Edgar Filing: CHESAPEAKE ENERGY CORP

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2015

[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission File No. 1-13726

Chesapeake Energy Corporation

(Exact name of registrant as specified in its charter)



Oklahoma		73-1395733
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
6100 North Western Avenue
Oklahoma City, Oklahoma		73118
(Address of principal executive offices)		(Zip Code)

(405) 848-8000

(Registrant’s telephone number, including area code)



Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01		New York Stock Exchange
3.25% Senior Notes due 2016		New York Stock Exchange
6.25% Senior Notes due 2017		New York Stock Exchange
6.5% Senior Notes due 2017		New York Stock Exchange
7.25% Senior Notes due 2018		New York Stock Exchange
Floating Rate Senior Notes due 2019		New York Stock Exchange
6.625% Senior Notes due 2020		New York Stock Exchange
6.875% Senior Notes due 2020		New York Stock Exchange
6.125% Senior Notes due 2021		New York Stock Exchange
5.375% Senior Notes due 2021		New York Stock Exchange
4.875% Senior Notes due 2022		New York Stock Exchange
5.75% Senior Notes due 2023		New York Stock Exchange
2.75% Contingent Convertible Senior Notes due 2035		New York Stock Exchange
2.5% Contingent Convertible Senior Notes due 2037		New York Stock Exchange
2.25% Contingent Convertible Senior Notes due 2038		New York Stock Exchange
4.5% Cumulative Convertible Preferred Stock		New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [ ] NO [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. YES [ ] NO [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES [X] NO [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer [X] Accelerated Filer [ ] Non-accelerated Filer [ ] Smaller Reporting Company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [ ] NO [X]

The aggregate market value of our common stock held by non-affiliates on June 30, 2015 was approximately $7.4 billion. As of February 9, 2016, there were 664,992,714 shares of our $0.01 par value common stock outstanding.

__________________________________________

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the 2016 Annual Meeting of Shareholders are incorporated by reference in Part III.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

2015 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS



PART I		Page
Item 1.	Business	1
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	37
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	68
Item 8.	Financial Statements and Supplementary Data	72
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	159
Item 9A.	Controls and Procedures	159
Item 9B.	Other Information	159
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	159
Item 11.	Executive Compensation	159
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	159
Item 13.	Certain Relationships and Related Transactions and Director Independence	159
Item 14.	Principal Accountant Fees and Services	159
PART IV
Item 15.	Exhibits and Financial Statement Schedules	160

PART I


Item 1.	Business

Unless the context otherwise requires, references to “Chesapeake”, the “Company”, “us”, “we” and “our” in this report are to Chesapeake Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000. Definitions of oil and gas industry terms appearing in this report can be found under Glossary of Oil and Gas Terms beginning on page 19.

Our Business

Chesapeake is currently the second-largest producer of natural gas and the 14th largest producer of oil and natural gas liquids (NGL) in the United States. We own interests in approximately 43,700 oil and natural gas wells and produced an average of approximately 661 mboe per day in the 2015 fourth quarter, net to our interest. We have a large and geographically diverse resource base of onshore U.S. unconventional natural gas and liquids assets. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas; the Utica Shale in Ohio and Pennsylvania; the Anadarko Basin in northwestern Oklahoma and the Texas Panhandle; and the Niobrara Shale in the Powder River Basin in Wyoming. Our natural gas resource plays are the Haynesville/Bossier Shales in northwestern Louisiana and East Texas; the Marcellus Shale in the northern Appalachian Basin in Pennsylvania; and the Barnett Shale in the Fort Worth Basin of north-central Texas. We also own oil and natural gas marketing and natural gas gathering and compression businesses.

The Company's estimated proved reserves as of December 31, 2015 were 1.504 bboe, a decrease of 965 mmboe, or 39%, from 2.469 bboe as of December 31, 2014. The 2015 proved reserve movement included 1.098 bboe of downward revisions resulting primarily from lower average oil and natural gas prices offset by 231 mmboe of extensions and discoveries and 213 mmboe of upward revisions resulting from changes to previous estimates as further discussed below in Oil, Natural Gas and NGL Reserves and in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. In 2015, we produced 248 mmboe and divested 63 mmboe of estimated proved reserves. Before basis differential adjustments, oil and natural gas prices used in estimating proved reserves decreased substantially as of December 31, 2015 compared to December 31, 2014 using the trailing 12-month average prices required by the Securities and Exchange Commission (SEC). Oil prices decreased by $44.70 per bbl, or 47%, to $50.28 per bbl from $94.98 per bbl. Natural gas prices decreased $1.77 per mcf, or 41%, to $2.58 per mcf from $4.35 per mcf. Proved developed reserves represented 84% of our proved reserves as of December 31, 2015 compared to 75% as of December 31, 2014.

Our daily production for 2015 averaged 679 mboe, a decrease of 27 mboe, or 4%, from the 706 mboe of daily production for 2014, and consisted of approximately 114,000 bbls of oil (17% on an oil equivalent basis), approximately 2.9 bcf of natural gas (72% on an oil equivalent basis) and approximately 76,700 bbls of NGL (11% on an oil equivalent basis). Our average daily oil production decreased by 2%, or approximately 2 mbbls per day; our average daily natural gas production decreased by 2%, or approximately 69 mmcf per day; and our average daily NGL production decreased by 15%, or approximately 14 mbbls per day over the average daily production for 2014.

Information About Us

We make available, free of charge on our website at www.chk.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. Documents and information on our website are not incorporated by reference herein.

Business Strategy

Chesapeake’s strategy for 2016 is to focus on maximizing liquidity, improving margins and improving the value of our significant positions in premier U.S. onshore resource plays. We continue to apply financial discipline to all aspects of our business with the goal of increasing financial and operational flexibility through lower, value-driven spending. Our 2016 capital program will be focused on efficient investments that can improve our cash flow generating ability in a depressed commodity price environment. This strategy results in utilizing fewer rigs than in 2015, however, to improve cash flow, we anticipate increasing completion crews to capitalize on prior investments and generate revenues from initial production on new wells.

As part of a broader effort to decrease our financial complexity and increase our liquidity, we took the following actions in 2015:


•	reduced total capital expenditures in 2015 compared to 2014 by approximately 46% in response to the lower commodity price environment;


•	amended our revolving credit facility to give us greater flexibility and access to liquidity;


•	exchanged certain senior notes for new secured second lien notes to reduce and extend our future debt and interest obligations;


•	eliminated quarterly dividends on our common stock;


•	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 prices;


•	removed drilling and overriding royalty interest commitments related to our CHK Cleveland Tonkawa (CHK C-T) subsidiary; and


•	restructured certain gathering agreements to improve our per-unit gathering rates beginning in 2016, satisfy minimum volume commitment obligations and increase realized pricing per mcf of natural gas.

In 2016, we intend to build on these actions to better position Chesapeake to create additional value as we work to improve liquidity and increase the value of our asset base. We expect our recent decision to suspend payment of dividends on our convertible preferred stock and the sales of assets that do not fit in our strategic priorities to provide increased liquidity. In addition, we are strengthening our balance sheet and improving our liquidity position by repurchasing, at a discount, certain of our debt instruments that are scheduled to mature or are subject to a demand repurchase in 2016 and 2017.

Our substantial inventory of hydrocarbon resources, including our undeveloped acreage, provides a strong foundation to create future value. We have seen and continue to see increased efficiencies and operational improvements, including increased well productivity from larger completions and lower production declines due to a greater focus on strengthening our base production. Building on our strong and diverse asset base, we believe that our dedication to financial discipline, the flexibility of our capital program, and our continued focus on safety and environmental stewardship will provide many opportunities to create greater future value for Chesapeake and its stakeholders in 2016 and beyond.

Operating Divisions

Chesapeake focuses its exploration, development, acquisition and production efforts in the two geographic operating divisions described below.

Southern Division. Includes the Eagle Ford Shale in South Texas, the Anadarko Basin in northwestern Oklahoma and the Texas Panhandle, the Haynesville/Bossier Shales in northwestern Louisiana and East Texas and the Barnett Shale in the Fort Worth Basin in north-central Texas.

Northern Division. Includes the Utica Shale in Ohio and Pennsylvania, the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Niobrara Shale in the Powder River Basin in Wyoming.

Well Data

As of December 31, 2015, we held an interest in approximately 43,700 gross (18,000 net) productive wells, including 32,200 properties in which we held a working interest and 11,500 properties in which we held an overriding or royalty interest. Of the wells in which we had a working interest, 27,000 gross (15,600 net) were classified as natural gas productive wells and 5,200 gross (2,400 net) were classified as oil productive wells. Chesapeake operated approximately 20,800 of its 32,200 productive wells in which we had a working interest. During 2015, we drilled or participated in 611 gross (409 net) wells as operator and participated in another 203 gross (19 net) wells completed by other operators. We operate approximately 92% of our current daily production volumes.

Drilling Activity

The following table sets forth the wells we drilled or participated in during the periods indicated. In the table, "gross" refers to the total wells in which we had a working interest and "net" refers to gross wells multiplied by our working interest.



	2015				2014				2013
	Gross	%	Net	%	Gross	%	Net	%	Gross	%	Net	%
Development:
Productive	806	99	423	100	1,784	99	629	99	1,704	99	847	99
Dry	1	1	—	—	3	1	1	1	21	1	9	1
Total	807	100	423	100	1,787	100	630	100	1,725	100	856	100

Exploratory:
Productive	7	100	5	100	145	95	46	88	209	97	124	96
Dry	—	—	—	—	8	5	6	12	6	3	5	4
Total	7	100	5	100	153	100	52	100	215	100	129	100

The following table shows the wells we drilled or participated in by operating division:



	2015		2014		2013
	Gross Wells	Net Wells	Gross Wells	Net Wells	Gross Wells	Net Wells

Southern	537	258	1,448	473	1,352	698
Northern	277	170	492	209	588	287
Total	814	428	1,940	682	1,940	985

At December 31, 2015, we had 300 gross (180 net) wells in drilling or completing status.

Production, Sales Prices, Production and Gathering, Processing and Transportation Expenses

The following table sets forth information regarding our production volumes, oil, natural gas and NGL sales, average sales prices received and production and gathering, processing and transportation expenses for the periods indicated:



	Years Ended December 31,
	2015		2014		2013
Net Production:
Oil (mmbbl)	42		42		41
Natural gas (bcf)	1,070		1,095		1,095
NGL (mmbbl)	28		33		21
Oil equivalent (mmboe)^(a)	248		258		244

Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	45.77	$	89.41	$	96.78
Natural gas ($ per mcf)	$	2.31	$	4.14	$	3.44
NGL ($ per bbl)	$	14.06	$	30.95	$	36.08
Oil equivalent ($ per boe)	$	19.23	$	36.21	$	34.77

Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)	$	66.91	$	85.04	$	94.14
Natural gas ($ per mcf)	$	2.72	$	3.97	$	3.45
NGL ($ per bbl)	$	14.06	$	30.95	$	36.08
Oil equivalent ($ per boe)	$	24.54	$	34.74	$	34.36

Expenses ($ per boe):
Oil, natural gas and NGL production	$	4.22	$	4.69	$	4.74
Oil, natural gas and NGL gathering, processing and transportation	$	8.55	$	8.43	$	6.44

___________________________________________


(a)	Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency.

Oil, Natural Gas and NGL Reserves

The tables below set forth information as of December 31, 2015 with respect to our estimated proved reserves, the associated estimated future net revenue and present value (discounted at an annual rate of 10%) of estimated future net revenue before and after future income taxes (standardized measure). Neither the pre-tax present value of estimated future net revenue nor the after-tax standardized measure is intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.



	December 31, 2015
	Oil	Natural Gas		NGL		Total
	(mmbbl)	(bcf)		(mmbbl)		(mmboe)
Proved developed	216	5,329		158		1,262
Proved undeveloped	98	712		25		242
Total proved^(a)	314	6,041		183		1,504

		Proved Developed		Proved Undeveloped		Total Proved
		($ in millions)
Estimated future net revenue^(b)		$	7,153	$	2,334	$	9,487
Present value of estimated future net revenue^(b)		$	3,948	$	779	$	4,727
Standardized measure^(b)(c)						$	4,693



Operating Division	Oil	Natural Gas	NGL	Oil Equivalent	Percent of Proved Reserves		Present Value
	(mmbbl)	(bcf)	(mmbbl)	(mmboe)			($ millions)
Southern	272	3,252	110	924	61	%	$	3,347
Northern	42	2,789	73	580	39	%	1,380
Total	314	6,041	183	1,504	100	%	$	4,727	^(b)

___________________________________________


(a)	Includes 1 mmbbl of oil, 32 bcf of natural gas and 3 mmbbl of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 16 bcf of natural gas and 2 mmbbl of NGL of which are attributable to the noncontrolling interest holders.

(b)

Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2015. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2015. The prices used in our reserve reports were $50.28 per bbl of oil and $2.58 per mcf of natural gas, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2015. The amounts shown do not give effect to nonproperty-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue differs from the standardized measure only because the former does not include the effects of estimated future income tax expenses ($34 million as of December 31, 2015).

Management uses future net revenue, which is calculated without deducting estimated future income tax expenses, and the present value thereof as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While future net revenue and the present value thereof are based on prices, costs and discount factors which are consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company.


(c)	Additional information on the standardized measure is presented in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report.

As of December 31, 2015, our proved reserve estimates included 242 mmboe of reserves classified as proved undeveloped, compared to 605 mmboe as of December 31, 2014. Presented below is a summary of changes in our proved undeveloped reserves (PUDs) for 2015.



	Total
	(mmboe)
Proved undeveloped reserves, beginning of period	605
Extensions, discoveries and other additions	82
Revisions of previous estimates	(376	)
Developed	(67	)
Sale of reserves-in-place	(2	)
Purchase of reserves-in-place	—
Proved undeveloped reserves, end of period	242

As of December 31, 2015, there were no PUDs that had remained undeveloped for five years or more. In 2015, we invested approximately $720 million, net of drilling and completion cost carries of $18 million, to convert 67 mmboe of PUDs to proved developed reserves. In 2016, we estimate that we will invest approximately $347 million for PUD conversion. The downward revisions of 376 mmboe of PUDs in 2015 were related to a 505 mmboe reduction due to lower commodity prices partially offset by positive revisions of 129 mmboe resulting mainly from improved efficiencies and performance in our Eagle Ford assets.

The future net revenue attributable to our estimated PUDs of $2.3 billion as of December 31, 2015, and the $779 million present value thereof, have been calculated assuming that we will expend approximately $1.4 billion to develop these reserves ($347 million in 2016, $318 million in 2017, $437 million in 2018, $153 million in 2019 and $119 million in 2020), although the amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Chesapeake's developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as unexpected developmental drilling results, title issues and infrastructure availability or constraints.

Our proved undeveloped extensions, discoveries and other additions included 82 mmboe of reserves that were booked due to the application of reliable technology, including statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, reservoir simulation and volumetric analysis. The statistical nature of production performance coupled with highly certain reservoir continuity or quality and sufficient proved undeveloped locations established the reasonable certainty criteria required for booking proved reserves.

Our annual net decline rate on current proved producing properties is projected to be 31% in 2016, 21% in 2017, 17% in 2018, 14% in 2019 and 12% in 2020. Of our 1,262 mmboe of proved developed reserves as of December 31, 2015, approximately 97 mmboe, or 8%, were non-producing.

Chesapeake's ownership interest used for calculating proved reserves and the associated estimated future net revenue assumes maximum participation by other parties to our farm-out and participation agreements. SEC pricing used for calculating the estimated future net revenue attributable to our proved reserves does not reflect actual market prices for oil and natural gas production sold subsequent to December 31, 2015.

The Company's estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves as of December 31, 2015, 2014 and 2013, along with the changes in quantities and standardized measure of the reserves for each of the three years then ended, are shown in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of these estimates, and these revisions may be material. Accordingly, reserve estimates often differ from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate.

Reserves Estimation

Chesapeake's Corporate Reserves Department prepared approximately 41% of the proved reserves estimates (by volume), and approximately 23% of the proved reserves estimates (by value), disclosed in this report. Those estimates were based upon the best available production, engineering and geologic data.

Chesapeake's Director – Corporate Reserves is the technical person primarily responsible for overseeing the preparation of the Company's reserve estimates. His qualifications include the following:


•	25 years of practical experience working for major oil companies, including 17 years in reservoir engineering responsible for estimation and evaluation of reserves;


•	Bachelor of Science degree in Petroleum Engineering;


•	registered professional engineer in the state of Texas; and


•	member in good standing of the Society of Petroleum Engineers.

We ensure that the key members of our Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserves estimates. Each of our Corporate Reserves Advisors has more than 25 years’ experience in reserve estimation as a reservoir engineer. Our engineering technicians have a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. We maintain a continuous education program for our engineers and technicians on new technologies and industry advancements as well as refresher training on basic skills and analytical techniques.

We maintain internal controls such as the following to ensure the reliability of reserves estimations:


•	We follow comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserve estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Corporate Reserves Advisors.


•	The Corporate Reserves Department reviews the Company's proved reserves at the close of each quarter.


•	Each quarter, Corporate Reserves Department managers, the Director – Corporate Reserves, the Vice Presidents of our business units, the Director of Corporate and Strategic Planning and the Executive Vice Presidents of our operating divisions review all significant reserves changes and all new proved undeveloped reserves additions.


•	The Corporate Reserves Department reports independently of our operating divisions.


•	The five year PUD development plan is reviewed and approved annually by the Director of Corporate Reserves and the Director of Corporate and Strategic Planning.

We engaged two third-party engineering firms to prepare approximately 59% by volume and 77% by value of our estimated proved reserves at year-end 2015. The portion of our estimated proved reserves prepared by each of our third-party engineering firms as of December 31, 2015 is presented below.



	% Prepared (by Volume)	% Prepared (by Value)	Operating Division
Ryder Scott Company, L.P.	36%	58%	Southern
PetroTechnical Services, Division of Schlumberger Technology Corporation	23%	19%	Northern

Copies of the reports issued by the engineering firms are filed with this report as Exhibits 99.1 and 99.2. The qualifications of the technical person at each of these firms primarily responsible for overseeing his firm's preparation of the Company's reserve estimates are set forth below.

Ryder Scott Company, L.P.


•	over 30 years of practical experience in the estimation and evaluation of reserves


•	registered professional engineer in the state of Texas


•	member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers


•	Bachelor of Science degree in Electrical Engineering

PetroTechnical Services, Division of Schlumberger Technology Corporation


•	over 30 years of practical experience in the estimation and evaluation of reserves


•	registered professional geologist license in the Commonwealth of Pennsylvania


•	member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers


•	Bachelor of Science degree in Geological Sciences

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

The following table sets forth historical costs incurred in oil and natural gas property acquisitions, exploration and development activities during the periods indicated:



	Years Ended December 31,
	2015		2014		2013
	($ in millions)
Acquisition of Properties:
Proved properties	$	—	$	214	$	22
Unproved properties	454		1,224		997
Exploratory costs	112		421		699
Development costs	2,941		4,204		4,888
Costs incurred^(a)(b)	$	3,507	$	6,063	$	6,606

___________________________________________


(a)	Exploratory and development costs are net of joint venture drilling and completion cost carries of $51 million, $679 million and $884 million in 2015, 2014 and 2013, respectively.


(b)	Includes capitalized interest and asset retirement obligations as follows:



Capitalized interest	$	410		$	604	$	815
Asset retirement obligations	$	(15	)	$	39	$	7

A summary of our exploration and development, acquisition and divestiture activities in 2015 by operating division is as follows:



	Gross Wells Drilled	Net Wells Drilled	Exploration and Development		Acquisition of Unproved Properties		Acquisition of Proved Properties		Sales of Unproved Properties			Sales of Proved Properties			Total^(a)
	($ in millions)
Southern	537	258	$	1,833	$	120	$	—	$	(128	)	$	(1,026	)	$	799
Northern	277	170	1,220		334		—		(91		)	(3		)	1,460
Total	814	428	$	3,053	$	454	$	—	$	(219	)	$	(1,029	)	$	2,259

___________________________________________


(a)	Includes capitalized internal costs of $196 million and related capitalized interest of $410 million.

Acreage

The following table sets forth our gross and net developed and undeveloped oil and natural gas leasehold and fee mineral acreage as of December 31, 2015. "Gross" acres are the total number of acres in which we own a working interest. "Net" acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our unexercised options to acquire additional acreage.



	Developed Leasehold		Undeveloped Leasehold		Fee Minerals		Total
	Gross Acres	Net Acres	Gross Acres	Net Acres	Gross Acres	Net Acres	Gross Acres	Net Acres
	(in thousands)
Southern	5,420	2,704	1,205	579	164	30	6,789	3,313
Northern	1,885	1,424	4,932	2,996	701	438	7,518	4,858
Total	7,305	4,128	6,137	3,575	865	468	14,307	8,171

Most of our leases have a three- to five-year primary term, and we manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our drilling to establish production in paying quantities in order to hold leases by production, timely exercising our contractual rights to pay delay rentals to extend the terms of leases we value, planning noncore divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth as of December 31, 2015 the expiration periods of gross and net undeveloped leasehold acres.



	Acres Expiring
	Gross Acres	Net Acres
	(in thousands)
Years Ending December 31:
2016	1,691	1,067
2017	1,084	663
2018	425	169
After 2018	2,937	1,676
Total^(a)	6,137	3,575

___________________________________________


(a)	Includes 1.565 million gross (797,272 net) held-by-production acres that will remain in force as our production continues on the subject leases, and other leasehold acreage where management anticipates the lease to remain in effect past the primary term of the agreement due to our contractual option to extend the lease term.

Marketing, Gathering and Compression

Our marketing activities, along with our midstream gathering and compression operations, constitute a reportable segment under accounting guidance for disclosure about segments of an enterprise and related information. See Note 21 of the notes to our consolidated financial statements included in Item 8 of Part II of this report.

Marketing

Chesapeake Energy Marketing, L.L.C., one of our wholly owned subsidiaries, provides oil, natural gas and NGL marketing services, including commodity price structuring, securing and negotiating gathering, hauling, processing and transportation services, contract administration and nomination services for Chesapeake and other interest owners in Chesapeake-operated wells. We also perform marketing services for third-party producers in wells in which we do not have an interest. We attempt to enhance the value of oil and natural gas production by aggregating volumes to be sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments.

Oil production is generally sold under market-sensitive short-term or spot price contracts. Natural gas and NGL production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. By the terms of the percentage-of-proceeds contracts, we receive a percentage of the resale price received from the ultimate purchaser. Under percentage-of-index contracts, the price we receive is tied to published indices. Sales to BP PLC constituted approximately 14% of our total revenues (before the effects of hedging) for the year ended December 31, 2015. Sales to Exxon Mobil Corporation constituted approximately 12% of our total revenues (before the effects of hedging) for the year ended December 31, 2014. There were no sales to individual customers constituting 10% or more of total revenues (before the effects of hedging) for the year ended December 31, 2013.

Midstream Gathering Operations

Historically, we invested, directly and through affiliates, in gathering systems and processing facilities to complement our natural gas operations in regions where we had significant production and additional infrastructure was required. These systems were designed primarily to gather our production for delivery into major intrastate or interstate pipelines. In addition, our midstream business provides services to joint working interest owners and other third-party customers. We generate revenues from our gathering, treating and compression activities through various gathering rate structures. We also process a portion of our natural gas at various third-party plants.

In 2012 and 2013, we sold substantially all of our midstream business, including most of our gathering assets. We continue to own certain gathering pipelines primarily associated with vertical well production in the eastern United States and four natural gas processing facilities located in West Virginia. See Note 16 of the notes to the consolidated financial statements included in Item 8 of Part II of this report for further discussion of the midstream sales transactions.

Compression Operations

Since 2003, we have operated our compression business through our wholly owned subsidiaries Compass Manufacturing, L.L.C. (Compass) and MidCon Compression, L.L.C. (MidCon). Compass designs, engineers, fabricates, installs and sells natural gas compression units, accessories and equipment used in the production, treatment and processing of oil and natural gas. A majority of the completed compressors are sold to MidCon. MidCon operates wellhead and system compressors, with approximately 450,000 horsepower of compression, to facilitate the transportation of natural gas primarily produced from Chesapeake-operated wells.

Spin-Off of Oilfield Services Business

On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary Chesapeake Oilfield Operating, L.L.C. (COO), into an independent, publicly traded company called Seventy Seven Energy Inc. (SSE). See Note 13 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional information regarding the spin-off.

Following the spin-off, we have no ownership interest in SSE. Therefore, we ceased to consolidate SSE’s assets and liabilities as of the spin-off date. Because we expect to have significant continued involvement associated with SSE’s future operations through the various agreements described in Note 13 of the notes to our consolidated financial statements included in Item 8 of Part II of this report, our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations.

Competition

We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than ours. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. We believe that our technological expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively.

Regulation – General

All of our operations are conducted onshore in the United States. The U.S. oil and natural gas industry is regulated at the federal, state and local levels, and some of the laws and regulations that govern our operations carry substantial administrative, civil and criminal penalties for non-compliance. Although we believe we are in material compliance with all applicable laws and regulations, and that the cost of compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations could be, and frequently are, amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance or non-compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, local governments, the courts and federal agencies, such as the U.S. Environmental Protection Agency (EPA), the Federal Energy Regulatory Commission (FERC), the Department of Transportation (DOT), the Department of Interior (DOI) and the U.S. Army Corps of Engineers (USACE). We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems.

Exploration and Production Operations

The laws and regulations applicable to our exploration and production operations include requirements for permits or approvals to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to such laws and regulations include, but are not limited to, the following:


•	seismic operations;


•	the location of wells;


•	construction and operations activities, including in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species or their habitats;


•	the method of drilling and completing wells;


•	production operations, including the installation of flowlines and gathering systems;


•	air emissions and hydraulic fracturing;


•	the surface use and restoration of properties upon which oil and natural gas facilities are located, including the construction of well pads, pipelines, impoundments and associated access roads;


•	water withdrawal;


•	the plugging and abandoning of wells;


•	the generation, storage, transportation treatment, recycling or disposal of hazardous waste, fluids or other substances in connection with operations;


•	the construction and operation of underground injection wells to dispose of produced water and other liquid oilfield wastes;


•	the construction and operation of surface pits to contain drilling muds and other fluids associated with drilling operations;


•	the marketing, transportation and reporting of production; and


•	the valuation and payment of royalties.

Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.

Our exploration and production activities are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells that may be drilled in a particular area) and the unitization or pooling of oil and natural gas properties. In this regard, some states, such as Oklahoma, allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas, West Virginia and Pennsylvania, rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to fully develop a project if the operator owns or controls less than 100% of the leasehold. In addition, some states’ conservation laws establish maximum rates of production from oil and natural gas wells, generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil and natural gas we can produce and to limit the number of wells and the locations at which we can drill.

Hydraulic Fracturing

Hydraulic fracturing is typically regulated by state oil and gas regulatory authorities, including specifically the requirement to disclose certain information related to hydraulic fracturing operations. We follow applicable legal requirements for groundwater protection in our operations that are subject to supervision by state and federal regulators (including the BLM on federal acreage). Furthermore, our well construction practices require the installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers. Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. In June 2015, New York created a statewide ban on hydraulic fracturing. Similar bans have been adopted by local governments, although many of these actions are the subject of legal challenges.

In February 2014, the EPA released its final guidance on the use of diesel additives in hydraulic fracturing operations. The EPA is also engaged in a study of the potential impacts of hydraulic fracturing activities on drinking water resources in these states where the EPA is the permitted authority, including Pennsylvania, with a progress report released in late 2012 and a draft report released in June 2015. It concluded that hydraulic fracturing activities have not led to widespread systematic impacts on drinking water resources in the U.S., but there are above and below- ground mechanisms by which hydraulic fracturing could affect drinking water resources. In addition, in March 2015, the BLM issued a final rule to regulate hydraulic fracturing on federal and Indian land; however, enforcement of the rule has been delayed pending a decision in a legal challenge in the U.S. District Court of Wyoming. Further, the EPA issued an Advanced Notice of Proposed Rulemaking in May 2014 seeking comments relating to the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and mechanisms for obtaining this information. These actions, in conjunction with other analyses by federal and state agencies to assess the impacts of hydraulic fracturing could spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities. For example, on February 16, 2016, the Oklahoma Corporation Commission (OCC) implemented a volume reduction plan for oil and natural gas disposal wells injecting wastewater into the Arbuckle formation. The OCC’s plan, in conjunction with a 191,000 barrel per day reduction plan already implemented in the Byron/Cherokee area, will create a total volume cutback of over 500,000 barrels per day, or about 40%.

Restrictions on hydraulic fracturing could make it prohibitive to conduct our operations, and also reduce the amount of oil, natural gas and NGL that we are ultimately able to produce in commercial quantities from our properties. For further discussion, see Item 1A. Risk Factors – Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Midstream Operations

Historically, Chesapeake invested, directly and through an affiliate, in gathering systems and processing facilities to complement our natural gas operations in regions where we had significant production and additional infrastructure was required. In 2012 and 2013, we sold substantially all of our midstream business, including most of our gathering assets. As a result, the impact on our business of compliance with the laws and regulations described below has decreased significantly since the fourth quarter of 2012.

In addition to the environmental, health and safety laws and regulations discussed below under Regulation – Environment, Health and Safety Matters, a small amount of our midstream facilities is subject to federal regulation by the Pipeline and Hazardous Materials Safety Administration of the DOT pursuant to the Natural Gas Pipeline Safety Act of 1968 (NGPSA) and the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their assertion of authority and capacity to address pipeline safety. Our natural gas pipelines have inspection and compliance programs designed to keep the facilities in compliance with applicable pipeline safety and pollution control laws and regulations.

Natural gas gathering and intrastate transportation facilities are exempt from the jurisdiction of the FERC under the Natural Gas Act. Although the FERC has made no formal determinations with regard to any of our facilities, we believe that our natural gas pipelines and related facilities are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to the FERC's jurisdiction. Nevertheless, FERC regulation affects our gathering and compression business, generally, in that some of our assets feed into FERC-regulated systems. FERC provides policies and practices across a range of natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency, and market center promotion, which indirectly affect our gathering and compression business. In addition, the distinction between FERC-regulated transmission facilities and federally unregulated gathering and intrastate transportation facilities is a fact-based determination made by the FERC on a case-by-case basis; this distinction has also been the subject of regular litigation and change. The classification and regulation of our gathering and intrastate transportation facilities are subject to change based on future determinations by the FERC, the courts and Congress.

Our natural gas gathering operations are subject to ratable-take and common-purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate typically have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination.

Regulation – Environment, Health and Safety

Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of human health and safety, the environment and natural resources. These laws and regulations can restrict or impact our business activities in many ways, such as:


•	requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of wastes and other substances associated with operations;


•	limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species and/or species of special statewide concern or their habitats;


•	requiring investigatory and remedial actions to address pollution caused by our operations or attributable to former operations;


•	requiring noise, lighting, visual impact, odor and/or dust mitigation, setbacks, landscaping, fencing, and other measures;


•	restricting access to certain equipment or areas to a limited set of employees or contractors who have proper certification or permits to conduct work (e.g., confined space entry and process safety maintenance requirements); and


•	restricting or even prohibiting water use based upon availability, impacts or other factors.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial or restoration obligations, and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, local restrictions, such as state or local moratoria, city ordinances, zoning laws and traffic regulations, may restrict or prohibit the execution of our drilling and production plans. In addition, third parties, such as neighboring landowners, may file claims alleging property damage, nuisance or personal injury arising from our operations or from the release of hazardous substances, hydrocarbons or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. We monitor developments at the federal, state and local levels to inform our actions pertaining to future regulatory requirements that might be imposed to mitigate the costs of compliance with any such requirements. We also participate in industry groups that help formulate recommendations for addressing existing or future regulations and that share best practices and lessons learned in relation to pollution prevention and incident investigations.

Below is a discussion of the major environmental, health and safety laws and regulations that relate to our business. We believe that we are in material compliance with these laws and regulations. We do not believe that compliance with existing environmental, health and safety laws or regulations will have a material adverse effect on our financial condition, results of operations or cash flow. At this point, however, we cannot reasonably predict what applicable laws, regulations or guidance may eventually be adopted with respect to our operations or the ultimate cost to comply with such requirements.

Hazardous Substances and Waste

Federal and state laws, in particular the federal Resource Conservation and Recovery Act (RCRA) regulate hazardous and non-hazardous wastes. In the course of our operations, we generate petroleum hydrocarbon wastes, such as drill cuttings, produced water and ordinary industrial wastes. Under a longstanding legal framework, certain of these wastes are not subject to federal regulations governing hazardous wastes, although they are regulated under other federal and state waste laws. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.

Federal, state and local laws may also require us to remove or remediate wastes or hazardous substances that have been previously disposed of or released into the environment. This can include removing or remediating wastes or hazardous substances disposed of or released by us (or prior owners or operators) in accordance with then current laws, suspending or ceasing operations at contaminated areas, or performing remedial well plugging operations or

response actions to reduce the risk of future contamination. Federal laws, including the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and analogous state laws impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered legally responsible for releases of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, persons who disposed of or arranged for the disposal of hazardous substances at the site, and any person who accepted hazardous substances for transportation to the site. CERCLA and analogous state laws also authorize the EPA, state environmental agencies and, in some cases, third parties to take action to prevent or respond to threats to human health or the environment and/or seek recovery of the costs of such actions from responsible classes of persons.

The Underground Injection Control (UIC) Program authorized by the Safe Drinking Water Act prohibits any underground injection unless authorized by a permit. Chesapeake recycles and reuses some produced water and we also dispose of produced water in Class II UIC wells, which are designed and permitted to place the water into deep geologic formations, isolated from fresh water sources. Permits for Class II UIC wells may be issued by the EPA or by a state regulatory agency if EPA has delegated its UIC Program authority. Because some states have become concerned that the disposal of produced water could under certain circumstances contribute to seismicity, they have adopted or are considering adopting additional regulations governing such disposal.

Air Emissions

Our operations are subject to the federal Clean Air Act (CAA) and comparable state laws and regulations. Among other things, these laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and impose various control, monitoring and reporting requirements. Permits and related compliance obligations under the CAA, each state's development and promulgation of regulatory programs to comport with federal requirements, as well as changes to state implementation plans for controlling air emissions in regional non-attainment or near-non-attainment areas, may require oil and gas exploration and production operators to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies.

In 2012, the EPA published final New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP) that amended the existing NSPS and NESHAP standards for oil and gas facilities and created new NSPS standards for oil and gas production, transmission and distribution facilities with a compliance deadline of January 1, 2015. In 2013 and 2014, the EPA issued updated rules regarding storage tanks and made additional clarifications to these rules. In December 2014, the EPA issued additional amendments to these rules that, among other things, distinguish between multiple flowback stages during completion of hydraulically fractured wells and clarify that storage tanks permanently removed from service are not affected by any requirements. In July 2015, the EPA finalized two updates to the rules addressing the definition of low pressure gas wells and references to tanks that are connected to one another (referred to as connected in parallel). Further, in September 2015, the EPA issued a proposed rule that would update and expand the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In January 2016, the BLM also proposed rules to require additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Indian lands.

In 2010, the EPA published rules that require monitoring and reporting of greenhouse gas emissions from petroleum and natural gas systems. We, along with other industry groups, filed suit challenging certain provisions of the rules and are engaged in settlement negotiations to amend and correct the rules. We anticipate final resolution to this litigation in the near future. In October 2015, EPA finalized new reporting requirements for boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. In January 2016, the EPA proposed two more revisions to the greenhouse gas reporting rule. One proposal addresses leaks from oil and gas equipment and the other proposal is intended to improve implementation of the rule, while also proposing confidentiality determinations for the reporting of certain data elements to the program.

In addition, in October 2015, the EPA published its final rule revising downward the ozone national ambient air quality standard to 70 parts per billion. Our business and operations could be subject to increased operating and compliance costs associated with these regulations.

Discharges into Waters

The federal Water Pollution Control Act, or the Clean Water Act (CWA), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as U.S. waters. In June 2015, the EPA and USACE jointly published a rule regarding the definition of waters of the United States that substantially expands the waters regulated under the CWA. Implementation of the rule was temporarily stayed in October 2015 by the U.S. Court of Appeals for the Sixth Circuit, pending further action. The placement of dredge or fill material into jurisdictional water or U.S. wetlands is prohibited, except in accordance with the terms of a permit issued by the USACE. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state agency delegated with EPA's authority. In April 2015, the EPA also published proposed pretreatment standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works (POTWs). Further, Chesapeake's corporate policy prohibits discharge of produced water to surface waters. Spill prevention, control and countermeasure regulations require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities and construction activities.

The Oil Pollution Act of 1990 (OPA) establishes strict liability for owners and operators of facilities that release oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A ''responsible party'' under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the United States.

Health and Safety

The Occupational Safety and Health Act (OSHA) and comparable state laws regulate the protection of the health and safety of our employees. The federal Occupational Safety and Health Administration has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. OSHA also requires employee training and maintenance of records, and the OSHA hazard communication standard and EPA community right-to-know regulations under the Emergency Planning and Community Right-to-Know Act of 1986 require that we organize and/or disclose information about hazardous materials used or produced in our operations.

Endangered Species

The Endangered Species Act (ESA) restricts activities that may affect areas that contain endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, as a result of a settlement reached in 2011, the U.S. Fish and Wildlife Service is required to make a determination on the listing of more than 250 species as endangered or threatened over the next several years. The designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.

Global Warming and Climate Change

At the federal level, EPA regulations require us to establish and report an inventory of greenhouse gas emissions. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change, such as the President’s Climate Action Plan which calls for reducing methane emissions, could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell. As discussed above, the EPA proposed new standards of performance limiting methane emissions from oil and gas sources in 2015. The potential increase in our operating costs could include new or increased costs to (i) obtain permits, (ii) operate and maintain our equipment and facilities (through the reduction or elimination of venting and flaring of methane), (iii) install new emission controls on our equipment and facilities, (iv) acquire allowances authorizing our greenhouse gas emissions, (v) pay taxes related to our greenhouse gas emissions and (vi) administer and manage a greenhouse gas emissions program. In addition to these federal actions, various state governments and/or regional agencies may consider enacting new legislation and/or promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations.

Title to Properties

Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and natural gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Nevertheless, we are involved in title disputes from time to time which result in litigation.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, Chesapeake could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

Chesapeake maintains a control of well policy with a $50 million single well limit and a $100 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. Chesapeake also carries a $460 million comprehensive general liability umbrella policy and a $150 million pollution liability policy. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to Chesapeake’s working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.

Facilities

Chesapeake owns an office complex in Oklahoma City and owns or leases various field offices in cities or towns in the areas where we conduct our operations.

Executive Officers

Robert D. Lawler, President, Chief Executive Officer and Director

Robert D. (“Doug”) Lawler, 49, has served as President and Chief Executive Officer since June 2013. Prior to joining Chesapeake, Mr. Lawler served in multiple engineering and leadership positions at Anadarko Petroleum Corporation. His positions at Anadarko included Senior Vice President, International and Deepwater Operations and member of Anadarko’s Executive Committee from July 2012 to May 2013; Vice President, International Operations from December 2011 to July 2012; Vice President, Operations for the Southern and Appalachia Region from March 2009 to July 2012; and Vice President, Corporate Planning from August 2008 to March 2009. Mr. Lawler began his career with Kerr-McGee Corporation in 1988 and joined Anadarko following its acquisition of Kerr-McGee in 2006.

Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer

Domenic J. (“Nick”) Dell'Osso, Jr., 39, has served as Executive Vice President and Chief Financial Officer since November 2010. Mr. Dell'Osso served as Vice President – Finance of the Company and Chief Financial Officer of Chesapeake's wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010.

M. Christopher Doyle, Executive Vice President – Operations, Northern Division

M. Christopher Doyle, 43, has served as Executive Vice President – Operations, Northern Division since January 2015 and previously served as Senior Vice President – Operations, Northern Division since August 2013. Prior to joining Chesapeake, Mr. Doyle served for 18 years at Anadarko in various positions of increasing responsibility within operations, finance and planning including international assignments in Algeria and London. His positions at Anadarko included Vice President of Operations from May to August 2013; Director, Corporate Planning from July 2012 to May 2013; General Manager – Appalachian Basin from June 2009 to July 2012; and Manager, Reserves and Planning – Southern Region from January to June 2009.

Frank Patterson, Executive Vice President – Exploration, Technology & Land

Frank Patterson, 57, has served as Executive Vice President – Exploration, Technology & Land since May 2015. Before joining Chesapeake, Mr. Patterson served in various roles at Anadarko from 2006 to 2015, most recently as Senior Vice President – International Exploration. Prior to that he was Vice President – Deepwater Exploration at Kerr-McGee and Manager – Geology at Sun E&P/Oryx Energy.

Mikell J. Pigott, Executive Vice President – Operations, Southern Division

Mikell J. (“Jason”) Pigott, 42, has served as Executive Vice President – Operations, Southern Division since January 2015 and previously served as Senior Vice President – Operations, Southern Division since August 2013. Before joining Chesapeake, Mr. Pigott served in various positions at Anadarko and focused on all aspects of developing unconventional resources. His positions at Anadarko included General Manager Eagle Ford from June to August 2013; General Manager East Texas and North Louisiana from October 2010 to June 2013; Southern & Appalachia Planning Manager from October 2009 to October 2010; Reservoir Engineering Manager East Texas and North Louisiana from July to October 2009; and Reservoir Engineering Manager Bossier from 2007 to July 2009.

James R. Webb, Executive Vice President – General Counsel and Corporate Secretary

James R. Webb, 48, has served as Executive Vice President – General Counsel and Corporate Secretary since January 2014. Previously, he served as Senior Vice President – Legal and General Counsel since October 2012 and as Corporate Secretary since August 2013. Mr. Webb first joined Chesapeake in May 2012 on a contract basis as Chief Legal Counsel. Prior to joining Chesapeake, Mr. Webb was an attorney with the law firm of McAfee & Taft from 1995 to October 2012.

Michael A. Johnson, Senior Vice President – Accounting, Controller and Chief Accounting Officer

Michael A. Johnson, 50, has served as Senior Vice President – Accounting, Controller and Chief Accounting Officer since 2000. He served as Vice President of Accounting and Financial Reporting from 1998 to 2000 and as Assistant Controller from 1993 to 1998.

Other Senior Officer

Cathlyn L. Tompkins, Senior Vice President – Information Technology and Chief Information Officer

Cathlyn L. Tompkins, 55, has served as Senior Vice President – Information Technology and Chief Information Officer since 2006. Ms. Tompkins served as Vice President – Information Technology from 2005 to 2006.

Employees

Chesapeake had approximately 4,400 employees as of December 31, 2015.

Glossary of Oil and Gas Terms

The terms defined in this section are used throughout this report.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bboe. One billion barrels of oil equivalent.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet of natural gas equivalent.

Bbtu. One billion British thermal units.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Boe. Barrel of oil equivalent.

Commercial Well; Commercially Productive Well. A well which produces oil, natural gas and/or NGL in sufficient quantities such that proceeds from the sale of this production exceeds production expenses and taxes.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, natural gas or NGL, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Drilling Carry Obligation. An obligation of one party to pay certain well costs attributable to another party.

Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Exploratory Well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

Full Cost Pool. The full cost pool consists of all costs associated with property acquisition, exploration and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.

Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the NYMEX.

Horizontal Drilling. Drilling at angles greater than 70 degrees from vertical.

Mboe. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet.

Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.

Mmboe. One million barrels of oil equivalent.

Mmbtu. One million btus.

Mmcf. One million cubic feet.

Natural Gas Liquids (NGL). Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.

Net Acres or Net Wells. The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil, natural gas and NGL reserves.

Present Value or PV-10. When used with respect to oil, natural gas and NGL reserves, present value, or PV-10, means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Price Differential. The difference in the price of oil, natural gas or NGL received at the sales point and the NYMEX price.

Productive Well. A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.

Proved Developed Reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved Properties. Properties with proved reserves.

Proved Reserves. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of a reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves (PUDs). Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively high expenditure compared to the cost of drilling a new well is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless these techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Realized and Unrealized Gains and Losses on Oil, Natural Gas and NGL Derivatives. Realized gains and losses includes the following items:(i) settlements of non-designated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period production revenues offset by amounts reclassified as realized gains and losses during the period. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty Interest. An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production free of costs of production.

Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures).

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Standardized Measure of Discounted Future Net Cash Flows. The discounted future net cash flows relating to proved reserves based on the prices used in estimating the proved reserves, year-end costs and statutory tax rates (adjusted for permanent differences) and a 10% annual discount rate.

Tbtu. One trillion British thermal units.

Undeveloped Acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether the acreage contains proved reserves.

Unproved Properties. Properties with no proved reserves.

Volumetric Production Payment (VPP). As we use the term, a volumetric production payment represents a limited-term overriding royalty interest in oil and natural gas reserves that: (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser's only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain the remaining reserves, if any, after the scheduled production volumes have been delivered.

Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

West Texas Intermediate (WTI). A grade of crude oil used as a benchmark in oil pricing.


ITEM 1A.	Risk Factors

There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, operating results, cash flows, reserves and/or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.

Oil, natural gas and NGL prices fluctuate widely, and continued low prices or lower prices for an extended period of time are likely to have a material adverse effect on our business.

Our revenues, operating results, profitability, liquidity and ability to grow depend primarily upon the prices we receive for the oil, natural gas and NGL we sell. We require substantial expenditures to replace reserves, sustain production and fund our business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, low prices may result in ceiling test write-downs of our oil and natural gas properties. We urge you to read the risk factors below for a more detailed description of each of these risks.

Historically, the markets for oil, natural gas and NGL have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGL, market uncertainty and other factors that are beyond our control, including:


•	domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;


•	weather conditions;


•	changes in the level of consumer and industrial demand;


•	the price and availability of alternative fuels;


•	the effectiveness of worldwide conservation measures;


•	the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;


•	the level and effect of trading in commodity futures markets, including by commodity price speculators and others;


•	U.S. exports of oil and/or liquefied natural gas;


•	the price and level of foreign imports;


•	the nature and extent of domestic and foreign governmental regulations and taxes;


•	the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;


•	political instability or armed conflict in oil and natural gas producing regions;


•	acts of terrorism; and


•	domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. Oil and natural gas prices continued to decline and remain low throughout 2015 and into the 2016 first quarter. As of February 23, 2016, 56% and 58% of our forecasted 2016 oil production and natural gas production, respectively, was hedged under swaps. Even with oil and natural gas derivatives currently in place to mitigate price risks associated with a portion of our future production, our 2016 revenue and results of operations are expected to be below 2015 levels and will be further adversely affected if commodity prices remain at current levels. In addition, a prolonged extension of prices at these levels will reduce the quantities of reserves that may be economically produced.

We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and we may have difficulty paying our debts as they become due.

As of December 31, 2015, we had approximately $9.7 billion in principal amount of debt (including current maturities), and borrowing capacity of approximately $4.0 billion under our revolving credit facility, which was undrawn (other than letters of credit issued thereunder in the aggregate amount of $16 million) as of December 31, 2015. Approximately $1.9 billion principal amount of debt matures or can be put to us in 2017 and approximately $878 million principal amount of debt matures or can be put to us in 2018. We also had a net working capital deficit of approximately $1.205 billion as of December 31, 2015.

The level of and terms and conditions governing our debt:


•	require us to dedicate a substantial portion of our cash flow from operations to service our existing debt obligations and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;


•	increase our vulnerability to economic downturns or adverse developments in our business;


•	limit our ability to access the capital markets to refinance our existing indebtedness, to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, debt service requirements or execution of our business strategy or for other purposes;


•	expose us to the risk of increased interest rates as certain of our borrowings, including borrowings under our credit facility, bear interest at floating rates;


•	place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;


•	place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or that have less restrictive terms governing their indebtedness and, therefore, that may be able to take advantage of opportunities that our indebtedness prevents us from pursuing;


•	limit management’s discretion in operating our business; and


•	increase our cost of borrowing.

Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation. We have previously drawn on our credit facility for liquidity, and the borrowing base under our credit facility is subject to redetermination. To the extent that the value of the collateral pledged under the credit facility declines in light of declining oil and natural gas prices or otherwise, we may be required to pledge additional collateral in order to maintain the full availability of the commitments thereunder, and we cannot assure you that we will be able to maintain a sufficiently high valuation to maintain the full commitments. Asset sales may also reduce available collateral and availability under the credit facility. In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we are unable to service our indebtedness and other obligations, we may be required to restructure or refinance all or part of our existing debt, sell assets, reduce capital expenditures, borrow more money or raise equity. We may not be able to restructure or refinance our debt, reduce capital expenditures, sell assets, borrow more money or raise equity on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness. In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness is uncertain and will be affected by our future performance and events or circumstances beyond our control. Failure to comply with these covenants would result in an event of default under such indebtedness, the potential acceleration of our obligation to repay outstanding debt and the potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness. Any of the above risks could materially adversely affect our business, financial condition, cash flows and results of operations and could lead to a restructuring, which may include bankruptcy filing.

We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by our debt level and industry conditions.

Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Recent decreases in commodity prices, among other factors, are causing and may continue to cause lenders to increase interest rates, enact tighter lending standards which we may not satisfy as a result of our debt level or otherwise, refuse to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. In addition, the filing of this annual report will render us unable to use our currently effective universal shelf Form S-3 registration statement. Because we failed to pay dividends on our convertible preferred stock during the 2016 first quarter, we will no longer meet the criteria of a "well-known seasoned issuer" on the date of filing of this report, which previously enabled us to, among other things, file automatically effective shelf registration statements. Accordingly, even if we were able to access the capital markets, any attempt to do so could be more expensive or subject to significant delays. If we are unable to access the capital and credit markets on favorable terms or at all, it could materially adversely affect our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. Any cash flow insufficiency would materially adversely impact our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and service our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy, the impact of legislative or regulatory actions on how we conduct our business or competitive initiatives of our competitors, are beyond our control. Factors that may cause us to generate cash flow that is insufficient to meet our debt obligations include the events and risks related to our business, many of which are beyond our control.

Our liquidity is dependent on many factors, including availability under our credit facility and cost and access to capital and credit markets, which are affected by the price and performance of our equity and debt securities. If the borrowing base under our credit facility is reduced and we are otherwise unable to maintain an adequate liquidity position, we may not have the financial flexibility to meet our debt obligations or manage our business, including activities that we do not currently fund with our credit facility but may in the future, such as our planned capital expenditures.

If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay or refinance our indebtedness, manage our working capital or fund our other capital needs. We do not expect to generate sufficient cash flow from operations to satisfy our 2017 and 2018 debt maturities. Accordingly, we are undertaking and will continue to undertake various alternative financing plans, which may include:


•	refinancing or restructuring all or a portion of our debt;


•	obtaining alternative financing;


•	selling assets;


•	reducing or delaying capital investments;


•	seeking to raise additional capital; or


•	revising or delaying our strategic plans.

However, we cannot assure you that we would be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations and capital requirements or that these actions would be permitted under the terms of our various debt instruments. If commodity prices remain at depressed levels and we are unsuccessful in implementing our alternative financing plans or otherwise improving our liquidity, we may not be able to fund budgeted capital expenditures or meet our debt service requirements in 2017 and beyond.

Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition, results of operations, cash flows and liquidity. Any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a further reduction of our credit rating, which could significantly harm our ability to incur additional indebtedness on acceptable terms. Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our credit facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. In addition, the lenders under our credit facility could compel us to apply our available cash to repay our borrowings. If the amounts outstanding under the credit facility or any of our other significant indebtedness were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our credit facility and floating rate senior notes due 2019 bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Restrictive covenants in our credit facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Our credit facility imposes operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:


•	incur additional indebtedness;


•	make investments or loans;


•	create liens;


•	consummate mergers and similar fundamental changes;


•	make restricted payments;


•	make investments in unrestricted subsidiaries; and


•	enter into transactions with affiliates.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our credit facility. The restrictions contained in the credit facility could:


•	limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and


•	adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.

Also, our credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Further declines in oil, NGL and natural gas prices, or a prolonged period of

oil, NGL and natural gas prices at depressed levels, could eventually result in our failing to meet one or more of the financial covenants under our credit facility, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit facility. A default under our credit facility, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder. The accelerated debt would become immediately due and payable, which would in turn trigger cross-acceleration and cross-default rights under our other debt. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. In addition, in the event of an event of default under the credit facility, the lenders could foreclose on the collateral securing the credit facility and require repayment of all borrowings outstanding. If the amounts outstanding under the credit facility or any of our other indebtedness were to be accelerated, our assets may not be sufficient to repay in full the money owed to the lenders or to our other debt holders. Moreover, any new indebtedness we incur may impose financial restrictions and other covenants on us that may be more restrictive than our existing debt agreements.

A further downgrade in our credit rating could negatively impact our availability and cost of capital and could require us to post more collateral under certain commercial arrangements.

Since December 2015, Moody’s Investor Services, Inc. has lowered the Company’s senior unsecured credit rating from “Ba3” to “Caa3”, and Standard & Poor’s Rating Services has lowered the Company’s senior unsecured credit rating from “BB-” to “CC”. The downgrades were primarily a result of the effect of low oil and natural gas prices on our ability to generate cash flow from operations. We cannot provide assurance that our credit ratings will not be further reduced if commodity prices continue to remain low. Any further downgrade to our credit ratings could negatively impact our availability and cost of capital.

Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as transportation, gathering, processing and hedging agreements. As of February 24, 2016, we have received requests to post approximately $220 million in collateral, of which we have posted approximately $92 million. We have posted the required collateral, primarily in the form of letters of credit and cash, or are otherwise complying with these contractual requests for collateral. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $698 million (excluding the supersedeas bond with respect to the 2019 Notes litigation discussed in Note 3 of the notes to our consolidated financial statements included in Item 8 of this report), which may be in the form of additional letters of credit, cash or other acceptable collateral. Any posting of collateral consisting of cash or letters of credit, which would reduce availability under our credit facility, will negatively impact our liquidity.

We expect to have further significant write downs of the carrying value of our oil and natural gas properties if commodity prices remain low.

Under the full cost method of accounting for costs related to our oil and natural gas properties, we are required to write down the carrying value of our oil and natural gas assets if capitalized costs exceed the quarterly ceiling limit, which is based on the average of commodity prices on the first day of the month over the trailing 12-month period. Such write-downs can be material. For example, for the year ended December 31, 2015, we reported non-cash impairment charges on our oil and natural gas properties totaling $18.238 billion, primarily resulting from a substantial decrease in the trailing 12-month average first-day-of-the-month oil and natural gas prices throughout 2015, and the impairment of certain undeveloped leasehold interests. The trailing 12-month average first-day-of-the-month prices used to calculate our oil and natural gas reserves decreased from $94.98 per bbl of oil and $4.35 per mcf of natural gas as of December 31, 2014 to $50.28 per bbl of oil and $2.58 per mcf of natural gas as of December 31, 2015. Oil and natural gas prices have continued to decline further in the 2016 first quarter. The NYMEX WTI index price of oil on February 22, 2016 was $31.48 per bbl, and the Henry Hub index price of natural gas was $1.82 per mcf. As of December 31, 2015, the present value of estimated future net revenue of our proved reserves, discounted at an annual rate of 10%, was $4.7 billion. Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of that date. Based on first-day-of-the-month index prices for January and February of 2016, as well as recent strip prices for March 2016, we reasonably expect a decrease of approximately $4.50 per barrel of oil and $0.15 per mcf of natural gas in the prices we will be using to calculate the estimated future net revenue of our proved reserves as of March 31, 2016, and such decreases are expected to reduce

the present value of estimated future net revenue of our proved reserves by approximately $1.2 billion in the 2016 first quarter. Such decrease is likely to be a significant factor in the amount of impairment recorded in the 2016 first quarter. Further material write-downs in subsequent quarters will occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters.

Significant capital expenditures are required to replace our reserves and conduct our business, and our access to capital is constrained and subject to uncertainty.

Our exploration, development and acquisition activities require substantial capital expenditures. We intend to fund our capital expenditures through cash flows from operations, cash on hand and borrowings under our revolving credit facility. Our ability to generate operating cash flow is subject to many of the risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time. Future cash flows from operations are subject to a number of risks and variables, such as the level of production from existing wells, prices of oil, natural gas and NGL, our success in developing and producing new reserves and the other risk factors discussed herein. If we are unable to fund our capital expenditures as planned, we could experience a curtailment of our exploration and development activity, a loss of properties and a decline in our oil, natural gas and NGL reserves.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Our reserve estimates as of December 31, 2015 reflect an expected decline in the production rate on our producing properties of approximately 31% in 2016 and 21% in 2017. Thus, our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.

The actual quantities of and future net revenues from our proved reserves may be less than our estimates.

The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil, natural gas and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

As of December 31, 2015, approximately 16% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $1.4 billion during the five years ending in 2020. You should be aware that the estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.

You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average oil and natural gas price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2015 present value is based on $50.28 per bbl of oil and $2.58 per mcf of natural gas before basis differential adjustments. These prices are substantially higher than current 2016 prices for oil and natural gas. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.

The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. Any changes in consumption or in governmental regulations or taxation will also affect the actual future net cash flows from our production. In addition, the 10% discount factor which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We have acquired undeveloped properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such undeveloped properties or wells.

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated as commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for oil, natural gas and NGL, costs associated with producing oil, natural gas and NGL and our ability to add reserves at an acceptable cost. All costs of development and exploratory drilling activities are capitalized, even if the activities do not result in commercially productive discoveries, which may result in a future impairment of our oil and natural gas properties if commodity prices remain low.

We rely to a significant extent on seismic data and other advanced technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.

Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. If commodity prices remain low, we may be required to delay our drilling plans and, as a result, lose our right to develop the related properties.

Our commodity price risk management activities may reduce the prices we receive for our oil, natural gas and NGL sales, require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.

In order to manage our exposure to price volatility in marketing our production, we enter into oil and natural gas price derivative contracts for a portion of our expected production. Commodity price derivatives may limit the prices we actually realize and therefore reduce oil, natural gas and NGL revenues in the future. Our commodity price risk management activities will impact our earnings in various ways, including recognition of certain mark-to-market gains and losses on derivative instruments. The fair value of our oil and natural gas derivative instruments can fluctuate significantly between periods. In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances.

Derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, such as the period beginning in the fourth quarter of 2014 and continuing into 2016, our commodity price derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being exposed to commodity price changes.

Most of our oil and natural gas derivative contracts are with eleven counterparties under bi-lateral hedging arrangements. As of December 31, 2015, we had hedged under bi-lateral arrangements 164.0 mmboe of our future production with price derivatives and 9.5 mmboe with basis derivatives. Under some of those arrangements, the counterparties’ and our obligations under the bi-lateral hedging arrangements 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. Under certain circumstances, the cash collateral value posted could fall below the coverage designated, and we would be required to post additional cash or letter of credit collateral under our hedging arrangements. We are in the process of changing the collateral provided for several of the counterparties, to provide that they will be secured by hydrocarbon interests. Future collateral requirements are dependent to a great extent on oil and natural gas prices.

The ultimate outcome of pending legal and governmental proceedings is uncertain, and there are significant costs associated with these matters.

We are defending against claims by royalty owners alleging, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sales of natural gas and NGL. Numerous cases, primarily in Texas, Pennsylvania and Ohio, are pending. The resolution of disputes regarding past payments could cause our future obligations to royalty owners to increase and would negatively impact our future results of operations.

In addition, there are ongoing governmental regulatory investigations and inquiries into such matters as our royalty practices and possible antitrust violations. The outcome of any pending or future litigation or governmental regulatory matter is uncertain and may adversely affect our results of operations. In addition, we have incurred substantial legal expenses in the past three years, and such expenses may continue to be significant in the future. Further, attention to these matters by members of our senior management has been required, reducing the time they have available to devote to managing our business.

We may continue to incur cash and noncash charges that would negatively impact our future results of operations and liquidity.

While executing our strategic priorities to reduce financial leverage and complexity and to lower our capital expenditures in the face of lower commodity prices, we have incurred certain cash charges, including contract termination charges, restructuring and other termination costs, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, we may incur additional cash and noncash charges in 2016 and in future years. If incurred, these charges could materially adversely impact our future results of operations and liquidity.

Oil and natural gas drilling and producing operations can be hazardous and may expose us to liabilities.

Oil and natural gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, oil spills, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks. Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of our prospects. If any of these risks occurs, we could sustain substantial losses as a result of:


•	injury or loss of life;


•	severe damage to or destruction of property, natural resources or equipment;


•	pollution or other environmental damage;


•	clean-up responsibilities;


•	regulatory investigations and administrative, civil and criminal penalties; and


•	injunctions resulting in limitation or suspension of operations.

For our non-operated properties, we are dependent on the operator for operational and regulatory compliance.

Our midstream and compression operations are subject to all of the risks and operational hazards inherent in transporting oil and natural gas and natural gas compression, including:


•	damages to pipelines, facilities and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism;


•	maintenance, repairs, mechanical or structural failures;


•	damages to, loss of availability of and delays in gaining access to interconnecting third-party pipeline;


•	disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack; and


•	leaks of oil or natural gas as a result of the malfunction of equipment or facilities.

A material event such as those described above could expose us to liabilities, monetary penalties or interruptions in our business operations. While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which we are not fully insured may expose us to liabilities.

We are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner and feasibility of doing business, and further regulation in the future could increase costs, impose additional operating restrictions and cause delays.

Our operations and properties are subject to numerous federal, regional, state and local laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:


•	conduct of our exploration, drilling, completion, production and midstream activities;


•	amounts and types of emissions and discharges;


•	generation, management, and disposition of hazardous substances and waste materials;


•	reclamation and abandonment of wells and facility sites; and


•	remediation of contaminated sites.

In addition, these laws and regulations may impose substantial liabilities for our failure to comply or for any contamination resulting from our operations, including the assessment of administrative, civil and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Future environmental laws and regulations imposing further restrictions on the emission of pollutants into the air, discharges into state or U.S. waters and hydraulic fracturing, or

the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our industry. We cannot predict the actions that future regulation will require or prohibit, but our business and operations could be subject to increased operating and compliance costs if certain regulatory proposals are adopted. In addition, such regulations may have an adverse impact on our ability to develop and produce our reserves.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Several states are considering adopting regulations that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. There are also certain governmental reviews either underway or being proposed that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. These studies assess, among other things, the risks of groundwater contamination and earthquakes caused by hydraulic fracturing and other exploration and production activities. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate or even ban such activities. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. For example, on February 16, 2016, the Oklahoma Corporation Commission (OCC) implemented a volume reduction plan for oil and natural gas disposal wells injecting wastewater into the Arbuckle formation. The OCC’s plan, in conjunction with a 191,000 barrel per day reduction plan already implemented in the Byron/Cherokee area, will create a total volume cutback of over 500,000 barrels per day, or about 40%.

We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions.

Our ability to produce oil, natural gas and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Development activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations, such as the EPA’s April 2015 proposed pretreatment standards for wastewater, could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of oil and natural gas.

Potential legislative and regulatory actions addressing climate change could significantly impact our industry and the Company, causing increased costs and reduced demand for oil and natural gas.

Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. At the federal level, the EPA has already made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions. There were attempts at comprehensive federal legislation establishing a cap and trade program, but this legislation did not pass. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. However, in June 2014, the U.S. Supreme Court, in UARG v. EPA, limited the application of the GHG permitting requirements under the Prevention of Significant Deterioration and Title V permitting programs to sources that would otherwise need permits based on the emission of conventional pollutants. In April 2015, the D.C. Circuit Court of Appeals narrowed the rule in accordance with the Supreme Court’s decision. Additional legislative and/or regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell. The potential increase in our operating costs could include new or increased costs to obtain

permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Even without federal legislation or regulation of greenhouse gas emissions, states may pursue the issue either directly or indirectly. In addition, the U.S. was actively involved in the United Nations Conference on Climate Change in Paris, which led to the creation of the Paris Agreement. The Paris Agreement will be open for signing on April 22, 2016 and will require countries to review and “represent a progression” in their intended nationally determined contributions, which set emissions reduction goals, every five years, beginning in 2020. If adopted, the Paris Agreement could further drive regulation in the United States. Restrictions on emissions of methane or carbon dioxide that have been or may be imposed in various states, or at the federal level could adversely affect the oil and gas industry. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for oil and natural gas. Finally, we note that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as higher sea levels, increased frequency and severity of storms, droughts, floods, and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The taxation of independent producers is subject to change, and federal and state proposals being considered could increase our cost of doing business.

From time to time, legislative proposals are made that would, if enacted into law, make significant changes to United States tax laws, including the elimination or postponement of certain key United States federal income tax incentives currently available to independent producers of oil and natural gas. Proposals that would significantly affect us would repeal the expensing of intangible drilling costs, repeal the percentage depletion allowance and increase the amortization period of geological and geophysical expenses. In addition, legislative changes to impose additional taxes have been proposed in Louisiana and Pennsylvania. These changes, if enacted, will make it more costly for us to explore for and develop our oil and natural gas resources.

Evolving OTC derivatives regulation could impact the effectiveness of our commodity hedging program.

In July 2010, the U.S. Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), which contains measures aimed at migrating over-the-counter (OTC) derivative markets to exchange-traded and cleared markets. Certain companies that use derivatives to hedge commercial risk, referred to as end-users, are permitted to continue to use OTC derivatives under newly adopted regulations. We maintain an active price and basis risk management program related to the oil and natural gas we produce for our own account in order to manage the impact of low commodity prices and to predict future cash flows with greater certainty. We have used the OTC market exclusively for our oil and natural gas derivative contracts, and we also use OTC derivatives to manage risks arising from interest rate exposure. The Dodd-Frank Act and the rules and regulations promulgated thereunder should permit us, as an end user, to continue to utilize OTC derivatives, but could cause increased costs and reduce liquidity in such markets. Such changes could materially reduce our hedging opportunities which would negatively affect our revenues and cash flow during periods of low commodity prices. New position limits rules proposed under the Dodd-Frank Act could also impact our commodity hedging program and could, if enacted as proposed, affect our ability to continue to use the full scope of OTC derivatives to hedge commodity price risk in the manner that we have in the past.

The oil and gas exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.

We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing oil, natural gas or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do and, due to our debt levels and other factors, may have greater access to the capital and credit markets. As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.

Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively will be diminished.

A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.

In recent years, concerns over global economic conditions, energy costs, geopolitical issues, the availability and cost of credit, and the U.S. real estate and financial markets have contributed to economic uncertainty and reduced expectations for the global economy. Concerns about global economic growth have had a significant impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and materially adversely impact our results of operations, liquidity and financial condition.

Terrorist activities could materially and adversely affect our business and results of operations.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations.

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. For the year ended December 31, 2015, we did not operate approximately 8% of our daily production volumes. We have limited ability to influence or control the operation or future development of these non-operated properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Our operations may be adversely affected by pipeline and gathering system capacity constraints.

In certain shale plays, the capacity of gathering systems and transportation pipelines is insufficient to accommodate potential production from existing and new wells. We rely heavily on third parties to meet our oil, natural gas and NGL gathering needs. Capital constraints could limit the construction of new pipelines and gathering systems by third parties, and we may experience delays in building intrastate gathering systems necessary to transport our natural gas to interstate pipelines. Until this new capacity is available, we may experience delays in producing and selling our oil, natural gas and NGL. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell oil, natural gas or NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.

A portion of our oil, natural gas and NGL production may be subject to interruptions that could adversely affect our cash flow.

A portion of our oil, natural gas and NGL production in any region may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. We have been the subject of cyber-attacks on our internal systems and through those of third parties, but these incidents did not have a material adverse impact on our results of operations. Nevertheless, unauthorized access to our seismic data, reserves information or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks.

In the event of a bankruptcy of SSE, our spin-off of SSE may be challenged. In addition, SSE may not perform its obligations under the agreements entered into with us in connection with the spin-off.

In June 2014 we completed the spin-off of our oilfield services business into Seventy Seven Energy Inc. (“SSE”), an independent, publicly traded company. The substantial decline in oil and natural gas prices since the completion of the spin-off has significantly and adversely affected SSE’s business, and in January 2016 SSE publicly announced that it was exploring opportunities in its capital structure that may involve reducing debt and enhancing liquidity. If SSE were to become subject to a case under the federal Bankruptcy Code or other insolvency laws, certain aspects of the spin-off could be challenged under fraudulent conveyance and transfer laws, in addition to other potential claims. Such a claim could seek to avoid transfers of assets to us or obligations incurred by SSE in connection with the spin-off and to impose other remedies, such as a judgment for the value of assets so transferred. Defending against such claims could be costly and could distract our management from other priorities. Although no assurance can be given as to the outcome of any claim, we believe we have a number of defenses to any such claim and any such claim would be without merit. In addition, SSE may not perform its indemnity and other obligations under its agreements with us, in which case we would be entitled to a general unsecured claim for damages, which may not be paid in full in the event of SSE’s bankruptcy.

An interruption in operations at our headquarters could adversely affect our business.

Our headquarters are located in Oklahoma City, Oklahoma, an area that experiences severe weather events, including tornadoes and earthquakes. Our information systems and administrative and management processes are primarily provided to our various drilling projects throughout the United States from this location, which could be disrupted if a catastrophic event, such as a tornado, power outage or act of terror, destroyed or severely damaged our headquarters. Any such catastrophic event could harm our ability to conduct normal operations and could adversely affect our business.

We do not anticipate paying dividends on our common stock or preferred stock in the near future.

In July 2015, our Board of Directors determined to eliminate quarterly cash dividends on our common stock, and in January 2016, our Board of Directors determined to suspend dividend payments on our preferred stock. Accordingly, we do not intend to pay cash dividends on our common stock or preferred stock in the foreseeable future. We currently intend to retain any earnings for the future operation and development of our business, including exploration, development and acquisition activities. Any future dividend payments will require approval by the Board of Directors. In addition, dividends may be restricted by the terms of our debt agreements. If we fail to pay dividends on our preferred stock with respect to six or more quarterly periods (whether or not consecutive), the holders of our preferred stock, voting as a single class, will be entitled at the next regular or special meeting of shareholders to elect two additional directors of the Company.

Certain anti-takeover provisions may affect your rights as a shareholder.

Our certificate of incorporation authorizes our Board of Directors to set the terms of and issue preferred stock without shareholder approval. Our Board of Directors could use the preferred stock as a means to delay, defer or prevent a takeover attempt that a shareholder might consider to be in our best interest. In addition, our revolving credit facility contains terms that may restrict our ability to enter into change of control transactions, including requirements to repay borrowings under our revolving credit facility on a change in control. These provisions, along with specified provisions of the Oklahoma General Corporation Act and our certificate of incorporation and bylaws, may discourage or impede transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common stock.


ITEM 1B.	Unresolved Staff Comments

Not applicable.


ITEM 2.	Properties

Information regarding our properties is included in Item 1 and in the Supplementary Information included in Item 8 of Part II of this report.


ITEM 3.	Legal Proceedings

Litigation and Regulatory Proceedings

The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is currently indeterminate. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings.

Regulatory Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and natural gas rights in various states. The Company also has received DOJ, U.S. Postal Service and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ, U.S. Postal Service and state agency representatives and continues to respond to such subpoenas and demands.

Redemption of 2019 Notes. See Chesapeake Senior Notes and Contingent Convertible Senior Notes in Note 3 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a description of pending litigation regarding our redemption in May 2013 of our 6.775% Senior Notes due 2019 (2019 Notes).

Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. With regard to contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these failure-to-close cases in various courts, has settled and resolved other such cases and disputes and believes that its remaining loss exposure for these claims will not have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages with respect to royalty underpayment in various states, including, but not limited to, Texas, Pennsylvania, Ohio, Oklahoma, Louisiana and Arkansas. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ, U.S. Postal Service and state subpoenas seeking information on the Company’s royalty payment practices.

Plaintiffs have varying royalty provisions in their respective leases and oil and gas law varies from state to state. Royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations, an issue in a putative class action filed in November 2010 in the District Court of Beaver County, Oklahoma on behalf of Oklahoma royalty owners asserting claims dating back to 2004. In July 2014, this case was remanded to the trial court for further proceedings following the reversal on appeal of certification of a statewide class. We and the named plaintiff participated in mediation concerning the claims asserted in the putative class action litigation and negotiated a settlement requiring the Company to pay $119 million cash to compensate the putative settlement class for alleged past royalty underpayments in exchange for the release of claims for the ten-year period ended December 31, 2014. Following a fairness hearing, the District Court certified the settlement class and approved the $119 million settlement on July 3, 2015. In 2015, the Company paid $114 million, which was net of opted-out claims, in settlement of the case.

Chesapeake is defending numerous lawsuits filed by individual royalty owners alleging royalty underpayment with respect to properties in Texas. On April 8, 2015, Chesapeake obtained a transfer order from the Texas Multidistrict Litigation Panel to transfer a substantial portion of these lawsuits filed since June 2014 to the 348th District Court of Tarrant County for pre-trial purposes. On February 12, 2016, Chesapeake filed a motion to change venue for several other lawsuits to Harris County, or alternatively, to Tarrant County. These lawsuits, which primarily relate to the Barnett Shale, generally allege that Chesapeake underpaid royalties by making improper deductions and using incorrect production volumes. In addition to allegations of breach of contract, a number of these lawsuits allege fraud, conspiracy, joint venture and antitrust violations by Chesapeake. Chesapeake expects that additional lawsuits will be filed by new plaintiffs making similar allegations. The lawsuits seek direct damages in varying amounts, together with exemplary damages, attorneys’ fees, costs and interest.

On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that Chesapeake violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit seeks statutory restitution, civil penalties and costs, as well as temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid and permanent injunction from further violations of the UTPCPL. On February 8, 2016, the Office of Attorney General amended the complaint to, among other things, add an additional UTPCPL claim and antitrust claim alleging that a joint exploration agreement to which Chesapeake is a party established unlawful market allocation for the acquisition of leases.

Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and one of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources.

Environmental Proceedings

Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violations of the permitting requirements of the federal Clean Water Act, the Pennsylvania Clean Streams Law and the Pennsylvania Dam Safety and Encroachments Act in connection with the placement of dredge and fill material during construction of certain sites in Pennsylvania. CALLC identified the potential violations in connection with an internal review of its facilities siting and construction processes and voluntarily reported them to the regulatory agencies. Resolution of the matter may result in monetary sanctions of more than $100,000.

In November 2015, CALLC and the PADEP agreed to a settlement to resolve alleged violations of the Pennsylvania Clean Streams Law as a result of pad subsidence allegedly causing material to enter a nearby stream. To resolve the matter, CALLC agreed to pay a civil penalty in the amount of $1.4 million and to complete certain remediation actions by September 30, 2016.

In December 2015, CALLC and the PADEP separately entered into a settlement agreement in connection with contamination in the vicinity of one of CALLC’s well pads in Bradford County, Pennsylvania. As part of the settlement agreement, CALLC paid a penalty in December 2015 in the amount of $201,969.

On January 12, 2016, we were named as a defendant in a putative class action filed in state district court in Logan County, Oklahoma. On February 16, 2016, the putative class action was moved to the Western District of Oklahoma. The petition alleges that the defendants, all exploration and production companies, have operated produced water disposal wells in a manner that has caused earthquakes and that these earthquakes have, among other things, damaged the plaintiffs’ real property. The proposed class would consist of all Oklahoma residents whose property has been so damaged. The petition seeks an unspecified amount of actual and punitive damages.

On February 16, 2016, we and two other exploration and production companies were named as defendants in a lawsuit brought in the U.S. District Court for the Western District of Oklahoma by the Sierra Club. The complaint alleges that we and the other defendants have violated the federal Resource Conservation and Recovery Act by operating produced water disposal wells in a manner that has caused earthquakes. It requests a court order requiring substantial reduction of the amounts of produced water disposed of in such manner, the creation of an earthquake prediction center, and the reinforcement of purportedly vulnerable structures that could be impacted by earthquakes.


ITEM 4.	Mine Safety Disclosures

Not applicable.

PART II


ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Price Range of Common Stock and Dividends

Our common stock trades on the New York Stock Exchange under the symbol "CHK". The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange and the amount of cash dividends declared per share:



	Common Stock				Dividend
	High		Low		Declared
Year Ended December 31, 2015:
Fourth Quarter	$	9.55	$	3.56	$	—
Third Quarter	$	11.90	$	6.01	$	—
Second Quarter	$	16.98	$	10.94	$	—
First Quarter	$	21.49	$	13.38	$	0.0875

Year Ended December 31, 2014:
Fourth Quarter	$	24.43	$	16.41	$	0.0875
Third Quarter	$	29.92	$	22.77	$	0.0875
Second Quarter	$	31.49	$	25.66	$	0.0875
First Quarter	$	27.54	$	23.92	$	0.0875

As of February 11, 2016, there were approximately 2,000 holders of record of our common stock and approximately 330,000 beneficial owners.

In July 2015, our Board of Directors determined to eliminate quarterly cash dividends on our common stock.

In January 2016, we announced that we were suspending payment of dividends on each series of our outstanding convertible preferred stock. Suspension of the dividends did not constitute an event of default under our revolving credit facility or outstanding bond indentures.

Our revolving credit facility contains a restriction on our ability to declare and pay cash dividends on our common or preferred stock if an event of default has occurred. The certificates of designation for our preferred stock prohibit payment of cash dividends on our common stock unless we have declared and paid (or set apart for payment) full accumulated dividends on the preferred stock.

Unregistered Sales of Equity Securities and Use of Proceeds

The following table presents information about repurchases of our common stock during the quarter ended December 31, 2015:



Period	Total Number of Shares Purchased^(a)	Average Price Paid Per Share^(a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs^(b)
					($ in millions)
October 1, 2015 through October 31, 2015	19,711	$	7.13	—	$	1,000
November 1, 2015 through November 30, 2015	11,684	$	5.45	—	$	1,000
December 1, 2015 through December 31, 2015	9,714	$	4.27	—	$	1,000
Total	41,109	$	5.98	—

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(a)	Reflects the surrender to the Company of shares of common stock to pay withholding taxes in connection with the vesting of employee restricted stock. Also includes shares of common stock purchased on behalf of Chesapeake’s deferred compensation plan related to participant deferrals and Company matching contributions.


(b)	In December 2014, the Company’s Board of Directors authorized the repurchase of up to $1 billion in value of its common stock from time to time. The repurchase program does not have an expiration date. As of December 31, 2015, no repurchases had been made under the program.


ITEM 6.	Selected Financial Data

The following table sets forth selected consolidated financial data of Chesapeake as of and for the years ended December 31, 2015, 2014, 2013, 2012 and 2011. The data are derived from our audited consolidated financial statements, revised to reflect the reclassification discussed below. Beginning in the 2015 fourth quarter, we have reclassified our presentation of third party transportation costs to report the costs as a component of operating expenses in the accompanying statements of operations. Previously, these costs were reflected as a deduction to oil, natural gas and NGL sales. The net effect of this reclassification had no impact on our previously reported net income, stockholders’ equity or cash flows; however, previously reported oil, natural gas and NGL sales and consequently total revenues have increased from the amounts previously reported, and total operating expenses have increased by those same amounts. For additional information regarding this reclassification see Note 1 of the notes to our consolidated financial statements included in Item 8 of this report. The table below should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes thereto, appearing in Items 7 and 8, respectively, of this report.



	Years Ended December 31,
	2015			2014		2013		2012			2011
	($ in millions, except per share data)
STATEMENT OF OPERATIONS DATA:
Total revenues	$	12,764		$	23,125	$	19,080	$	13,422		$	12,574
Net income (loss) available to common stockholders^(a)	$	(14,856	)	$	1,273	$	474	$	(940	)	$	1,570

EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(22.43	)	$	1.93	$	0.73	$	(1.46	)	$	2.47
Diluted	$	(22.43	)	$	1.87	$	0.73	$	(1.46	)	$	2.32

CASH DIVIDEND DECLARED PER COMMON SHARE	$	0.0875		$	0.35	$	0.35	$	0.35		$	0.3375

BALANCE SHEET DATA (AT END OF PERIOD):
Total assets	$	17,357		$	40,751	$	41,782	$	41,611		$	41,835
Long-term debt, net of current maturities	$	10,354		$	11,154	$	12,886	$	12,157		$	10,626
Total equity	$	2,397		$	18,205	$	18,140	$	17,896		$	17,961

___________________________________________


(a)	Includes $18.238 billion and $3.315 billion of ceiling test write-downs on our oil and natural gas properties for the years ended December 31, 2015 and December 2012, respectively.


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,
	2015			2014			2013
Net Production:
Oil (mmbbl)	42			42			41
Natural gas (bcf)	1,070			1,095			1,095
NGL (mmbbl)	28			33			21
Oil equivalent (mmboe)^(a)	248			258			244

Oil, Natural Gas and NGL Sales ($ in millions)^(b):
Oil sales	$	1,904		$	3,778		$	3,977
Oil derivatives – realized gains (losses)^(c)	880			(185		)	(108		)
Oil derivatives – unrealized gains (losses)^(c)	(536		)	859			280
Total oil sales	2,248			4,452			4,149

Natural gas sales	2,470			4,535			3,767
Natural gas derivatives – realized gains (losses)^(c)	437			(191		)	9
Natural gas derivatives – unrealized gains (losses)^(c)	(157		)	535			(52		)
Total natural gas sales	2,750			4,879			3,724

NGL sales	393			1,023			753
Total NGL sales	393			1,023			753

Total oil, natural gas and NGL sales	$	5,391		$	10,354		$	8,626

Average Sales Price (excluding gains (losses) on derivatives):
Oil ($ per bbl)	$	45.77		$	89.41		$	96.78
Natural gas ($ per mcf)	$	2.31		$	4.14		$	3.44
NGL ($ per bbl)	$	14.06		$	30.95		$	36.08
Oil equivalent ($ per boe)	$	19.23		$	36.21		$	34.77

Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)	$	66.91		$	85.04		$	94.14
Natural gas ($ per mcf)	$	2.72		$	3.97		$	3.45
NGL ($ per bbl)	$	14.06		$	30.95		$	36.08
Oil equivalent ($ per boe)	$	24.54		$	34.74		$	34.36

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	Years Ended December 31,
	2015			2014			2013
Other Operating Income^(d) ($ in millions):
Marketing, gathering and compression net margin^(e)	$	243		$	(11	)	$	98
Oilfield services net margin	$	—		$	115		$	159

Expenses ($ per boe):
Oil, natural gas and NGL production	$	4.22		$	4.69		$	4.74
Oil, natural gas and NGL gathering, processing and transportation	$	8.55		$	8.43		$	6.44
Production taxes	$	0.40		$	0.90		$	0.94
General and administrative^(f)	$	0.95		$	1.25		$	1.86
Oil, natural gas and NGL depreciation, depletion and amortization	$	8.47		$	10.41		$	10.59
Depreciation and amortization of other assets	$	0.53		$	0.90		$	1.28
Interest expense^(g)	$	1.30		$	0.63		$	0.65

Interest Expense ($ in millions):
Interest expense	$	329		$	173		$	169
Interest rate derivatives – realized (gains) losses^(h)	$	(6	)	$	(12	)	$	(9	)
Interest rate derivatives – unrealized (gains) losses^(h)	$	(6	)	$	(72	)	$	67
Total interest expense	$	317		$	89		$	227

___________________________________________


(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)

Beginning in the 2015 fourth quarter, we have reclassified our presentation of third party oil, natural gas and NGL gathering, processing and transportation costs to report the costs as a component of operating expenses in the accompanying statements of operations. Previously, these costs were reflected as deductions to oil, natural gas and NGL sales. The net effect of this reclassification did not impact our previously reported net income, stockholders’ equity or cash flows; however, previously reported oil, natural gas and NGL sales and consequently total revenues have increased from the previously reported, and total operating expenses have increased by these same amounts. For additional information regarding this reclassification, see Note 1 of the notes to our consolidated financial statements included in Item 8 of this report.

(c)

Realized gains (losses) include the following items: (i) 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 offset by amounts reclassified as realized gains (losses) during the period.


(d)	Includes revenue and operating costs. See Depreciation and Amortization of Other Assets under Results of Operations for details of the depreciation and amortization associated with our marketing, gathering and compression and former oilfield services operating segments.


(e)	For the year ended December 31, 2015, we recorded unrealized gains of $296 million on the fair value of our supply contract derivatives. See Note 11 of the notes to our consolidated financial statements included in Item 8 of Part I of this report for discussion related to these instruments.


(f)	Includes share-based compensation but excludes restructuring and other termination costs.


(g)	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.

(h)

Realized (gains) losses include settlements related to the current period interest accrual and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

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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 2015 production of 248 mmboe consisted of 42 mmbbls of oil (17% on an oil equivalent basis), 1.1 tcf of natural gas (72% on an oil equivalent basis), and 28 mmbbls of NGL (11% on an oil equivalent basis). Our daily production for 2015 averaged approximately 679 mboe, a decrease of 4% from 2014. Compared to 2014, average daily oil production decreased by 2%, or approximately 2 mbbls per day; average daily natural gas production decreased by 2%, or approximately 69 mmcf per day; and average daily NGL production decreased by 15%, or approximately 14 mbbls per day. Our natural gas and NGL production decreased primarily as a result of the sales of certain of our Cleveland and Tonkawa assets in August 2015 and southern Marcellus Shale and Utica Shale assets in December 2014. In addition, our natural gas production decreased due to shut-in volume from our curtailment in the Marcellus and Utica Shales. Adjusted for asset sales, our total daily production increased 8% in 2015 compared to 2014. Our oil, natural gas and NGL revenues (excluding gains or losses on oil and natural gas derivatives) decreased approximately $4.570 billion to $4.767 billion in 2015 compared to $9.336 billion in 2014, primarily due to significant decreases in the prices received for oil, natural gas and NGL sold. See Results of Operations below for additional details.

Capital Expenditures

Our drilling and completion capital expenditures during 2015 were approximately $3.0 billion and capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment were approximately $231 million, for a total of approximately $3.2 billion. In 2015, we operated an average of 28 rigs, a decrease of 36 rigs, or 56%, compared to 2014. As a result of lower drilling and completion activity, partially offset by a reduction in drilling carries received from our joint venture partners, drilling and completion expenditures decreased approximately $1.5 billion in 2015 compared to 2014. The level of capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment decreased approximately $438 million compared to 2014. The reduction is primarily the result of the elimination of capital expenditures for our former oilfield services business which was spun off in June 2014. In 2014, we also 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 2014, we also invested approximately $450 million in our Powder River Basin Property exchange. See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for details regarding the transaction.

Our capitalized interest was approximately $424 million and $637 million in 2015 and 2014, respectively. Including capitalized interest, total capital investments were approximately $3.6 billion in 2015 compared to $6.7 billion for 2014, a decrease of 46%.

Based on planned activity levels for 2016, we project that capital expenditures for drilling and completion, leasehold, geological and geophysical and other property and equipment will be $1.3 billion to $1.8 billion, inclusive of capitalized interest. The decrease from the $3.6 billion spent in 2015 is primarily driven by reduced activity as a result of continued lower forecasted oil and natural gas prices in 2016. See Liquidity and Capital Resources for additional information on how we plan to fund our capital budget.

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Strategic Developments

Debt Exchanges and Repurchases

In November 2015, as required by the terms of the indenture for our 2.75% Contingent Convertible Senior Notes due 2035 (the 2035 Notes), each holder was provided the option to require us to purchase on November 15, 2015, all or a portion of such holder’s 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 the 2035 Notes that were tendered and not withdrawn.

In December 2015, we privately exchanged newly issued 8.00% Senior Secured Second Lien Notes due 2022 (Second Lien Notes) for certain outstanding senior unsecured notes and contingent convertible notes (Existing Notes). Approximately $3.9 billion of the Existing Notes were exchanged for approximately $2.4 billion aggregate principal amount of the Second Lien Notes. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further details related to this exchange.

In December 2015, we repurchased in the open market approximately $119 million aggregate principal amount of our 3.25% Senior Notes due 2016 for $114 million.

Credit Facility Amendments

In September and December 2015, we amended our $4.0 billion senior revolving credit facility dated December 15, 2014, and maturing December 2019, which is used for general corporate purposes. Pursuant to the amended credit agreement, we are required to secure our obligations under the facility with liens on certain of our oil and natural gas properties, with such liens to be released upon the satisfaction of specific conditions. The amended credit facility provides that, while the obligations are required to be secured, (i) we have the right to incur junior lien indebtedness of up to $4.0 billion; (ii) our use of the facility will be subject to a borrowing base; (iii) the rate of interest on outstanding loans, as well as fees on undrawn commitments, will vary based on the percentage of the borrowing base used, rather than on our credit ratings; (iv) the total leverage ratio covenant will be suspended; and (v) the amended credit facility will be subject to a first lien secured leverage ratio and an interest coverage ratio. The permitted junior lien debt basket of $4.0 billion may be further increased upon the satisfaction of certain conditions, including the following: (i) after giving effect to all debt secured by such junior liens and the uses of such debt in retirement of other indebtedness, our net annual cash interest expense would increase by no more than $75 million, and (ii) we have exchanged debt secured by such junior liens for more than $2.0 billion aggregate principal amount of outstanding senior notes with maturities or initial put dates in 2017 through 2019. The amended credit facility requires us to maintain, as of the last day of each fiscal quarter while it is required to be secured by a portion of our oil and natural gas properties, (i) a first lien secured leverage ratio of no more than 3.5 to 1 through 2017 and 3.0 to 1.0 thereafter, and (ii) an interest rate coverage ratio of at least 1.1 to 1.0 through the first quarter of 2017, increasing to 1.25 to 1.0 by the end of 2017. The amendment sets the borrowing base at $4.0 billion. This amendment gives us greater flexibility and access to our liquidity.

Through the amendments discussed above, the total commitments under the credit facility remain at $4.0 billion, subject to reduction in connection with issuances of junior lien indebtedness by us after April 15, 2016, the date of the first borrowing base redetermination. No adjustment to the total commitment has occurred or will occur for any junior lien indebtedness issuance that occurs before April 15, 2016.

Workforce Reduction

On September 29, 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 in 2015 for one-time termination benefits.

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New Haynesville and Dry Gas Utica Gathering Agreements

In September 2015, we entered into new fixed-fee gas gathering agreements with subsidiaries of The Williams Companies, Inc. (Williams) in our Haynesville Shale operating area and our dry gas Utica Shale operating area. The fixed-fee provisions will be effective beginning in January 2016, replacing the previous fee structures that have applied. We expect that our gas gathering fees, when the new fee structure is effective, will be lower in both operating areas. Under the Haynesville Shale agreement, we expect to meet our existing minimum volume commitments (MVC) because of the consolidation of two Williams gathering systems and a projected increase in our Haynesville Shale volumes. Inclusive of previously expected MVC shortfall payments, we expect reductions in our Haynesville gas gathering rates of approximately $0.20 per mcf in 2016 and 2017 and approximately $0.30 per mcf in 2018 and beyond. Under the Utica Shale agreement, we estimate a gathering rate reduction of approximately $0.25 per mmbtu. We are dedicating an additional 50,000 net acres in the Utica Shale to Williams and will be subject to a new MVC of 250,000 mmbtu per day beginning in mid-2017. We expect to meet this Utica Shale MVC with approximately one rig per year.

Cleveland Tonkawa Transactions

On August 31, 2015, our subsidiary CHK C-T sold all of its oil and natural gas properties to FourPoint Energy, LLC (FourPoint) and immediately used the consideration received, plus other cash it had on hand, to repurchase and cancel all of CHK C-T’s outstanding preferred shares. Chesapeake is responsible for post-closing adjustments to the purchase price and has certain indemnity obligations in connection with the sale to FourPoint. In connection with the repurchase and cancellation of the CHK C-T preferred stock and related agreements with the CHK C-T investors, we eliminated the noncontrolling interest and overriding royalty interest (ORRI) obligation on our consolidated balance sheet, $75 million in annual preferred dividend payments and all future drilling and ORRI commitments attributable to CHK C-T. Also on August 31, 2015, in a related transaction, we sold to FourPoint for approximately $90 million certain noncore properties adjacent to the CHK C-T properties. Chesapeake’s net production from the assets sold in the two transactions was approximately 15 mboe per day in 2015. See Note 8 of the notes to our condensed consolidated financial statements included in Item 8 of this report for a description of CHK C-T.

2016 Developments

Subsequent to December 31, 2015, we repurchased in the open market approximately $60 million of our outstanding 2.5% Contingent Convertible Notes due 2037 for $32 million, $122 million of our 3.25% Senior Notes due 2016 for $115 million and $2 million of our 6.5% Senior Notes due 2017 for $1 million.

Subsequent to December 31, 2015, we amended certain of our firm transportation agreements in the Haynesville, Barnett and Eagle Ford operating areas which reduces our firm transportation volume commitments and fees described in Note 4 of the notes to our condensed consolidated financial statements included in Item 8 of this report. 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.

Subsequent to December 31, 2015, we closed certain asset divestitures for proceeds of approximately $138 million. We also executed sales agreements for other asset divestitures with expected proceeds of approximately $586 million. The asset divestitures cover various operating areas.

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Liquidity and Capital Resources

Liquidity Overview

Chesapeake’s strategy for 2016 is to focus on improving liquidity and generating cash. 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 recent substantial decline in oil, natural gas and NGL prices has negatively affected the amount of cash we have available for capital expenditures and debt service.

As of December 31, 2015, we had a cash balance of approximately $825 million and a net working capital deficit of approximately $1.205 billion. 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 budget, meet our debt service requirements and fund our other commitments and obligations for 2016. Oil and natural gas prices have a material impact on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. If depressed prices persist throughout 2017 and we are unable to restructure or refinance our debt or generate additional liquidity through other actions, this would adversely impact our ability to comply with the financial covenants under our revolving credit facility and to make scheduled debt payments. To the extent that the value of the collateral pledged under the credit facility declines, we may be required to pledge additional collateral in order to maintain the availability of the commitments thereunder. In February 2016, our secured commodity hedging facility was terminated. This facility was collateralized with assets that are now unencumbered and for which we have the flexibility to pledge under our credit facility, if needed. Because of this additional unpledged collateral, we do not expect availability under our revolving credit facility to be materially reduced as a result of the next borrowing base redetermination in the 2016 second quarter. However, our borrowing base may be reduced as a result of oil and natural gas asset sales, a further decline in prices or other factors, some of which are outside of our control. See Note 3 and Note 11 of the notes to our consolidated financial statements included in Item 8 of this annual report for further discussion of the financial covenants in our revolving credit facility and for discussion of our secured commodity hedging facility, respectively.

As of December 31, 2015, we had approximately $9.706 billion principal amount of long-term debt outstanding, of which $381 million matures in March 2016, $1.892 billion matures or can be put to us in 2017 (of which $329 million matures in January 2017, $1.110 billion can be put to us in May 2017 and $453 million matures in August 2017) and $878 million matures or can be put to us in 2018. 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. We expect to draw on our revolving credit facility as early as the 2016 first quarter, primarily due to the principal payment to be made to retire our 3.25% Senior Notes due March 2016 and other 2016 first quarter cash needs. See Notes 3 and 4 of the notes to our consolidated financial statements included in Item 8 of this report for further details related to these items. We were undrawn on our revolving credit facility as of December 31, 2015.

As operator of a substantial portion of our oil and natural gas properties under development, we have significant control and flexibility over the development plan and the associated timing, enabling us to reduce at least a portion of our capital spending as needed. We have reduced our budgeted 2016 capital expenditures, inclusive of capitalized interest, to $1.3 - $1.8 billion, a significant reduction from our 2015 capital spending level of $3.6 billion. We currently plan to use cash flow from operations, cash on hand and our revolving credit facility to fund our capital expenditures during 2016. We expect to generate additional liquidity with proceeds from potential sales of assets that we determine do not fit our strategic priorities. Management continues to review operational plans for 2016 and beyond, which could result in changes to projected capital expenditures and 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.

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Since December 2015, Moody’s has lowered our senior unsecured credit rating from “Ba3” to “Caa3”, and S&P has lowered our senior unsecured credit rating from “BB-” to “CC”. Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as transportation, gathering, processing and hedging agreements. As of February 24, 2016, we have received requests to post approximately $220 million in collateral, of which we have posted approximately $92 million. We have posted the required collateral, primarily in the form of letters of credit and cash, or are otherwise complying with the contractual requests for collateral. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $698 million (excluding the supersedeas bond with respect to the 2019 Notes litigation discussed in Note 3 of the notes to our consolidated financial statements included in Item 8 of this report), which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business operations with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business commitments and by offsetting amounts that the counterparty owes us. Any posting of additional collateral consisting of cash or letters of credit, which would reduce availability under our credit facility, will negatively impact our liquidity.

In addition, during 2016, we may be required to pay up to $439 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. For additional information, see Note 3 of the notes to our consolidated financial statements included in Item 8 of this report.

To supplement our cash flow from operations, we may seek to access the capital markets to refinance a portion of our outstanding indebtedness and improve our liquidity. We have historically used the debt capital markets, our most efficient method of raising capital, to supplement our liquidity needs. However, access to funds obtained through the high-yield debt market, particularly in the energy sector, has been severely constrained by a variety of market factors that could hinder our ability to raise new capital. We do not believe the high-yield debt market is currently accessible to us at favorable terms, and our accessibility may not improve during 2016.

We have taken a number of actions to improve our liquidity. We eliminated quarterly cash dividends on our common stock effective in the 2015 third quarter and suspended payment of dividends on our convertible preferred stock in the 2016 first quarter. In December 2015, we completed private exchanges of approximately $3.9 billion aggregate principal amount of long-term debt for approximately $2.4 billion aggregate principal amount of newly issued 8.00% Senior Secured Second Lien Notes due 2022. In September and December 2015, we amended our $4.0 billion revolving credit facility to provide more flexibility and access to liquidity. In September 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 August 2015, we closed the CHK C-T transactions described above in Strategic Developments. We terminated our secured hedge facility in February 2016 and are in the process of securing new hedges with the collateral for our revolving credit facility. The collateral for our recently terminated secured hedge facility is now available for other purposes, including additional collateral under our credit facility. We are also evaluating additional capital exchanges, asset sales, joint ventures and farmouts to increase our liquidity and cash flow. Finally, we recently restructured certain of our gathering agreements to improve our per-unit-gathering rates beginning in 2016, enhance volume growth and satisfy minimum volume commitment obligations.

To add more certainty to our future estimated cash flows by mitigating our downside exposure to lower commodity prices, as of February, 23, 2016, we have downside price protection, through open swaps, on approximately 56% of our projected 2016 oil production at an average price of $47.79 per bbl. We have downside price protection, through open swaps, on approximately 58% of our projected 2016 natural gas production at an average price of $2.84 per mcf. In addition, in exchange for a higher swap price, we have sold certain call options that allow the counterparty to double the notional amount on existing fixed-price swaps.

As highlighted above, we have taken measures to mitigate the liquidity concerns facing us in 2016 and beyond, but there can be no assurance that such measures, even if successfully implemented, 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. If commodity prices remain at depressed levels, or if we fail to complete significant asset sales, access the capital markets on favorable terms or take other actions to improve our liquidity, we may not be able to fund budgeted capital expenditures or meet our debt service requirements in 2017 and beyond.

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Sources of Funds

The following table presents the sources of our cash and cash equivalents for the years ended December 31, 2015, 2014 and 2013. 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,
	2015		2014		2013
	($ in millions)
Cash Provided by Operating Activities	$	1,234	$	4,634	$	4,614

Divestitures of Oil and Natural Gas Assets:
Joint venture leasehold	33		33		58
Other oil and natural gas properties	156		5,780		3,409
Total divestitures of oil and natural gas assets	189		5,813		3,467

Sales of Other Assets:
Compressors sold to ACMP	—		159		—
Compressors sold to Exterran	—		495		—
Sale of Mid-America Midstream Gas Services, L.L.C.	—		—		306
Sale of Granite Wash Midstream Gas Services, L.L.C.	—		—		252
Other property and equipment	89		349		364
Total sales of other assets	89		1,003		922

Other Sources of Cash and Cash Equivalents:
Proceeds from sales of investments	—		239		115
Proceeds from long-term debt, net	—		2,966		2,274
Proceeds from oilfield services long-term debt, net	—		888		—
Other	52		37		187
Total other sources of cash and cash equivalents	52		4,130		2,576

Total sources of cash and cash equivalents	$	1,564	$	15,580	$	11,579

Cash provided by operating activities was $1.234 billion in 2015 compared to $4.634 billion in 2014 and $4.614 billion in 2013. The decrease in cash provided by operating activities from 2015 to 2014 is primarily the result of lower realized prices for the oil, natural gas and NGL we sold, partially offset by realized gains on our derivative instruments and 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.

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The following table reflects the proceeds received from issuances of debt in 2015, 2014 and 2013. 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,
	2015				2014				2013
	Principal Amount of Debt Issued		Net Proceeds		Principal Amount of Debt Issued		Net Proceeds		Principal Amount of Debt Issued		Net Proceeds
	($ in millions)
Senior notes^(a)	$	—	$	—	$	3,500	$	3,460	$	2,300	$	2,274
Term loans^(a)	—		—		400		394		—		—
Total	$	—	$	—	$	3,900	$	3,854	$	2,300	$	2,274

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(a)

Our 2015 debt exchange of Existing Notes for Second Lien Notes did not result in any additional debt issued or proceeds received. 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 2016. We expect to generate additional liquidity with proceeds from potential sales of assets that we have determined are non-core or do not fit our long-term plans. 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 had no borrowings or repayments in 2015, borrowed $7.406 billion and repaid $7.788 billion in 2014 and borrowed $7.669 billion and repaid $7.682 billion in 2013.

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Uses of Funds

The following table presents the uses of our cash and cash equivalents for 2015, 2014 and 2013: