as interest expense. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges 58 -------------------------------------------------------------------------------- are also recognized currently in earnings. See Derivative Activities above and Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information regarding our derivative activities. One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established 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-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. 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. Additionally, in accordance with accounting guidance for derivatives and hedging, to the extent that a legal right of set-off exists, we net the value of our derivative instruments with the same counterparty in the accompanying consolidated balance sheets. Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the derivative instruments and the transactions being hedged, both at inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our derivative instruments are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control. Due to the volatility of natural gas, oil and NGL prices and, to a lesser extent, interest rates and foreign exchange rates, the Company's financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2013, 2012 and 2011, the fair value of our derivatives were liabilities of $649 million, $979 million and $1.719 billion, respectively. Income Taxes. As part of the process of preparing the consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which Chesapeake operates. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as derivative instruments, depreciation, depletion and amortization, and certain accrued liabilities for tax and accounting purposes. These differences and our net operating loss carryforwards result in deferred tax assets and liabilities, which are included in our consolidated balance sheets. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. Generally, to the extent Chesapeake establishes a valuation allowance or increases or decreases this allowance in a period, we must include an expense or reduction of expense within the tax provision in the consolidated statement of operations. Under accounting guidance for income taxes, an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (i) the more positive evidence is necessary and (ii) the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. Among the more significant types of evidence that we consider are: • taxable income projections in future years; • whether the carryforward period is so brief that it would limit realization of the tax benefit; • future sales and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures; and • our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition. If (i) natural gas and oil prices were to decrease significantly below present levels (and if such decreases were considered other than temporary), (ii) exploration, drilling and operating costs were to increase significantly beyond current levels, or (iii) we were confronted with any other significantly negative evidence pertaining to our ability to realize our net operating loss carryforwards prior to their expiration, we may be required to provide a valuation allowance against our deferred tax assets. As of December 31, 2013 and 2012, we had deferred tax assets of $1.621 billion and $1.726 billion, respectively, upon which we had a valuation allowance of $148 million and $160 million, respectively, for certain state net operating losses that we have concluded are not more likely than not to be utilized prior to expiration. 59 -------------------------------------------------------------------------------- Accounting guidance for recognizing and measuring uncertain tax positions prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. Based on this guidance, we regularly analyze tax positions taken or expected to be taken in a tax return based on the threshold condition prescribed. Tax positions that do not meet or exceed this threshold condition are considered uncertain tax positions. We accrue interest related to these uncertain tax positions which is recognized in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. Additional information about uncertain tax positions appears in Note 6 of the notes to our consolidated financial statements included in Item 8 of this report. Disclosures About Effects of Transactions with Related Parties Former Chief Executive Officer On April 1, 2013, Aubrey K. McClendon, the co-founder of the Company, ceased serving as President and CEO and as a director of the Company pursuant to his agreement with the Board of Directors announced on January 29, 2013. Since Chesapeake was founded in 1989, Mr. McClendon and his affiliates have acquired working interests in virtually all of our natural gas and oil properties by participating in our drilling activities under the terms of Mr. McClendon's employment agreements and, since 2005, the Founder Well Participation Program (FWPP). The Company is reimbursed for costs associated with leasehold acquired under the FWPP, and well costs are charged to FWPP interests based on percentage ownership. On April 30, 2012, the Company's Board of Directors and Mr. McClendon agreed to terminate the FWPP 18 months before the end of the 10-year term approved by our shareholders in June 2005. Mr. McClendon has elected to participate in the FWPP through the expiration of the FWPP on June 30, 2014 at the maximum 2.5% working interest permitted, the same participation percentage that Mr. McClendon has elected every year since 2004. The Compensation Committee of the Board of Directors, which administers and interprets the FWPP, is reviewing with the assistance of independent counsel the prior administration of the plan. As of December 31, 2013 and 2012, we had accrued accounts receivable from Mr. McClendon of $62 million and $23 million, respectively, representing FWPP joint interest billings. In conjunction with certain sales of natural gas and oil properties by the Company, affiliates of Mr. McClendon have sold interests in the same properties and on the same terms as those that applied to the interests sold by the Company, and the proceeds were paid to the sellers based on their respective ownership percentages. These interests were acquired through the FWPP. On December 31, 2008, we entered into a new five-year employment agreement with Mr. McClendon that contained a one-time well cost incentive award to him. The total cost of the award to Chesapeake was $75 million plus employment taxes in the amount of approximately $1 million. The net incentive award, after deduction of applicable withholding and employment taxes, of approximately $44 million was fully applied against costs attributable to interests in Company wells acquired by Mr. McClendon or his affiliates under the FWPP. The incentive award was subject to a clawback provision equal to any unvested portion of the award if during the initial five-year term of the employment agreement, Mr. McClendon resigned from the Company or was terminated for cause by the Company. We recognized the incentive award as general and administrative expense over the five-year vesting period for the clawback, resulting in an expense of approximately $15 million per year beginning in 2009. The incentive award clawback did not apply to Mr. McClendon's termination in 2013. See Note 17 of the notes to our consolidated financial statements included in Item 8 of this report for additional information on the terms of Mr. McClendon's separation from the Company. On July 26, 2013, the Company and Mr. McClendon rescinded the December 2008 sale of an antique map collection pursuant to the terms of a settlement agreement terminating pending shareholder litigation that was approved by the District Court of Oklahoma County, Oklahoma on January 30, 2012 and affirmed on appeal. The Company returned the subject maps to Mr. McClendon, and Mr. McClendon paid the Company $12 million plus interest. 60 -------------------------------------------------------------------------------- Equity Method Investees Other than Mr. McClendon, only our equity method investees were considered related parties. During 2013, 2012 and 2011, we had the following related party transactions with our equity method investees. Years Ended December 31, 2013 2012 2011 ($ in millions) Purchases(a) $ - $ 73 $ - Sales(b) $ 666 $ 392 $ 171 Services(c) $ 397 $ 480 $ 369 ___________________________________________ (a) Purchase of equipment from FTS. (b) In 2013, 2012 and 2011, Chesapeake sold produced gas to our 30%-owned investee, Twin Eagle Resource Management LLC. (c) Hydraulic fracturing and other services provided to us by FTS in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs. The table below shows the total related party amounts due from and due to our equity method investees. December 31, 2013 2012 2011 ($ in millions)Amounts due from equity method investment related parties $ 47 $ 67 $ 29 Amounts due to equity method investment related parties $ 1 $ 42 $ 115 Recently Issued Accounting Standards Recently Adopted Accounting Standards In February 2012, the Financial Accounting Standards Board (FASB) issued guidance changing the presentation requirements of significant reclassifications out of accumulated other comprehensive income in their entirety and their corresponding effect on net income. We adopted this standard in the first quarter of 2013 and it did not have a material impact on our financial statements. In December 2011 and January 2013, the FASB issued guidance amending and expanding disclosure requirements about offsetting and related arrangements associated with derivatives. We adopted this standard in the first quarter of 2013 and it did not have a material impact on our financial statements. Recently Issued Accounting Standards To reduce diversity in practice related to the presentation of unrecognized tax benefits, in July 2013 the FASB issued guidance requiring the presentation of an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward. This net presentation is required unless a net operating loss carryforward, a similar tax loss or a tax credit carryforward is not available at the reporting date or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset to settle any additional income tax that would result from the disallowance of the unrecognized tax benefit. The guidance will be effective on January 1, 2014; retrospective application and early adoption are permitted, but not required. Because we have historically presented unrecognized tax benefits net of net operating loss carryforwards, similar tax losses or tax credit carryforwards, this standard will not impact our consolidated financial statements. In February 2013, the FASB 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 will adopt this standard effective January 1, 2014. We do not expect the adoption to have a material impact on our consolidated financial statements. 61 -------------------------------------------------------------------------------- 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 this report 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; • 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 62 -------------------------------------------------------------------------------- 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. 63-------------------------------------------------------------------------------- |