Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Financial Data

The following table sets forth certain information regarding our production volumes, oil, natural gas and NGL sales, average sales prices received, and other operating income and expenses for the periods indicated:

Years Ended December 31,
201620152014
Net Production:
Oil (mmbbl)334242
Natural gas (bcf)1,0491,0701,095
NGL (mmbbl)242833
Oil equivalent (mmboe)(a)233248258
Oil, Natural Gas and NGL Sales ($ in millions):
Oil sales$1,351$1,904$3,778
Oil derivatives – realized gains (losses)(b)97880(185)
Oil derivatives – unrealized gains (losses)(b)(318)(536)859
Total oil sales1,1302,2484,452
Natural gas sales2,1552,4704,535
Natural gas derivatives – realized gains (losses)(b)151437(191)
Natural gas derivatives – unrealized gains (losses)(b)(500)(157)535
Total natural gas sales1,8062,7504,879
NGL sales3603931,023
NGL derivatives – realized gains (losses)(b)(8)——
NGL derivatives – unrealized gains (losses)(b)———
Total NGL sales3523931,023
Total oil, natural gas and NGL sales$3,288$5,391$10,354
Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)$40.65$45.77$89.41
Natural gas ($ per mcf)$2.05$2.31$4.14
NGL ($ per bbl)$14.76$14.06$30.95
Oil equivalent ($ per boe)$16.63$19.23$36.21
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)$43.58$66.91$85.04
Natural gas ($ per mcf)$2.20$2.72$3.97
NGL ($ per bbl)$14.43$14.06$30.95
Oil equivalent ($ per boe)$17.66$24.54$34.74
Other Operating Income ($ in millions):
Marketing, gathering and compression net margin(c)(d)$(194)$243$(11)
Oilfield services net margin$—$—$115
Years Ended December 31,
201620152014
Expenses ($ per boe):
Oil, natural gas and NGL production$3.05$4.22$4.69
Oil, natural gas and NGL gathering, processing and transportation$7.98$8.55$8.43
Production taxes$0.32$0.40$0.90
General and administrative(e)$1.03$0.95$1.25
Oil, natural gas and NGL depreciation, depletion and amortization$4.31$8.47$10.41
Depreciation and amortization of other assets$0.45$0.53$0.90
Interest expense(f)$1.18$1.30$0.63
Interest Expense ($ in millions):
Interest expense$286$329$173
Interest rate derivatives – realized (gains) losses(g)(11)(6)(12)
Interest rate derivatives – unrealized (gains) losses(g)21(6)(72)
Total interest expense$296$317$89
(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.
(b)Realized gains (losses) include the following items: (i) settlements and accruals for settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains (losses) related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains (losses) include the change in fair value of open derivatives scheduled to settle against future period production revenues (including current period settlements for option premiums and early terminated derivatives) offset by amounts reclassified as realized gains (losses) during the period.
(c)Includes revenue and operating costs. See Depreciation and Amortization of Other Assets under Results of Operations for details of the depreciation and amortization associated with our marketing, gathering and compression segment.
(d)For the years ended December 31, 2016 and 2015, we recorded unrealized losses of $297 million and unrealized gains of $296 million, respectively, on the fair value of our supply contract derivative. Additionally, in 2016, we sold the long-term natural gas supply contract to a third party for cash proceeds of $146 million. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for discussion related to this instrument.
(e)Excludes restructuring and other termination costs.
(f)Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives and is shown net of amounts capitalized.
(g)Realized (gains) losses include interest rate derivative settlements related to current period interest and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

Overview

For an overview of our business and strategy, please see Our Business and Business Strategy in Item 1 of this report.

Operating Results

Our 2016 production of 233 mmboe consisted of 33 mmbbls of oil (14% on an oil equivalent basis), 1.0 tcf of natural gas (75% on an oil equivalent basis), and 24 mmbbls of NGL (11% on an oil equivalent basis). Our daily production for 2016 averaged approximately 635 mboe, a decrease of 6% from 2015. Compared to 2015, average daily oil production decreased by 20% or approximately 23 mbbls per day; average daily natural gas production decreased by 2%, or approximately 64 mmcf per day; and average daily NGL production decreased by 13%, or approximately 10 mbbls per day. Our oil and NGL production decreased primarily as a result of the sale of certain of our Mid-Continent assets in 2016 and 2015 as well as a significant reduction in drilling activity. Adjusted for asset sales, our total daily production was comparable between 2016 and 2015. Our oil, natural gas and NGL revenues (excluding gains or losses on oil and natural gas derivatives) decreased approximately $901 million to $3.866 billion in 2016 compared to $4.767 billion in 2015, primarily due to significant decreases in the prices received for oil and natural gas sold in addition to lower oil, natural gas and NGL volumes sold. See Results of Operations below for additional details.

Capital Expenditures

Our drilling and completion capital expenditures during 2016 were approximately $1.316 billion and capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment were approximately $130 million, for a total of approximately $1.446 billion. In 2016, we operated an average of 10 rigs, a decrease of 18 rigs, or 64%, compared to 2015. As a result of lower drilling and completion activity, drilling and completion expenditures decreased approximately $1.7 billion in 2016 compared to 2015. The level of capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment decreased approximately $101 million compared to 2015.

Our capitalized interest was approximately $251 million and $424 million in 2016 and 2015, respectively. The decrease in capitalized interest resulted from a lower average balance of our unproved oil and natural gas properties, the primary asset on which interest is capitalized. Including capitalized interest, total capital investments were approximately $1.7 billion in 2016 compared to $3.6 billion for 2015, a decrease of 53%.

Based on planned activity levels for 2017, we project that 2017 capital expenditures for drilling and completions, leasehold, geological and geophysical and other property and equipment will be $1.9 - $2.5 billion, inclusive of capitalized interest, as compared to $1.7 billion of capital expenditures in 2016. See Liquidity and Capital Resources for additional information on how we plan to fund our capital budget.

Strategic Developments

Debt Issuances

In December 2016, we issued in a private placement $1.0 billion principal amount of unsecured 8.00% Senior Notes due 2025. In October 2016, we issued in a private placement $1.25 billion principal amount of unsecured 5.5% Convertible Senior Notes due 2026, which are convertible, under certain specified circumstances, into cash, common stock or a combination of cash and common stock, at our election. In August 2016, we entered into a secured five-year term loan facility in aggregate principal amount of $1.5 billion. We used the net proceeds from these issuances primarily to purchase and retire senior notes and contingent convertible senior notes as described below, with a focus on retiring debt scheduled to mature or that could be put to us in 2017 and 2018.

Debt Retirements

In January 2017, we repurchased in the open market approximately $221 million principal amount of our outstanding debt scheduled to mature or that could be put to us in 2018 and 2020 for $224 million. On January 20, 2017, we redeemed our $133 million principal amount of outstanding 6.5% Senior Notes due 2017. On January 6, 2017, we purchased and retired approximately $287 million principal amount of our outstanding contingent convertible senior notes and $2 million principal amount of our outstanding senior notes for an aggregate of $286 million pursuant to tender offers.

In 2016, we used the proceeds from our senior notes, convertible notes and term loan issuances to purchase and retire $2.035 billion aggregate principal amount of our outstanding senior notes and $849 million aggregate principal amount of our outstanding contingent convertible senior notes for an aggregate purchase price of $2.734 billion pursuant to tender offers, open market repurchases and repayment upon maturity. Additionally, we privately negotiated exchanges of (i) approximately $290 million principal amount of our outstanding senior notes for 53,923,925 shares of our common stock, and (ii) approximately $287 million principal amount of our outstanding contingent convertible senior notes for 55,427,782 shares of our common stock.

Credit Facility Amendment

In April 2016, we further amended our senior secured revolving credit facility agreement. Pursuant to the amendment, our borrowing base was reaffirmed in the amount of $4.0 billion (as a result of subsequent asset sales, our borrowing base was reduced to $3.8 billion) and our next scheduled borrowing base redetermination date was postponed until June 15, 2017, with the consenting lenders agreeing not to exercise their interim redetermination right prior to that date. The amendment also modified the credit agreement to provide for, among other things, (i) the suspension or modification of certain financial covenants, and (ii) the granting of liens and security interests on substantially all of our assets, including mortgages encumbering 90% of our proved oil and gas properties that constitute borrowing base properties, all derivative contracts and personal property, subject to certain agreed-upon carve outs. 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 revolving credit facility.

Preferred Stock Exchanges and Conversions

In January 2017, we completed private exchanges of an aggregate of approximately 10.0 million shares of our common stock for (i) 150,948 shares of 5.00% Cumulative Convertible Preferred Stock (Series 2005B), (ii) 72,600 shares of 5.75% Cumulative Convertible Preferred Stock and (iii) 12,500 shares of 5.75% Cumulative Convertible Preferred Stock (Series A). The preferred stock exchanged represents approximately $100 million of liquidation value.

In October and November 2016, we completed private exchanges of an aggregate of approximately 119.2 million shares of our common stock for (i) 134,000 shares of 5.00% Cumulative Convertible Preferred Stock (Series 2005B), (ii) 629,271 shares of 5.75% Cumulative Convertible Preferred Stock and (iii) 622,936 shares of 5.75% Cumulative Convertible Preferred Stock (Series A). The preferred stock exchanged represents approximately $1.3 billion of liquidation value.

In February and March 2016, certain preferred shareholders converted (i) 24,601 shares of 5.75% Cumulative Convertible Preferred Stock and (ii) 1,201 shares of 5.75% Cumulative Convertible Preferred Stock (Series A) into an aggregate of approximately 1 million shares of our common stock. The preferred stock converted represents approximately $26 million of liquidation value.

In January 2016, we suspended dividend payments on our convertible preferred stock to provide additional liquidity in the depressed commodity environment that existed throughout 2016. On February 15, 2017, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock and paid our dividends in arrears. The preferred stock exchanges and conversions completed in 2016 and 2017 eliminated approximately $80 million of annual dividend obligations.

Divestitures

During 2016 and into 2017, we sold oil and natural gas properties and related assets for net proceeds of approximately $2.3 billion, providing additional liquidity for debt reduction and operations. In addition, we purchased five of our VPP transactions for approximately $386 million, removing all future obligations we have with those VPPs.

In February 2017, we sold a portion of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $465 million, subject to certain customary post-closing adjustments. Included in the sale were approximately 41,500 net acres. The sale also included 326 operated and non-operated wells currently producing approximately 50 mmcf of gas per day.

In January 2017, we sold a portion of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $450 million, subject to certain customary post-closing adjustments. Included in the sale were approximately 78,000 net acres. The sale also included 250 wells currently producing approximately 30 mmcf of gas per day.

In October 2016, we conveyed our interests in the Barnett Shale operating area located in north central Texas and received from the buyer aggregate net proceeds of approximately $218 million. We sold approximately 212,000 net developed and undeveloped acres, approximately 2,900 operated wells which produced an average of approximately 59 mboe per day in the 2016 third quarter, along with other property and equipment. We simultaneously terminated most of our future natural gas gathering and transportation commitments associated with this asset. In connection with this disposition, we paid $361 million to terminate certain natural gas gathering and transportation agreements, and paid $58 million to restructure a long-term sales agreement. We may be required to pay additional amounts in respect of certain title and environmental contingencies. Additionally, we recognized a charge of $284 million related to the impairment of other fixed assets sold in the divestiture. By exiting the Barnett Shale, we eliminated approximately $1.9 billion of total future midstream and downstream commitments, leading to an expected increase in our operating income for 2017 through 2019 of $200 to $300 million annually.

In December 2016, we sold the majority of our upstream and midstream assets in the Devonian Shale located in West Virginia, Kentucky and Virginia for proceeds of $140 million. We sold an interest in approximately 1.3 million net acres, retaining all rights below the base of the Kope formation, and approximately 5,300 wells, along with related gathering assets, and other property and equipment. Additionally, we recognized an impairment charge of $142 million related to other fixed assets sold in the divestiture. In connection with this divestiture, we purchased one of our remaining VPP transactions for $127 million. All of the acquired interests were conveyed in our divestiture and we no longer have any future obligations related to this VPP.

In 2016, we sold certain of our other noncore assets for net proceeds of approximately $1.048 billion after post-closing adjustments. In conjunction with certain of these sales, we purchased four of our VPP transactions for approximately $259 million. A majority of the acquired interests were part of the asset divestitures discussed above and we no longer have any further commitments or obligations related to these VPPs. The asset divestitures cover various operating areas. We continue to pursue the sale of assets that do not fit in our strategic priorities.

Gathering, Processing and Transportation Agreements

In February 2017, we paid approximately $290 million to assign an oil transportation agreement. This assignment is expected to reduce our future oil transportation commitments by approximately $450 million. The assignment is effective April 1, 2017. In addition, we terminated future natural gas transportation commitments related to divested assets of approximately $110 million for a cash payment of approximately $100 million. This termination was effective March 1, 2017.

In December 2016, we restructured our natural gas gathering and service agreement in our Powder River Basin operating area with Williams Partners L.P. and Crestwood Equity Partners L.P. The restructured services will replace the current cost-of-service arrangement and improve economics which support increased development across an expanded area of dedication in the region. The restructured services were effective January 1, 2017, for a 20-year term.

In 2016, we renegotiated our natural gas gathering agreement with Williams in our Mid-Continent operating area in exchange for a net $57 million payment. We estimate a 36% reduction in Mid-Continent gathering costs over the life of the contract. This amount will be amortized to oil, natural gas and NGL gathering, processing and transportation expense over the life of the agreement.

In 2016, we amended certain of our firm transportation agreements in the Haynesville, Barnett and Eagle Ford operating areas, which will reduce our firm transportation volume commitments and fees. We estimate a benefit of approximately $650 million gross ($415 million net) over the term of the contracts, including $80 million gross ($50 million net) in lower unused demand charges for the underutilized capacity and lower transportation fees in 2016.

Other

In 2016, we sold a long-term natural gas supply contract for $146 million in cash proceeds.

Liquidity and Capital Resources

Liquidity Overview

Our ability to grow, make capital expenditures and service our debt depends primarily upon the prices we receive for the oil, natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically, oil and natural gas prices have been very volatile, and may be subject to wide fluctuations in the future. The substantial decline in oil, natural gas and NGL prices from 2014 levels has negatively affected the amount of cash we have available for capital expenditures and debt service. A substantial or extended decline in oil, natural gas and NGL prices could have a material impact on our financial position, results of operations, cash flows and on the quantities of reserves that we may economically produce. Other risks and uncertainties that could affect our liquidity include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks and our ability to meet financial ratios and covenants in our financing agreements.

As of December 31, 2016, we had a cash balance of $882 million compared to $825 million as of December 31, 2015, and we had a net working capital deficit of $1.506 billion, compared to a net working capital deficit of $1.205 billion as of December 31, 2015. We made significant progress in 2016 and into 2017 to reduce near-term debt maturities, including reducing our 2017 debt maturities by $1.878 billion, or 99%, and our 2018 debt maturities by $815 million, or 93%. As of February 24, 2017, we had $77 million of debt maturing or that could be put to us in 2017 and 2018. As of December 31, 2016, we had $2.749 billion of borrowing capacity available under our revolving credit facility, with no outstanding borrowings and $1.036 billion utilized for various letters of credit (including the $461 million supersedeas bond with respect to the 2019 Notes litigation). See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including principal and carrying amounts of our notes. Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.

In 2016, we took the following measures to improve our liquidity:

•entered into a secured five-year term loan facility in aggregate principal amount of $1.5 billion;
•issued $1.25 billion principal amount of unsecured 5.5% Convertible Senior Notes due 2026;
•issued $1.0 billion principal amount of unsecured 8.00% Senior Notes due 2025;
•exchanged 109 million shares of common stock for $577 million principal amount of our outstanding senior notes and contingent convertible senior notes, including $373 million principal amount that was scheduled to mature or could be put to us in 2017 or 2018;
•retired $2.884 billion principal amount of our outstanding senior notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $2.734 billion, including $1.621 billion principal amount that was scheduled to mature or could be put to us in 2017 and 2018;
•exchanged 120.2 million shares of common stock for $1.3 billion liquidation value of our preferred stock, eliminating $74 million of annual dividend obligations;
•further amended our revolving credit agreement to reaffirm our borrowing base, postpone our next scheduled borrowing base redetermination date and modify or suspend certain credit agreement financial covenants; and
•mitigated a portion of our downside exposure to commodity prices through derivative contracts, suspended dividend payments on our convertible preferred stock and divested assets to increase our liquidity.

Additionally in 2017, we retired $643 million aggregate principal amount of our outstanding senior notes and contingent convertible senior notes pursuant to tender offers, open market repurchases and redemptions. We also repaid our 6.25% Euro-denominated Senior Notes due 2017 upon maturity. We completed private exchanges of an aggregate of approximately 10.0 million shares of our common stock for approximately $100 million liquidation value of our preferred stock.

We may continue to access the capital markets or otherwise incur debt to refinance a portion of our outstanding indebtedness and improve our liquidity.

As operator of a substantial portion of our oil and natural gas properties under development, we have significant control and flexibility over the timing and execution of our development plan, enabling us to reduce our capital spending as needed. Our forecasted 2017 capital expenditures, inclusive of capitalized interest, are $1.9 - $2.5 billion, compared to our 2016 capital spending level of $1.7 billion. We currently plan to use cash flow from operations, cash on hand and availability under our revolving bank credit facility to fund our capital expenditures during 2017. We had liquidity (calculated as cash on hand and availability under our revolving credit facility) of approximately $3.4 billion as of February 24, 2017. We expect to generate additional liquidity with proceeds from future sales of assets that we determine do not fit our strategic priorities. Management continues to review operational plans for 2017 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL. We closely monitor 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 revolving credit facility.

Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, processing, transportation and hedging agreements. As of February 24, 2017, we have received requests and posted approximately $275 million in collateral under such arrangements (excluding the supersedeas bond with respect to the 2019 Notes litigation). We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $451 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.

In addition, during the next 12 months, we may be required to pay up to $440 million in connection with the judgment against us related to the redemption at par value of our 6.775% Senior Notes due 2019. In connection with our appeal of the decision by the U.S. District Court for the Southern District of New York regarding the redemption, we posted a supersedeas bond in the amount of $461 million in July 2015, which is reflected as an outstanding letter of credit under our revolving credit facility. This contingent payment is fully accrued on our consolidated balance sheet. See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the recent developments in this litigation.

To add more certainty to our future estimated cash flows by mitigating our downside exposure to lower commodity prices, as of February 24, 2017, we have downside price protection, through open swaps, on approximately 68% of our projected 2017 oil production at an average price of $50.19 per bbl. We also have downside price protection, through open swaps and collars, on approximately 71% of our projected 2017 natural gas production at an average price of $3.07 per mcf, of which 3% is hedged under two-way collar arrangements based on an average bought put NYMEX price of $3.00 per mcf. We also have downside price protection, through open swaps, on approximately 7% of our projected 2017 NGL production at an average price of $0.28 per gallon of ethane.

As highlighted above, we have taken measures to mitigate the liquidity concerns facing us in 2017 and beyond, but there can be no assurance that such measures will satisfy our needs. Further, our ability to generate operating cash flow in the current commodity price environment, sell assets, access capital markets or take any other action to improve our liquidity and manage our debt is subject to the risks discussed above and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time or control.

Sources of Funds

The following table presents the sources of our cash and cash equivalents for the years ended December 31, 2016, 2015 and 2014. See Notes 12, 14 and 16 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of divestitures of oil and natural gas assets, investments and other assets, respectively.

Years Ended December 31,
201620152014
($ in millions)
Cash provided by (used in) operating activities$(204)$1,234$4,634
Proceeds from issuance of term loan1,476——
Proceeds from long-term debt, net2,210—2,966
Proceeds from oilfield services long-term debt, net——888
Divestitures of proved and unproved properties1,4061895,813
Sales of other property and equipment131891,003
Proceeds from sales of investments——239
Other—5237
Total sources of cash and cash equivalents$5,019$1,564$15,580

Cash used in operating activities was $204 million in 2016 compared to cash provided by operating activities of $1.234 billion in 2015 and $4.634 billion in 2014. The decrease is primarily the result of lower realized prices for the oil and natural gas we sold in addition to lower volumes of oil, natural gas and NGL sold, partially offset by decreases in certain of our operating expenses. 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, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our derivative instruments. See further discussion below under Results of Operations.

The following table reflects the proceeds received from issuances of debt in 2016, 2015 and 2014. 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,
201620152014
Principal Amount of Debt IssuedNet ProceedsPrincipal Amount of Debt IssuedNet ProceedsPrincipal Amount of Debt IssuedNet Proceeds
($ in millions)
Convertible senior notes$1,250$1,235$—$—$—$—
Senior notes(a)1,000975——3,5003,460
Term loans(a)1,5001,476——400394
Total$3,750$3,686$—$—$3,900$3,854
(a)Our 2015 debt exchange of certain outstanding unsecured senior notes and contingent notes for Second Lien Notes did not result in any additional debt issued or proceeds received. The 2014 amounts include debt issued in connection with the spin-off of our oilfield services business. All deferred charges and debt balances related to the spin-off were removed from our consolidated balance sheet as of June 30, 2014. See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the spin-off.

We currently plan to use cash flow from operations, cash on hand and our revolving credit facility to fund our capital expenditures during 2017. We expect to generate additional liquidity with proceeds from future sales of assets that we determine do not fit our strategic priorities. Prior to June 2014, we also utilized a $500 million oilfield services credit facility. This facility was terminated in June 2014 in connection with the spin-off of our oilfield services business. See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the spin-off. Under our revolving credit facilities, we borrowed and repaid $5.146 billion in 2016, we had no borrowings or repayments in 2015 and we borrowed $7.406 billion and repaid $7.788 billion in 2014.

Uses of Funds

The following table presents the uses of our cash and cash equivalents for 2016, 2015 and 2014:

Years Ended December 31,
201620152014
($ in millions)
Oil and Natural Gas Expenditures:
Drilling and completion costs(a)$1,276$3,083$4,495
Acquisitions of proved and unproved properties571135793
Interest capitalized on unproved leasehold236410604
Total oil and natural gas expenditures2,0833,6285,892
Other Uses of Cash and Cash Equivalents:
Cash paid to repurchase debt2,7345083,362
Cash paid for title defects69——
Cash paid to repurchase noncontrolling interest of CHK C-T(b)—143—
Cash paid to purchase leased rigs and compressors——499
Cash paid to repurchase CHK Utica preferred shares(b)——1,254
Cash paid on financing derivatives(c)——53
Payments on credit facility borrowings, net——382
Additions to other property and equipment37143227
Dividends paid—289405
Distributions to noncontrolling interest owners1085173
Additions to investments—1—
Other295062
Total other uses of cash and cash equivalents2,8791,2196,417
Total uses of cash and cash equivalents$4,962$4,847$12,309
(a)Net of $51 million and $679 million in drilling and completion carries received from our joint venture partners during 2015 and 2014, respectively.
(b)See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for 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 drilling and completion costs on our oil and natural gas properties. Our drilling and completion costs decreased in 2016 compared to 2015 and 2014, primarily as a result of significantly decreased activity. During 2016, our average operated rig count was 10 rigs compared to an average operated rig count of 28 rigs in 2015 and 64 rigs in 2014. Our acquisitions of proved and unproved properties increased in 2016 compared to 2015, primarily resulting from purchases of oil and natural gas interests previously sold to third parties in connection with five of our VPP transactions for approximately $387 million.

Capital expenditures related to our midstream assets, oilfield services business, and other fixed assets were $37 million in 2016 compared to $143 million in 2015 and $227 million in 2014. The reduction of these expenditures in 2016 and 2015 as compared to 2014 is primarily the result of the spin-off of our oilfield services business in June 2014 and reductions in construction expenditures on our corporate headquarters and field offices.

In 2014, we purchased rigs and compressors previously sold under long-term lease arrangements for approximately $499 million as part of a strategic initiative to reduce complexity and future commitments as well as to facilitate asset sales and the spin-off of our oilfield services business in June 2014.

In 2016, we used $2.734 billion of cash to repurchase $2.884 billion principal amount of debt. In addition to the repayment at maturity of $259 million principal amount of our 3.25% Senior Notes due 2016, we repurchased in the open market approximately $141 million principal amount of our contingent convertible senior notes and $325 million principal amount of our outstanding senior notes for $386 million in aggregate. Additionally in 2016, we used the proceeds from our term loan facility, convertible note issuance, senior note issuance and cash on hand to purchase and retire $1.451 billion principal amount of our senior notes and $708 million principal amount of our contingent convertible senior notes for an aggregate $2.089 billion pursuant to tender offers.

In 2015, we used $508 million of cash to reduce debt. As required by the terms of the indenture for our 2.75% Contingent Convertible Senior Notes due 2035 (the 2035 Notes), the holders were provided the option to require us to purchase on November 15, 2015, all or a portion of the holders’ 2035 Notes at par plus accrued and unpaid interest up to, but excluding, November 15, 2015. On November 16, 2015, we paid an aggregate of approximately $394 million to purchase all of the 2035 Notes that were tendered and not withdrawn. An aggregate of $2 million principal amount of the 2035 Notes remains outstanding. In addition, during November and December 2015, we repurchased through privately negotiated transactions, approximately $119 million aggregate principal amount of our 3.25% Senior Notes due 2016 for approximately $114 million.

In 2014, we used $3.362 billion of cash to reduce debt. We issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our $2.0 billion term loan credit facility. We used the remaining proceeds along with cash on hand to redeem the $97 million principal amount of 6.875% Senior Notes due 2018 and to purchase and redeem the $1.265 billion principal amount of the 9.5% Senior Notes due 2015 for $1.454 billion.

We paid dividends on our preferred stock of $171 million in each of 2015 and 2014. We paid dividends on our common stock of $118 million in 2015 and $234 million in 2014. We eliminated common stock dividends effective in the 2015 third quarter and suspended preferred stock dividends effective in the 2016 first quarter. On February 15, 2017, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock and paid our dividends in arrears.

Term Loan Facility

In 2016, we entered into a secured five-year term loan facility in aggregate principal amount of $1.5 billion for net proceeds of approximately $1.476 billion. Our obligations under the new facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee our revolving credit facility, second lien notes and senior notes and are secured by first-priority liens on the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 7.50% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 6.50% per annum, subject to a 2.00% ABR floor, at our option. The loan was made at par without original discount. We used the net proceeds to finance tender offers for our unsecured notes. The term loan matures in August 2021 and voluntary prepayments are subject to a make-whole premium prior to the second anniversary of the closing of the term loan, a premium to par of 4.25% from the second anniversary until but excluding the third anniversary, a premium to par of 2.125% from the third anniversary until but excluding the fourth anniversary and at par beginning on the fourth anniversary. The term loan may be subject to mandatory prepayments and offers to purchase with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control. See Note 3 of the notes to our consolidated financial statements included in Item 8 for further discussion of the term loan facility.

Revolving Credit Facility

We have a $4.0 billion senior secured revolving credit facility (currently subject to a $3.8 billion borrowing base) that matures in December 2019. As of December 31, 2016, we had no outstanding borrowings under the revolving credit facility and had used $1.036 billion of the revolving credit facility for various letters of credit (including the $461 million supersedeas bond with respect to the 2019 Notes litigation). See Liquidity Overview above for additional information on our collateral postings. Borrowings under the facility bear interest at a variable rate. We are required to secure our obligations under the facility with liens on certain of our oil and natural gas properties, with the liens to be released upon the satisfaction of specific conditions. The applicable interest rates under the facility fluctuate based on the percentage of the borrowing base used. In 2016, we amended our revolving credit facility to provide covenant relief and affirm our $4.0 billion borrowing base. Our borrowing base may be reduced if we dispose of a certain percentage of the value of the collateral securing the facility. As a result of certain asset sales discussed in Note 12 of the notes to our consolidated financial statements included in Item 8 of this report and certain other sales of collateral since the date of the most recent amendment, our borrowing base was reduced to $3.8 billion in October 2016. See Note 3 of the notes to our consolidated financial statements included in Item 8 of Part II for further discussion of the terms of the revolving credit facility, as amended. As of December 31, 2016, our interest coverage ratio was approximately 2.04 to 1.0, and we were in compliance with all applicable financial covenants under the credit agreement.

Hedging Arrangements

In 2015, we began entering into bilateral hedging agreements. The counterparties’ and our obligations under certain of the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds. In 2016, certain of our counterparties that are also lenders (or affiliates of our lenders) under our revolving credit facility entered into derivative contracts to be secured by the same collateral that secures our revolving credit facility. This allows us to reduce any letters of credit posted as security with those counterparties.

Senior Note Obligations

Our senior note obligations consisted of the following as of December 31, 2016:

December 31, 2016
Principal AmountCarrying Amount
($ in millions)
6.25% euro-denominated senior notes due 2017(a)$258$258
6.5% senior notes due 2017134134
7.25% senior notes due 20186464
Floating rate senior notes due 2019380380
6.625% senior notes due 2020780780
6.875% senior notes due 2020279279
6.125% senior notes due 2021550550
5.375% senior notes due 2021270270
4.875% senior notes due 2022451451
8.00% senior secured second lien notes due 2022(b)2,4193,409
5.75% senior notes due 2023338338
8.00% senior notes due 20251,0001,000
5.5% convertible senior notes due 2026(c)(d)1,250811
2.75% contingent convertible senior notes due 2035(e)22
2.5% contingent convertible senior notes due 2037(d)(e)114112
2.25% contingent convertible senior notes due 2038(d)(e)200180
Debt issuance costs—(41)
Discount on senior notes—(16)
Interest rate derivatives(f)—3
Total senior notes, net8,4898,964
Less current maturities of senior notes, net(g)(506)(503)
Total long-term senior notes, net$7,983$8,461
(a)The principal amount shown is based on the exchange rate of $1.0517 to €1.00 as of December 31, 2016. 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.
(b)The carrying amount as of December 31, 2016, includes a premium of $990 million associated with a troubled debt restructuring. The premium is being amortized based on an effective yield method.
(c)The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash, common stock or a combination of cash and common stock, at our election.
(d)The carrying amount as of December 31, 2016, is reflected net of a discount associated with the equity component of our convertible and contingent convertible senior notes of $461 million.
(e)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. We may redeem our 2.75% Contingent Convertible Senior Notes due 2035 at any time. 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.
(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.
(g)As of December 31, 2016, current maturities of long-term debt, net includes our 6.25% Euro-denominated Senior Notes due January 2017, 6.5% Senior Notes due 2017 and our 2037 Notes. As discussed in footnote (b) above and in Note 3 of the notes to our consolidated financial statements included in Item 8 of this report, the holders of our 2037 Notes could exercise their individual demand repurchase rights on May 15, 2017, which would require us to repurchase all or a portion of the principal amount of the notes. As of December 31, 2016, there was $2 million of discount associated with the equity component of the 2037 Notes.

For further discussion and details regarding our senior notes and convertible senior notes, see Note 3 of the notes to our consolidated financial statements included in Item 8 of this report.

Credit Risk

Derivative instruments that enable us to manage our exposure to oil, natural gas and NGL prices, as well as to 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, 2016, our oil, natural gas, NGL and cross currency derivative instruments were spread among 12 counterparties. Additionally, the counterparties under our commodity hedging arrangements are required to secure their obligations in excess of defined thresholds.

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL ($840 million as of December 31, 2016) and exploration and production companies that own interests in properties we operate ($156 million as of December 31, 2016). 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 that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During 2016, 2015 and 2014, we recognized $10 million, $4 million and $2 million, respectively, of bad debt expense related to potentially uncollectible receivables. Additionally, during 2015, we recorded $22 million of impairment of a note receivable related to a previous asset sale as a result of the increased credit risk associated with declining commodity prices.

Contractual Obligations and Off-Balance Sheet Arrangements

From time to time, we enter into arrangements and transactions that can give rise to contractual obligations and off-balance sheet commitments. As of December 31, 2016, these arrangements and transactions included (i) operating lease agreements, (ii) volumetric production payments (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 which could result in a future cash obligation. 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.

The table below summarizes our contractual cash obligations for both recorded obligations and certain off-balance sheet arrangements and commitments as of December 31, 2016.

Payments Due By Period
TotalLess Than 1 Year1-3 Years3-5 YearsMore Than 5 Years
($ in millions)
Long-term debt:
Principal(a)$9,989$506$644$3,381$5,458
Interest3,9696641,3001,101904
Operating lease obligations(b)945——
Operating commitments(c)11,2691,5782,4212,0455,225
Unrecognized tax benefits(d)97——97—
Standby letters of credit1,0361,036———
Other296896
Total contractual cash obligations(e)$26,398$3,794$4,378$6,633$11,593
(a)Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes.
(b)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.
(c)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 pressure pumping contracts.
(d)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.
(e)This table does not include derivative liabilities or the estimated discounted liability for future dismantlement, abandonment and restoration costs of oil and natural gas properties. See Notes 11 and 20, respectively, of the notes to our consolidated financial statements included in Item 8 of this report for more information on our derivatives and asset retirement obligations. 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 these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these 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 VPP-related production expenses and taxes, based on cost levels as of December 31, 2016, pursuant to SEC reporting requirements, was estimated to be approximately $19 million for the next twelve months and $76 million over the remaining life on an undiscounted basis, or approximately $18 million and $67 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 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

Oil, Natural Gas and NGL Derivatives

Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas 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, 2016, our oil, natural gas and NGL derivative instruments consisted of swaps, options, collars 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 oil, natural gas and NGL derivatives during 2016, 2015 and 2014. 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 Arrangements in Note 11 of the notes to our consolidated financial statements included in Item 8 of this report, the counterparties’ and our obligation under certain of the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds. In 2016, certain of our counterparties that are also lenders under our revolving credit facility entered into derivative contracts to be secured by the same collateral that secures the revolving credit facility. This will allow us to reduce any letters of credit posted as security with those counterparties.

The estimated fair values of our oil, natural gas and NGL derivative contracts as of December 31, 2016 and 2015 are provided below. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information concerning the fair value of our oil and natural gas derivative instruments.

December 31,
20162015
($ in millions)
Derivative assets (liabilities):
Oil fixed-price swaps$(140)$144
Oil call options(1)(7)
Natural gas fixed-price swaps(349)229
Natural gas collars(9)—
Natural gas call options—(99)
Natural gas basis protection swaps(5)—
NGL fixed-price swaps——
Estimated fair value$(504)$267

Changes in the fair value of oil and natural gas 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, 2016, 2015 and 2014, accumulated other comprehensive income included unrealized losses, net of related tax effects, totaling $97 million, $113 million and $136 million, respectively, associated with commodity derivative contracts. Based upon the market prices at December 31, 2016, we expect to transfer approximately $22 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. A detailed explanation of accounting for oil, natural gas 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 revolving credit facility, 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, 2016, 2015 and 2014 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. In December 2015, we exchanged and subsequently retired €42 million in aggregate principal amount of these senior notes in the private exchange described above, and we simultaneously unwound the cross currency swaps for the same principal amount. During 2016, in connection with our tender offers, we retired €56 million in aggregate principal amount of our 6.25% Euro-denominated Senior Notes due 2017, and we simultaneously unwound the cross currency swaps for the same principal amount at a cost of $13 million. A detailed explanation of accounting for foreign currency derivatives appears under Application of Critical Accounting Policies – Derivatives elsewhere in this Item 7.

Results of Operations

General. For the year ended December 31, 2016, Chesapeake had a net loss of $4.399 billion, or $6.45 per diluted common share, on total revenues of $7.872 billion. This compares to a net loss of $14.635 billion, or $22.43 per diluted common share, on total revenues of $12.764 billion for the year ended December 31, 2015 and net income of $2.056 billion, or $1.87 per diluted share, on total revenues of $23.125 billion for the year ended December 31, 2014. The net loss in 2016 was primarily driven by non-cash impairment of oil and natural gas properties and impairments of fixed assets and other while the net loss in 2015 was primarily driven by non-cash impairments of our oil and natural gas properties. See Impairment of Oil and Natural Gas Properties and Impairments of Fixed Assets and Other below. The decreases in total revenues in 2016 and 2015 were primarily driven by decreases in the average realized prices we received for oil and natural gas production, lower production volumes, increased unrealized hedging losses and a decrease in the volumes sold and the prices received by our marketing affiliate on behalf of third-party producers.

Oil, Natural Gas and NGL Sales. During 2016, oil, natural gas and NGL sales were $3.288 billion compared to $5.391 billion in 2015 and $10.354 billion in 2014. In 2016, Chesapeake sold 233 mmboe for $3.866 billion at a weighted average price of $16.63 per boe (excluding the effect of derivatives), compared to 248 mmboe sold in 2015 for $4.767 billion at a weighted average price of $19.23 per boe (excluding the effect of derivatives) and 258 mmboe sold in 2014 for $9.336 billion at a weighted average price of $36.21 per boe (excluding the effect of derivatives). The decrease in the price received per boe in 2016 compared to 2015 resulted in a $606 million decrease in revenues, and decreased sales volumes resulted in a $295 million decrease in revenues, for a total decrease in revenues of $901 million (excluding the effect of derivatives).

For 2016, our average price received per barrel of oil (excluding the effect of derivatives) was $40.65, compared to $45.77 in 2015 and $89.41 in 2014. Natural gas prices received per mcf (excluding the effect of derivatives) were $2.05, $2.31 and $4.14 in 2016, 2015 and 2014, respectively. NGL prices received per barrel (excluding the effect of derivatives) were $14.76, $14.06 and $30.95 in 2016, 2015 and 2014, respectively.

Gains and losses from our oil and natural gas derivatives resulted in a net decrease in oil, natural gas and NGL revenues of $578 million in 2016 and net increases of $624 million and $1.018 billion in 2015 and 2014, respectively. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk of this report for a complete listing of all of our derivative instruments as of December 31, 2016.

A change in oil, natural gas and NGL prices has a significant impact on our revenues and cash flows. Assuming our 2016 production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would result in an increase or decrease in 2016 revenues and cash flows of approximately $33 million and $32 million, respectively, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in 2016 revenues and cash flows of approximately $105 million and $104 million, respectively, and an increase or decrease of $1.00 per barrel of NGL sold would result in an increase or decrease in 2016 revenues and cash flows of $24 million.

The following tables show production and average sales prices received by our operating divisions for 2016, 2015 and 2014:

2016
OilNatural GasNGLTotal
(mmbbl)($/bbl)(a)(bcf)($/mcf)(a)(mmbbl)($/bbl)(a)(mmboe)%($/boe)(a)
Southern(b)26.441.84537.12.2011.314.77127.35519.29
Northern(c)6.836.01512.41.9013.114.75105.34513.40
Total33.240.651,049.52.0524.414.76232.6100%16.63
2015
OilNatural GasNGLTotal
(mmbbl)($/bbl)(a)(bcf)($/mcf)(a)(mmbbl)($/bbl)(a)(mmboe)%($/boe)(a)
Southern(b)33.447.33573.82.5214.913.13143.95822.40
Northern(c)8.239.45496.02.0613.115.12104.04214.85
Total41.645.771,069.82.3128.014.06247.9100%19.23
2014
OilNatural GasNGLTotal
(mmbbl)($/bbl)(a)(bcf)($/mcf)(a)(mmbbl)($/bbl)(a)(mmboe)%($/boe)(a)
Southern(b)35.391.15580.74.2016.932.18148.95841.62
Northern(c)7.080.15514.34.0816.229.56108.94228.81
Total42.389.411,095.04.1433.130.95257.8100%36.21
(a)Average sales prices exclude gains (losses) on derivatives.
(b)Our Southern Division includes the Eagle Ford and Anadarko Basin liquids plays and the Haynesville/Bossier and Barnett (prior to October 31, 2016) natural gas shale plays. The Eagle Ford Shale accounted for approximately 33% of our estimated proved reserves by volume as of December 31, 2016. Eagle Ford Shale production for 2016, 2015 and 2014 was 35.4 mmboe, 38.5 mmboe and 35.4 mmboe, respectively.
(c)Our Northern Division includes the Utica and Powder River liquids plays and the Marcellus natural gas play. The Utica Shale accounted for approximately 22% of our estimated proved reserves by volume as of December 31, 2016. Utica Shale production for 2016, 2015 and 2014 was 46.7 mmboe, 43.8 mmboe and 26.6 mmboe, respectively. The Marcellus Shale accounted for approximately 18% of our estimated proved reserves by volume as of December 31, 2016. Marcellus Shale production for 2016, 2015 and 2014 was 50.0 mmboe, 49.7 mmboe and 74.7 mmboe, respectively.

Our average daily production of 635 mboe for 2016 consisted of approximately 90,800 bbls of oil (14% on an oil equivalent basis), approximately 2.9 bcf of natural gas (75% on an oil equivalent basis) and approximately 66,700 bbls of NGL (11% on an oil equivalent basis). Oil production decreased by 20% year over year primarily as a result of the sale of certain of our Mid-Continent assets in 2016 and 2015 as well as a significant reduction in drilling activity. Natural gas production decreased by 2% and NGL production decreased by 13%.

Excluding the impact of derivatives, our percentage of revenues from oil, natural gas and NGL is shown in the following table:

Years Ended December 31,
201620152014
Oil354040
Natural gas565249
NGL9811
Total100%100%100%

Marketing, Gathering and Compression Revenues and Expenses. Marketing, gathering and compression revenues consist of third-party revenues as well as fair value adjustments on our supply contract derivatives (see Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for additional information on our supply contract derivatives). Expenses related to our marketing, gathering and compression operations consist of third-party expenses and exclude depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See Depreciation and Amortization of Other Assets below for the depreciation and amortization recorded on our marketing, gathering and compression assets. We recognized $4.584 billion in marketing, gathering and compression revenues in 2016, of which $146 million related to cash proceeds from the sale of a long-term natural gas supply contract to a third party, offset by the reversal of cumulative unrealized gains of $297 million associated with the natural gas supply contract, with corresponding expenses of $4.778 billion, for a net loss of $194 million. This compares to revenues of $7.373 billion, of which $296 million related to unrealized gains on the fair value of our supply contract derivative, with corresponding expenses of $7.130 billion, for a net margin of $243 million in 2015 and revenues of $12.225 billion, expenses of $12.236 billion and a net loss before depreciation of $11 million in 2014. Revenues and expenses decreased in 2016 compared to 2015 and 2014 primarily as a result of lower oil, natural gas and NGL prices paid and received in our marketing operations. The margin increase in 2015 as compared to 2014 was primarily the result of an unrealized gain on the fair value adjustment on our supply contract derivatives, partially offset by cost increases on certain sales contracts with third parties entered into to help meet certain of our oil pipeline and other commitments and by lower compression margin as a result of the sale of a significant portion of our compression assets in 2014 and 2015.

Oilfield Services Revenues and Expenses. Our oilfield services consisted of third-party revenues and expenses related to our former oilfield services operations and excluded 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 in 2014. Chesapeake recognized revenues of $546 million, expenses of $431 million with a net margin before depreciation of $115 million in 2014. As a result of the spin-off of our oilfield services business in June 2014, we did not have oilfield services revenues and expenses in 2016 and 2015.

Oil, Natural Gas and NGL Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $710 million in 2016, compared to $1.046 billion in 2015 and $1.208 billion in 2014. On a unit-of-production basis, production expenses were $3.05 per boe in 2016 compared to $4.22 per boe in 2015 and $4.69 per boe in 2014. The absolute and per unit decrease in 2016 was primarily the result of a reduction in repair and maintenance expenses as well as operating efficiencies across most of our operating areas. Production expenses in 2016, 2015 and 2014 included approximately $44 million, $104 million and $157 million, or $0.19, $0.42 and $0.61 per boe, respectively, associated with VPP production volumes. In connection with certain 2016 divestitures, we purchased the remaining oil and natural gas interests previously sold in connection with five of our VPPs, and a majority of these repurchased oil and natural gas interests were subsequently sold. In addition, one of our VPPs expired in 2015. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.

The following table shows our production expenses (excluding ad valorem taxes) by operating division and our ad valorem tax expenses for 2016, 2015 and 2014:

201620152014
Production Expenses$/boeProduction Expenses$/boeProduction Expenses$/boe
($ in millions, except per unit)
Southern$4983.92$7715.36$8825.92
Northern1571.491881.812292.10
6552.819593.871,1114.31
Ad valorem tax550.24870.35970.38
Total$7103.05$1,0464.22$1,2084.69

Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses. Oil, natural gas and NGL gathering, processing and transportation expenses were $1.855 billion in 2016 compared to $2.119 billion in 2015 and $2.174 billion in 2014. On a unit-of-production basis, gathering, processing and transportation expenses were $7.98 per boe in 2016 compared to $8.55 per boe in 2015 and $8.43 per boe in 2014. Certain of our gathering agreements required us to pay the service provider a fee for any production shortfall below certain annual minimum gathering volume commitments. These fees amounted to $171 million in 2015 and $120 million in 2014, or $0.69 and $0.47 per boe, respectively. We were not required to pay any shortfall fees in 2016.

A summary of oil, natural gas and NGL gathering, processing and transportation expenses by product is shown below.

Years Ended December 31,
201620152014
Oil ($ per bbl)$3.61$3.38$2.86
Natural gas ($ per mcf)$1.47$1.66$1.68
NGL ($ per bbl)$7.83$7.37$6.59

Production Taxes. Production taxes were $74 million in 2016 compared to $99 million in 2015 and $232 million in 2014. On a unit-of-production basis, production taxes were $0.32 per boe in 2016 compared to $0.40 per boe in 2015 and $0.90 per boe in 2014. In general, production taxes are calculated using value-based formulas that produce lower per unit costs when oil, natural gas and NGL prices are lower. The absolute and per unit decrease in production taxes in 2016 and 2015 was primarily due to lower prices received for oil, natural gas and NGL. Production taxes in 2016, 2015 and 2014 included approximately $3 million $2 million and $16 million respectively, or $0.01, $0.01 and $0.06 per boe, respectively, associated with VPP production volumes.

General and Administrative Expenses. General and administrative expenses were $240 million in 2016, $235 million in 2015 and $322 million in 2014, or $1.03, $0.95 and $1.25 per boe, respectively. Lower general and administrative expenses in 2016 and 2015 were due primarily to reduced overhead as a result of our workforce reduction in the 2015 third quarter and our continuing efforts to reduce other administrative expenses, as well as the spin-off of our oilfield services business in June 2014.

Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $148 million, $196 million and $230 million of internal costs in 2016, 2015 and 2014, respectively, directly related to our leasehold acquisition and drilling and completion efforts.

Restructuring and Other Termination Costs. We recorded $6 million, $36 million and $7 million in 2016, 2015 and 2014, respectively, for restructuring and other termination costs. The 2016 amount was primarily related to the reduction in workforce in connection with the restructuring of our compressor manufacturing subsidiary and the reductions of workforce in connection with certain of our divestitures. In 2015, we reduced our workforce by approximately 15% as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we incurred a total charge of approximately $55 million for one-time termination benefits, all of which were paid in cash in the fourth quarter of 2015. Additionally, the 2015 and 2014 amounts included negative fair value adjustments to PSUs granted to former executives of the Company, which were primarily the result of a decrease in the trading price of our common stock. The 2014 expense also includes charges incurred in connection with the spin-off of our oilfield services business and senior management separations. See Note 18 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our restructuring and other termination costs.

Provision for Legal Contingencies. In 2016, 2015 and 2014, we recorded $123 million, $353 million and $234 million, respectively, for legal contingencies. The 2016 provision consists of accruals for loss contingencies primarily related to royalty claims. See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of royalty claims. The 2015 amount includes $25 million related to the April 2015 resolution of litigation we were defending against the state of Michigan and $339 million related to litigation involving the early redemption of our 2019 notes. See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for discussion of ongoing 2019 Notes litigation. Additionally, in 2015, we reduced our royalty provision amount from $119 million to $109 million to reflect the amount paid in 2015 to settle litigation with Oklahoma royalty owners, net of claimants that opted out. In 2014, we accrued $134 million of loss contingencies related to royalty claims, and a $100 million loss contingency for litigation regarding our 2019 Notes litigation.

Oil, Natural Gas and NGL Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (DD&A) of oil, natural gas and NGL properties was $1.003 billion, $2.099 billion and $2.683 billion in 2016, 2015 and 2014, respectively. 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 $4.31, $8.47 and $10.41 per boe in 2016, 2015 and 2014, respectively. The absolute and per unit decrease in 2016 was the result of a lower amortization base, which is due to the 2016 and 2015 impairments of our oil and natural gas properties. The absolute and per unit decrease in 2015 was the result of a lower amortization base as a result of our impairment of oil and gas properties in 2015 and a reduction in our estimated future development costs as a result of drilling efficiencies and a forecasted reduction in our future capital plans, partially offset by an approximate 39% reduction in our reserve base driven primarily by lower prices used in calculating our estimated reserves.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $104 million in 2016 compared to $130 million in 2015 and $232 million in 2014. On a unit-of-production basis, depreciation and amortization of other assets was $0.45 per boe in 2016 compared to $0.53 per boe in 2015 and $0.90 per boe in 2014. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. In June 2014, we completed the spin-off of our oilfield services business and, therefore, did not incur oilfield services depreciation expense in 2016 or 2015 and will not incur this expense in future periods. In 2014, to the extent company-owned oilfield services equipment was used to drill and complete our wells, a substantial portion of the depreciation (i.e., the portion related to our utilization of the equipment) was capitalized in oil and natural gas properties as drilling and completion costs. The following table shows depreciation expense by asset class for the years ended December 31, 2016, 2015 and 2014 and the estimated useful lives of these assets.

Years Ended December 31,Estimated Useful Life
201620152014
($ in millions)(in years)
Buildings and improvements$38$39$4210 – 39
Natural gas compressors(a)2438373 – 20
Computers and office equipment2022323 – 7
Vehicles310240 – 7
Natural gas gathering systems and treating plants(a)7111220
Oilfield services equipment(b)——743 – 15
Other1210112 – 20
Total depreciation and amortization of other assets$104$130$232
(a)Included in our marketing, gathering and compression operating segment.
(b)Included in our former oilfield services operating segment.

Impairment of Oil and Natural Gas Properties. Our oil and natural gas properties are subject to quarterly full cost ceiling tests. 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 cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. For 2016 and 2015, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in impairments of the carrying value of our oil and natural gas properties of $2.564 billion and $18.238 billion, respectively.

As of December 31, 2016, the present value of estimated future net revenue of our proved reserves, discounted at an annual rate of 10%, was $4.405 billion. Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, gathering, processing, transportation and future development costs, using prices and costs under existing economic conditions as of that date. The prices used in the present value calculation as of December 31, 2016 were $42.75 per bbl of oil and $2.49 per mcf of natural gas, before price differential adjustments.

Impairments of Fixed Assets and Other. In 2016, 2015 and 2014, we recognized $838 million, $194 million and $88 million, respectively, of fixed asset impairment losses and other charges. In 2016, we conveyed our interests in the Barnett Shale operating area located in north central Texas and simultaneously terminated most of our future commitments associated with this asset. In connection with this disposition, we recognized $361 million of charges related to the termination of natural gas gathering and transportation agreements. We also recognized an impairment charge of $284 million in 2016 related to other fixed assets sold in the divestiture. Also in 2016, we sold the majority of our upstream and midstream assets in the Devonian Shale located in West Virginia and Kentucky. We recognized an impairment charge of $142 million in 2016 related to other fixed assets sold in the divestiture. The 2015 amount consisted primarily of a $70 million settlement charge for a net acreage maintenance obligation to Total S.A. in our Barnett Shale joint venture, a $47 million loss contingency related to contract disputes, a $21 million impairment related to the sale of third-party rental compressors, a $22 million impairment of a note receivable and $7 million of charges incurred for terminating drilling contracts as a result of the decline in oil and natural gas prices. The 2014 amount consisted primarily of a $22 million charge for our Barnett Shale joint venture net acreage shortfall with Total and $64 million of impairments related to a gathering system, drilling rigs, natural gas compressors and buildings and land.

Net (Gains) Losses on Sales of Fixed Assets. In 2016, net gains on sales of fixed assets were $12 million compared to net losses of $4 million in 2015 and net gains of $199 million in 2014. The 2016 and 2015 amounts primarily related to the sale of gathering systems, buildings, land and other property and equipment. The 2014 amount primarily related to the sale of natural gas compressors and crude hauling assets. See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our net (gains) losses on sales of fixed assets.

Interest Expense. Interest expense was $296 million in 2016 compared to $317 million in 2015 and $89 million in 2014 as follows:

Years Ended December 31,
201620152014
($ in millions)
Interest expense on senior notes$588$682$704
Interest expense on term loan46—36
Amortization of loan discount, issuance costs and other336242
Amortization of premium associated with troubled debt restructuring(165)(3)—
Interest expense on revolving credit facilities351228
Realized gains on interest rate derivatives(a)(11)(6)(12)
Unrealized (gains) losses on interest rate derivatives(b)21(6)(72)
Capitalized interest(251)(424)(637)
Total interest expense$296$317$89
Average senior notes borrowings$8,749$11,70511,653
Average credit facilities borrowings$195$—306
Average term loan borrowings$537$—625
(a)Includes settlements related to the interest accrual for the period 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.

The 2016 and 2015 decreases in capitalized interest resulted from lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. The 2016 decrease in interest expense on senior notes is due to the decrease in the average outstanding principal amount of senior notes. The 2016 increase in the amortization of premium associated with troubled debt restructuring is due to a full year of amortization on our second lien notes. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our debt refinancing. Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $1.18 per boe in 2016 compared to $1.30 per boe in 2015 and $0.63 per boe in 2014.

Losses on Investments. Losses on investments were $8 million, $96 million and $75 million in 2016, 2015 and 2014, respectively. In 2016, the losses were primarily related to our equity investment in Sundrop Fuels, Inc. (Sundrop). Losses on investments in 2015 and 2014 were primarily related to our equity investments in FTS International, Inc. (FTS) and Sundrop. See Note 14 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our investments.

Impairment of Investments. In 2016, 2015 and 2014, we recognized impairments of investments of $119 million, $53 million and $5 million, respectively. The 2016 amount consisted of an other-than-temporary impairment of our Sundrop investment. The 2015 amount consisted of an other-than-temporary impairment of our FTS investment due to the extended decrease in the oil and natural gas pricing environment. The 2014 amount related to an other miscellaneous investment. See Note 14 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of our investments.

Net Gain (Loss) on Sales of Investments. In 2016, we recorded a $10 million net loss on the sale of an investment compared to a $67 million net gain on the sales of investments in 2014. In 2016, we sold certain of our mineral interests and assigned our partnership interest in Mineral Acquisition Company I, L.P. to KKR Royalty Aggregator LLC. As a result of the transaction, we wrote off our equity investment and recognized a $10 million loss. In 2014, we sold all of our interest in Chaparral Energy, Inc. for net cash proceeds of $209 million and recorded a $73 million gain related to the sale. In addition, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction.

Gains (Losses) on Purchases or Exchanges of Debt. In 2016 and 2015, we recorded gains of $236 million and $279 million, respectively, on purchases of debt and we recorded losses on purchases of debt of $197 million in 2014.

In 2016, we used the proceeds from our term loan facility, convertible notes issuance and senior notes issuance, together with cash on hand, to purchase and retire $1.451 billion principal amount of our senior notes and $708 million principal amount of our contingent convertible senior notes for an aggregate $2.078 billion pursuant to tender offers. Also, in 2016, we repurchased in the open market approximately $325 million principal amount of our senior notes for $300 million and $141 million principal amount of our contingent convertible senior notes for $86 million. Additionally, in 2016, we privately negotiated exchanges of approximately $290 million principal amount of our outstanding senior notes for 53,923,925 shares of our common stock and $287 million principal amount of our outstanding contingent convertible senior notes for 55,427,782 shares of our common stock. We recorded an aggregate gain of $236 million associated with these debt repurchases and exchanges.

In December 2015, we privately exchanged newly issued 8.00% Senior Secured Second Lien Notes due 2022 for certain outstanding senior unsecured notes and contingent convertible notes. For certain of the notes exchanged, we are accounting for these exchanges as a trouble debt restructuring (TDR). For exchanges classified as TDR, if the future undiscounted cash flows of the newly issued debt are less than the net carrying value of the original debt, a gain is recorded for the difference and the carrying value of the newly issued debt is adjusted to the future undiscounted cash flow amount and no interest expense is recorded going forward. For the remaining TDR exchanges, where the future undiscounted cash flows are greater than the net carrying value of the original debt, no gain is recognized and a new effective interest rate is established. Accordingly, we recognized a gain of $304 million in our consolidated statement of operations. Direct costs incurred for $29 million related to the notes exchange were also recognized. Additionally, we purchased in the open market approximately $119 million aggregate principal amount of our 3.25% Senior Notes due 2016 for cash. We recorded a gain of approximately $5 million associated with the repurchase.

In December 2014, we entered into a new five-year $4.0 billion senior revolving credit facility to use for general corporate purposes. That credit facility replaced our then-existing $4.0 billion senior secured revolving credit facility that was scheduled to mature in December 2015. We recognized a loss of approximately $2 million in extinguishment costs related to former lenders under the terminated facility who were not continuing under the new facility. In 2014, we repaid the borrowings under and terminated our $2.0 billion term loan credit facility due 2017 and recorded a loss of approximately $90 million. Also in 2014, we purchased and redeemed $1.265 billion in aggregate principal amount of our 9.5% Senior Notes due 2015. We recorded a loss of approximately $99 million associated with the purchase and redemption. In addition, we redeemed $97 million in principal amount of our 6.875% Senior Notes due 2018 at par. We recorded a loss of approximately $6 million associated with the redemption.

Other Income. Other income was $19 million in 2016 compared to $8 million in 2015 and $22 million in 2014. The 2016 other income consisted primarily of $2 million of interest income and $17 million of miscellaneous income. The 2015 income consisted of $6 million of interest income and $2 million of miscellaneous income. The 2014 other income consisted of $3 million of interest income and $19 million of miscellaneous income.

Income Tax Expense (Benefit). Chesapeake recorded an income tax benefit of $190 million in 2016, an income tax benefit of $4.463 billion in 2015 and income tax expense of $1.144 billion in 2014. Our effective income tax rate was 4.1% in 2016 compared to 23.4% in 2015 and 35.8% in 2014. The decrease in the effective income tax rate from 2015 to 2016 is primarily due to the tax benefit at expected rates being offset by a valuation allowance. Further, our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences. See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a discussion of income tax expense (benefit).

Net Income Attributable to Noncontrolling Interests. Chesapeake recorded net income attributable to noncontrolling interests of $2 million, $50 million and $139 million in 2016, 2015 and 2014, respectively. The 2016 amount was attributable to the Chesapeake Granite Wash Trust (the Trust). The 2015 amount was primarily related to dividends paid on preferred stock of our CHK C-T subsidiary. The decrease from 2015 to 2016 is due to the repurchase of all of the preferred shares of CHK C-T from third-party shareholders in August 2015. The 2014 amount included income related to the Trust as well as dividends paid on preferred stock of our CHK C-T and CHK Utica subsidiaries. The decrease from 2014 to 2015 is primarily due to the repurchase of all of the outstanding preferred shares of CHK Utica and CHK C-T from third-party preferred shareholders in July 2014 and August 2015, respectively. See Notes 8 and 15 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 most significant to our financial statements 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 is an important process that changes as our business evolves and accounting rules are refined. Accounting rules generally do not involve a selection among alternatives, but rather they provide for the interpretation of existing rules and the use of judgment in applying guidance to the specific set of circumstances existing in our business.

Oil and Natural Gas Properties. The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas 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 oil and natural gas 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 oil and natural gas properties under the successful efforts method. As a result, our financial statements differ from those of companies that apply the successful efforts method since we generally reflect a higher level of capitalized costs as well as a higher oil and natural gas 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 oil and natural gas 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 these 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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. These 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 oil and natural gas prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas 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 Oil and Natural Gas 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 oil, natural gas and NGL 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 oil, natural gas 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 oil, natural gas 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 oil, natural gas 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 oil, natural gas and NGL sales. Any change in the fair value resulting from ineffectiveness is recognized immediately in oil, natural gas 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 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. This 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 oil, natural gas 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, 2016 and 2015, the fair values of our derivatives were net liabilities of $577 million and net assets of $512 million, respectively.

Income Taxes. The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of both federal and state taxing jurisdictions. Income taxes are accounted for using the asset and liability approach. The Company has recognized deferred tax assets and liabilities for temporary differences between tax and book basis, tax credit carryforwards and net operating loss carryforwards. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for additional or adjustments to existing valuation allowances, we consider the preponderance of evidence concerning the realization of the deferred tax asset. Among the more significant types of evidence that we consider are:

•taxable income projections in future years;
•reversal of existing deferred tax liabilities against deferred tax assets and 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.

Our judgments and assumptions in estimating future taxable income include such factors as future operating conditions and commodity prices. As of December 31, 2016 and 2015, we had deferred tax assets of $4.690 billion and $4.122 billion, respectively, upon which we had a valuation allowance of $4.389 billion and $2.949 billion, respectively. The valuation allowance as of December 31, 2016 and 2015 was recorded against our net deferred tax assets. We have concluded that these deferred tax assets are not more likely than not to be realized.

The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. 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. 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

Our equity method investees are considered related parties. See Note 7 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of transactions with our equity method investees.

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 oil, natural gas and NGL production and future expenses, estimated operating costs, assumptions regarding future oil, natural gas and NGL prices, planned drilling activity, estimates of future drilling and completion and other capital expenditures (including the use of joint venture drilling carries), potential future write-downs of our oil and natural gas assets, anticipated sales, and the adequacy of our provisions for legal contingencies, as well as statements concerning anticipated cash flow and liquidity, ability to comply with financial maintenance covenants and meet contractual cash commitments to third parties, debt repurchases, operating and capital efficiencies, business strategy, the effect of our remediation plan for a material weakness, and other plans and objectives for future operations. 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 Part I of this report and include:

•the volatility of oil, natural gas and NGL prices;
•the limitations our level of indebtedness may have on our financial flexibility;
•our inability to access the capital markets on favorable terms;
•the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations;
•our credit rating requiring us to post more collateral under certain commercial arrangements;
•write-downs of our oil and natural gas asset carrying values due to low commodity prices;
•our ability to replace reserves and sustain production;
•uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;
•our ability to generate profits or achieve targeted results in drilling and well operations;
•leasehold terms expiring before production can be established;
•commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales;
•the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations;
•adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;
•charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity;
•drilling and operating risks and resulting liabilities;
•effects of environmental protection laws and regulation on our business;
•legislative and regulatory initiatives further regulating hydraulic fracturing;
•our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used;
•impacts of potential legislative and regulatory actions addressing climate change;
•federal and state tax proposals affecting our industry;
•potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations;
•competition in the oil and gas exploration and production industry;
•a deterioration in general economic, business or industry conditions;
•negative public perceptions of our industry;
•limited control over properties we do not operate;
•pipeline and gathering system capacity constraints and transportation interruptions;
•terrorist activities and/or cyber-attacks adversely impacting our operations;
•potential challenges by SSE’s former creditors of our spin-off of in connection with SSE’s recently completed bankruptcy under Chapter 11 of the U.S. Bankruptcy Code;
•an interruption in operations at our headquarters due to a catastrophic event;
•the continuation of suspended dividend payments on our common stock;
•the effectiveness of our remediation plan for a material weakness;
•certain anti-takeover provisions that affect shareholder rights; and
•our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.

We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information except as required by applicable law. We urge you to carefully review and consider the disclosures made in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.

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