UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form ~~10-K/A~~

~~(Amendment No. 1)~~

~~(Mark One)~~

x~~ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~

~~For the fiscal year ended December 31, 2016~~

o~~TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~

10-K



(Mark One)
☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended	December 31, 2019
OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______________ to _______________

Commission file number 001-31446

CIMAREX ENERGY ~~CO.~~

CO.

(Exact name of registrant as specified in its charter)



Delaware			45-0466694
(State or other jurisdiction of incorporation or organization)			~~45-0466694~~ (I.R.S. Employer Identification No.)

1700 Lincoln Street, Suite 3700	Denver	Colorado	80203
(Address of principal executive offices)			(Zip Code)

~~1700 Lincoln Street, Suite 3700, Denver, Colorado 80203~~

(~~Address of principal executive offices)~~

~~(303)~~ 303) 295-3995

(Registrant’s telephone number)

Securities ~~Registered Pursuant~~registered pursuant to Section 12(b) of the Act:



Title of ~~Each Class~~ each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock ($0.01 par value)	XEC	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~~ x NO o

Yes ☒No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ~~YES~~ o NO x

Yes ☐No ☒

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 o

Yes ☒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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the 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

Yes ☒No ☐

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



Large accelerated filerx	☒	Accelerated filer o
	☐
Non-accelerated filero ~~(Do not check if a~~ ~~smaller reporting company)~~	☐	Smaller reporting company o	☐
				Emerging ~~growth company~~ o Growth Company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ~~YES~~ o NO x

Yes ☐No ☒

Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, ~~2016~~2019 was approximately ~~$11.1~~$5.92 billion.

Number of shares of Cimarex Energy Co. common stock outstanding as of January 31, ~~2017~~2020 was ~~95,121,492.~~

102,135,577.

Documents Incorporated by Reference: Portions of the Registrant’s Proxy Statement for its ~~2017~~2020 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.

Table of Contents

~~EXPLANATORY NOTE~~

Cimarex Energy Co. (together with its subsidiaries, “Cimarex,” the “company,” “our,” “we” or “us”) is filing this Amendment No. 1 (this “Form 10-K/A”) to amend its Annual Report on Form 10-K for the year ended December 31, 2016, originally filed with the Securities and Exchange Commission (the “SEC”) on February 24, 2017 (the “Original Filing”), to correct certain errors in our Consolidated Financial Statements included in Part II, Item 8 (collectively referred to as “Financial Statements”) and related footnote disclosures as of December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014 (including the unaudited interim periods within 2016 and 2015). In connection with the corrections made in this Form 10-K/A, management reassessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2016 and concluded that a deficiency in the design of the company’s internal controls related to the full cost ceiling test calculation represents a material weakness in our internal control over financial reporting and, therefore, that we did not maintain effective internal control over financial reporting as of December 31, 2016. In addition, this Form 10-K/A includes under Part II, Item 6 corrected selected financial data as of and for the years ended December 31, 2016 - 2012. This Form 10-K/A also amends certain other items in the Original Filing, as listed in “Items Amended in This Filing” below.

~~Background and Effects of Corrections~~

Subsequent to the filing of the Original Filing, in the course of preparing our consolidated financial statements for the quarter ended March 31, 2017, we identified an error in the quarterly ceiling test calculations used in prior periods to test our oil and gas properties for possible impairment. Specifically, the calculations did not properly consider the company’s tax net operating loss carryforwards in the calculation of the capitalized costs of net oil and gas properties to be tested for impairment. This error had the effect of incorrectly reporting impairment amounts in prior periods, which resulted in incorrectly reporting depletion expense and income tax expense (benefit) in prior periods. Management promptly reported the matter to the Audit Committee of the company’s Board of Directors and KPMG LLP, the company’s independent registered public accounting firm.

~~After considering the guidance in SEC Staff Accounting Bulletin (“SAB”) No. 99,~~ ~~Materiality~~~~, and Accounting Standards Codification 250,~~ ~~Accounting Changes and Error Corrections,~~ we evaluated the materiality of the error on financial statement items quantitatively and qualitatively and concluded that the error was not material to any of the company’s prior annual or interim period financial statements. The consolidated financial statements as of and for the years ended December 31, 2016, 2015 and 2014, and the unaudited interim period consolidated financial statements within the years ended December 31, 2016 and 2015 in this Form 10-K/A, have been revised in accordance with SAB No. 108, ~~Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements~~ in order to reflect these corrections. The corrections reflect the adjustments to impairment amounts, depletion expense and income tax expense (benefit) described above, as well as the resulting adjustments to deferred income taxes, accumulated depreciation, depletion and amortization and impairment, and retained earnings (accumulated deficit), including a cumulative catchup to the January 1, 2014 balance that gives effect to corrections made to the 2013 and 2012 periods.

In addition to correcting the consolidated financial statements, we have also corrected the Supplemental Quarterly Financial Data (Unaudited) and the following Notes to the consolidated financial statements for the effects of the errors discussed above:

· ~~Note 1 — Basis of Presentation and Summary of Significant Accounting Policies~~

· ~~Note 7 — Earnings (Loss) Per Share~~

· ~~Note 9 — Income Taxes~~

The following tables present the effect of the corrections on selected line items of the previously reported consolidated financial statements as of December 31, 2016 and 2015, and for the years ended December 31, 2016, 2015 and 2014.

Consolidated Balance Sheet
December 31, 2016

(in thousands)

As Previously
Reported

Corrections

As
Corrected

Accumulated depreciation, depletion and amortization and impairment

$
(13,849,701
)
$
(499,804
)
$
(14,349,505
)
Net oil and gas properties

$
2,854,071

$
(499,804
)
$
2,354,267

Total assets

$
4,681,693

$
(443,969
)
$
4,237,724

Deferred income tax (asset) liability

$
126,894

$
(182,729
)
$
(55,835
)
Total liabilities

$
2,321,629

$
(126,894
)
$
2,194,735

Retained earnings (accumulated deficit)

$
(405,284
)
$
(317,075
)
$
(722,359
)
Total stockholders’ equity

$
2,360,064

$
(317,075
)
$
2,042,989

Total liabilities and stockholders’ equity

$
4,681,693

$
(443,969
)
$
4,237,724

Consolidated Balance Sheet
December 31, 2015

(in thousands)

As Previously
Reported

Corrections

As
Corrected

Accumulated depreciation, depletion and amortization and impairment

$
(12,710,968
)
$
(534,864
)
$
(13,245,832
)
Net oil and gas properties

$
3,276,146

$
(534,864
)
$
2,741,282

Total assets

$
5,243,286

$
(534,864
)
$
4,708,422

Deferred income tax (asset) liability

$
352,705

$
(195,543
)
$
157,162

Total liabilities

$
2,445,608

$
(195,543
)
$
2,250,065

Retained earnings (accumulated deficit)

$
33,313

$
(339,321
)
$
(306,008
)
Total stockholders’ equity

$
2,797,678

$
(339,321
)
$
2,458,357

Total liabilities and stockholders’ equity

$
5,243,286

$
(534,864
)
$
4,708,422

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2016

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Impairment of oil and gas properties

$
719,142

$
38,528

$
757,670

Depreciation, depletion and amortization

$
465,936

$
(73,588
)
$
392,348

Total operating expenses

$
1,864,292

$
(35,060
)
$
1,829,232

Operating income (loss)

$
(606,947
)
$
35,060

$
(571,887
)
Income (loss) before income tax

$
(658,264
)
$
35,060

$
(623,204
)
Income tax expense (benefit)

$
(227,215
)
$
12,814

$
(214,401
)
Net income (loss)

$
(431,049
)
$
22,246

$
(408,803
)
Total comprehensive income (loss)

$
(430,545
)
$
22,246

$
(408,299
)

Earnings (loss) per share to common stockholders:

Basic

Distributed

$
0.32

$

$
0.32

Undistributed

(4.94
)
0.24

(4.70
)

$
(4.62
)
$
0.24

$
(4.38
)
Diluted

Distributed

$
0.32

$

$
0.32

Undistributed

(4.94
)
0.24

(4.70
)

$
(4.62
)
$
0.24

$
(4.38
)

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2015

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Impairment of oil and gas properties

$
3,716,883

$
316,412

$
4,033,295

Depreciation, depletion and amortization

$
778,923

$
(47,463
)
$
731,460

Total operating expenses

$
5,193,422

$
268,949

$
5,462,371

Operating income (loss)

$
(3,740,803
)
$
(268,949
)
$
(4,009,752
)
Income (loss) before income tax

$
(3,782,384
)
$
(268,949
)
$
(4,051,333
)
Income tax expense (benefit)

$
(1,373,436
)
$
(98,293
)
$
(1,471,729
)
Net income (loss)

$
(2,408,948
)
$
(170,656
)
$
(2,579,604
)
Total comprehensive income (loss)

$
(2,409,609
)
$
(170,656
)
$
(2,580,265
)

Earnings (loss) per share to common stockholders:

Basic

Distributed

$
0.64

$

$
0.64

Undistributed

(26.56
)
(1.83
)
(28.39
)

$
(25.92
)
$
(1.83
)
$
(27.75
)
Diluted

Distributed

$
0.64

$

$
0.64

Undistributed

(26.56
)
(1.83
)
(28.39
)

$
(25.92
)
$
(1.83
)
$
(27.75
)

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2014

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Depreciation, depletion and amortization

$
806,021

$
(30,444
)
$
775,577

Total operating expenses

$
1,610,242

$
(30,444
)
$
1,579,798

Operating income (loss)

$
813,934

$
30,444

$
844,378

Income (loss) before income tax

$
805,901

$
30,444

$
836,345

Income tax expense (benefit)

$
298,697

$
11,150

$
309,847

Net income (loss)

$
507,204

$
19,294

$
526,498

Total comprehensive income (loss)

$
507,117

$
19,294

$
526,411

Earnings (loss) per share to common stockholders:

Basic

Distributed

$
0.64

$

$
0.64

Undistributed

5.15

0.22

5.37

$
5.79

$
0.22

$
6.01

Diluted

Distributed

$
0.64

$

$
0.64

Undistributed

5.14

0.22

5.36

$
5.78

$
0.22

$
6.00

Correction of the errors discussed above impacted certain non-cash line items within the operating cash flow section of the consolidated statements of cash flows; however, the corrections did not change previously reported Net cash provided by operating activities for any period.

~~Internal Control Consideration~~

The Original Filing included a report of management’s assessment regarding internal control over financial reporting and an audit report of KPMG LLP, the company’s independent registered public accounting firm, without

qualifications. However, in connection with the corrections made in this Form 10-K/A, management re-evaluated the effectiveness of the company’s internal control over financial reporting as of December 31, 2016 and concluded that a deficiency in the design of the company’s internal controls related to the full cost ceiling test calculation represents a material weakness in the company’s internal control over financial reporting and, therefore, that the company did not maintain effective internal control over financial reporting as of December 31, 2016. This Form 10-K/A reflects this determination as of December 31, 2016 and the company’s independent registered public accounting firm, KPMG LLP, reissued its February 24, 2017 report on internal control over financial reporting as of December 31, 2016 to reflect an adverse opinion on the effectiveness of internal control over financial reporting due to the existence of a material weakness. For a description of the material weakness identified by management and the remediation efforts expected to be implemented to address that material weakness, see “Part II, Item 9A — Controls and Procedures.”

~~Items Amended in This Filing~~

For the convenience of the reader, this Form 10-K/A sets forth the Original Filing, in its entirety, as amended to reflect the corrections described above. No attempt has been made in this Form 10-K/A to update other disclosures presented in the Original Filing of our Annual Report on Form 10-K for the year ended December 31, 2016, except as required to reflect the effects of the corrections.

~~The following items have been amended as a result of corrections described above:~~

· ~~Part I — Cautionary Information about Forward-Looking Statements~~

· ~~Part I, Item 1A — Risk Factors~~

· ~~Part II, Item 6 — Selected Financial Data~~

· ~~Part II, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

· ~~Part II, Item 8 — Financial Statements and Supplementary Data~~

· ~~Part II, Item 9A — Controls and Procedures~~

The company’s Principal Executive Officer and Principal Financial Officer are providing currently dated certifications in connection with this Amended Annual Report on Form 10-K/A. These certifications are filed as Exhibits 31.1, 31.2, 32.1 and 32.2.

TABLE OF CONTENTS

DESCRIPTION

Item

Page
Glossary

Part I

1.& 2.
Business and Properties
10
1A.
Risk Factors
19
1B.
Unresolved Staff Comments
35
3.
Legal Proceedings
35
4.
Mine Safety Disclosures
35

Part II

5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
36
6.
Selected Financial Data
38
7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
39
7A.
Quantitative and Qualitative Disclosures About Market Risk
64
8.
Financial Statements and Supplementary Data
65
9.
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
116
9A.
Controls and Procedures
116
9B.
Other Information
119

Part III

10.
Directors, Executive Officers and Corporate Governance
120
11.
Executive Compensation
121
12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
121
13.
Certain Relationships and Related Transactions, and Director Independence
121
14.
Principal Accounting Fees and Services
122

Part IV

15.
Exhibits, Financial Statement Schedules
123
16.
Form 10-K Summary
127



Item		Page
Glossary
	Part I
1. & 2.	Business and Properties	6
1A.	Risk Factors	17
1B.	Unresolved Staff Comments	34
3.	Legal Proceedings	34
4.	Mine Safety Disclosures	34
	Part II
5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
6.	Selected Financial Data	37
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
7A.	Quantitative and Qualitative Disclosures About Market Risk	60
8.	Financial Statements and Supplementary Data	62
9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	108
9A.	Controls and Procedures	108
9B.	Other Information	111
	Part III
10.	Directors, Executive Officers and Corporate Governance	112
11.	Executive Compensation	114
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
13.	Certain Relationships and Related Transactions, and Director Independence	114
14.	Principal Accounting Fees and Services	114
	Part IV
15.	Exhibits, Financial Statement Schedules	115
16.	Form 10-K Summary	121

Table of Contents

GLOSSARY

~~Bbl/d~~—

Bbls—Barrels (of oil or natural gas liquids) ~~per day~~

~~Bbls~~~~—Barrels (of oil or natural gas liquids)~~

~~Bcf~~~~—Billion cubic feet~~

~~Bcfe~~—

Bcf—Billion cubic feet (of natural gas)

BOE—Barrels of oil equivalent

~~Btu~~~~—British thermal unit~~

~~GAAP~~—

GAAP—Generally accepted accounting principles in the U.S.

~~MBbls~~—

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

MBbls—Thousand barrels

~~Mcf~~—

MBOE—Thousand barrels of oil equivalent

Mcf—Thousand cubic feet ~~(of natural gas)~~

~~Mcfe~~~~—Thousand cubic feet equivalent~~

~~MMBbl/MMBbls~~—

MMBbls—Million barrels

~~MMBtu~~—

MMBtu—Million British thermal units

~~MMcf~~—

MMBOE—Million barrels of oil equivalent

MMcf—Million cubic feet

~~MMcf/d~~~~—Million cubic feet per day~~

~~MMcfe~~~~—Million cubic feet equivalent~~

~~MMcfe/d~~~~—Million cubic feet equivalent per day~~

Net Acres~~—Gross acreage multiplied by~~ or Net Wells—The sum of the fractional working interest ~~percentage~~

owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.

Net ~~Production~~—Production—Gross production multiplied by net revenue interest

NGL or ~~NGLs~~—NGLs—Natural gas liquids

~~PUD~~—

PUD—Proved undeveloped

~~Tcf~~—

Tcf—Trillion cubic feet

~~Tcfe~~~~—Trillion cubic feet equivalent~~

Energy equivalent is determined using the ratio of one barrel of crude oil, condensate, or NGL to six Mcf of natural gas.

Table of Contents

PART I

~~Cautionary Information about Forward-Looking Statements~~

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

Throughout this Form ~~10-K/A,~~10-K, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. In particular, in our Management’s Discussion and Analysis of Financial Condition and Results of Operations, we ~~are providing “~~~~2017 Outlook,”~~ ~~which contains~~provide projections ~~for certain 2017 operational activities.~~of our 2020 capital expenditures. All statements, other than statements of historical facts, that address activities, events, outcomes, and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form ~~10- K/A.~~10-K. Forward-looking statements include statements with respect to, among other things:

Fluctuations in the price we receive for our oil, gas, and NGL ~~production;~~

·production, including local market price differentials;

Operating costs and other expenses;

Timing and amount of future production of oil, gas, and NGLs;

Reductions in the quantity of oil, gas, and NGLs sold and prices received due to decreased industrywide demand and/or curtailments in production from specific properties or areas due to mechanical, transportation, marketing, weather, or other problems;

Estimates of proved reserves, exploitation potential, or exploration prospect size;

Our ability to successfully integrate the business acquired from Resolute Energy Corporation (“Resolute”);

Unknown liabilities related to Resolute;

Our hedging activities and viability of hedge counterparties;

The effectiveness of our internal control over financial reporting and our ability to remediate a material weakness in our internal control over financial reporting;

Cash flow and anticipated liquidity;

Amount, nature, and timing of capital expenditures;

· ~~Access~~

Availability of financing and access to capital markets;

Administrative, legislative, and regulatory changes;

· ~~Operating costs and other expenses;~~

Operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated;

Exploration and development opportunities that we pursue may not result in economic, productive oil and gas properties;

Table of Contents

Drilling of wells;

Increased financing costs due to a significant increase in interest rates;

· ~~De-risking~~

Proving up undeveloped acreage; and

Full cost ceiling test impairments to the carrying values of ~~acreage;~~our oil and

· ~~Our ability to remediate the identified material weakness in our internal control over financial reporting.~~

gas properties.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production, and sale of oil, gas, and NGLs.

These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production, ~~and~~production type curves, well spacing, timing of development expenditures, and other risks described herein.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results of drilling, testing, and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.

Risk factors related to our acquisition of Resolute include, among others: the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected, the risk that the combined company may be unable to achieve synergies or other anticipated benefits of the transaction or it may take longer than expected to achieve those synergies or benefits, and other important factors, such as expenses related to integration, that could cause actual results to differ materially from those projected.

Should one or more of the risks or uncertainties described above or elsewhere in this Form ~~10-K/A~~10-K cause our underlying assumptions to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, express or implied, included in this Form ~~10-K/A~~10-K and attributable to Cimarex are qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form ~~10-K/A~~10-K with the Securities and Exchange Commission, except as required by law.

Table of Contents

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

General

Cimarex Energy Co., a Delaware corporation formed in 2002, is an independent oil and gas exploration and production company. Our operations are located mainly in ~~Oklahoma,~~Texas, New Mexico, and Oklahoma. Currently our operations are focused in two main areas: the Permian Basin and the Mid-Continent. Our Permian Basin region encompasses west Texas and southeast New Mexico. Our Mid-Continent region consists of Oklahoma and the Texas Panhandle. On our website — www.cimarex.com — you will find our annual reports, proxy statements, and all of our Securities and Exchange Commission ~~(SEC) filings.~~(“SEC”) filings, which we make available free of charge. Information contained on our website is not incorporated by reference into this Annual Report. Throughout this Form ~~10-K/A~~10-K we use the terms “Cimarex,” “company,” “we,” “our,” and “us” to refer to Cimarex Energy Co. and its subsidiaries.

Our principal business objective is to ~~profitably grow~~increase shareholder value through the profitable long-term growth of our proved reserves and production while seeking to minimize our impact on the communities in which we operate for the ~~long-term benefit of our shareholders.~~long-term. Our strategy centers on maximizing cash flow from producing properties toso that we can reinvest in exploration and development ~~opportunities.~~opportunities and provide cash returns to shareholders through dividends. We consider merger and acquisition opportunities that enhance our competitive position and we occasionally divest ~~non-core~~non-strategic assets. Key elements to our approach include:

· ~~Maintain~~

Maintaining a strong financial position;

· ~~Investment~~

Investing in a diversified portfolio of drilling opportunities;

· ~~Rate-of-return driven evaluation~~

Evaluating projects based on rate-of-return and ~~ranking of~~rank investment decisions;

Tracking predicted versus actual results in a centralized exploration management system ~~providing~~to provide feedback to improve results;

Attracting quality employees and maintaining integrated teams of geoscientists, landmen, and engineers;

· and

Maximizing profitability.

Conservative use of leverage has long been the key to our financial strategy. We believe that low leverage coupled with strong full-cycle returns enables us to better withstand volatility in commodity prices and provide competitive returns and growth to shareholders. See Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Stock Performance Graph and Item 6 Selected Financial Data for additional financial and operating information for fiscal years ~~2012 — 2016.~~

2015 - 2019.

Table of Contents

Proved Oil and Gas Reserves

Our December 31, 2019 total proved reserves ~~were essentially flat in 2016.~~grew 5% from prior year-end. Proved undeveloped reserves as a percentage of total proved reserves decreased to ~~21%~~14% from ~~25%~~15% a year ago. We added ~~324.0 Bcfe~~119.3 MMBOE of new reserves through extensions and ~~discoveries and 126.2 Bcfe through net positive performance~~discoveries. Net negative revisions ~~replacing 128%~~totaled 50.7 MMBOE, which consisted primarily of ~~production.~~47.2 MMBOE in downward price revisions. The change in our proved reserves is as ~~follows (in Bcfe):~~

follows:



	Proved Reserves (MBOE)
Reserves at December 31, ~~2015~~ 2018	591,195	~~2,909.4~~
Revisions of previous estimates	(50,661	~~19.8~~	)
Extensions and discoveries	119,261	~~324.0~~
Purchases of reserves	63,019	~~0.9~~
Production	(101,645	~~(352.6~~	)
Sales of reserves	(1,574	~~(11.0~~	)
Reserves at December 31, ~~2016~~ 2019	619,595	~~2,890.5~~

Revisions of previous estimates in the above table include net positive performance and operating cost related revisions of 126.2 Bcfe and 138.5 Bcfe, respectively, partially offset by negative commodity price revisions of 244.9 Bcfe.

A breakdown by commodity of our proved oil and gas reserves follows:

December 31,

2016

2015

2014

Total Proved Reserves:

Gas (Bcf)

1,471.4

1,517.0

1,666.7

Oil (MMBbls)

105.9

107.8

119.0

NGL (MMBbls)

130.6

124.3

125.3

Equivalent (Bcfe)

2,890.5

2,909.4

3,132.3

% Developed

79

75

77

~~See “Supplemental Oil and Gas Information” in Item 8 of this report for further information.~~

~~Production Volumes, Prices, and Costs~~

~~Our 2016 production volumes totaled 963 MMcfe per day, a 2% decrease from 2015, and were comprised of 48% natural gas, 28% oil and 24% NGLs.~~



	December 31,
	2019		2018		2017
Proved reserves:
Gas (MMcf)	1,532,145		1,591,321		1,607,635
Oil (MBbls)	169,770		146,538		137,238
NGL (MBbls)	194,468		179,436		153,860
Total (MBOE)	619,595		591,195		559,037
Percent developed	86	%	85	%	83	%

The following ~~tables show~~table summarizes our production volumes by region, the average commodity prices received and production cost per unit of production. Separate data is also included for the Cana area, which comprises the majority of the production of our largest producing field, the Watonga-Chickasha in western Oklahoma.

Production Volumes

Net Average Daily Volumes

Gas

Oil

NGL

Total

Gas

Oil

NGL

Total

Years Ended December 31,

(MMcf)

(MBbls)

(MBbls)

(MMcfe)

(MMcf)

(MBbls)

(MBbls)

(MMcfe)

2016

Permian Basin

65,191

13,183

6,677

184,351

178.1

36.0

18.2

503.7

Mid-Continent

102,501

3,283

7,508

167,243

280.1

9.0

20.5

456.9

Other

535

62

15

997

1.4

0.2

0.1

2.8

Total Company

168,227

16,528

14,200

352,591

459.6

45.2

38.8

963.4

Cana area

82,423

2,848

6,855

140,647

225.2

7.8

18.7

384.3

2015

Permian Basin

66,006

15,719

6,220

197,644

180.8

43.1

17.0

541.5

Mid-Continent

100,801

2,746

6,757

157,821

276.2

7.5

18.5

432.4

Other

2,180

198

86

3,878

6.0

0.5

0.3

10.6

Total Company

168,987

18,663

13,063

359,343

463.0

51.1

35.8

984.5

Cana area

77,882

2,206

5,957

126,865

213.4

6.0

16.3

347.6

2014

Permian Basin

45,200

12,552

4,187

145,636

123.8

34.4

11.5

399.0

Mid-Continent

106,711

2,682

6,980

164,682

292.4

7.3

19.1

451.2

Other

3,217

405

176

6,704

8.8

1.1

0.5

18.4

Total Company

155,128

15,639

11,343

317,022

425.0

42.8

31.1

868.6

Cana area

76,915

1,903

5,937

123,952

210.7

5.2

16.3

339.6

Average Realized Price

Production

Gas

Oil

NGL

Cost

Years Ended December 31,

(per Mcf)

(per Bbl)

(per Bbl)

(per Mcfe)

2016

Permian Basin

$
2.35

$
38.45

$
12.32

$
0.86

Mid-Continent

$
2.29

$
37.65

$
15.59

$
0.43

Other

$
2.00

$
38.86

$
14.80

$
1.59

Total Company

$
2.31

$
38.30

$
14.05

$
0.66

Cana area

$
2.28

$
37.73

$
15.80

$
0.23

2015

Permian Basin

$
2.55

$
43.58

$
11.94

$
1.06

Mid-Continent

$
2.51

$
41.90

$
15.41

$
0.52

Other

$
3.16

$
48.01

$
14.72

$
1.72

Total Company

$
2.53

$
43.38

$
13.75

$
0.83

Cana area

$
2.51

$
41.54

$
15.59

$
0.26

2014

Permian Basin

$
4.48

$
82.44

$
30.04

$
1.58

Mid-Continent

$
4.42

$
88.23

$
35.03

$
0.58

Other

$
4.40

$
92.82

$
32.09

$
2.31

Total Company

$
4.43

$
83.70

$
33.14

$
1.08

Cana area

$
4.32

$
88.21

$
34.89

$
0.24

~~Acquisitions and Divestitures~~

~~In 2016 we sold interests in various non-core~~estimated proved oil and gas ~~properties for $21 million and made various acquisitions totaling $11 million.~~

~~Exploration and Development Overview~~

Cimarex has one reportable segment, exploration and production (E&P). Our E&P activities take place primarily in two areas: the Permian Basin and the Mid-Continent region. Almost all of our exploration and development (E&D) capital is allocated between these two areas. In 2016, E&D investment totaled $735 million. Of that, 59% was invested in the Permian Basin and 40% in the Mid-Continent region.

In 2016, Cimarex drilled or participated in 154 gross (61.0 net) wells, of which we operated 73 gross (51.2 net) wells. At year-end, we were in the process of drilling or participating in 19 gross (8.4 net) wells and there were 93 gross (27.0 net) wells waiting on completion. A summary of our 2016 exploration and development activity by region is as follows:

Gross

Net

%

E&D

Wells

Wells

Completed

Capital

Drilled

Drilled

As Producers

(in millions)

Permian Basin

$
433

48

30.3

100

Mid-Continent

291

106

30.7

99

Other

11

—

—

—

$
735

154

61.0

99

The Permian region encompasses west Texas and southeast New Mexico. Cimarex’s Permian Basin efforts are located in the western half of the Permian Basin known as the Delaware Basin. In 2016, we focused on drilling horizontal wells that yielded oil and liquids-rich gas from the Wolfcamp shale and the Bone Spring formation. Cimarex saw improved results in its Wolfcamp shale wells, as measured by production and reserves ~~with the further implementation of long laterals and continued improvement in well completion design and in the Bone Spring wells via upsized well completions.~~

~~The Permian region produced 504 MMcfe per day in 2016, which was 52% of our total company production. Total production from the region decreased 7% in 2016 over 2015.~~

Our Mid-Continent region consists of Oklahoma and the Texas Panhandle. Our activity in 2016 in the Mid-Continent was focused in the Woodford shale and the Meramec horizon, both in Oklahoma. We continued to implement larger well completions in the Woodford shale and we applied those same techniques to delineate the Meramec horizon, located above the Woodford. Cimarex continues to evaluate the size and potential of the Meramec play.

~~During 2016, production from the Mid-Continent averaged 457 MMcfe per day, or 47% of total company production. Total production from the region increased 6% in 2016 over 2015.~~

~~Drilling Activity~~

~~We completed the following number of exploratory and developmental wells in the years indicated:~~

Wells Completed

2016

2015

2014

Gross

Net

Gross

Net

Gross

Net

Exploratory

Productive

—

—

—

—

1

0.4

Dry

—

—

—

—

1

0.5

Total

—

—

—

—

2

0.9

Developmental

Productive

153

61.0

219

98.7

309

173.6

Dry

1

—

3

1.7

1

0.1

Total

154

61.0

222

100.4

310

173.7

~~We have working interests in the following number of productive wells~~ by region as of December 31, ~~2016:~~

Gas

Oil

Gross

Net

Gross

Net

Mid-Continent

3,831

1,480

531

166

Permian Basin

831

406

4,967

1,029

Other

100

9

19

4

4,762

1,895

5,517

1,199

~~Significant Properties~~

2019.



	Gas (MMcf)	Oil (MBbls)	NGL (MBbls)	Total (MBOE)	% of Total Proved Reserves
Mid-Continent	660,161	21,848	64,377	196,252	32	%
Permian Basin	870,208	147,662	130,007	422,703	68	%
Other	1,776	260	84	640	—	%
	1,532,145	169,770	194,468	619,595	100	%

See SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) in Item 8 for further information regarding our reserves.

Table of Contents

Production Volumes, Prices, and Costs

All of our oil and gas assets are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty, and overriding royalty interests. Operated wells account for ~~76%~~approximately 87% of our proved reserves. ~~In 2016,~~

Our 2019 production volumes totaled 278.5 MBOE per day, a 25% increase from 2018, and were comprised of 41% gas, 31% oil, and 28% NGLs. The following table presents our total and average daily production volumes by region.



	Total Production Volumes				Average Daily Production Volumes
Years Ended December 31,	Gas (MMcf)	Oil (MBbls)	NGL (MBbls)	Total (MBOE)	Gas (MMcf)	Oil (MBbls)	NGL (MBbls)	Total (MBOE)
2019
Permian Basin	145,612	26,376	18,973	69,618	398.9	72.3	52.0	190.8
Mid-Continent	105,515	5,033	9,263	31,882	289.1	13.8	25.4	87.3
Other	440	54	18	145	1.2	0.1	—	0.4
Total company	251,567	31,463	28,254	101,645	689.2	86.2	77.4	278.5

2018
Permian Basin	92,593	19,104	11,499	46,035	253.7	52.3	31.5	126.1
Mid-Continent	112,697	5,530	10,474	34,787	308.8	15.2	28.7	95.3
Other	547	76	21	188	1.4	0.2	0.1	0.5
Total company	205,837	24,710	21,994	81,010	563.9	67.7	60.3	221.9

2017
Permian Basin	79,521	16,271	8,858	38,382	217.9	44.6	24.3	105.2
Mid-Continent	107,463	4,547	8,503	30,960	294.4	12.5	23.3	84.8
Other	484	43	13	137	1.3	0.1	—	0.4
Total company	187,468	20,861	17,374	69,479	513.6	57.2	47.6	190.4

Table of Contents

At December 31, 2019, we had three fields that contained 15% or more of our total proved ~~reserves~~reserves. These fields are: (i) Watonga-Chickasha in the Cana area of the ~~Watonga-Chickasha field were~~Mid-Continent, which contained approximately ~~57% of Cimarex’s total proved reserves. No other field had reserves in excess of 15%~~29% of our total proved reserves; (ii) Dixieland in the Permian Basin in Reeves County Texas, which contained approximately 21% of our total proved reserves; and (iii) Ford West in the Permian Basin in Culberson County Texas, which contained approximately 17% of our total proved reserves.

At December 31, ~~2016, 63%~~2018, we had two fields that contained 15% or more of our total proved reserves, ~~were~~Watonga-Chickasha and Ford West. At December 31, 2017, the only field that contained 15% or more of our total proved reserves was Watonga-Chickasha. Production for these fields is presented in the following table.



	Total Production Volumes				Average Daily Production Volumes
Years Ended December 31,	Gas (MMcf)	Oil (MBbls)	NGL (MBbls)	Total (MBOE)	Gas (MMcf)	Oil (MBbls)	NGL (MBbls)	Total (MBOE)
2019
Watonga-Chickasha	89,564	4,588	8,688	28,203	245.4	12.6	23.8	77.3
Dixieland	42,570	8,890	5,911	21,897	116.6	24.4	16.2	60.0
Ford West	40,843	5,006	5,180	16,993	111.9	13.7	14.2	46.6

2018
Watonga-Chickasha	96,373	5,094	9,774	30,930	264.0	14.0	26.8	84.7
Dixieland	10,285	2,510	1,328	5,552	28.2	6.9	3.6	15.2
Ford West	30,958	3,748	3,804	12,711	84.8	10.3	10.4	34.8

2017
Watonga-Chickasha	88,557	4,156	7,829	26,744	242.6	11.4	21.4	73.3
Dixieland	9,668	2,279	1,032	4,922	26.5	6.2	2.8	13.5
Ford West	26,405	3,370	2,883	10,654	72.3	9.2	7.9	29.2

Table of Contents

The following table presents the average commodity prices received and production cost per unit of production by region.



	Average Realized Price						Production Cost (per BOE)
Years Ended December 31,	Gas (per Mcf)		Oil (per Bbl)		NGL (per Bbl)		Production Cost (per BOE)
2019
Permian Basin	$	0.49	$	52.55	$	12.62	$	3.47
Mid-Continent	$	1.95	$	53.89	$	15.47	$	3.04
Other	$	2.44	$	56.52	$	15.70	$	9.59
Total Company	$	1.11	$	52.77	$	13.55	$	3.34

2018
Permian Basin	$	1.69	$	54.95	$	22.84	$	4.37
Mid-Continent	$	2.23	$	62.31	$	21.67	$	2.69
Other	$	2.97	$	58.40	$	26.46	$	7.63
Total Company	$	1.99	$	56.61	$	22.28	$	3.66

2017
Permian Basin	$	2.72	$	46.96	$	20.25	$	4.73
Mid-Continent	$	2.78	$	47.42	$	23.02	$	2.60
Other	$	2.74	$	46.53	$	23.11	$	9.03
Total Company	$	2.76	$	47.06	$	21.61	$	3.79

Acquisitions and Divestitures

We consider property acquisitions, divestitures, and occasional mergers to enhance our competitive position. Moreover, sales of non-strategic assets are a source of liquidity that we can use to supplement funding of capital expenditures and acquisitions of strategic assets.

On March 1, 2019, we completed the acquisition of Resolute Energy Corporation (“Resolute”), an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the Permian Basin of west Texas. This acquisition expanded our footprint in Reeves County, Texas on acreage complementary to our existing Reeves County position. The principal factors considered by management in making this acquisition included: (i) our expectation that Resolute’s assets’ attractive returns are competitive with those in our existing portfolio, (ii) the opportunity to apply our experience and learnings from already operating in this area to generating productivity gains from Resolute’s properties, (iii) the ability to increase our acreage position in the Delaware Basin, and (iv) the expectation that the acquisition will be financially accretive. We paid $325.7 million in cash and issued common and preferred stock valued at an aggregate of $494.6 million, for total consideration transferred of $820.3 million. In addition, we assumed $870.0 million of Resolute’s long-term debt, which we immediately repaid. See Note 13 to the Consolidated Financial Statements for further information.

In 2019, we sold interests in various non-strategic oil and gas properties for cash proceeds totaling $29 million.

Table of Contents

Exploration and Development Overview

Cimarex has one reportable segment, exploration and production (“E&P”). Our E&P activities take place primarily in two areas: the Permian Basin and the Mid-Continent region. Almost all of our exploration and development (“E&D”) capital is allocated between these two areas.

A summary of our 2019 exploration and development activity by region is as follows:



	E&D Capital		Gross Wells Completed	Net Wells Completed
	(in millions)
Permian Basin	$	1,048	131	75.5
Mid-Continent	193		160	16.6
Other	1		—	—
	$	1,242	291	92.1

The Permian Basin encompasses west Texas and southeast New Mexico. Cimarex’s Permian Basin efforts are located in the western half of the Permian Basin known as the Delaware Basin. In 2019, we began infill development of our Wolfcamp shale assets in the Delaware Basin. Development was focused on the oil-rich Upper Wolfcamp shale in Culberson and Reeves Counties in Texas. The Upper Wolfcamp is being developed with horizontal wells using primarily two-mile laterals.

The Permian Basin produced 190.8 MBOE per day in 2019, which was 68% of our total company production. Total production from the region increased 51% in 2019 over 2018. In 2019, we invested $1.05 billion, or 84% of our total E&D investment, in the Permian Basin and acquired Resolute, as discussed above in Acquisitions and Divestitures.

Our Mid-Continent region consists of Oklahoma and ~~37%~~the Texas Panhandle. Our activity in 2019 in the Mid-Continent was focused in the Woodford shale and the Meramec horizon, both in Oklahoma. We focused our efforts on oil development and we continued to refine well completion and spacing in these formations.

Table of Contents

During 2019, production from the Mid-Continent averaged 87.3 MBOE per day, or 31% of total company production. Total production from the region decreased 8% in 2019 as compared to 2018. In 2019, we invested $193 million, or 16% of our total E&D investment, in the Mid-Continent.

Drilling Activity

In 2019, we completed or participated in the completion of 291 gross (92.1 net) wells, of which we operated 119 gross (85.3 net) wells. At year-end, we were in the ~~Permian Basin.~~ process of drilling or participating in 15 gross (5.3 net) wells and there were 95 gross (32.4 net) wells waiting on completion.

We completed the following number of developmental wells in the years indicated in the table below. During these years, we completed no exploratory wells.



	Wells Completed
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Developmental
Productive	289	90.2	349	122.1	314	96.4
Dry	2	1.9	—	—	5	1.6
Total	291	92.1	349	122.1	319	98.0

At December 31, 2019, we owned an interest in ~~10,279~~9,864 gross ~~(3,094~~(2,782 net) productive oil and gas wells. ~~The~~We had working interests in the following ~~table summarizes our estimated proved oil and gas reserves~~number of productive wells by region as of December 31, ~~2016.~~

% of

Gas

Oil

NGL

Total

Total Proved

(Bcf)

(MMBbl)

(MMBbl)

(Bcfe)

Reserves

Mid-Continent

1,095.2

31.4

89.6

1,821.3

63

Permian Basin

372.4

74.3

41.0

1,064.0

37

Other

3.8

0.2

—

5.2

—

1,471.4

105.9

130.6

2,890.5

100

2019:



	Gas		Oil
	Gross	Net	Gross	Net
Mid-Continent	3,792	1,435	729	186
Permian Basin	745	331	4,469	823
Other	112	5	17	2
	4,649	1,771	5,215	1,011

~~At December 31, 2016, our ten largest producing fields held 86%~~Table of ~~total proved reserves. We are the principal operator of our production in each of these fields.~~

% of

Total

Average

Approximate

Proved

Working

Average Depth

Field

Region

Reserves

Interest%

(feet)

Primary Formation

Watonga-Chickasha

Mid-Continent

57.1

34.1

13,000'

Woodford

Ford, West

Permian Basin

8.4

56.9

9,500'

Wolfcamp

Dixieland

Permian Basin

6.1

96.8

11,000'

Wolfcamp

Lusk

Permian Basin

3.9

54.8

9,500'

Bone Spring

Cottonwood Draw

Permian Basin

2.6

73.7

3,000' - 10,000'

Delaware/Wolfcamp

Grisham

Permian Basin

1.8

100.0

11,000'

Wolfcamp

Phantom

Permian Basin

1.7

57.5

11,500'

Bone Spring

Two Georges

Permian Basin

1.7

90.5

11,500'

Bone Spring

Sandbar

Permian Basin

1.4

58.8

7,500'

Bone Spring

Quail Ridge

Permian Basin

1.0

36.5

8,000' - 13,000'

Bone Spring/Morrow

85.7

Contents

Acreage

The following table sets forth the gross and net acres of both developed and undeveloped leases held by Cimarex as of December 31, ~~2016.~~2019. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest.

Acreage

Undeveloped

Developed

Total

Gross

Net

Gross

Net

Gross

Net

Mid-Continent

Kansas

18,231

18,191

—

—

18,231

18,191

Oklahoma

107,015

71,658

686,489

295,176

793,504

366,834

Texas

22,045

11,301

133,839

56,708

155,884

68,009

147,291

101,150

820,328

351,884

967,619

453,034

Permian Basin

New Mexico

73,882

52,669

175,842

119,597

249,724

172,266

Texas

81,443

63,289

201,078

147,829

282,521

211,118

155,325

115,958

376,920

267,426

532,245

383,384

Other

Arizona

2,097,201

2,097,201

17,847

—

2,115,048

2,097,201

California

383,647

383,647

—

—

383,647

383,647

Colorado

41,992

18,867

40,800

1,642

82,792

20,509

Gulf of Mexico

25,000

13,000

28,848

6,381

53,848

19,381

Louisiana

3,533

484

2,877

170

6,410

654

Michigan

26,491

26,414

1,183

1,183

27,674

27,597

Montana

34,381

9,167

7,688

1,721

42,069

10,888

Nevada

1,007,167

1,007,167

440

1

1,007,607

1,007,168

New Mexico

1,641,206

1,633,821

18,371

2,436

1,659,577

1,636,257

Texas

10,478

3,724

27,174

6,167

37,652

9,891

Utah

80,527

59,433

32,552

1,575

113,079

61,008

Wyoming

97,157

13,744

43,626

4,197

140,783

17,941

Other

194,398

171,229

9,734

3,460

204,132

174,689

5,643,178

5,437,898

231,140

28,933

5,874,318

5,466,831

Total

5,945,794

5,655,006

1,428,388

648,243

7,374,182

6,303,249



	Acreage
	Undeveloped		Developed		Total
	Gross	Net	Gross	Net	Gross	Net
Mid-Continent
Kansas	18,231	18,191	—	—	18,231	18,191
Oklahoma	90,502	60,611	653,827	304,570	744,329	365,181
Texas	14,272	9,356	123,135	51,338	137,407	60,694
	123,005	88,158	776,962	355,908	899,967	444,066
Permian Basin
New Mexico	68,103	50,296	174,320	119,318	242,423	169,614
Texas	58,632	39,496	193,932	135,636	252,564	175,132
	126,735	89,792	368,252	254,954	494,987	344,746
Other
Arizona	2,097,841	2,097,841	—	—	2,097,841	2,097,841
California	383,487	383,487	—	—	383,487	383,487
Colorado	30,346	18,867	8,950	1,642	39,296	20,509
Gulf of Mexico	20,000	11,000	18,853	6,381	38,853	17,381
Louisiana	132,808	129,759	2,868	168	135,676	129,927
Michigan	234	156	587	587	821	743
Montana	29,359	7,698	7,004	1,037	36,363	8,735
Nevada	1,007,167	1,007,167	440	1	1,007,607	1,007,168
New Mexico	1,640,646	1,633,819	14,282	2,436	1,654,928	1,636,255
Texas	8,800	2,695	23,375	4,784	32,175	7,479
Utah	79,947	59,473	17,078	1,485	97,025	60,958
Wyoming	90,586	11,923	24,447	4,711	115,033	16,634
Other	100,839	84,484	7,362	3,408	108,201	87,892
	5,622,060	5,448,369	125,246	26,640	5,747,306	5,475,009
Total	5,871,800	5,626,319	1,270,460	637,502	7,142,260	6,263,821

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The table below summarizes by year and region our undeveloped acreage expirations in the next five years. In most cases, the drilling of a commercial well will hold the acreage beyond the expiration.

Acreage

2017

2018

2019

2020

2021

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Mid-Continent

22,804

18,383

11,288

6,462

1,695

1,525

—

—

—

—

Permian Basin

17,025

17,005

5,527

5,527

8,360

8,198

40

40

598

598

Other

51,036

50,281

30,709

29,992

63,334

59,092

28,867

28,652

7,042

6,953

90,865

85,669

47,524

41,981

73,389

68,815

28,907

28,692

7,640

7,551

% of undeveloped acreage

1.5

1.5

0.8

0.7

1.2

1.2

0.5

0.5

0.1

0.1



	Acreage
	2020		2021		2022		2023		2024
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Mid-Continent	10,939	10,902	6,235	6,235	1,860	1,860	284	284	—	—
Permian Basin	5,732	5,732	4,136	4,136	1,641	1,641	960	960	40	40
Other	149,623	149,593	10,935	10,855	32,977	31,956	5,709	5,594	904	648
	166,294	166,227	21,306	21,226	36,478	35,457	6,953	6,838	944	688

% of undeveloped acreage	2.8	3.0	0.4	0.4	0.6	0.6	0.1	0.1	—	—

At December 31, ~~2016,~~2019, we had no proved undeveloped reserves ~~associated with expiring~~booked on undeveloped acreage that were scheduled for development beyond the expiration dates of the undeveloped acreage.

Marketing

Our oil and gas production is sold under short-term arrangements at market-responsive prices. We sell our oil at prices tied directly or indirectly to field postings. Our gas is sold under price mechanisms related to either monthly or daily index prices on pipelines where we deliver our gas.

We sell our NGLs at prices tied to monthly index prices where we deliver our NGLs.

We sell our oil, gas, and ~~gas~~NGLs to a broad portfolio of ~~customers. Our~~customers, including major ~~customer during 2016 was Sunoco Logistics Partners L.P. (Sunoco), which accounted for 20%~~energy companies, pipeline companies, local distribution companies, and other end-users. In 2019, we made sales to two customers that each amounted to 10% or more of our consolidated revenues for ~~the year.~~

2019. Sales to those two customers accounted for 29% and 25%, respectively, of our consolidated revenues for 2019. If ~~Sunoco~~any one of our major customers were to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production with some delay. If multiple significant customers were to discontinue purchasing our ~~product,~~production, we believe there would be challenges initially, but ample markets to handle the disruption.

We regularly monitor the credit worthiness of all our customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary.

Historically, losses associated with uncollectible receivables have not been significant.

Corporate Headquarters and Employees

Our corporate headquarters is located at 1700 Lincoln St., Suite 3700, Denver, Colorado 80203. On December 31, ~~2016~~2019 and ~~2015,~~2018, Cimarex had ~~856~~987 and ~~925~~955 employees, respectively. None of our employees are subject to collective bargaining agreements.

Competition

The oil and gas industry is highly competitive, particularly for prospective undeveloped leases and purchases of proved reserves. There is also competition for rigs and related equipment used to drill for and produce oil and gas, however, to a lesser extent in the current market environment. Our competitive position also is ~~also~~ highly dependent on our ability to recruit and retain geological, geophysical, and engineering expertise. We compete for prospects, proved reserves, oil-field services, and qualified oil and gas professionals with major and diversified energy companies and other independent operators that have larger financial, human, and technological resources than we do.

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We compete with integrated, independent, and other energy companies for the sale and transportation of our oil, gas, and NGLs to marketing companies and end users. The oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial, and residential consumers. Many of these competitors have greater financial and human ~~resources.~~resources than we do. The effect of these competitive factors cannot be predicted.

Proved Reserves Estimation Procedures

Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with the SEC’s rules for reporting oil and gas reserves. Our reserve definitions conform with definitions of Rule 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by our internal Corporate Reservoir Engineering group, which is comprised of ~~reservoir~~ engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and production functions of the company. The primary objective of our Corporate Reservoir Engineering group is to maintain accurate forecasts on all properties of the company through ongoing monitoring and timely updates of operating and economic parameters (production forecasts, prices and regional differentials, operating expenses, ownership, etc.) in accordance with guidelines established by the SEC. This separation of function and responsibility is a key internal control.

Cimarex engineers are responsible for estimates of proved reserves. Corporate engineers interact with the exploration and production departments to ensure all available engineering and geologic data is taken into account prior to establishing or revising an estimate. After preparing the reserves update, the corporate engineers review their recommendations with the Vice President of Corporate Engineering. After approval from the Vice President of Corporate Engineering, the revisions are entered into our reserves database by the engineering technician.

During the course of the year, the Vice President of Corporate Engineering presents summary reserves information to senior management and to our Board of Directors for their review. From time to time, the Vice President of Corporate Engineering also will confer with the Vice President of Exploration, Chief Operating Officer, and the Chief Executive Officer regarding specific reserves-related issues. In addition, Corporate Reservoir Engineering maintains a set of basic guidelines and procedures to ensure that critical checks and reviews of the reserves database are performed on a regular basis.

Together, these internal controls are designed to promote a comprehensive, objective, and accurate reserves estimation process. As an additional confirmation of the reasonableness of our internal estimates, DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, ~~reviewed~~performed an independent evaluation of our estimated net reserves ~~associated with~~representing greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of December 31, ~~2016.~~2019. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over 3735 years of experience in oil and gas reservoir studies and reserves evaluations.

The technical employee primarily responsible for overseeing the oil and gas reserves estimation process is Cimarex’s Vice President of Corporate Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than 2225 years of practical experience in oil and gas reservoir evaluation. He has been directly involved in the annual reserves reporting process of Cimarex since 2002 and has served in his current role for the past 1215 years.

Title to Oil and Gas Properties

We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a prospect, or acquire proved properties. We believe title to our properties is good and defensible, and is in accordance with industry standards. Nevertheless, we are involved in title disputes from time to time that result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens, and other burdens and minor encumbrances, easements, and restrictions.

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Government Regulation

Oil and gas production and transportation is subject to extensive federal, state, and local laws and regulations. Compliance with existing laws often is difficult and costly, but has not had a significant adverse effect on our operations or financial condition. In recent years, we have been most directly impacted by federal and state environmental regulations and energy conservation rules. We are also impacted by federal and state regulation of pipelines and other oil and gas transportation systems.

The states in which we conduct operations establish requirements for drilling permits, the method of developing fields, the size of well spacing units, drilling density within productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production from wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability of production.

Environmental Regulation.Various federal, state, and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development, and production operations, which consequently impact our operations and costs. These laws and regulations govern, among other things, emissions into the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation, and disposal of waste materials, and protection of public health, natural resources, and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

Cimarex is committed to environmental protection and believes we are in material compliance with applicable environmental laws and regulations. We obtain permits for our facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations. Expenditures are required to comply with environmental regulations. These costs are a normal, recurring expense of operations and not an extraordinary cost of compliance with current government regulations.

We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could arise, or our future costs of complying with governmental requirements. We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water, or other substances as well as additional coverage for certain other pollution events.

Gas Gathering and Transportation.The Federal Energy Regulatory Commission ~~(FERC)~~(“FERC”) requires interstate gas pipelines to provide open access transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other regulations applicable to interstate pipelines.

Under the Natural Gas Policy Act ~~(NGPA)~~(“NGPA”), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA has evolved through FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional “gathering” systems under the NGPA and that our facilities are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and federal agencies regarding the safety and operating aspects of the transportation and storage activities of these facilities.

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In addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship our gas to markets.

Additional proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, Bureau of Land Management ~~(BLM)~~(“BLM”), U.S. Environmental Protection Agency ~~(EPA)~~(“EPA”), state legislatures, state agencies, local governments, and the courts. We cannot predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state, and local laws, rules, or regulations will have a material adverse effect upon our capital expenditures, earnings, or competitive position.

Federal and State Income and Other Local Taxation

Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax regulations involving ad valorem, personal property, franchise, severance, and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that ~~there~~they will because any material undisclosed impact on our capital expenditures, earnings, or competitive position.

Executive Officers of the Registrant

See Part III, Item 10, Directors, Executive Officers and Corporate Governance for information regarding our executive officers as of February ~~24, 2017.~~

26, 2020.

ITEM 1A. RISK FACTORS

The following risks and uncertainties, together with other information set forth in this Form ~~10-K/A,~~10-K, should be carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties presently unknown to us or currently deemed immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, ~~our~~ financial condition, and ~~the~~ results of ~~our~~ operations, which in turn could negatively impact the value of our securities.

Risks Concerning Cimarex and its Operations

Oil, gas, and NGL prices fluctuate due to a number of ~~uncontrollable~~ factors beyond our control, creating a component of uncertainty in our development plans and overall operations. Declines in prices adversely affect our financial results and rate of growth in proved reserves and production.

Oil and gas markets are volatile. We cannot predict future prices. The prices we receive for our production heavily influence our revenue, profitability, access to capital, and future rate of growth. The prices we receive depend on numerous factors beyond our control. These factors include, but are not limited to, changes in domestic and global supply and demand for oil and gas, the level of domestic and global oil and gas exploration and production activity, pipeline capacity constraints limiting takeaway and increasing basis differentials, geopolitical instability, the actions of the Organization of Petroleum Exporting Countries, weather conditions, technological advances affecting energy consumption, governmental regulations and taxes, and the price and technological advancement of alternative fuels.

Our proved oil and gas reserves and production volumes will decrease unless those reserves are replaced with new discoveries or acquisitions. Accordingly, for the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations, our revolving credit facility, and proceeds from the sale of senior notes or equity. Low prices reduce our cash flow and the amount of oil and gas that we can economically produce and may cause us to curtail, delay, or defer certain exploration and development projects.

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Moreover, low prices may impact our abilities to borrow under our revolving credit facility and to raise additional debt or equity capital to fund acquisitions.

If prices decrease, we ~~will~~may be required to take write-downs of the carrying values of our oil and gas properties and/or our goodwill.

Accounting rules require that we periodically review the carrying value of our oil and gas properties and goodwill for possible impairment.

In ~~2016,~~2019, we recognized a ceiling test ~~impairments totaling $757.7 million ($481.4 million, net~~impairment of ~~tax). In 2015, we recognized ceiling test impairments in each quarter totaling $4.0 billion ($2.6 billion, net of tax).~~$618.7 million. The ~~impairments~~impairment resulted primarily from the impact of decreases in the ~~12-month~~trailing twelve-month average ~~trailing~~ prices for oil, ~~natural~~ gas, and NGLs utilized in determining the estimated future net cash flows from proved reserves. ~~At December 31, 2016,~~We did not recognize any ceiling test impairments in 2018 or 2017 because the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the ~~test, and no~~

~~impairment was necessary. However, a decline of approximately 7% or more in the value of the ceiling limitation would have resulted in an impairment.~~test. Because the ceiling calculation uses ~~rolling 12-month~~trailing twelve-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.

We evaluate our goodwill for impairment annually and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. We have had no goodwill impairments during the years ended December 31, 2019, 2018, and 2017.

Ineffective internal controls could impact our business and financial results.

Our internal control over financial reporting may not prevent or detect misstatements because of its inherent limitations, including the possibility of human error, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, including any failure to implement required new or improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed and we could fail to meet our financial reporting obligations. For example, ~~in connection with the corrections made in this Form 10-K/A, management re-evaluated the effectiveness of our internal control over financial reporting as of~~at December 31, 2016, ~~and~~management concluded that a deficiency in the design of our internal controls related to the full cost ceiling test calculation represented a material weakness in our internal control over financial reporting and, therefore, that we did not maintain effective internal control over financial reporting as of December 31, 2016, as reported in our Form 10-K/A for that period. We have since remediated this material weakness. However, in connection with the preparation of this Form 10-K, management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2019 and concluded that we did not have an effective process and control in place to periodically evaluate the quantitative effect associated with the inclusion or exclusion of certain inputs, such as skim oil and drip liquids, in the Company’s oil and gas reserve database used in the ceiling test impairment calculations, depletion calculations, and the preparation of the related disclosures included in the supplemental information on oil and gas producing activities (unaudited), which represents a material weakness in our internal control over financial reporting and, therefore, that we did not maintain effective internal control over financial reporting as of December 31, ~~2016.~~2019. For a description of the material weakness identified by management and the remediation efforts being implemented for that material weakness, see “Part II, Item 9A — Controls and Procedures.” If the new controls implemented to address the material weakness and to strengthen the overall internal control related to the ~~full cost ceiling test calculation~~reserve reporting process are not designed or do not operate effectively, if we are unsuccessful in implementing or following these new ~~processes,~~controls, or we are otherwise unable to remediate this material weakness, this may result in untimely or inaccurate reporting of our financial statements.

U.S. or global financial markets may impact our business and financial condition.

A credit crisis or other turmoil in the U.S. or global financial system may have a negative impact on our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. This could have an impact on our flexibility to react to changing economic and

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business conditions. Deteriorating economic conditions could have a negative impact on our lenders, the purchasers of our oil and gas production, and the working interest owners in properties we operate, causing them to fail to meet their obligations to us.

Failure to economically replace oil and gas reserves could negatively affect our financial results and future rate of ~~growth.~~

growth; exploration and development involves numerous risks.

In order to replace the reserves depleted by production and to maintain or increase our total proved reserves and overall production levels, we must either locate and develop new oil and gas reserves or acquire ~~producing properties~~proved reserves from others. This requires significant capital expenditures and can impose reinvestment risk for us, as we may not be able to continue to replace our reserves economically. While we occasionally may seek to acquire proved reserves, our main business strategy is to grow through exploration and drilling. Without successful exploration and development, our reserves, production, and revenues could decline rapidly, which would negatively impact the results of our operations.

Exploration and development involves numerous risks, including new governmental regulations and the risk that we will not discover any commercially productive oil or gas reservoirs. Additionally, it can be unprofitable, not only from drilling dry holes but also from drilling productive wells that do not return a profit because of insufficient reserves or declines in commodity prices.

Our drilling operations may be curtailed, delayed, or canceled for many reasons. Factors such as unforeseen poor drilling conditions, title problems, unexpected pressure irregularities, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, bans, moratoria, or other restrictions implemented by local governments and the cost of, or shortages or delays in the availability of, drilling and completion services could negatively impact our drilling operations.

Our proved reserve estimates may be inaccurate and future net cash flows are uncertain.

Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future net cash flow depend on a number of variables and assumptions. Refer to “~~Cautionary Information about Forward-Looking Statements~~”CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in Part I of this report. Among others, changes in any of the following factors may cause actual results to vary considerably from our estimates:

oil, gas, and NGL prices;

timing of development expenditures;

amount of required capital expenditures and associated economics;

recovery efficiencies, decline rates, drainage areas, and reservoir limits;

anticipated reservoir and production characteristics and interpretations of geologic and geophysical data;

· ��

production rates, reservoir pressure, unexpected water encroachment, and other subsurface conditions;

· ~~oil, gas, and NGL prices;~~

governmental regulation;

access to assets restricted by local government action;

operating costs;

property, severance, excise, and other taxes incidental to oil and gas operations;

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workover and remediation costs; and

federal and state income taxes.

Our proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, an independent petroleum ~~engineers, reviewed~~engineering consulting firm, performed an independent evaluation of our ~~reserve estimates for properties that comprised at least~~estimated net reserves representing greater than 80% of the ~~discounted~~total future net ~~cash flows before income taxes, using a~~revenue discounted at 10% ~~discount rate,~~, as of December 31, ~~2016.~~

2019.

The cash flow amounts referred to in this filing should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted net cash flow from proved reserves is based on the average of the previous 12twelve months’ first-day-of-the-month prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different.

Our business depends on oil and gas pipeline and transportation facilities, some of which are owned by others.

In addition to the existence of adequate markets, our oil and ~~natural~~ gas production depends in large part on the proximity and capacity of pipeline systems, as well as storage, transportation, processing and fractionation facilities, most of which are owned by third parties. The inability to transport one commodity, such as gas, could also impair our ability to produce and sell other commodities, such as oil and NGLs, produced from the same wells. The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. This is more likely in remote areas ~~without~~with less established infrastructure, such as our Delaware Basin area where we and competitors have significant development activities. The lack of availability of or capacity in these facilities or the loss of these facilities due to construction delays, weather, fire, or other reasons, for an extended period of time could negatively affect our revenues.

~~A limited number of companies purchase a majority of our oil, NGLs and natural gas. The loss of a significant purchaser could have a material adverse effect on our ability to sell production.~~

Federal and state regulation of oil and natural gas, local government activity, adverse court rulings, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce and market oil and natural gas.

~~Hedging~~

Commodity price derivative transactions may limit our potential gains and involve other risks.

To limit our exposure to price risk, we enter into ~~hedging~~derivative agreements from time to ~~time, and use commodity derivatives. Hedges~~time. Commodity price derivatives limit volatility and increase the predictability of a portion of our cash flow. These transactions also limit our potential gains when oil and gas prices exceed the prices established by the ~~hedges.~~

derivatives.

In certain circumstances, ~~hedging~~derivative transactions may expose us to the risk of financial loss, including instances in which:

the counterparties to our ~~hedging~~derivative agreements fail to perform;

there is a sudden unexpected event that materially increases oil and ~~natural~~ gas prices; or

there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the ~~hedge arrangement.~~

derivative agreement.

Because we account for derivative contracts under mark-to-market accounting, during periods we have ~~hedging~~derivative transactions in place we expect continued volatility in derivative gains orand losses on our ~~income~~ statement of operations as changes occur in the relevant price indexes.

~~The adoption~~

Table of ~~derivatives legislation could have an adverse effect on our ability to use derivative instruments as hedges against fluctuating commodity prices.~~

In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act called for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission (CFTC), to establish regulations for implementation of many of its provisions. The Dodd-Frank Act contains significant derivatives regulations, including requirements that certain transactions be cleared on exchanges and that cash collateral (margin) be posted for such transactions. The Dodd-Frank Act provides for an exemption from the clearing and cash collateral requirements for commercial end-users, such as Cimarex, and it includes a number of defined terms used in determining how this exemption applies to particular derivative transactions and the parties to those transactions.

We have satisfied the requirements for the commercial end-user exception to the clearing requirement and intend to continue to engage in derivative transactions. In December 2015, the CFTC approved final rules on margin requirements that will have an impact on our hedging counterparties and an interim final rule exemption from the margin requirements for certain uncleared swaps with commercial end-users. The final rules did not impose additional requirements on commercial end-users. The ultimate effect of these new rules and any additional regulations is currently uncertain. New rules and regulations in this area may result in significant increased costs and disclosure obligations as well as decreased liquidity as entities that previously served as hedge counterparties exit the market.

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We have been an early entrant into new or emerging resource plays. As a result, our drilling results in these areas are uncertain. The value of our undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful.

New or emerging oil and gas resource plays have limited or no production history. Consequently, in those areas it is difficult to predict our future drilling costs and results. Therefore, our cost of drilling, completing, and operating wells in these areas may be higher than initially expected. Similarly, our production may be lower than initially expected, and the value of our undeveloped acreage may decline if our results are unsuccessful. As a result, we may be required to impair the carrying value of our undeveloped acreage in new or emerging plays.

Furthermore, unless production is established during the primary term of certain of our undeveloped oil and gas leases, the leases will expire, and we will lose our right to develop those properties.

Competition in our industry is intense and many of our competitors have greater financial and technological resources.

We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, well-established companies that have larger operating staffs and greater capital resources. These competitors may be willing to pay more for exploratory prospects and productive oil and gas properties. They may also be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit.

Because our activity is also concentrated in areas of heavy industry competition, there is heightened demand for personnel, equipment, power, services, facilities, and resources, resulting in higher costs than in other areas. Such intense competition also could result in delays in securing, or the inability to secure, the personnel, equipment, power, services, resources, or facilities necessary for our development activities, which could negatively impact our production volumes. We also face higher costs in remote areas where vendors can charge higher rates due to that remoteness ~~along with~~and the inability to attract employees to those areas, ~~and~~as well as the vendors’ ability to deploy their resources in ~~easier to access~~easier-to-access areas.

We are subject to complex laws and regulations that can adversely affect the cost, manner, and feasibility of doing business.

Exploration, production, and the sale of oil and gas are subject to extensive laws and regulations, including those implemented to protect the environment, human health and safety, and wildlife. Federal, state, and local regulatory agencies frequently require permitting and impose conditions on our activities. During the permitting process, these regulatory agencies often exercise considerable discretion in both the timing and scope of the permits, and the public, including special interest groups, often has an opportunity to influence the timing and outcome of the process. The requirements or conditions imposed by these agencies can be costly and can delay the commencement of our operations. In addition, a number of initiatives ~~had been~~were put forth by the Obama administration in the form of Presidential or Secretarial Memoranda, which are still in effect, and have the potential to impact the cost of doing business or could result in substantial delays in permitting, drilling, and other oil and gas activities. One example is the Presidential Memorandum on “no net loss” which will take the form of agency action by the Department of Interior, EPA and other agencies to ensure that harmful effects to lands are avoided, minimized and those which remain mitigated up to and including prohibiting actions which may have been previously allowed or requiring compensation.

Failing to comply with any of the applicable laws and regulations, or Presidential initiatives, could result in the suspension or termination of our operations and subject us to administrative, civil, and criminal liabilities and penalties. Such costs could have a material adverse effect on both our financial condition and operations. ~~In addition, it is uncertain what impact the 2016 U.S. presidential and congressional elections will have on the energy industry.~~

Environmental matters and costs can be significant.

As an owner, lessee, or operator of oil and gas properties, we are subject to various complex, stringent, and constantly evolving environmental laws and regulations. Our operations inherently create the risk of environmental liability to the government and private parties stemming from our use, generation, handling, and disposal of water and

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waste materials, as well as the release of hydrocarbons or other substances into the air, soil, or water. The environmental laws and regulations to which we are subject impose numerous obligations applicable to our operations, including: the acquisition of permits before conducting regulated activities associated with drilling for and producing oil and gas; the restriction of types, quantities, and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, waters of the United States, and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Liabilities under certain environmental laws can be joint and several and may in some cases be imposed regardless of fault on our part such as where we own a working interest in a property operated by another party. We also could be held liable for damages or remediating lands or facilities previously owned or operated by others regardless of whether such contamination resulted from our own actions and regardless if we were in compliance with all applicable law at the time. Further, claims for damages to persons or property, including natural resources, may result from the environmental, health, and safety impacts of our operations. ~~Since~~Because these environmental risks generally are not fully insurable and can result in substantial costs, such liabilities could have a material adverse effect on both our financial condition and operations.

Our financial condition and results of operations may be materially adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, pollutants, solid and hazardous wastes, and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, discharge, transportation, and disposal of pollutants and solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The most significant of these environmental laws are as follows:

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as CERCLA or the Superfund law, and comparable state laws, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

The Oil Pollution Act of 1990 ~~(OPA)~~(“OPA”), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States;

The Resource Conservation and Recovery Act ~~(RCRA)~~(“RCRA”), as amended, and comparable state statutes, which governs the treatment, storage, and disposal of solid waste;

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act ~~(CWA)~~(“CWA”), which governs the discharge of pollutants, including natural gas wastes, into federal and state waters;

The Safe Drinking Water Act ~~(SDWA)~~(“SDWA”), which governs the disposal of wastewater in underground injection wells; and

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The Clean Air Act ~~(CAA)~~(“CAA”) which governs the emission of pollutants into the air.

We believe we are in substantial compliance with the requirements of CERCLA, OPA, RCRA, ~~OPA,~~ CWA, SDWA, CAA and related state and local laws and regulations. We also believe we hold all necessary and up-to-date permits, registrations, and other authorizations required under such laws and regulations. Although the current costs of managing our wastes as they presently are classified are reflected in our budget, any legislative or regulatory reclassification of oil and ~~natural~~ gas exploration and production wastes could increase our costs to manage and dispose of such wastes and have a material adverse effect on our financial condition and operations.

Federal regulatory initiatives relating to the protection of threatened or endangered species could result in increased costs and additional operating restrictions or delays.

The Federal Endangered Species Act ~~(ESA)~~(“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service ~~(FWS)~~(“FWS”) may designate critical habitat and suitable habitat areas it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and ~~natural~~ gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on federal oil and ~~natural~~ gas leases in areas where certain species are currently listed as threatened or endangered, or could be listed as such, under the ESA. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our drilling activities in those areas or during certain seasons, such as breeding and nesting seasons. On March 27, 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico, and Oklahoma, where we conduct operations, as a threatened species under the ESA. Listing of the lesser prairie chicken as a threatened species imposes restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm, or otherwise result in a “taking” of this species. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies ~~(WAFWA)~~(“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. We entered into a voluntary Candidate Conservation Agreement ~~(CCA)~~(“CCA”) with the WAFWA, whereby we agreed to take certain actions and limit certain activities, such as limiting drilling on certain portions of our acreage during nesting seasons, in an effort to protect the lesser prairie chicken. ~~Such~~On February 9, 2018, the FWS announced the listing of the Texas Hornshell, a fresh water mussel species in areas including New Mexico and Texas where we operate in the Permian Basin, as an endangered species. In March 2018, we entered into a CCA concerning voluntary conservation actions with respect to the Texas Hornshell. Participating in CCAs could result in increased costs to us from species protection measures, time delays or limitations on drilling activities, which costs, delays or limitations may be significant. ~~While a federal judge in Texas vacated the listing of the lesser prairie chicken in 2015, listing~~Listing petitions continue to be filed with the FWS which could impact our operations. Many non-governmental organizations ~~(NGOs)~~(“NGOs”) work closely with the FWS regarding the listing of many species, including species with broad and even nationwide ranges. The recent listing of the Mexican Long Nosed bat, whose habitat includes the Permian Basin where we operate, ~~is an example~~and the Dunes Sagebrush Lizard in the Permian Basin, are examples of the NGOs’ influence on ESA listing decisions. The increase in endangered species listings may impact our ability to explore for or produce oil and gas in certain areas and increase our costs.

Our hydraulic fracturing activities are subject to risks that could negatively impact our operations and profitability.

We use hydraulic fracturing for the completion of almost all of our wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation’s pores to the well bore. Typically, the fluid used in this process is primarily water. In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply. A lack of readily available water or a significant increase in the cost of water could cause delays or increased completion costs.

~~While hydraulic fracturing historically has been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts~~

Table of ~~the country, resulting in increased scrutiny and regulation from~~Contents

Certain federal ~~agencies. For example, the EPA has~~agencies have asserted ~~federal~~ regulatory authority over ~~certain hydraulic-fracturing activities~~aspects of the hydraulic fracturing process. The EPA, for example, has issued regulations under the ~~SDWA involving~~federal Clean Air Act establishing performance standards for oil and gas activities, including standards for the ~~use~~capture of ~~diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Although~~air emissions released during hydraulic fracturing. In 2016, the EPA ~~has delegated~~finalized regulations that prohibit the ~~permitting authority for the~~

~~SDWA’s Underground Injection Control Class II programs in Oklahoma, Texas~~discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants and ~~New Mexico where we maintain operational acreage, the EPA is encouraging state programs~~issued a report finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could impact water resources. The BLM previously finalized regulations to ~~review and consider use of such draft guidance.~~

~~In addition, on March 26, 2015, the federal BLM published a final rule governing~~regulate hydraulic fracturing on federal ~~and Indian lands. The rule requires public disclosure~~lands but subsequently issued a repeal of ~~chemicals used~~those regulations in 2017. States in which we operate also have adopted, or stated intentions to adopt, laws or regulations that mandate further restrictions on hydraulic fracturing, on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, development of appropriate plans for managing flowback water that returns to the surface, increased standards for interim storage of recovered waste fluids, and submission to the BLM of detailed information on the geology, depth and location of preexisting wells. This rule originally was scheduled to take effect on June 24, 2015. However, the rule is the subject of several pending lawsuits filed by industry groups, two Indian tribes, and at least four states, alleging that federal law does not give the BLM authority to regulate hydraulic fracturing. The federal judge has enjoined the rule while the case is pending. The district court held that BLM did not have jurisdiction to promulgate the rule. The Obama Justice Department appealed and that appeal is pending.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has concluded a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA’s draft report was released on June 4, 2015. The findings of the report suggest that hydraulic fracturing does not pose a systemic risk to groundwater although there are risks to both groundwater and soils posed by inadequate water handling practices in certain situations. A public comment period on the report was open until August 28, 2015 and a series of public hearings were conducted by the EPA’s Scientific Advisory Board (SAB) throughout the fall of 2015. The EPA issued its final report and has reached two different topline conclusions, although the content of the study itself remains unchanged. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing.

Additionally, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Most producing states, including Texas and Colorado, have adopted, and other states are considering adopting, regulations that could imposesuch as imposing more stringent permitting, ~~public~~ disclosure and ~~well construction~~well-construction requirements on ~~hydraulic-fracturing~~hydraulic fracturing operations and establishing standards for the capture of air emissions released during hydraulic fracturing. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general or ~~otherwise seek~~hydraulic fracturing in particular.

Moreover, policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed implementing stricter restrictions on hydraulic fracturing, including banning the process outright. For example, certain 2020 candidates for President of the United States have pledged to impose a ban on hydraulic fracturing. It is possible such restrictions could target industry activity on federal lands, which could adversely impact our operations in the Delaware Basin, as well as other areas where we operate under federal leases. As of December 31, 2019, approximately 3% of our total net leasehold resides on federal lands, and approximately 43% of our total net leasehold in the Delaware Basin is located on federal lands. Although it is not possible at this time to predict the outcome of these or other proposals, any new restrictions on hydraulic fracturing ~~activities altogether.~~

that may be imposed in areas in which we conduct business could potentially result in increased compliance costs, delays or cessation in development or other restrictions on our operations.

Any of the above factors could have a material adverse effect on our financial position, results of operations, or cash flows and could make it more difficult, costly or ~~costly~~impossible for us to perform hydraulic fracturing to stimulate production from ~~dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill~~future wells. ~~In addition, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs.~~ Restrictions on hydraulic fracturing also could ~~also~~ reduce the amount of oil and ~~natural~~ gas that we are ultimately able to produce from our reserves.

The adoption of climate change legislation or regulations restricting emission of greenhouse gases, investor pressure concerning climate-related disclosures, and lawsuits could result in increased operating costs and reduced demand for the oil and ~~natural~~ gas we ~~produce.~~

produce as well as reductions in the availability of capital.

Studies have ~~suggested~~found that emission of certain gases, commonly referred to as greenhouse gases ~~(GHGs) may be impacting~~(“GHGs”), impact the earth’s climate. Methane, a primary component of natural gas, and carbon dioxide, also present in natural gas as a secondary product, sometimes considered an impurity or a by-product of the burning of oil and natural gas, are examples of GHGs. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict emissions of GHGs. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the Federal Clean Air Act that establish Prevention of Significant Deterioration ~~(PSD)~~(“PSD”) and Title V permit reviews for GHG emissions from certain large stationary sources. Facilities required to obtain PSD and/or Title V permits under EPA’s GHG Tailoring Rule for their GHG emissions also may be required to meet “Best Available Control Technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and ~~natural~~ gas production facilities on an annual basis, which includes certain of our operations. In recent proposed rulemaking, EPA is widening the scope of annual GHG reporting to include not only activities associated with completion and workover of gas wells with hydraulic fracturing and activities associated with oil and ~~natural~~ gas production operations, but also completions and workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines.

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While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In January 2015, President Obama announced a series of administration actions to reduce methane emissions, including rulemaking by the EPA and the BLM as well as updating of standards by the Department of Transportation’s Pipeline and Hazardous Materials Administration. The previous administration intended to promulgate proposed climate change rulemaking aimed at reducing GHG emissions by 45% by 2025 compared to 2012 levels. These proposals target both new and existing sources. On January 22, 2016, the Department of the Interior announced its proposed emissions mandate on oil and natural gas producers who operate on federal and Indian lands. While this rule was finalized in November of 2016, it is currently being challenged by several states and industry. While we expect new legislation and regulations to increase the cost of business, at this time it is not possible to quantify the impact on our business. Any such future laws and final regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to develop and implement best management practices aimed at reducing GHG emissions, install and maintain emissions control technologies, as well as monitor and report on GHG emissions associated with our operations, which would increase our operating costs, and such requirements also could adversely affect demand for the oil and ~~natural~~ gas that we produce.

With respect to more comprehensive regulation, policy makers and political candidates have made, or expressed support for, a variety of proposals, such as the development of cap-and-trade or carbon tax programs, as well as the more sweeping “green new deal” resolutions introduced in Congress in early 2019. As generally proposed, a cap-and-trade program would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances, while a carbon tax could impose taxes based on emissions from our operations and downstream uses of our products. The “green new deal” resolutions call for a 10-year national mobilization effort to, among other things, transition 100% of power demand in the U.S. to zero-emission sources and overhaul transportation systems in the U.S. to remove greenhouse gas emissions as much as is technologically feasible.

The following is a summary of potential climate-related risks that could adversely affect Cimarex:

Transition Risks. Transition risks are risks related to the transition to a lower-carbon economy and include policy, legal, technology, and market risks.

Policy and Legal Risks. Policy risks include policy actions that attempt to contract actions that contribute to adverse effects of climate change or policy actions that seek to promote adaptation to climate change. Examples include implementing carbon-pricing mechanisms to reduce GHG emissions (which would increase the costs of our doing business), shifting energy use toward lower emission sources (which could lower demand for our oil and gas production, resulting in lower prices and lower revenues), adopting energy-efficiency solutions (which also could lower demand for our oil and gas production, resulting in lower prices and lower revenues), encouraging greater water efficiency measures (which would increase our costs of production), and promoting more sustainable land-use practices (which also would increase our costs of production and could impact our ability to operate in certain areas). Policy actions also may include restrictions or bans on oil and gas activities, including bans on hydraulic fracturing proposed by Democratic presidential candidates, which could lead to write-downs or impairments of our assets. Legal and litigation risks include potential lawsuits claiming failure to mitigate impacts of climate change, failure to adapt to climate change, and the insufficiency of disclosure around material financial risks.

Technology Risk. Technological improvements or innovations that support the transition to a lower-carbon, more energy efficient economic system may have a significant impact on Cimarex. The development and use of emerging technologies such as renewable energy, battery storage, and energy efficiency may lower demand for oil and gas, resulting in lower prices and revenues, and increase our costs.

Market Risk. Markets could be affected by climate change through shifts in supply and demand for certain commodities, especially carbon-intensive commodities such as oil and gas and other products dependent on oil and gas, as climate-related risks and opportunities are increasingly taken into account. This could lower demand for our oil and gas production, resulting in lower prices and lower revenues. Market risk also may take the form of limited access to capital as investors shift investments to less carbon-intensive industries and alternative energy industries. In

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addition, there have also been efforts in recent years to influence the investment community, including investment advisers and certain sovereign wealth, pension, and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations, and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil, NGL, and gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. While we are currently not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Reputation Risk. Climate change has been identified as a potential source of reputational risk tied to changing customer or community perceptions of an organization’s contribution to or detraction from the transition to a lower-carbon economy. This could lower demand for our oil and gas production, resulting in lower prices and lower revenues as consumers avoid carbon-intensive industries. This may also put pressure on investment managers to shift investments to less carbon-intensive industries and alternative energy industries, limiting our access to capital.

Physical Risks. Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes or floods) or longer-term shifts in climate patterns that may cause sea level rise or chronic heat waves. Potential physical risks may cause direct damage to assets and indirect impacts such as supply chain disruption. Potential physical risks also include changes in water availability, sourcing, and quality, which could impact drilling and completions operations. These physical risks could cause increased costs, production disruptions, and lower revenues, and also could substantially increase the cost or limit the availability of insurance.

Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to engage in hydraulic fracturing during completion operations and to dispose of saltwater produced in connection with our oil and gas production, which could limit our ability to produce oil and gas economically and have a material adverse effect on our business.

We dispose of large volumes of saltwater produced in connection with our drilling and production operations pursuant to permits issued to us or ~~third party~~third-party operators of disposal wells by governmental authorities overseeing produced water disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.

There exists a growing concern that hydraulic fracturing during well completion operations and the injection of

produced water into ~~belowground~~underground disposal wells triggers seismic activity in certain areas, including Oklahoma and Texas, where we operate. In response to these concerns, regulators in some states are pursuing initiatives designed to impose additional requirements in connection with hydraulic fracturing and in the permitting of saltwater disposal wells or otherwise to assess any relationship between seismicity and these oil and gas operations. For example, in 2014, the Oklahoma Corporation Commission (“OCC”) began adopting rules for operators of saltwater disposal wells in certain seismically-active areas, or Areas of Interest, in the Arbuckle formation, requiring operators to monitor and record well pressure and discharge volume on a daily basis and further requiring operators of wells permitted for disposal of 20,000 barrels per day or more of saltwater to conduct mechanical integrity testing. Throughout 2015 and 2016, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division ~~or OGCD,~~(“OGCD”), issued a series of directives, expanding the areas of interest for induced seismicity and enhanced disposal restrictions and limiting the depths at which produced water could be injected or, in the alternative, reducing disposal volumes. Additional regulations and restrictions are possible as more is understood about this issue. In addition to and separate from induced seismicity associated with injection, the OGCD has issued guidelines to operators to follow when engaged in well stimulation activities, which some studies now seem to correlate with a small number of low intensity seismic ~~events.~~

events, and the OCC required operators

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of saltwater injection wells, including Cimarex, that were within 10 miles of saltwater disposal wells operated by third parties that were experiencing leaks to be shut in until the leaks in the third party wells were repaired or those third party wells were plugged. Shutting in our saltwater disposal wells increased our disposal costs.

In addition, in 2014 the Texas Railroad Commission, or TRC, published a new rule governing permitting or re-permitting of disposal wells in Texas that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections, and structure maps relating to the disposal area in question. If a permittee or a prospective permittee fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend, or terminate the permit application or existing operating permit for that well.

The adoption and implementation of any new laws, regulations, or directives that restrict our ability to stimulate wells or to dispose of produced water, by changing the depths of disposal wells, reducing the volume of oil and ~~natural~~ gas wastewater disposed in such wells, restricting disposal well locations or otherwise, or by requiring us or third parties who dispose of our saltwater to shut down disposal wells, could increase disposal costs or require us to shut in a substantial number of our oil and ~~natural~~ gas wells or otherwise have a material adverse effect on our ability to produce oil and gas economically and, accordingly, could materially and adversely affect our business, financial condition, and results of operations.

We could also face lawsuits alleging that seismic activity occurred as a result of completions or water disposal activities, resulting in damage to persons and property.

A substantial portion of our producing properties are located in limited geographic areas, making us vulnerable to risks associated with having geographically concentrated operations.

A substantial portion of our producing properties are geographically concentrated in the Permian Basin in Texas and New Mexico and our Cana area in the Mid-Continent region in Oklahoma, with these two areas comprising approximately ~~52%~~68% and ~~47%~~31%, respectively, of our oil, gas, and NGL production and approximately ~~61%~~73% and ~~39%~~27%, respectively, of our oil, gas, and NGL revenues for the year ended December 31, ~~2016.~~2019. Approximately ~~37%~~68% and 32% of our estimated proved reserves were located in the Permian Basin and ~~approximately 63% of our estimated proved reserves were located in~~ the Mid-Continent region, respectively, as of December 31, ~~2016.~~

2019.

Because of this concentration in limited geographic areas, the success and profitability of our operations may be disproportionately exposed to regional factors relative to our competitors that have more geographically dispersed operations. These factors include, among others: (i) the prices of ~~crude~~ oil and ~~natural~~ gas produced from wells in the regions and other regional supply and demand factors, including gathering, pipeline, and rail transportation capacity constraints; (ii) the availability of rigs, equipment, oil field services, supplies, and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operations in the Permian Basin and Mid-Continent region, as well as other areas, may be adversely affected by severe weather events such as floods, lightning, ice and other storms, and tornadoes, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in limited geographic areas also increases our exposure to changes in local laws and regulations including concerning hydraulic fracturing and ~~waste water~~wastewater disposal as discussed above in “Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to engage in hydraulic fracturing during completion operations and to dispose of saltwater produced in connection with our oil and gas production, which could limit our ability to produce oil and gas

economically and have a material adverse effect on our business”, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents, or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, results of operations, and cash flows.

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We use some of the latest available horizontal drilling and completion techniques, which involve risk and uncertainty in their application.

Our horizontal drilling operations utilize some of the latest drilling and completion techniques. The risks orof such techniques include, but are not limited to, the following:

landing the wellbore in the desired drilling zone;

staying in the desired drilling zone while drilling horizontally through the formation;

running casing the entire length of the wellbore;

being able to run tools and other equipment consistently through the horizontal wellbore;

the ability to fracture stimulate the planned number of stages;

the ability to run tools the entire length of the wellbore during completion operations; and

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

Any of the above factors could have a material adverse effect on our financial position, results of operations, or cash flows.

Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

We may be subject to information technology system failures, network disruptions, and breaches in data securityand our business, financial position, results of operations, and cash flows could be negatively affected by such security threats and disruptions.

As an oil and gas producer, we face various security threats, including cybersecurity threats such as attempts to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing facilities, pipelines and refineries; and threats from terrorist acts. Cybersecurity attacks are becoming more sophisticated and

include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data, and “ransomware” attacks where data is locked unless a payment is made, any of which could have an adverse effect on our reputation, business, financial condition, results of operations, or cash flows. While we have not suffered any material losses relating to such attacks, there can be no assurance that we will not suffer such losses in the future.

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We rely heavily on our information systems, and the availability and integrity of these systems are essential for us to conduct our business and operations. In addition to cybersecurity and data security threats, other information system failures and network disruptions could have a material adverse effect on our ability to conduct our business. We could experience system failures due to power or telecommunications failures, human error, natural disasters, fire, sabotage, hardware or software malfunction or defects, computer viruses, intentional acts of vandalism or terrorism and similar acts or occurrences. Such system failures could result in the unanticipated disruption of our operations, communications, or processing of transactions, as well as loss of, or damage to, sensitive information, facilities, infrastructure and systems essential to our business and operations, the failure to meet regulatory standards and the reporting of our financial results, and other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position, results of operations, and cash flows.

A cyber attack involving our information systems and related infrastructure, or those of our business associates, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to:

unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

data corruption or operational disruption of production-related infrastructure could result in a loss of production, or accidental discharge;

a cyber attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt our major development projects;

a cyber attack on ~~third party~~third-party gathering, pipeline, or rail transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues; and

a cyber attack on our accounting or accounts payable systems could expose us to liability to employees and third parties if their personal identifying information is obtained.

These events could damage our reputation and lead to financial losses from remedial actions, loss of business, or potential liability, which could have a material adverse effect on our financial condition, results of operations, or cash flows.

While management has taken steps to address these concerns by implementing network security and internal control measures to monitor and mitigate security threats and to increase security for our information, facilities, and infrastructure, our implementation of such procedures and controls may result in increased costs, and there can be no assurance that a system failure or data security breach will not occur and have a material adverse effect on our business, financial condition, and results of operations. In addition, as cybersecurity threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate or remediate any cybersecurity or information technology infrastructure vulnerabilities.

Our limited ability to influence operations and associated costs on non-operated properties could result in economic losses that are partially beyond our control.

For the year ended December 31, ~~2016,~~2019, other companies operated approximately ~~22%~~13% of our net production. Our success in properties operated by others depends upon a number of factors outside of our control. These factors include timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other

participants in drilling wells, selection of technology, and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities.

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Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.

Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures, or cement failures. Other such risks include theft, vandalism, and environmental hazards such as ~~natural~~ gas leaks, oil spills, and discharges of toxic gases. Any of these risks can cause substantial losses resulting from:

injury or loss of life;

damage to, loss of or destruction of, property, natural resources and equipment;

pollution and other environmental damages;

regulatory investigations, civil litigation, and penalties;

damage to our reputation;

suspension of our operations; and

costs related to repair and remediation.

In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease.

We maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operation.

The cost of insurance may increase, and the availability of insurance may decrease, as a result of climate change.

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

At December 31, ~~2016,~~2019, our long-term debt consisted of $750 million of 4.375% senior notes due in 2024, ~~and~~ $750 million of ~~5.875%~~3.90% senior notes due in ~~2022.~~2027, and $500 million of 4.375% senior notes due in 2029. In addition to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, ~~contractual commitments,~~capital expenditures, operating expenses, and ~~capital expenditures.~~

contractual commitments.

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations, and other factors, many of which are beyond our control. Our ability to meet our debt service obligations also may be impacted by changes in prevailing interest rates, as borrowing under our existing revolving credit facility bears interest at floating rates.

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We may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our indebtedness or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include:

reducing or delaying capital expenditures;

seeking additional debt financing or equity capital;

selling assets; or

restructuring or refinancing debt.

We may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations or contractual commitments, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations.

The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.

The indenture governing our senior notes and our credit agreement contain various restrictive covenants that may limit management’s discretion in certain respects. In particular, these agreements limit Cimarex’s and its subsidiaries’ ability to, among other things:

create certain liens;

consolidate, merge, or transfer all, or substantially all, of our assets and our restricted subsidiaries;

· or

enter into sale and leaseback transactions.

In addition, our revolving credit agreement requires us to maintain a total debt to capitalization ratio (as defined in the credit agreement) of not more than 65%. See Note 3 to the Consolidated Financial Statements for further information.

If we fail to comply with the restrictions in the indenture governing our senior notes or the agreement governing our credit facility or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds.

Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations.

The successful acquisition of properties requires an assessment of several factors, including:

geological risks and recoverable reserves;

future oil and gas prices and their appropriate market differentials;

operating costs; and

potential environmental risks and other liabilities.

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The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections will not likely be performed on every well or facility, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Furthermore, the seller may be unwilling or unable, such as in a corporate acquisition such as our acquisition of Resolute, to provide effective contractual protection against all or part of the identified problems.

On March 1, 2019, we completed the acquisition of Resolute. There can be no assurance that we will be able to successfully integrate Resolute’s assets or otherwise realize the expected benefits of the acquisition of Resolute. In addition, our business may be negatively impacted if we are unable to effectively manage our expanded operations going forward. The integration has required and will continue to require significant time and focus from management and could disrupt current plans and operations, which could delay the achievement of our strategic objectives.

For additional risks related to our acquisition of Resolute, see below “Risks Concerning Cimarex’s Merger with Resolute Energy Corporation”.

We may lose leases if production is not established within the time periods specified in the leases.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will ~~expire. If we are not able to renew leases before they~~ expire ~~any proved undeveloped reserves associated with such~~and the amounts spent for those leases will be ~~removed from our proved reserves.~~lost. The combined net acreage expiring in the next three years represents ~~3.5%~~approximately 4.0% of our total net undeveloped acreage at December 31, ~~2016.~~2019. At that date, we had leases representing ~~85,669~~166,227 net acres expiring in ~~2017, 41,981~~2020, 21,226 net acres expiring in ~~2018,~~2021, and ~~68,815~~35,457 net acres expiring in ~~2019.~~2022. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.

We regularly sell ~~non-core~~non-strategic assets in order to increase capital resources available for other ~~core~~strategic assets and to create organizational and operational efficiencies. We also occasionally sell interests in ~~core~~strategic assets for the purpose of accelerating the development of and increasing efficiencies in such ~~core~~strategic assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties, and the availability of purchasers willing to acquire the assets with terms we deem acceptable.

Sellers ~~often~~at times retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liability or ~~of the~~ indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, the company may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

In addition, with respect to offshore assets, if purchasers declare bankruptcy, the United States Department of Interior may pursue former owners for decommissioning expenses, which can be substantial. See Note 8 to the Consolidated Financial Statements for further discussion regarding our asset retirement obligations.

Competition for experienced technical personnel may negatively impact our operations.

Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. As we continue to develop our asset base and the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering, and operations.

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We are involved in various legal proceedings, the outcome of which could have an adverse effect on our liquidity.

In the normal course of business, we ~~have~~are involved with various lawsuits and related disputed claims, including but not limited to claims concerning title, royalty payments, environmental issues, personal injuries, and contractual issues. Although we currently believe the resolution of these lawsuits and claims, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations, our assessment of our current litigation and other legal proceedings could change in light of the discovery of facts with respect to legal actions or other proceedings pending against us not presently known to us or determinations by judges, juries, or other finders of fact that are not in accord with our evaluation of the possible liability or outcome of such proceedings. Therefore, there can be no assurance that outcomes of future legal proceedings would not have an adverse effect on our liquidity and capital resources.

Certain federal income tax deductions currently available with respect to ~~natural~~oil and gas ~~and oil~~ exploration and development may be limited or eliminated as a result of recently enacted or future legislation.

On December 22, 2017, the United States enacted H.R.1, commonly referred to as the Tax Cuts and Jobs Act or U.S. Tax Reform. H.R.1, among other things, includes changes to U.S. federal tax rates, imposes new limitations on the utilization of net operating losses and the deductibility of interest and executive compensation, temporarily allows for the expensing of capital expenditures, and eliminates the corporate Alternative Minimum Tax. Various ~~proposals~~proposed regulations have been issued regarding H.R.1. Until final regulations are issued the full impact of changes to the company is not known at this time. From time to time, various proposals are made recommending the elimination of certain key U.S. federal income tax incentives currently available to oil and ~~natural~~ gas exploration and production companies. ~~Legislation is often~~Future legislation may be introduced in Congress which would implement many of these proposals. These changes include, but are not limited ~~to,~~to: (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to oil and ~~natural~~ gas exploration and development, and any such change could have an adverse effect on our financial ~~position.~~

position, results of operations, and cash flows, including the payment of cash taxes earlier than expected.

Risks Concerning Cimarex’s Merger with Resolute Energy Corporation

Cimarex’s merger with Resolute may not achieve its intended results, and Cimarex and Resolute may be unable to successfully integrate their operations.

Cimarex and Resolute entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, expanding Cimarex’s asset base and creating synergies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Cimarex and Resolute can be integrated in an efficient and effective manner.

The combined company’s results of operations could also be adversely affected by any issues attributable to either company’s operations that arise from or are based on events or actions that occurred prior to the closing of the merger, including unknown liabilities of Resolute or its subsidiaries or liabilities of Resolute or its subsidiaries related to properties sold by Resolute prior to the merger. The integration process is subject to a number of uncertainties, and no assurance can be given whether anticipated benefits will be realized or, if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company’s future business, financial condition, operating results, and prospects.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

~~None.~~

ITEM 3. LEGAL PROCEEDINGS

The information set forth under the heading “Litigation” in Note 10 ~~of the Notes~~ to the Consolidated Financial Statements included in Part II, Item 8 of this ~~Annual Report on~~ Form ~~10-K/A~~10-K, is incorporated by reference in response to this item.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR ~~THE~~ REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our $0.01 par value common stock trades on the New York Stock Exchange ~~(NYSE)~~(“NYSE”) under the symbol XEC. A cash dividend was paid to our common stockholders in each quarter of ~~2016.~~2019. Future dividend payments will depend on the company’s level of earnings, financial requirements, and other factors considered relevant by the Board of Directors.

~~Stock Prices and Dividends by Quarter.~~ ~~The following table sets forth, for the periods indicated, the high and low sales price per share of our common stock on the NYSE and the per share dividends declared during the period.~~

Dividends

Declared Per

2016

High

Low

Share

First Quarter

$
100.07

$
72.77

$
0.08

Second Quarter

$
123.48

$
93.21

$
0.08

Third Quarter

$
136.95

$
112.19

$
0.08

Fourth Quarter

$
146.96

$
118.59

$
0.08

Dividends

Declared Per

2015

High

Low

Share

First Quarter

$
118.87

$
91.74

$
0.16

Second Quarter

$
132.18

$
108.59

$
0.16

Third Quarter

$
118.87

$
97.23

$
0.16

Fourth Quarter

$
124.91

$
85.00

$
0.16

The closing price of Cimarex stock as reported on the NYSE on January 31, ~~2017,~~2020, was ~~$135.21.~~$43.89. At January 31, ~~2017,~~2020, Cimarex’s ~~95,121,492~~102,135,577 shares of outstanding common stock were held by approximately ~~1,393~~1,388 stockholders of record.

Issuer Purchases of Equity Securities

The following table sets forth information ~~with respect to~~regarding repurchases of our common stock during the ~~equity compensation plans available to directors, officers, and employees of the company at~~year ended December 31, ~~2016:~~

(c)

Number of securities

(a)

remaining available

Number of securities

(b)

for future issuance

to be issued upon

Weighted-average

under equity

exercise of

exercise price of

compensation plans

outstanding options,

outstanding options,

(excluding securities

Plan Category

warrants, and rights

warrants, and rights

reflected in column (a))

Equity compensation plans approved by security holders

307,810

$
101.72

3,287,830

Equity compensation plans not approved by security holders

—

—

—

Total

307,810

$
101.72

3,287,830

2019. The shares repurchased represent shares of our common stock that employees elected to surrender to satisfy their tax withholding obligations upon the vesting of shares of restricted stock. Cimarex does not consider this a share buyback program.

Period Total number of shares purchased Average price paid per share Total number of shares purchased as part of publicly announced plans or programs Maximum number of shares that may yet be purchased under the plans or programs
January 1-31, 2019 1,162
$ 70.46
—
—
February 1-28, 2019 —
—
—
—
March 1-31, 2019 8,393
68.16
—
—
April 1-30, 2019 —
—
—
—
May 1-31, 2019 —
—
—
—
June 1-30, 2019 —
—
—
—
July 1-31, 2019 34,607
50.67
—
—
August 1-31, 2019 —
—
—
—
September 1-30, 2019 —
—
—
—
October 1-31, 2019 —
—
—
—
November 1-30, 2019 —
—
—
—
December 1-31, 2019 61,374
45.97
—
—
Total 105,536
$ 49.55
—
—

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Stock Performance Graph

The following graph ~~compares~~shows the cumulative ~~5-year~~five-year total return ~~attained by stockholders~~ on Cimarex Energy Co.’s common stock relative to the cumulative total returns of the S&P 500 index, the Dow Jones US Exploration & Production index, and the S&P Oil & Gas Exploration & Production index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the reinvestment of all dividends) from December 31, ~~2011~~2014 to December 31, ~~2016.~~2019. The stock price performance included in this graph is not necessarily indicative of future stock price performance.

12/2011

12/2012

12/2013

12/2014

12/2015

12/2016

Cimarex Energy Co.

$
100.00

$
93.95

$
171.90

$
174.58

$
148.03

$
225.95

S&P 500

$
100.00

$
116.00

$
153.58

$
174.60

$
177.01

$
198.18

Dow Jones US Exploration & Production

$
100.00

$
105.82

$
139.52

$
124.48

$
94.94

$
118.19

S&P Oil & Gas Exploration & Production

$
100.00

$
103.65

$
132.14

$
118.15

$
77.80

$
103.36

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN*

Among Cimarex Energy Co., the S&P 500 Index,

the Dow Jones US Exploration & Production Index, and the S&P Oil & Gas Exploration & Production Index

* $100 invested on 12/31/14 in stock or index, including reinvestment of dividends. Fiscal year ending December 31.

A tabular presentation of the data in the above graph is provided below.



	2014		2015		2016		2017		2018		2019
Cimarex Energy Co.	$	100.00	$	84.79	$	129.42	$	116.52	$	59.25	$	51.21
S&P 500	$	100.00	$	101.38	$	113.51	$	138.29	$	132.23	$	173.86
Dow Jones US Exploration & Production	$	100.00	$	76.27	$	94.94	$	96.18	$	79.09	$	88.10
S&P Oil & Gas Exploration & Production	$	100.00	$	65.85	$	87.48	$	81.96	$	65.98	$	73.91

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data set forth below should be read in conjunction with the Consolidated Financial Statements and accompanying notes thereto provided in Item 8 of this report.

Years Ended December 31,

2016

2015

2014

2013

2012

(in millions, except per share amounts)

Operating Results:

Oil, gas and NGL sales

$
1,221

$
1,418

$
2,373

$
1,953

$
1,582

Total Revenues (1)

$
1,257

$
1,453

$
2,424

$
1,998

$
1,624

Net income (loss) (2)

$
(409
)
$
(2,580
)
$
526

$
462

$
269

Earnings (loss) per share to common stockholders:

Basic

$
(4.38
)
$
(27.75
)
$
6.01

$
5.30

$
3.10

Diluted

$
(4.38
)
$
(27.75
)
$
6.00

$
5.29

$
3.09

Cash dividends declared per share

$
0.32

$
0.64

$
0.64

$
0.56

$
0.48

Cash flow data:

Net cash provided by operating activities

$
599

$
692

$
1,619

$
1,324

$
1,193

Net cash used by investing activities

$
(692
)
$
(1,009
)
$
(1,740
)
$
(1,531
)
$
(1,415
)
Net cash (used) provided by financing activities

$
(33
)
$
691

$
522

$
142

$
289

December 31,

2016

2015

2014

2013

2012

(in millions, except proved reserves amounts)

Balance sheet data:

Cash and cash equivalents

$
653

$
779

$
406

$
5

$
70

Oil and gas properties, net (2)

$
2,354

$
2,741

$
6,638

$
5,669

$
4,871

Goodwill

$
620

$
620

$
620

$
620

$
620

Total assets (2) (3)

$
4,238

$
4,708

$
8,443

$
6,947

$
6,160

Deferred income tax (asset) liability

$
(56
)
$
157

$
1,657

$
1,351

$
1,072

Long-term obligations

Long-term debt (principal)

$
1,500

$
1,500

$
1,500

$
924

$
750

Other

$
184

$
197

$
194

$
164

$
313

Stockholders’ equity

$
2,043

$
2,458

$
4,332

$
3,834

$
3,390

Proved Reserves:

Oil (MBbls)

105,878

107,798

118,992

108,533

77,921

Gas (Bcf)

1,471

1,517

1,667

1,294

1,252

NGL (MBbls)

130,633

124,277

125,273

92,044

89,909

Total (Bcfe)

2,890

2,909

3,132

2,497

2,259



	Years Ended December 31,
	2019			2018			2017			2016			2015
	(in thousands, except per share amounts)
Operating results:
Oil, gas, and NGL sales	$	2,321,921		$	2,297,645		$	1,874,003		$	1,221,218		$	1,417,538
Total revenues (1)	$	2,362,969		$	2,339,017		$	1,918,249		$	1,257,345		$	1,452,619
Net (loss) income (2)	$	(124,619	)	$	791,851		$	494,329		$	(408,803	)	$	(2,579,604	)

Earnings (loss) per common share:
Basic	$	(1.33	)	$	8.32		$	5.19		$	(4.38	)	$	(27.75	)
Diluted	$	(1.33	)	$	8.32		$	5.19		$	(4.38	)	$	(27.75	)
Cash dividends declared per common share	$	0.80		$	0.68		$	0.32		$	0.32		$	0.64

Cash flow data:
Net cash provided by operating activities	$	1,343,966		$	1,550,994		$	1,096,564		$	625,849		$	725,728
Net cash used by investing activities	$	(1,577,882	)	$	(1,085,618	)	$	(1,265,897	)	$	(692,410	)	$	(1,008,605	)
Net cash (used) provided by financing activities	$	(472,028	)	$	(65,244	)	$	(83,009	)	$	(59,945	)	$	656,397



	December 31,
	2019		2018		2017		2016			2015
	(in thousands, except proved reserves amounts)
Balance sheet data:
Cash and cash equivalents (3)	$	94,722	$	800,666	$	400,534	$	652,876		$	779,382
Oil and gas properties, net (2) (3)	$	5,210,698	$	3,715,330	$	3,241,530	$	2,354,267		$	2,741,282
Goodwill (3)	$	716,865	$	620,232	$	620,232	$	620,232		$	620,232
Total assets (2)	$	7,140,029	$	6,062,084	$	5,042,639	$	4,237,724		$	4,708,422
Deferred income tax liability (asset)	$	338,424	$	334,473	$	101,618	$	(55,835	)	$	157,162
Long-term obligations:
Long-term debt (principal) (4)	$	2,000,000	$	1,500,000	$	1,500,000	$	1,500,000		$	1,500,000
Operating and finance leases (5)	$	202,921	$	—	$	—	$	—		$	—
Other	$	197,056	$	200,564	$	206,249	$	184,444		$	197,216
Redeemable preferred stock (3)	$	81,620	$	—	$	—	$	—		$	—
Stockholders’ equity	$	3,576,141	$	3,329,786	$	2,568,278	$	2,042,989		$	2,458,357

Proved Reserves:
Oil (MBbls)	169,770		146,538		137,238		105,878			107,798
Gas (Bcf)	1,532		1,591		1,608		1,471			1,517
NGL (MBbls)	194,468		179,436		153,860		130,633			124,277
Total (MBOE)	619,595		591,195		559,037		481,748			484,901

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~~(1)~~ Prior to 2014, our average realized prices for gas and NGLs were net of certain processing fees. Beginning in 2014, these fees were no longer netted against realized prices, but were included in “Transportation, processing and other operating” costs. The effect of this change in 2014 was that total revenue was $51.4 million higher with an offsetting increase in total transportation, processing and other operating costs. This change had no effect on operating income. Periods prior to 2014 were not reclassified to reflect this change in accounting treatment as it was impracticable.

~~(2)~~ During 2016, 2015, 2013 and 2012 we recorded non-cash full cost ceiling test impairments to our oil and gas properties totaling $757.7 million ($481.4 million, net of tax), $4.0 billion ($2.6 billion, net of tax), $190.2 million ($120.8 million, net of tax), and $134.1 million ($85.2 million, net of tax), respectively.

(1)

Effective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”), utilizing the modified retrospective approach. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of ASC 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating in the Consolidated Statements of Operations and Comprehensive Income (Loss) under prior accounting standards are now reflected as deductions from revenue.


(2)	During 2019, 2016, and 2015, we recorded non-cash full cost ceiling test impairments of our oil and gas properties totaling $618.7 million, $757.7 million, and $4.03 billion, respectively.

(3)

We acquired Resolute Energy Corporation on March 1, 2019. Consideration for this acquisition included $284.4 million in cash, net of cash acquired, and $81.6 million in redeemable preferred stock. The preliminary purchase price allocation included $1.72 billion to oil and gas properties and $96.6 million to goodwill. See Notes 2 and 13 to the Consolidated Financial Statements for further information regarding the redeemable preferred stock and acquisition.


(4)	On March 8, 2019, we issued $500.0 million aggregate principal amount of 4.375% senior unsecured notes due March 15, 2029 at 99.862% of par to yield 4.392% per annum. See Note 3 to the Consolidated Financial Statements for further information regarding our debt.

(5)

Effective January 1, 2019, we began accounting for leases in accordance with Accounting Standards Update 2016-02, Leases (“Topic 842”), which requires lessees to recognize lease liabilities and right-of-use assets on the balance sheet for contracts that provide lessees with the right to control the use of identified assets for periods of greater than 12 months. Prior to January 1, 2019, we accounted for leases in accordance with ASC Topic 840, Leases, under which operating leases were not recorded on the balance sheet. See Note 10 to the Consolidated Financial Statements for further information regarding our adoption of Topic 842.

~~(3)~~ At December 31, 2015, we adopted new guidance which requires debt issuance costs (except for those related to revolving credit facilities) to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability rather than as an asset. Such costs were previously recorded as deferred assets. Prior periods have been adjusted to conform to this guidance.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in Item 8 of this report and also with ~~“Risk Factors”~~RISK FACTORS in Item 1A of this report. This discussion also includes forward-looking statements. Refer to “~~Cautionary Information about Forward-Looking Statements~~”CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in Part I of this report for important information about these types of statements.

~~As discussed~~ Discussion and analysis regarding 2019 and 2018 is provided below. For discussion and analysis regarding 2017, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in ~~the Explanatory Note in this~~our Annual Report on Form ~~10-K/A and in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K/A, we have corrected our Consolidated Financial Statements and related disclosures~~10-K for the ~~years~~year ended December 31, ~~2016, 2015 and 2014. The following discussion and analysis of our financial condition and results of operations incorporates~~2018 as previously filed with the ~~corrected amounts. No attempt has been made to update other disclosures, except as required to reflect the effects of the corrections.~~

SEC.

OVERVIEW

Cimarex is an independent oil and gas exploration and production company. Our operations are entirely located in the United States, mainly in ~~Oklahoma,~~ Texas, New Mexico, and ~~New Mexico.~~Oklahoma. Currently our operations are focused in two main areas: the Permian Basin and the Mid-Continent. Our Permian Basin region encompasses west Texas and southeast New Mexico. Our Mid-Continent region consists of Oklahoma and the Texas Panhandle.

Our principal business objective is to ~~profitably grow~~increase shareholder value through the profitable long-term growth of our proved reserves and production while seeking to minimize our impact on the communities in which we operate for the ~~long-term benefit of our stockholders through a balanced and abundant drilling inventory.~~long-term. Our strategy centers on maximizing cash flow from producing properties ~~and profitably reinvesting~~so that ~~cash flow~~we can reinvest in exploration and development ~~activities.~~opportunities and provide cash returns to shareholders through dividends. We consider ~~property acquisitions, dispositions~~merger and ~~occasional mergers to~~acquisition opportunities that enhance our competitive ~~position.~~

position and we occasionally divest non-strategic assets.

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this acquisition included: (i) our expectation that Resolute’s assets’ attractive returns are competitive with those in our existing portfolio, (ii) the opportunity to apply our experience and learnings from already operating in this area to generating productivity gains from Resolute’s properties, (iii) the ability to increase our acreage position in the Delaware Basin, and (iv) the expectation that the acquisition will be financially accretive. The acquisition date fair value of the consideration transferred totaled $820.3 million, which consisted of cash, common stock, and preferred stock (see Note 13 to the Consolidated Financial Statements for more information on the acquisition).

We believe that detailed technical analysis, operational focus, and a disciplined capital investment process mitigate risk and position us to continue to achieve profitable increases in proved reserves and production. Our drilling inventory and limited long-term commitments provide the flexibility to respond quickly to industry volatility.

Our investments are generally funded with cash flow provided by operating activities together with cash on hand, bank borrowings, sales of non-strategic assets, and, ~~occasional~~from time to time, public financing based on our monitoring of capital markets and our balance sheet. Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand unpredictable fluctuations in commodity prices.

Market Conditions

The oil and gas industry is cyclical and commodity prices can ~~be volatile. In the second half~~fluctuate significantly. We expect this volatility to persist. Commodity prices are affected by many factors outside of 2014, oil prices began a rapid and significant decline as global oil supplies began to outpace demand. During 2015 and through the first quarter of 2016, global oil supply continued to outpace demand. While oil prices have been, and will likely remain, erratic, beginningour control, including changes in ~~the second quarter of 2016 and thus far in 2017, realized oil prices have improved.~~

~~Due to an imbalance between~~market supply and demand, ~~across North America,~~inventory storage levels, weather conditions, and other factors. Local market prices for ~~domestic natural~~oil and gas can be impacted by pipeline capacity constraints limiting takeaway and ~~NGLs began to decline during the third quarter of 2014 and continued to be weak through the first quarter of 2016. Beginning late~~increasing basis differentials.

As demonstrated in the ~~second quarter of 2016,~~table below, our company-wide average realized prices for ~~natural~~2019 as compared to 2018 have declined for all products. In the case of oil sales, these decreases result from a combination of declining NYMEX prices, partially offset by improving differentials. In the case of gas sales, these decreases are driven by declining NYMEX prices and ~~NGLs strengthened, but continue~~widening differentials.



	Years Ended December 31,						Variance Between 2019 / 2018
	2019			2018			Variance Between 2019 / 2018
Average NYMEX price
Oil — per barrel	$	57.03		$	64.77		(12)%
Gas — per Mcf	$	2.63		$	3.09		(15)%

Average realized price
Oil — per barrel	$	52.77		$	56.61		(7)%
Gas — per Mcf	$	1.11		$	1.99		(44)%
NGL — per barrel	$	13.55		$	22.28		(39)%

Average price differential
Oil — per barrel	$	(4.26	)	$	(8.16	)	48%
Gas — per Mcf	$	(1.52	)	$	(1.10	)	(38)%

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The average price differentials that we realized in our two primary areas of operation are shown in the table below for the periods indicated.



	Average Price Differentials
	Year			Fourth Quarter			Third Quarter			Second Quarter			First Quarter
2019
Oil
Permian Basin	$	(4.48	)	$	(2.18	)	$	(3.76	)	$	(5.80	)	$	(6.90	)
Mid-Continent	$	(3.14	)	$	(2.05	)	$	(3.72	)	$	(4.39	)	$	(2.17	)
Total Company	$	(4.26	)	$	(2.16	)	$	(3.74	)	$	(5.58	)	$	(6.03	)

Gas
Permian Basin	$	(2.14	)	$	(1.67	)	$	(1.83	)	$	(3.10	)	$	(1.91	)
Mid-Continent	$	(0.68	)	$	(0.74	)	$	(0.66	)	$	(0.86	)	$	(0.46	)
Total Company	$	(1.52	)	$	(1.31	)	$	(1.35	)	$	(2.14	)	$	(1.24	)

2018
Oil
Permian Basin	$	(9.82	)	$	(11.64	)	$	(14.34	)	$	(8.05	)	$	(3.12	)
Mid-Continent	$	(2.46	)	$	(2.33	)	$	(1.08	)	$	(2.18	)	$	(2.34	)
Total Company	$	(8.16	)	$	(9.51	)	$	(11.25	)	$	(6.89	)	$	(2.94	)

Gas
Permian Basin	$	(1.40	)	$	(2.21	)	$	(1.25	)	$	(1.31	)	$	(0.78	)
Mid-Continent	$	(0.86	)	$	(0.83	)	$	(0.94	)	$	(1.03	)	$	(0.70	)
Total Company	$	(1.10	)	$	(1.49	)	$	(1.07	)	$	(1.15	)	$	(0.73	)

Pipeline expansion projects in the Permian Basin are expected to ~~fluctuate.~~

ease capacity constraints as they come online over the next few years, which is reflected in the current futures markets that show narrowing differentials. However, if pipeline constraints remain because expansion projects are delayed or canceled, production increases faster than capacity increases, pipeline disruptions, or other reasons, higher differentials will persist or potentially worsen. Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and ~~natural~~ gas ~~production. Compared to 2015, our realized oil price for 2016 fell 12% to $38.30 per barrel. Similarly, our realized~~ ~~price for natural gas dropped 9% to $2.31 per Mcf, while our~~production and can be adversely affected by realized price ~~for NGLs increased 2% to $14.05 per barrel.~~decreases. SeeRESULTS OF OPERATIONS Revenues below for further information regarding our realized commodity prices.

The U.S. oil and gas industry continues to confront weak commodity prices, which has had adverse effects on our business and financial position. Our ability to access capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions. Further, oversupply and high oil and natural gas inventory storage levels could put downward pressure on commodity prices and have an adverse impact on our business partners, customers and lenders, potentially causing them to fail to meet their obligations to us.

~~2016~~

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Summary of Operating and Financial Results

~~Weakness~~ for the year ended December 31, 2019 as compared to the year ended December 31, 2018

Completed the acquisition of Resolute Energy Corporation. Resolute’s results are included in ~~commodity prices has continued~~our financial statements since the March 1, 2019 closing date.

Total daily production volumes increased 25% to ~~have a significant adverse impact on our results of operations, our balance sheet and the amount of cash flow available~~278.5 MBOE per day.

Oil volumes increased 27% to ~~invest in exploration~~86.2 MBbls per day.

Gas volumes increased 22% to 689.2 MMcf per day.

NGL volumes increased 28% to 77.4 MBbls per day.

Total production revenue increased 1% to $2.32 billion.

Year-end proved reserves increased 5% to 619.6 MMBOE, as compared to 591.2 MMBOE at year-end 2018.

Exploration and development ~~activities.~~

~~The following is a summary of certain 2016 operating and financial results:~~

· ~~In response to lower commodity prices, we reduced exploration and development expenditures 16% to $734.8 million~~capital investments were $1.24 billion, as compared to ~~$877.0 million in 2015.~~

· ~~Year-over-year average daily production declined 2% to 963.4 MMcfe per day.~~

· ~~During 2016, oil production declined by 12% to 45,158 barrels per day, gas volumes remained relatively flat at 459.6 MMcf per day and NGL volumes rose 8% to 38,797 barrels per day.~~

· ~~Year-over-year production revenues declined 14% to $1.2 billion.~~

· ~~During 2016, non-cash impairments of our oil and gas properties were $757.7 million, down from $4.0~~$1.57 billion in ~~2015.~~

· ~~In 2016, we incurred a net loss of $408.8 million ($4.38 per diluted share) compared to a net loss of $2.6 billion ($27.75 per diluted share) in 2015.~~

·2018.

Cash flow provided by operating activities decreased 13% to $1.34 billion.

Generated a net loss of ~~$599.2~~$124.6 million ~~was 13% lower than that~~($1.33 per diluted share) as compared to net income of ~~the prior year.~~

· ~~Cash on hand~~$791.9 million ($8.32 per diluted share) in 2018.

Further discussion of these results is provided below.

Proved Reserves

Our proved reserves by region at December 31, ~~2016 was $652.9 million.~~

·2019 and 2018 were as follows:



	December 31, 2019
	Gas (MMcf)	Oil (MBbls)	NGL (MBbls)	Total (MBOE)
Permian Basin	870,208	147,662	130,007	422,703
Mid-Continent	660,161	21,848	64,377	196,252
Other	1,776	260	84	640
Total	1,532,145	169,770	194,468	619,595



	December 31, 2018
	Gas (MMcf)	Oil (MBbls)	NGL (MBbls)	Total (MBOE)
Permian Basin	727,985	116,378	96,533	334,241
Mid-Continent	861,440	29,908	82,826	256,307
Other	1,896	252	77	647
Total	1,591,321	146,538	179,436	591,195

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Year-end 2019 proved reserves ~~were 2.89 Tcfe~~increased approximately 5% to 619.6 MMBOE, compared to ~~2.91 Tcfe~~591.2 MMBOE at year-end ~~2015.~~

~~Total debt at December 31, 2016 consisted of $1.5 billion of senior notes, with $750 million maturing in 2022 and $750 million maturing in 2024, unchanged from total debt at December 31, 2015.~~

2018. Proved ~~Reserves~~

December 31, 2016

Gas

Oil

NGL

Total

(MMcf)

(MBbl)

(MBbl)

(MMcfe)

Permian Basin

372,371

74,295

40,977

1,064,000

Mid-Continent

1,095,194

31,399

89,615

1,821,278

Other

3,855

184

41

5,209

Total

1,471,420

105,878

130,633

2,890,487

December 31, 2015

Gas

Oil

NGL

Total

(MMcf)

(MBbl)

(MBbl)

(MMcfe)

Permian Basin

378,516

78,482

36,598

1,069,002

Mid-Continent

1,134,434

29,048

87,639

1,834,554

Other

4,002

268

40

5,851

Total

1,516,952

107,798

124,277

2,909,407

~~Year-end 2016 proved reserves declined by less than 1% to 2.89 Tcfe, compared to 2.91 Tcfe at year-end 2015. Proved natural~~ gas reserves were ~~1.47~~1.53 Tcf, proved oil reserves were ~~0.64 Tcfe,~~169.8 MMBbls, and proved NGL reserves were ~~0.78 Tcfe.~~194.5 MMBbls. Reserves in ~~our Mid-Continent region~~the Permian Basin accounted for ~~63%~~68% of our total proved reserves with ~~the majority~~nearly all of the remainder in ~~the Permian Basin.~~

~~During 2016, we added 324.0 Bcfe of proved reserves through extensions and discoveries, primarily in the~~our Mid-Continent and Permian Basin, where we added 121.6 Bcfe and 198.7 Bcfe, respectively. In addition, we had net positive revisions of previous estimates of 19.8 Bcfe. Revisions were comprised of an increase of 126.2 Bcfe for net positive performance revisions, an increase of 138.5 Bcfe related to lower operating expenses and a decrease of 244.9 Bcfe for negative revisions due to lower commodity prices.region. See SUPPLEMENTAL INFORMATION ON OIL AND GAS ~~INFORMATION~~PRODUCING ACTIVITIES (UNAUDITED) in Item 8 ~~of this report~~ for a more detailed discussion regarding year-over-year changes in our proved reserves.

The process of estimating quantities of oil, gas, and NGL reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering, and economic data. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. See Proved Reserves Estimation Procedures in Items 1 and 2 ~~of this report~~ for a discussion of our reserve estimation process and Item ~~1A.~~1A RISK FACTORS ~~for~~, which includes a discussion of factors that affect our proved reserves estimates.

RESULTS OF OPERATIONS

Revenues

~~Almost all our~~

Our revenues are derived from sales of our oil, ~~natural~~ gas, and NGL production. Increases or decreases in our ~~revenue,~~revenues, profitability, and future production growth are highly dependent on the commodity prices we receive. Prices are market driven and we expect that future prices will continue to fluctuate due to supply and demand factors, availability of transportation, seasonality, ~~and~~ geopolitical, and economic factors.

~~Oil sales contributed 52%~~ See Item 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for more information regarding the sensitivity of our ~~total~~revenues to price fluctuations.

Production volumes were higher for all products during the year ended December 31, 2019 as compared to the year ended December 31, 2018, while realized prices were lower. Our acquisition of Resolute and ongoing completion of new wells have increased our volumes. Lower market prices, which are out of our control, have negatively impacted our realized prices. The increase in production ~~revenue for 2016. Gas sales accounted for 32%~~volumes, as well as the increase in our fourth quarter 2019 realized oil prices due to narrowing basis differentials, was enough to overcome the lower annual realized prices, particularly gas and NGL ~~sales contributed 16%. A $1.00 per barrel change in~~prices, to cause our ~~realized oil price would have resulted in a $16.5~~overall production revenues to increase by $24.3 million, change in revenues. A $0.10 per Mcf change in our realized gas price would have resulted in a $16.8 million change in our gas revenues. A $1.00 per barrel change in our realized NGL price would have changed revenues by $14.2 million.

or 1%, from prior year. The following table shows our production revenues for 2019 and 2018 as well as the change in revenues due to changes in prices and volumes.



	Years Ended December 31,									Price / Volume Variance
Production Revenue (in thousands)	2019		2018		Variance Between 2019 / 2018					Price			Volume		Total
Oil sales	$	1,660,210	$	1,398,813	$	261,397		19	%	$	(120,819	)	$	382,216	$	261,397
Gas sales	278,776		408,751		(129,975		)	(32	)%	(221,379		)	91,404		(129,975		)
NGL sales	382,935		490,081		(107,146		)	(22	)%	(246,658		)	139,512		(107,146		)
	$	2,321,921	$	2,297,645	$	24,276		1	%	$	(588,856	)	$	613,132	$	24,276

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The table below presents our production volumes by commodity, our average realized commodity prices, and certain major U.S. index prices. ~~Our realized prices do not include settlements~~The sale of ~~commodity derivative contracts.~~

Years Ended December 31,

2016

2015

2014

Oil Prices ($/Bbl):

Average realized sales price

$
38.30

$
43.38

$
83.70

Average WTI Midland price

$
43.34

$
48.39

$
86.18

Average WTI Cushing price

$
43.32

$
48.80

$
93.01

Gas Prices ($/Mcf):

Average realized sales price

$
2.31

$
2.53

$
4.43

Average Henry Hub price

$
2.46

$
2.67

$
4.43

NGL Prices ($/Bbl):

Average realized sales price

$
14.05

$
13.75

$
33.14

our Permian Basin oil production is typically tied to the WTI Midland benchmark price and the sale of our Mid-Continent oil production is typically tied to the WTI Cushing benchmark price. During ~~2016, 2015~~2019 and ~~2014, approximately 80%,~~2018, 84% and ~~80%~~77%, respectively, of our oil production was in the Permian Basin with the ~~sale of which is tied to the WTI Midland benchmark price. The~~ majority of the ~~remaining oil~~remainder in the Mid-Continent region. Our realized prices do not include settlements of commodity derivative contracts.



	Years Ended December 31,						Variance Between 2019 / 2018
	2019			2018			Variance Between 2019 / 2018
Oil
Total volume — MBbls	31,463			24,710			6,753			27	%
Total volume — MBbls per day	86.2			67.7			18.5			27	%
Percentage of total production	31		%	31		%
Average realized price — per barrel	$	52.77		$	56.61		$	(3.84	)	(7	)%
Average WTI Midland price — per barrel	$	55.53		$	58.31		$	(2.78	)	(5	)%
Average WTI Cushing price — per barrel	$	57.03		$	64.77		$	(7.74	)	(12	)%

Gas
Total volume — MMcf	251,567			205,837			45,730			22	%
Total volume — MMcf per day	689.2			563.9			125.3			22	%
Percentage of total production	41		%	42		%
Average realized price — per Mcf	$	1.11		$	1.99		$	(0.88	)	(44	)%
Average Henry Hub price — per Mcf	$	2.63		$	3.09		$	(0.46	)	(15	)%

NGL
Total volume — MBbls	28,254			21,994			6,260			28	%
Total volume — MBbls per day	77.4			60.3			17.1			28	%
Percentage of total production	28		%	27		%
Average realized price — per barrel	$	13.55		$	22.28		$	(8.73	)	(39	)%

Total
Total production — MBOE	101,645			81,010			20,635			25	%
Total production — MBOE per day	278.5			221.9			56.6			25	%
Average realized price — per BOE	$	22.84		$	28.36		$	(5.52	)	(19	)%

Our 2019 daily production volumes were 278.5 MBOE, a 25% increase from 2018. This increase is ~~from our Mid-Continent region,~~ the ~~sale of which is tied to the WTI Cushing benchmark price.~~

~~See~~ ~~RESULTS OF OPERATIONS~~ ~~below for analysis~~result of the ~~impact changes~~Resolute acquisition as well as drilling and completion activity during 2019. See Production Volumes, Prices, and Costs and Exploration and Development Overview in ~~realized~~Items 1 and 2 of this report for production information by region and a discussion of our drilling activities.

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Other Revenues

We transport, process, and market some third-party gas that is associated with our equity gas. We market and sell gas for other working interest owners under short term agreements and may earn a fee for such services. The table below reflects revenues from third-party gas gathering and processing and our net marketing margin for marketing third-party gas.



	Years Ended December 31,					Variance Between 2019 / 2018
Gas Gathering and Marketing Revenues (in thousands):	2019			2018		Variance Between 2019 / 2018
Gas gathering and other	$	42,454		$	41,180	$	1,274
Gas marketing	$	(1,406	)	$	192	$	(1,598	)

Fluctuations in revenues from gas gathering and gas marketing activities are a function of increases and decreases in volumes, commodity prices, ~~had on our year-over-year revenues.~~

and gathering rate charges.

Operating ~~costs~~Costs and ~~expenses~~

Expenses

Costs associated with producing oil and ~~natural~~ gas are substantial. ~~Some~~Among other factors, some of these costs vary with commodity prices, some trend with the ~~type and~~ volume of production, ~~and others~~some are a function of the number of wells we ~~own. At~~own, some depend on the ~~end~~prices charged by service companies, and some fluctuate based on a combination of ~~2016, we owned interests~~the foregoing.

Total operating costs and expenses of $2.48 billion in ~~10,279 gross productive wells.~~

2019 were 92% higher than the $1.29 billion incurred in 2018. The primary reasons for the increase were : (i) the $618.7 million ceiling test impairment incurred in 2019, (ii) the $291.7 million increase in depreciation, depletion, and amortization, and (iii) the $162.8 million increase in losses on derivative instruments. The following table shows our operating costs and expenses for the years indicated and a discussion of year-over-year differences follows.



	Years Ended December 31,					Variance Between 2019 / 2018			Per BOE
Operating Costs and Expenses (in thousands, except per BOE)	2019		2018			Variance Between 2019 / 2018			2019		2018
Impairment of oil and gas properties	$	618,693	$	—		$	618,693		N/A		N/A
Depreciation, depletion, and amortization	882,173		590,473			291,700			$	8.68	$	7.29
Asset retirement obligation	8,586		7,142			1,444			$	0.08	$	0.09
Production (1)	339,941		296,189			43,752			$	3.34	$	3.66
Transportation, processing, and other operating (1)	238,259		211,463			26,796			$	2.34	$	2.61
Gas gathering and other (1)	23,294		28,327			(5,033		)	$	0.23	$	0.35
Taxes other than income	148,953		125,169			23,784			$	1.47	$	1.55
General and administrative	95,843		77,843			18,000			$	0.94	$	0.96
Stock compensation	26,398		22,895			3,503			$	0.26	$	0.28
Loss (gain) on derivative instruments, net	76,850		(85,959		)	162,809			N/A		N/A
Other operating expense, net	19,305		18,507			798			N/A		N/A
	$	2,478,295	$	1,292,049		$	1,186,246

________________________________________

(1)

In order to conform with the 2019 presentation, the 2018 amount presented reflects the reclassification of certain Gas gathering and other expenses to Transportation, processing, and other operating expenses and Production expense. These reclassifications were made to reflect an allocation of the costs incurred to operate our gas gathering facilities as a cost to transport our equity share of gas produced and operate our wells. See Note 1 to the Consolidated Financial Statements for further information regarding these prior year reclassifications.

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Impairment of Oil and Gas Properties

We use the full cost method of accounting for our oil and gas operations. ~~Accounting rules require us~~Under this method, we are required to perform a quarterly ceiling test ~~calculation~~calculations to test our ~~capitalized~~ oil and gas ~~property costs~~properties for possible impairment. If the net capitalized cost of our oil and gas properties, ~~subject to amortization (the carrying value)~~as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum ofof: (i) the present value discounted at 10% of estimated future net ~~cash flows~~revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, ~~and (iv) all related tax effects.~~as adjusted for income taxes. We currently do not have any unproven properties that are being amortized. Estimated future net ~~cash flows~~revenues are determined bybased on trailing twelve-month average commodity prices and estimated proved reserve quantities, ~~and commodity prices net of~~ operating costs, and capital expenditures.

~~We recognized~~

The quarterly ceiling test impairments in each quarter of 2015 totaling $4.0 billion ($2.6 billion, net of tax). In the first three quarters of 2016 we recognized ceiling test impairments totaling $757.7 million ($481.4 million, net of tax). The impairments resultedis primarily ~~from the impact of decreases in the 12-month average trailing prices for oil, natural gas and NGLs utilized in determining the estimated future net cash flows from proved reserves.~~

At December 31, 2016, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. However, a decline of approximately 7% or more in the value of the ceiling limitation would have resulted in an impairment. Because the ceiling calculation uses rolling 12-month averageimpacted by commodity prices, ~~the effect of increases~~changes in estimated reserve quantities, reserves produced, overall exploration and decreases in period-over-period prices can significantly impact the ceiling limitation calculation. In addition, other factors that also impact the ceiling limitation calculation include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operatingdevelopment costs, depletion expense, and ~~all related tax effects.~~

~~There are numerous uncertainties inherent in~~deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the ~~estimation~~other components of ~~proved reserves and accounting for oil and natural gas properties.~~the calculation, we may incur a full cost ceiling test impairment. The calculated ceiling limitation ~~calculation~~ is not intended to be indicative of the fair marketvalue of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income ~~(loss)~~ and various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date.

During 2019, we recognized a ceiling test impairment of $618.7 million. The impairment resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves. It is likely that we will incur another ceiling test impairment in the first quarter 2020 and we may recognize additional ceiling test impairments in the future.

Depreciation, Depletion, ~~depreciation~~ and ~~amortization (DD&A)~~Amortization

Depletion of our ~~proved oil and gas~~producing properties is computed using the

units-of-production method. The economic life of each producing well depends upon the estimated proved reserves for that well, which in turn depend upon the assumed realized sales price for future ~~sales of~~ production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our ~~DD&A rate.~~depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved, and impairments of oil and gas properties will also impact depletion expense. ~~DD&A is calculated quarterly before~~Our net proved properties, production, and reserves have increased during 2019 as compared to 2018 due to our ongoing exploration and development activities as well as due to our acquisition of Resolute. The increase in net properties and production resulted in an overall increase in depletion expense, while the ~~ceiling test impairment calculation. The impairments~~increase in reserves partially offset the increased expense.

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Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from 3 to 30 years. Additionally, with the adoption of Topic 842, we depreciate our right-of-use assets, with the depreciation of our ~~oil~~finance lease gathering system right-of-use asset being included in our depreciation expense. The increase in depreciation expense during 2019 as compared to 2018 is primarily due to: (i) increased depreciation on our gathering and ~~gas properties, discussed above, resulted~~plant facilities due to ongoing expenditures on this infrastructure and (ii) the depreciation on our gathering system right-of-use asset. Depreciation, depletion, and amortization (“DD&A”) consisted of the following for the periods indicated:



	Years Ended December 31,				Variance Between 2019 / 2018		Per BOE
DD&A Expense (in thousands, except per BOE)	2019		2018		Variance Between 2019 / 2018		2019		2018
Depletion	$	817,099	$	538,919	$	278,180	$	8.04	$	6.65
Depreciation	65,074		51,554		13,520		0.64		0.64
	$	882,173	$	590,473	$	291,700	$	8.68	$	7.29

Asset Retirement Obligation

Asset retirement obligation expense is typically primarily comprised of accretion expense. In periods subsequent to the initial measurement of an asset retirement obligation liability at present value, a period-to-period increase in ~~lower DD&A rates~~the carrying amount of the liability is recognized as accretion expense, which represents the effect of the passage of time on the amount of the liability. An equivalent amount is added to the carrying amount of the liability. Also included in ~~each quarter following an impairment.~~

asset retirement obligation expense are gains and losses recognized on the settlement of asset retirement obligation liabilities.

Production

Production expense generally consists of costs for labor, equipment, maintenance, ~~salt water~~saltwater disposal, compression, power, treating, and miscellaneous other ~~costs.~~costs (lease operating expense). Production expense also includes well workover activity necessary to maintain production from existing wells.

Production expense consisted of lease operating expense and workover expense as follows:



	Years Ended December 31,				Variance Between 2019 / 2018		Per BOE
Production Expense (in thousands, except per BOE)	2019		2018		Variance Between 2019 / 2018		2019		2018
Lease operating expense	$	273,092	$	244,861	$	28,231	$	2.68	$	3.03
Workover expense	66,849		51,328		15,521		0.66		0.63
	$	339,941	$	296,189	$	43,752	$	3.34	$	3.66

On an absolute dollar basis, lease operating expense increased 12%, or $28.2 million, in 2019 compared to 2018. The increases have primarily stemmed from the Resolute acquisition and the addition of new wells as a result of our ongoing exploration and development activities. These increases were partially offset by expense reductions related to the sale of non-strategic properties principally located in Ward County, Texas in August 2018. The majority of the increase in lease operating expense is due to increases in water disposal and electricity costs. On a per BOE basis, lease operating expense decreased 12% as a result of our production growing at a faster rate than increases in our lease operating expense.

Workover expense increased 30%, or $15.5 million, during 2019 as compared to 2018. We had an increased number of workover projects contributing to our workover expense during 2019 as compared to 2018. The following types of expenses have been the primary drivers of increased expense in 2019 as compared to 2018: (i) surface equipment maintenance and repair, (ii) lift, which includes changing lift types or repairing/replacing lift equipment, and (iii) major

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well work, which can include replacing tubing, casing repair, cleanouts, and fishing. During 2018, our workover expense was reduced due to receiving approximately $4.0 million in insurance proceeds related to the remediation and repairs incurred as a result of a 2015 flooding event.

Transportation, Processing, and Other Operating

Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, ~~together with gas~~including gathering, fuel, compression, and processing ~~costs and costs to transport production to a specified sales point.~~costs. Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.

If the sales contract transfers control of the product at the wellhead, transportation and processing costs are included as a reduction in the revenue we record and are not included in transportation, processing, and other operating costs. The largest sales contract that we acquired with Resolute is structured this way and sales volumes under legacy Cimarex contracts structured this way have increased, therefore, our transportation and processing costs have not increased commensurate with production volume increases. Transportation, processing, and other operating costs in 2019 were 13%, or $26.8 million, higher than in 2018; however, on a per BOE basis, such costs have decreased 10% to $2.34 in 2019 from $2.61 in 2018.

Gas Gathering and Other

Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs and operating and maintenance expenses. A portion of these costs are reclassified to Transportation, processing, and other expense and Production expense in order to reflect an allocation of the costs incurred to operate our gas gathering facilities as a cost of transporting our equity share of gas produced and operating our wells. Gas gathering and other in 2019 was 18%, or $5.0 million, lower than in 2018. The decrease was primarily due to an increase in compression costs in 2019 offset by a lower amount reclassified to Transportation, processing, and other expense in 2018.

Taxes Other than Income

Taxes other than income consist of production (or severance) taxes, ad valorem taxes, and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production and ad valorem taxes being based on the value of properties.



	Years Ended December 31,						Variance Between 2019 / 2018
Taxes Other than Income (in thousands)	2019			2018			Variance Between 2019 / 2018
Production	$	111,819		$	105,014		$	6,805
Ad valorem	36,291			19,459			16,832
Other	843			696			147
	$	148,953		$	125,169		$	23,784

Taxes other than income as a percentage of production revenue	6.4		%	5.4		%

Taxes other than income increased 19%, or $23.8 million, in 2019 as compared to 2018. Production taxes make up the majority of our taxes other than income and they increased primarily due to: (i) decreased refunds, which are generally for high-cost gas wells in Texas, but also include marketing cost deduction refunds and (ii) increased production volumes. The largest increase in our taxes other than income was due to increased ad valorem taxes primarily as a result of the Resolute acquisition and increased assessed values. Other taxes other than income are comprised of franchise and consumer use and sales taxes.

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General and Administrative

General and administrative ~~expenses consist~~(“G&A”) expense consists primarily of salaries and related benefits, office rent, legal and ~~consultants~~consulting fees, systems costs, and other administrative costs ~~incurred in our offices and not directly associated with exploration, development or production activities.~~incurred. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting.

~~A discussion~~ The amount of ~~changes in operating costs~~expense capitalized varies and ~~expenses is included in~~ ~~RESULTS OF OPERATIONS~~~~, below.~~

~~RESULTS OF OPERATIONS~~

~~2016 compared to 2015~~

~~For~~depends on whether the ~~year ended December 31, 2016, we had a net loss~~cost incurred can be directly identified with acquisition, exploration, and development activities. The percentage of ~~$408.8 million ($4.38 per diluted share), down from a net loss of $2.6 billion ($27.75 per diluted share) in 2015. Production revenues in 2016~~gross G&A capitalized was 44% and ~~2015 were adversely affected by low realized commodity prices, which also brought about impairments of our oil~~48% during 2019 and gas properties and net losses for each year. Although production revenue in 2016 was lower than 2015, the decrease was more than offset by lower impairment, DD&A and other operating costs in 2016. Year-over-year changes are discussed further in the analysis that follows.

Percent

Years Ended

Change

December 31,

Between

Price / Volume Change

Production Revenue

2016

2015

2016 / 2015

Price

Volume

Total

(in thousands or as indicated)

Oil sales

$
632,934

$
809,664

(22
)%
$
(83,962
)
$
(92,768
)
$
(176,730
)
Gas sales

388,786

428,227

(9
)%
(37,010
)
(2,431
)
(39,441
)
NGL sales

199,498

179,647

11
%
4,260

15,591

19,851

Total production revenue

$
1,221,218

$
1,417,538

(14
)%
$
(116,712
)
$
(79,608
)
$
(196,320
)
Total oil volume — MBbls

16,528

18,663

(11
)%

Oil volume — barrels per day

45,158

51,132

(12
)%

Oil percentage of total production

28
%
31
%

Average oil price — per barrel

$
38.30

$
43.38

(12
)%

Total gas volume — MMcf

168,227

168,987

0
%

Gas volume — MMcf per day

459.6

463.0

(1
)%

Gas percentage of total production

48
%
47
%

Average gas price — per Mcf

$
2.31

$
2.53

(9
)%

Total NGL volume — MBbls

14,200

13,063

9
%

NGL volume — barrels per day

38,797

35,789

8
%

NGL percentage of total production

24
%
22
%

Average NGL price — per barrel

$
14.05

$
13.75

2
%

Total production — MMcfe

352,591

359,343

(2
)%

Total production — MMcfe per day

963.4

984.5

(2
)%

As reflected in the table above, our 2016 production revenue was 14% lower than that of 2015. Lower realized prices and production volumes for oil and gas were only partially offset by higher average realized prices and production volumes for NGLs.

Our 2016 aggregate production volumes were 352.6 Bcfe, a 2% decrease from 2015. Production volumes in 2016 were comprised of 48% natural gas, 28% oil and 24% NGL. In 2015, aggregate production volumes of 359.3 Bcfe were made up of 47% natural gas, 31% oil and 22% NGL. See ~~Production Volumes, Prices, and Costs~~ ~~and~~ ~~Exploration and Development Overview~~ ~~in Items 1 and 2 of this report for production information by region and a discussion of our drilling activities. See~~ ~~Revenues~~ ~~above, for information regarding realized prices.~~

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~~Other revenues~~

~~We sometimes transport, process and market third-party gas that is associated with our equity gas.~~2018, respectively. The table below ~~reflects income from third-party gas gathering and processing and~~shows our net marketing margin (revenues less purchases) for marketing third-party gas. We market and sell natural gas for working interest owners under short term sales and supply agreements and may earn a fee for such services.

Years Ended December 31,

2016

2015

Gas Gathering and Marketing (in thousands):

Gas gathering and other revenues

$
36,033

$
34,688

Gas marketing revenues, net of related costs

$
94

$
393

~~Fluctuations in revenues from gas gathering and gas marketing activities are a function of increases and decreases in volumes, commodity prices and gathering rate charges.~~

~~Analysis of operating costs and expenses~~

Total operating costs and expenses of $1.8 billion in 2016 were 67% lower than $5.5 billion incurred in 2015. Most of the decrease resulted from lower ceiling test impairments of our oil and gas properties and lower DDG&A ~~expense. See~~ ~~Operating costs and expenses~~ ~~above for a discussion of the ceiling limitation and DD&A calculations. Analyses of year-over-year differences are discussed below.~~

Variance

Years Ended December 31,

Between

Per Mcfe

Operating Costs and Expenses

2016

2015

2016 / 2015

2016

2015

(in thousands)

Impairment of oil and gas properties

$
757,670

$
4,033,295

$
(3,275,625
)
N/A

N/A

DD&A

392,348

731,460

(339,112
)
$
1.11

$
2.04

Asset retirement obligation

7,828

9,121

(1,293
)
$
0.02

$
0.03

Production

232,002

299,374

(67,372
)
$
0.66

$
0.83

Transportation, processing and other operating

190,725

182,362

8,363

$
0.54

$
0.51

Gas gathering and other

31,785

38,138

(6,353
)
$
0.09

$
0.11

Taxes other than income

61,946

84,764

(22,818
)
$
0.18

$
0.24

General and administrative

73,901

74,688

(787
)
$
0.21

$
0.21

Stock compensation

24,523

19,559

4,964

$
0.07

$
0.05

(Gain) loss on derivative instruments, net

55,749

(11,246
)
66,995

N/A

N/A

Other operating (income) expense, net

755

856

(101
)
N/A

N/A

$
1,829,232

$
5,462,371

$
(3,633,139
)

DDcosts.



	Years Ended December 31,						Variance Between 2019 / 2018
General and Administrative Expense (in thousands):	2019			2018			Variance Between 2019 / 2018
Gross G&A	$	170,757		$	149,820		$	20,937
Less amounts capitalized to oil and gas properties	(74,914		)	(71,977		)	(2,937		)
G&A expense	$	95,843		$	77,843		$	18,000

G&A expense increased 23%, or $18.0 million, in ~~2016 decreased 46%~~2019 as compared to ~~2015. The impairments~~2018 primarily due to increased employee-related costs such as salaries and wages, other compensation, and benefits. Included in 2019 was $3.1 million of ~~our oil~~severance expense related to former Resolute employees who performed transition work at Cimarex and ~~gas properties discussed above resulted in lower DD&A rates in each quarter following an impairment. DD&A is calculated quarterly before~~were subsequently terminated. During the ~~ceiling test impairment calculation. We did not incur a ceiling test impairment in the fourth~~first quarter of ~~2016. Our 2017 DD&A rate will likely fluctuate depending on the per-unit cost of adding new proved reserves and the average trailing twelve-month commodity prices~~2020, we accepted volunteers to ~~be utilized~~participate in ~~the DD&A calculations.~~

~~Production costs consist of lease operating expense and workover expense as follows:~~

Variance

Years Ended December 31,

Between

Per Mcfe

(in thousands)

2016

2015

2016 / 2015

2016

2015

Lease operating expense

$
189,291

$
249,744

$
(60,453
)
$
0.54

$
0.70

Workover expense

42,711

49,630

(6,919
)
0.12

0.13

$
232,002

$
299,374

$
(67,372
)
$
0.66

$
0.83

Lease operating expense in 2016 declined 24% compared to 2015. In 2016, we incurred lower salt water disposal costs due to implementation of operational efficiencies as well as lower costs associated with labor, rental equipment and property divestitures.

~~Workover expense decreased by 14% in 2016 compared to 2015. Generally, these costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.~~

~~Our 2016 year-over-year transportation, processing and other operating costs were 5% higher than those of 2015. These costs will vary by product type and region. The increase in 2016 is primarily~~an early retirement incentive program. As a result of ~~more gas production and higher fees associated with our Mid-Continent region.~~

Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs, operating and maintenance expenses. The 17% year-over-year decrease is primarily attributablethis program, we expect to ~~higher repair and maintenance activities occurring~~incur an aggregate of approximately $10.5 million in ~~2015.~~

~~Taxes other than income~~severance expense over the course of 2020 into early 2021. Going forward, these departures are assessed by state and local taxing authorities on production, revenues or the value of properties. Revenue based production and severance taxes are the largest components of these taxes. The 27% decreaseexpected to result in ~~2016 taxes is a result of~~ lower ~~production revenues due to lower realized commodity prices and lower production volumes.~~

~~General and administrative (G&A) costs were as follows:~~

Variance

Years Ended December 31,

Between

(in thousands)

2016

2015

2016 / 2015

G&A capitalized to oil and gas properties

$
72,531

$
58,332

$
14,199

G&A expense

73,901

74,688

(787
)

$
146,432

$
133,020

$
13,412

~~During 2016, aggregate~~employee-related G&A increased 10% compared to 2015. The year-over-year increase in aggregate G&A results from a combination of higher accruals in 2016 for short-term incentive based compensation together with severance payments in connection with a voluntary early retirement incentive program, which were partially offset by lower salaries and wages and lower corporate contributions and consulting fees.

costs.

Stock Compensation

Stock compensation expense consists of non-cash charges resulting from the amortization of the cost of restricted stock and stock option awards, net of amounts capitalized to oil and gas properties. We have recognized stock-based compensation cost as follows:

Variance

Years Ended December 31,

Between

(in thousands)

2016

2015

2016 / 2015

Restricted stock awards

Performance stock awards

$
24,183

$
18,991

$
5,192

Service-based stock awards

18,391

14,547

3,844

42,574

33,538

9,036

Stock option awards

2,565

2,803

(238
)

45,139

36,341

8,798

Less amounts capitalized

(20,616
)
(16,782
)
(3,834
)
Stock compensation

$
24,523

$
19,559

$
4,964

~~Expense associated with~~



	Years Ended December 31,						Variance Between 2019 / 2018
Stock Compensation Expense (in thousands):	2019			2018			Variance Between 2019 / 2018
Restricted stock awards:
Performance stock awards	$	21,590		$	23,083		$	(1,493	)
Service-based stock awards	25,611			20,385			5,226
	47,201			43,468			3,733
Stock option awards	1,903			2,456			(553		)
Total stock compensation cost	49,104			45,924			3,180
Less amounts capitalized to oil and gas properties	(22,706		)	(23,029		)	323
Stock compensation expense	$	26,398		$	22,895		$	3,503

Periodic stock compensation expense will fluctuate based on the ~~grant-date~~grant date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards. The increase in ~~2016~~total stock compensation cost in 2019 as compared to 2018 is primarily ~~related~~due to performance stock award forfeitures that occurred during 2018 as well as due to expense on awards granted during the periods more than offsetting the expense on awards that vested during the periods. Our accounting policy is to account for forfeitures in ~~December 2015, a portion of which were amortized during 2016, forfeiture rate adjustments~~compensation cost when they occur, therefore, all the previously recognized expense on the forfeited award is reversed at the time of forfeiture. During the first quarter of 2020, we accepted volunteers to participate in an early retirement incentive

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program, which includes the cash settlement of certain service-based stock awards and ~~acceleration~~accelerated vesting of ~~expense on a portion of service-based awards for employees who participated in a voluntary early retirement incentive program. Historical amounts may not be representative of future amounts as~~certain stock option awards. At this time, the ~~value of future awards may vary from historical amounts. See Note 6 to the Consolidated Financial Statements in Item 8~~effect of this ~~report for further discussion regarding our stock-based compensation.~~

program on future stock compensation expense is not determinable.

Loss (Gain) on Derivative Instruments, Net

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly ~~settlement~~cash settlements (if any) of the instruments. We have ~~chosen~~elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. ~~Therefore,~~Consequently, changes in the fair value of our derivative instruments and cash settlements on the ~~contracts~~instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments.

Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the ~~aggregate net~~components of Loss (gain) ~~loss from settlements and changes in the fair value of our derivative contracts and the (gains) losses from cash settlements included in the aggregate gain (loss)~~ on derivative instruments, ~~net.~~net for the years indicated. See Note 4 to the Consolidated Financial Statements ~~in Item 8 of this report~~ for ~~further details~~additional information regarding our derivative instruments.

Years Ended December 31,

(in thousands)

2016

2015

(Gain) loss on derivative instruments, net

$
55,749

$
(11,246
)
Settlement (gains) losses

$
(7,437
)
$
—

Years Ended December 31,
Variance
Between
2019 / 2018
Loss (Gain) on Derivative Instruments, Net (in thousands):
2019 2018
Decrease (increase) in fair value of derivative instruments, net:

Gas contracts $ (13,114 ) $ 15,742
$ (28,856 )
Oil contracts 76,833
(126,130 ) 202,963
63,719
(110,388 ) 174,107
Cash payments (receipts) on derivative instruments, net:

Gas contracts (40,114 ) (13,794 ) (26,320 )
Oil contracts 53,245
38,223
15,022
13,131
24,429
(11,298 )
Loss (gain) on derivative instruments, net $ 76,850
$ (85,959 ) $ 162,809

Other ~~(income)~~Operating Expense, Net

Other operating expense, net increased $0.8 million in 2019 as compared to 2018. This expense is comprised primarily of litigation settlements, acquisition-related costs, and allowance for doubtful accounts adjustments. Other operating expense,

Variance

Years Ended December 31,

Between

(in thousands)

2016

2015

2016 / 2015

Interest expense

$
83,272

$
85,746

$
(2,474
)
Capitalized interest

(21,248
)
(30,589
)
9,341

Other, net

(10,707
)
(13,576
)
2,869

$
51,317

$
41,581

$
9,736

net in 2019 and 2018 included $10.0 million and $14.9 million, respectively in litigation settlements. Other operating expense, net in 2019 and 2018 included $8.4 million and $3.0 million, respectively, in acquisition-related costs incurred to effect the Resolute acquisition. The acquisition-related costs consisted primarily of advisory and legal fees.

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Other Income and Expense



	Years Ended December 31,						Variance Between 2019 / 2018
Other Income and Expense (in thousands):	2019			2018			Variance Between 2019 / 2018
Interest expense	$	93,386		$	68,224		$	25,162
Capitalized interest	(56,232		)	(20,855		)	(35,377		)
Loss on early extinguishment of debt	4,250			—			4,250
Other, net	(5,741		)	(22,908		)	17,167
	$	35,663		$	24,461		$	11,202

The majority of our interest expense relates to interest on ~~debt and~~our senior unsecured notes. Also included in interest expense is interest expense on our Credit Facility borrowings, the amortization of ~~financing costs.~~debt issuance costs and discounts, and miscellaneous interest expense. See LIQUIDITY AND CAPITAL RESOURCES Long-Term Debt below for further information regarding our debt.

The increase in interest expense in 2019 as compared to 2018 is primarily due to (i) the March 8, 2019 issuance of $500 million aggregate principal amount of 4.375% senior unsecured notes due March 15, 2029 at 99.862% of par to yield 4.392% per annum, (ii) borrowings on our Credit Facility in 2019 to help fund the Resolute acquisition and thereafter to meet cash requirements as needed (we did not borrow on our Credit Facility in 2018), (iii) miscellaneous interest expense (primarily interest on revenues released from suspense), and (iv) interest expense on our finance lease. The $4.3 million loss on early extinguishment of debt incurred during 2019 was associated with the $600 million of 8.5% senior notes we acquired with Resolute and elected to immediately repay. The maturity date of the Resolute notes was May 1, 2020.

We capitalize interest on ~~the capitalized cost of unproved properties,~~non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing ~~qualified~~midstream assets. Capitalized interest will fluctuate based primarily on ~~our current rate of~~

~~interest and~~ the amount of costs subject to interest capitalization and based on ~~which~~the rates applicable to borrowings outstanding during the period. The amount of costs subject to interest ~~is calculated.~~capitalization was higher in 2019 as compared to 2018, primarily due to the Resolute acquisition. Included in the preliminary purchase price allocation of the Resolute acquisition was non-producing leasehold costs of $1.02 billion.

Other, net includes interest income of $3.3 million and $11.1 million in 2019 and 2018, respectively. The ~~31%~~ decrease in ~~year-over-year capitalized expense resulted from lower average unproved property costs~~interest income in ~~2016.~~

~~Components~~2019 is primarily due to the cash expended for the Resolute acquisition, which included $325.7 million in cash consideration and the repayment of ~~“Other, net” consist~~$870.0 million in principal amount of Resolute’s long-term debt existing at the acquisition date. This decreased our investable cash balance post-acquisition, thus lowering our interest income. Other components of Other, net include miscellaneous income and expense items that ~~will~~ vary from period to period, including gain or loss onrelated to the sale or value of oil and gas well equipment and supplies, gain or loss on miscellaneous fixed asset sales, and income and expense associated with other non-operating ~~activities, miscellaneous asset sales and interest income. The 21% decrease in 2016 income was primarily due to lower net gains on transactions related to oil and gas well equipment and supplies.~~

activities.

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Income ~~tax expense~~

Tax (Benefit) Expense

The components of our provision for income taxes ~~are~~and our combined federal and state effective income tax rates were as follows:

Years Ended December 31,

(in thousands)

2016

2015

Current tax (benefit) expense

$
(1,115
)
$
14,710

Deferred tax benefit

(213,286
)
(1,486,439
)

$
(214,401
)
$
(1,471,729
)
Combined federal and state effective income tax rate

34.4
%
36.3
%



	Years Ended December 31,						Variance Between 2019 / 2018
Income Tax (Benefit) Expense (in thousands):	2019			2018			Variance Between 2019 / 2018
Current tax expense (benefit)	$	532		$	(2,624	)	$	3,156
Deferred tax (benefit) expense	(26,902		)	233,280			(260,182		)
	$	(26,370	)	$	230,656		$	(257,026	)

Combined federal and state effective income tax rate	17.5		%	22.6		%

Our combined federal and state effective tax rates, as shown above, differ from the statutory rate ~~of 35%~~ primarily due to state income taxes and non-deductible ~~expenses and revisions.~~expenses. See Note 9 to the Consolidated Financial Statements ~~in Item 8 of this report~~ for further information regarding our income taxes.

~~RESULTS OF OPERATIONS~~

~~2015 compared to 2014~~

For the year ended December 31, 2015, we had a net loss of $2.6 billion ($27.75 per diluted share), compared to net income of $526.5 million ($6.00 per diluted share) for 2014. The net loss in 2015 was primarily a result of lower realized commodity prices, which also brought about impairments of our oil and gas properties. Year-over-year changes are discussed further in the analysis that follows.

Percent

Years Ended

Change

December 31,

Between

Price / Volume Change

Production Revenue

2015

2014

2015 / 2014

Price

Volume

Total

(in thousands or as indicated)

Oil sales

$
809,664

$
1,308,958

(38
)%
$
(752,492
)
$
253,198

$
(499,294
)
Gas sales

428,227

687,930

(38
)%
(321,075
)
61,372

(259,703
)
NGL sales

179,647

375,941

(52
)%
(253,292
)
56,998

(196,294
)
Total production revenue

$
1,417,538

$
2,372,829

(40
)%
$
(1,326,859
)
$
371,568

$
(955,291
)
Total oil volume — MBbls

18,663

15,639

19
%

Oil volume — barrels per day

51,132

42,846

19
%

Oil percentage of total production

31
%
30
%

Average oil price — per barrel

$
43.38

$
83.70

(48
)%

Total gas volume — MMcf

168,987

155,128

9
%

Gas volume — MMcf per day

463.0

425.0

9
%

Gas percentage of total production

47
%
49
%

Average gas price — per Mcf

$
2.53

$
4.43

(43
)%

Total NGL volume — MBbls

13,063

11,343

15
%

NGL volume — barrels per day

35,789

31,078

15
%

NGL percentage of total production

22
%
21
%

Average NGL price — per barrel

$
13.75

$
33.14

(59
)%

Total production — MMcfe

359,343

317,022

13
%

Total production — MMcfe per day

984.5

868.6

13
%

As reflected in the table above, our 2015 production revenue was 40% lower than that of 2014. Increased revenues from higher production volumes were more than offset by decreased revenues from lower realized commodity prices. The 13% year-over-year growth in production volumes was primarily due to our successful drilling programs in the Permian Basin and Mid-Continent region. See ~~Production Volumes, Prices, and Costs~~ ~~and~~ ~~Exploration and Development Overview~~ ~~in Items 1 and 2 of this report for further information and a discussion of 2015 activity in these regions. See~~ ~~Revenues~~ ~~above, for information regarding realized prices.~~

Our 2015 aggregate production volumes were 359.3 Bcfe, comprised of 47% natural gas, 31% oil and 22% NGL. This compares to 2014 aggregate production volumes of 317.0 Bcfe, made up of 49% natural gas, 30% oil and 21% NGL.

~~Table of Contents~~

~~Other revenues~~

We sometimes transport, process and market third-party gas that is associated with our equity gas. The table below reflects income from third-party gas gathering and processing and our net marketing margin (revenues less purchases) for marketing third-party gas. We market and sell natural gas for working interest owners under short term sales and supply agreements and may earn a fee for such services.

Years Ended December 31,

Gas Gathering and Marketing (in thousands):

2015

2014

Gas gathering and other revenues

$
34,688

$
49,602

Gas marketing revenues, net of related costs

$
393

$
1,745

Fluctuations in revenues from gas gathering and marketing activities are a function of increases and decreases in volumes and prices associated with third party gas. In 2015, revenue from gas gathering declined by $14.9 million (30%), primarily due to lower realized prices which were partially offset by increased volumes.

~~Total operating costs and expenses in 2015 were $5.46 billion compared to $1.58 billion for the prior year. As discussed above in~~ ~~Operating costs and expenses~~, during 2015 our quarterly ceiling limitation calculations resulted in impairments totaling $4.0 billion. Excluding the effect of the impairments, our year-over-year operating costs and expenses decreased by $150.7 million. Analyses of the year-over-year differences are discussed below.

Variance

Years Ended December 31,

Between

Per Mcfe

Operating Costs and Expenses

2015

2014

2015 / 2014

2015

2014

(in thousands)

Impairment of oil and gas properties

$
4,033,295

$
—

$
4,033,295

N/A

N/A

DD&A

731,460

775,577

(44,117
)
$
2.04

$
2.45

Asset retirement obligation

9,121

10,082

(961
)
$
0.03

$
0.03

Production

299,374

342,304

(42,930
)
$
0.83

$
1.08

Transportation, processing and other operating

182,362

195,414

(13,052
)
$
0.51

$
0.62

Gas gathering and other

38,138

35,113

3,025

$
0.11

$
0.11

Taxes other than income

84,764

128,793

(44,029
)
$
0.24

$
0.41

General and administrative

74,688

81,160

(6,472
)
$
0.21

$
0.26

Stock compensation

19,559

15,001

4,558

$
0.05

$
0.05

(Gain) loss on derivative instruments, net

(11,246
)
(3,762
)
(7,484
)
N/A

N/A

Other operating (income) expense, net

856

116

740

N/A

N/A

$
5,462,371

$
1,579,798

$
3,882,573

DD&A expense in 2015 decreased 6% compared to 2014. Increased expense due to higher 2015 production volumes was more than offset by lower DD&A rates in 2015. The impairments of our oil and gas properties, discussed above, resulted in lower DD&A rates in each quarter following an impairment. DD&A is calculated quarterly before the ceiling test impairment calculation.

Our year-over-year production costs decreased by 13% and accounted for 32% of the aggregate decrease in operating costs and expenses, excluding impairments. Production costs consist of lease operating expense and workover expense as follows:

Variance

Years Ended December 31,

Between

Per Mcfe

(in thousands)

2015

2014

2015 / 2014

2015

2014

Lease operating expense

$
249,744

$
276,395

$
(26,651
)
$
0.70

$
0.87

Workover expense

49,630

65,909

(16,279
)
0.13

0.21

$
299,374

$
342,304

$
(42,930
)
$
0.83

$
1.08

Lease operating expense in 2015 declined 10% compared to 2014. The decline was primarily a result of property divestitures, lower salt water disposal costs and decreased equipment and maintenance costs. These decreases were partially offset by increased expense related to new wells acquired and drilled. Increased production volumes in 2015 also contributed to the lower rate per Mcfe in 2015.

~~Workover expense decreased by 25% in 2015 compared to 2014. Generally, these costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.~~

Our 2015 year-over-year transportation, processing and other operating costs were 7% lower than those in 2014. These costs will vary by product type and region. In 2015, lower prices for natural gas and NGLs resulted in lower costs associated with fuel and processing fees, which were partially offset by higher processing volumes. Approximately 5% of the 2015 costs relates to accruals for expected minimum volume agreement shortfalls due to reduced drilling activity in 2015 and projected at the time for 2016.

Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs, operating and maintenance expenses. The year-over-year increase is due primarily to higher overall costs related to increased activity, which were largely offset by lower costs associated with product purchases.

Taxes other than income are assessed by state and local taxing authorities on production, revenues or the value of properties. Revenue based production and severance taxes comprised approximately 81% and 85% of these taxes for 2015 and 2014, respectively. The 34% decrease in 2015 taxes resulted primarily from lower production revenues due to lower realized commodity prices and accounted for 33% of the aggregate decrease in operating costs and expenses, excluding impairments.

~~General and administrative (G&A) costs were as follows:~~

Variance

Years Ended December 31,

Between

(in thousands)

2015

2014

2015 / 2014

G&A capitalized to oil and gas properties

$
58,332

$
76,636

$
(18,304
)
G&A expense

74,688

81,160

(6,472
)

$
133,020

$
157,796

$
(24,776
)

During 2015, aggregate G&A declined 16% compared to 2014. Because of the adverse effect of lower commodity prices on our financial results, we reduced our expectations and accruals for short-term incentive-based cash compensation and benefits.

Variance

Years Ended December 31,

Between

(in thousands)

2015

2014

2015 / 2014

Restricted stock awards

Performance stock awards

$
18,991

$
12,141

$
6,850

Service-based stock awards

14,547

13,607

940

33,538

25,748

7,790

Stock option awards

2,803

3,057

(254
)

36,341

28,805

7,536

Less amounts capitalized

(16,782
)
(13,804
)
(2,978
)
Stock compensation

$
19,559

$
15,001

$
4,558

Expense associated with stock compensation will fluctuate based on the grant-date fair value of awards, the number of awards and the timing of the awards. The increase in 2015 stock compensation is primarily related to performance awards granted in December 2014, a portion of which were amortized during 2015. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. See Note 6 to the Consolidated Financial Statements in Item 8 of this report for further discussion regarding our stock-based compensation.

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity prices and the monthly settlement (if any) of the instruments. We have chosen not to apply hedge accounting treatment to our derivative instruments. As a result, settlements on the contracts are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments.

The following table presents the aggregate net (gain) loss from settlements and changes in the fair value of our derivative contracts and the (gains) losses from cash settlements included in the aggregate gain (loss) on derivative instruments, net. See Note 4 to the Consolidated Financial Statements in Item 8 of this report for further details regarding our derivative instruments.

Years Ended December 31,

(in thousands)

2015

2014

(Gain) loss on derivative instruments, net

$
(11,246
)
$
(3,762
)
Settlement (gains) losses

$
—

$
(7,641
)

~~Other (income) and expense~~

Variance

Years Ended December 31,

Between

(in thousands)

2015

2014

2015 / 2014

Interest expense

$
85,746

$
72,865

$
12,881

Capitalized interest

(30,589
)
(35,925
)
5,336

Other, net

(13,576
)
(28,907
)
15,331

$
41,581

$
8,033

$
33,548

The majority of our interest expense relates to interest on debt and amortization of financing costs. The 18% year-over-year increase is primarily due to the issuance of $750 million of senior notes in June of 2014. See ~~Long-Term Debt~~ ~~below for further information regarding our debt.~~

We capitalize interest on the capitalized cost of unproved properties, the in-progress costs of drilling and completing wells and constructing qualified assets. Capitalized interest will fluctuate based on our current rate of interest and the amount of costs on which interest is calculated.

Components of “other, net” consist of miscellaneous income and expense items that will vary from period to period, including gain or loss on the sale or value of oil and gas well equipment and supplies, income and expense associated with other non-operating activities, miscellaneous asset sales and interest income. Most of the 53% year-over-year decrease in income was due to lower net gains on transactions related to oil and gas well equipment and supplies and lower gains from sales of fixed assets.

~~Income tax expense~~

~~The components of our provision for income taxes are as follows:~~

Years Ended December 31,

(in thousands)

2015

2014

Current tax expense (benefit)

$
14,710

$
404

Deferred tax expense

(1,486,439
)
309,443

$
(1,471,729
)
$
309,847

Combined federal and state effective income tax rate

36.3
%
37.1
%

Our combined federal and state effective tax rates differ from the statutory rate of 35% primarily due to state income taxes, non-deductible expenses and revisions. See Note 9 to the Consolidated Financial Statements in Item 8 of this report for further information regarding our income taxes.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We strive to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include our cash flow from operations, cash on hand, available borrowing capacity under our revolving credit facility, proceeds from sales of ~~non-core~~non-strategic assets, and, ~~occasional~~from time to time, public financings based on our monitoring of capital markets and our balance sheet.

Our liquidity is highly dependent on prices we receive for the oil, ~~natural~~ gas, and NGLs we produce. Prices we receive are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital, and future rate of growth. See ~~Market Conditions,~~ ~~Revenues~~ ~~and~~ RESULTS OF OPERATIONS Revenuesabove for further information ~~and analysis of~~regarding the impact realized prices have had on our ~~2016~~2019 earnings.

We ~~deal with~~address volatility in commodity prices primarily by maintaining flexibility in our capital investment program. We have a balanced and abundant drilling inventory and limited long-term commitments, which enables us to respond quickly to industry volatility. Based on current economic conditions, our ~~2017 exploration and development~~2020 total capital expenditures are projected to range from ~~$1.1 — $1.2~~$1.25 billion to $1.35 billion. ~~Investments in gathering and processing infrastructure and other fixed assets are expected to approximate an additional $60 million.~~ See Capital Expenditures below for information regarding our ~~2016 exploration~~2019 capital expenditures and ~~development (E&D) activities.~~

our projected 2020 expenditures.

We periodically use derivative instruments to mitigate volatility in commodity prices. At December 31, ~~2016,~~2019, we had derivative contracts covering a portion of our ~~2017~~2020 and ~~2018~~2021 production. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may ~~hedge up to 50% of~~increase or decrease our ~~oil and natural gas production on a forward five-quarter basis.~~derivative positions from current levels. See Note 4 to the Consolidated Financial Statements ~~in Item 8 of this report~~ for information regarding our derivative instruments.

~~We believe our conservative use of leverage, strong balance sheet and hedging activities will mitigate our exposure to lower prices.~~

Cash and cash equivalents at December 31, ~~2016~~2019 were ~~$652.9~~$94.7 million. ~~Our~~At December 31, 2019, our long-term debt consisted of ~~$1.5~~$2.00 billion of senior unsecured notes, with $750 million 4.375% notes due in ~~2022 and~~2024, $750 million 3.90% notes due in ~~2024. We~~2027, and $500 million 4.375% due in 2029. At December 31, 2019, we had no borrowings and $2.5 million in letters of credit outstanding under our credit facility, ~~of $2.5 million,~~ leaving an unused borrowing availability of ~~$997.5 million.~~

$1.248 billion. See Long-Term Debt below for more information regarding our debt.

Table of Contents

Our debt to total capitalization ratio at December 31, ~~2016~~2019 was ~~42%. The reconciliation~~37%, up from 31% at December 31, 2018. This ratio is calculated by dividing the sum of ~~debt to total capitalization, which is a non-GAAP measure, is:~~(i) the principal amount of long-term debt ~~of $1.5 billion divided~~and (ii) redeemable preferred stock by the sum of (i) the principal amount of long-term debt, ~~of $1.5 billion plus~~(ii) redeemable preferred stock, and (iii) total stockholders’ equity, ~~of $2.04 billion.~~with all numbers coming directly from the Consolidated Balance Sheet. Management uses this ~~non-GAAP measure~~ratio as one indicator of our financial ~~condition. Management~~condition and believes professional research analysts and rating agencies use this ~~non-GAAP measure~~ratio for this purpose and to compare our financial condition to other companies’ financial conditions.

We may, from time to time, seek to repurchase our outstanding redeemable preferred stock through cash repurchases and/or exchanges for equity securities, privately negotiated transactions, or otherwise. Such activities, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. See Note 2 to the Consolidated Financial Statements for information regarding our redeemable preferred stock.

We expect our operating cash flow and other capital resources to be adequate to meet our needs for planned capital expenditures, working capital, debt service, and dividends declared ~~in 2017 and beyond.~~

~~Sources and Uses of Cash~~

Our primary sources of liquidity and capital resources are operating cash flow, borrowings under our credit facility, asset sales and occasional public financings based on our monitoring of capital markets and our balance sheet. Our primary uses of funds are expenditures for ~~exploration and development, leasehold and property acquisitions, other capital expenditures, debt service, and cash dividends paid to holders of our common stock.~~

~~The decline in year-over-year realized prices for our oil and natural gas production adversely impacted our operating cash flow for 2016 and consequently reduced~~ the ~~amount of cash flow available for exploration and development activities. See~~ ~~Market Conditions~~ ~~above for further information regarding prevailing economic conditions.~~

The following table presents our sources and uses of cash and cash equivalents from 2014 to 2016. Capital expenditures are presented on a cash basis. These amounts differ from capital expenditures (including accruals) that are referred to elsewhere in this report.

Years Ended December 31,

(in thousands)

2016

2015

2014

Sources of cash and cash equivalents:

Operating cash flow

$
599,225

$
691,500

$
1,619,365

Sales of oil and gas and other assets

29,376

41,031

458,394

Increase in other long-term debt

—

—

750,000

Proceeds from sale of common stock

—

752,100

—

Proceeds from exercise of stock options and other

4,804

21,439

11,898

Total sources of cash and cash equivalents

633,405

1,506,070

2,839,657

Uses of cash and cash equivalents:

Oil and gas capital expenditures

(699,558
)
(979,044
)
(2,108,250
)
Other capital expenditures

(22,228
)
(70,592
)
(90,611
)
Net decrease in bank debt

—

—

(174,000
)
Financing and underwriting fees

(101
)
(24,633
)
(11,616
)
Dividends paid

(38,024
)
(58,281
)
(53,849
)
Total uses of cash and cash equivalents

(759,911
)
(1,132,550
)
(2,438,326
)
Net increase (decrease) in cash and cash equivalents

$
(126,506
)
$
373,520

$
401,331

Cash and cash equivalents at end of year

$
652,876

$
779,382

$
405,862

next twelve months.

Analysis of Cash Flow Changes ~~(See~~

The following table presents the totals of the major cash flow classification categories from our Consolidated Statements of Cash Flows ~~in Item 8 of this Report)~~

for the periods indicated.



	Years Ended December 31,
(in thousands)	2019			2018
Net cash provided by operating activities	$	1,343,966		$	1,550,994
Net cash used by investing activities	$	(1,577,882	)	$	(1,085,618	)
Net cash used by financing activities	$	(472,028	)	$	(65,244	)

Net cash ~~flow~~ provided by operating activities ~~(operating cash flow) for 2016~~in 2019 was ~~$599.2~~$1.34 billion, down $207.0 million, ~~down~~or 13%, from ~~$691.5 million for 2015.~~$1.55 billion in 2018. The ~~$92.3 million~~ decrease ~~was~~resulted primarily ~~a result~~from an increased investment in working capital, primarily related to the repayment of ~~a net~~liabilities assumed from Resolute, and increased operating expenses in 2019 as compared to 2018. Partially offsetting this decrease in ~~production revenue from lower realized commodity prices and~~operating cash flows was an increase due to increased revenues, primarily due to increased production volumes, ~~in 2016. The 2016~~and a decrease in ~~production revenue was partially offset by lower net operating expenses and increased proceeds from~~cash outflows for settlements of ~~our~~ derivative instruments. In 2015, operating cash flow was 57% lower than 2014, resulting from a net decrease in production revenue due to lower realized commodity prices in 2015, which was partially offset by lower net operating costs in 2015. See RESULTS OF OPERATIONS above for ~~details~~more information regarding ~~year-over-year~~the changes in ~~production revenues~~revenue and operating expenses.

~~In 2016, net~~

Net cash ~~flow~~ used ~~for~~by investing activities was ~~$692.4 million, compared to $1.0~~$1.58 billion and $1.09 billion in 2019 and 2018, respectively. The majority of our cash flows used by investing activities are for ~~2015~~oil and ~~$1.7 billion for 2014. Weakness~~gas capital expenditures, which, as reflected in ~~commodity prices has had a significant adverse impact on~~ the ~~amount~~statements of cash ~~flow available to invest~~flows, were $1.25 billion and $1.57 billion in ~~exploration~~2019 and development (E&D) activities. In 2016, our E&D and other capital expenditures were $721.8 million, and were partially offset by proceeds from asset sales of $29.4 million. Our 2015 E&D and other capital expenditures were $1.0 billion, which were partially offset by proceeds from asset sales of $41.0 million. For 2014, our E&D and other capital expenditures were $2.2 billion, which were partially offset by proceeds from asset sales of $458.4 million.

2018, respectively. Net cash ~~flow~~ used by ~~financing~~investing activities in ~~2016 was $33.3~~2019 included the $325.7 million ~~compared to~~cash portion of the consideration paid for the Resolute acquisition, net of the $41.2 million in cash ~~flow provided~~acquired with Resolute. Net cash used by ~~financing~~investing activities in ~~2015 of $690.6 million. In 2016, proceeds of $4.8~~2018 included $534.6 million ~~from issuance of common stock from employee option exercises and other were more than offset by dividend payments and financing fees of $38.1 million.~~

~~In 2015,~~in net cash ~~flow provided by financing activities of $690.6 million included approximately $730 million of net~~ proceeds from the sale of ~~common stock~~oil and ~~$21.4 million of~~gas properties principally located in Ward County, Texas. Net cash proceeds from ~~issuance of common stock from employee option exercises~~other asset sales in 2019 and ~~other. These cash flows were partially offset by dividend payments of $58.3~~2018 totaled $30.0 million and ~~$2.5~~$49.9 million, respectively. These asset sales are primarily for the divestiture of ~~financing costs.~~

non-strategic oil and gas properties. Our other capital expenditures, which are primarily for our midstream assets, were $73.7 million and $103.5 million in 2019 and 2018, respectively.

Net cash ~~flow provided~~used by financing activities ~~of $522.4~~was $472.0 million and $65.2 million in ~~2014 included the issuance~~2019 and 2018, respectively. During 2019, we issued $500 million aggregate principal amount of ~~$750~~4.375% senior unsecured notes due March 15, 2029 at 99.862% of par for proceeds of $499.3 million, paying $4.6 million in underwriting fees and financing costs. Additionally, we borrowed and repaid an aggregate of ~~senior notes and $11.9 million of proceeds from the issuance of common stock from employee option exercises and other, which were partially offset by payments of $174.0 million~~$2.12 billion on our credit facility ~~$11.6~~during 2019 to assist in funding the Resolute acquisition and thereafter to meet cash requirements as needed. In connection with the acquisition of Resolute, we assumed $870.0 million ~~for~~in principal amount of long-term debt that we immediately repaid, incurring a redemption fee of $4.3 million. During 2019, we amended our credit facility, paying $3.0 million in financing costs.

Table of Contents

We had no long-term debt-related financing cash flows during 2018. Net cash used by financing activities during both years included: (i) the payment of dividends, (ii) the payment of income tax withholdings made on behalf of our employees upon the net settlement of employee stock awards, and ~~underwriting fees~~(iii) the receipt of proceeds from exercises of stock options. During 2019 and 2018, we declared cash dividends on our common stock quarterly, paying them in the quarter following declaration. Additionally, during 2019, we declared cash dividends on our preferred stock quarterly, also paying them in the quarter following declaration. During 2019, we paid one $0.18 per common share dividend, three $0.20 per common share dividends, and three $20.3125 per preferred share dividends, totaling $81.7 million. During 2018, we paid one $0.08 per common share dividend, two $0.16 per common share dividends, and one $0.18 per common share dividend, totaling $55.2 million. Future dividend payments will depend on our level of ~~$53.8 million.~~

~~Adjusted~~earnings, financial requirements, and other factors considered relevant by our Board of Directors. We paid employee income tax withholdings on the net settlement of stock awards totaling $5.2 million and $12.1 million, in 2019 and 2018, respectively. Cash ~~Flow~~proceeds received from ~~Operations~~

stock option exercises were $1.3 million and $2.2 million in 2019 and 2018, respectively.

Capital Expenditures

The following table ~~provides a reconciliation from the GAAP measure of net cash provided by operating activities to the non-GAAP measure adjusted cash flow from operations:~~

Years Ended December 31,

(in thousands)

2016

2015

2014

Net cash provided by operating activities

$
599,225

$
691,500

$
1,619,365

Change in operating assets and liabilities

29,913

52,082

14,847

Adjusted cash flow from operations

$
629,138

$
743,582

$
1,634,212

Management uses the non-GAAP measure of adjusted cash flow from operations as a means of measuring our ability to fund our capital program and dividends, without fluctuations caused by changes in current assets and liabilities, which are included in the GAAP measure of cash provided by operating activities. Management believes this non-GAAP measure provides useful information to investors for the same reason, and that it is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry.

~~Capital Expenditures~~

~~The following table reflects~~presents capitalized expenditures for oil and gas ~~acquisitions,~~acquisition, exploration, and development ~~activities~~activities. The table also presents the amounts removed from our oil and ~~property sales:~~

Years Ended December 31,

(in thousands)

2016

2015

Acquisitions:

Proved

$
2,678

$
30

Unproved

11,865

6,666

Net purchase price adjustments (*)

—

(11,653
)

14,543

(4,957
)
Exploration and development:

Land and seismic

61,870

52,049

Exploration

40

1,073

Development

672,842

823,830

734,752

876,952

Property sales

(24,687
)
(41,276
)

$
724,608

$
830,719

~~(*) The~~gas properties balance, net ~~2015~~of applicable purchase price adjustments, ~~relate~~due to ~~activity in prior periods.~~

~~Capital expenditures~~property sales.



	Years Ended December 31,
(in thousands)	2019			2018
Acquisitions:
Proved	$	695,450		$	62
Unproved	1,025,376			26,216
	1,720,826			26,278
Exploration and development:
Land and seismic	60,175			82,791
Exploration and development	1,181,605			1,487,453
	1,241,780			1,570,244
Property sales	(35,320		)	(581,799		)
	$	2,927,286		$	1,014,723

Amounts in the table above are presented on an accrual basis. Oil and gas capital expenditures and sales of oil and gas assets in the Consolidated Statements of Cash Flows ~~in this report~~ reflect capital expenditures and proceeds from property sales on a cash basis, when payments are made and proceeds received.

~~Because~~

On March 1, 2019, we completed the acquisition of ~~lower commodity prices, we reduced~~Resolute Energy Corporation, an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the Permian Basin of west Texas. The fair value of the proved and unproved properties recorded in the preliminary purchase price allocation for this acquisition was $692.6 million and $1.02 billion, respectively.

We decreased our ~~2016~~2019 E&D expenditures ~~16%~~21% to ~~$734.8 million~~$1.24 billion compared to ~~$877.0 million~~$1.57 billion in ~~2015.~~2018. Approximately ~~59%~~84% of our ~~2016~~2019 E&D expenditures were in the Permian Basin and ~~40%~~16% were in ~~our Mid-Continent region.~~ the Mid-Continent. During ~~2016,~~2019, we completed or participated in the ~~drilling and~~ completion of ~~154~~291 gross ~~(61~~(92.1 net) wells, 73 of which we ~~operated.~~operated 119 gross (85.3 net) wells. See Items 1 and 2 of this report for further information regarding our ~~wells drilled and other information regarding our~~ oil and gas properties.

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Based on current economic conditions, our 2020 total capital expenditures are projected to range from $1.25 billion to $1.35 billion. This includes drilling and completion capital of approximately $950 million to $1.05 billion, investments in midstream and water infrastructure of approximately $100 million, and investments in other, including capitalized G&A and non-producing leasehold, of approximately $200 million. Approximately ~~66%~~90% of our planned ~~2017 E&D~~2020 drilling and completion capital investment ~~of $1.1 — $1.2 billion~~ is expected to be invested in the Permian Basin, ~~and most of~~with the remainder in the ~~Mid-Continent region.~~

Mid-Continent. As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on increases or decreases in commodity prices, service costs, and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions.

We intend to fund our ~~2017~~2020 capital investment program with cash flow from our operating activities, ~~and~~ cash on hand, ~~at December 31, 2016. Sales of non-core assets~~ and borrowings under our ~~Credit Facility~~credit facility. Sales of non-strategic assets and possible capital markets transactions may also be used to supplement funding of capital ~~expenditures.~~expenditures and acquisitions. The timing of capital expenditures and the receipt of cash flows do not necessarily match, which may cause us to borrow and repay funds under our ~~Credit Facility~~credit facility from time-to-time. See Long-Term Debt—Bank Debt below for further information regarding our credit facility.

In the ordinary course of business we actively evaluate opportunities to purchase properties that we believe could benefit from our technical capabilities, particularly in our core areas of operations. We also evaluate our non-core property holdings for potential divestitures. For further information on our property acquisitions and dispositions, see Note 12 to the Consolidated Financial Statements in Item 8 of this report.

We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations. While we expect current pending legislation or regulations to increase the cost of business, we do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact, based on current laws and regulations. However, compliance with new legislation or regulations could increase our costs or adversely affect demand for oil or gas and result in a material adverse effect on our financial position or operations.

~~Financial Condition~~

~~During 2016, our total assets decreased $470.7 million (10%) to $4.2 billion. Most~~ See Item 1A RISK FACTORS for a description of ~~the decrease~~risks related to ~~net oil~~current and ~~gas properties, which declined by $387.0 million. In 2016, $757.7 million of impairments~~potential future environmental and ~~DD&A of $392.3 million were only partially offset by net additions to oil~~safety regulations and ~~gas properties of $716.7 million. The remaining decrease in total assets was primarily related to a decrease of $126.5 million in cash~~requirements that could adversely affect our operations and ~~cash equivalents.~~

Total liabilities at year-end 2016 were $2.19 billion, down $55.3 million (2%) from $2.25 billion at year-end 2015. During 2016, deferred income taxes declined $213.0 million primarily as a result of our net loss for the year. The decline in deferred income taxes was partially offset by a net increase in current liabilities of $112.3 million.

~~At December 31, 2016, stockholders’ equity totaled $2.04 billion, a decrease of $415.4 million (17%) from $2.46 billion~~financial condition.

Long-Term Debt

Long-term debt at December 31, ~~2015. The decrease resulted primarily from our 2016 net loss of $408.8 million.~~

~~The 2016 decreases in our total assets, liabilities~~2019 and stockholders’ equity and our net loss for the year resulted primarily from the $757.7 million aggregate impairments of our oil and gas properties. During the first three quarters of 2016, impairments resulted from the continued impact of lower prices on the present value of future cash flows from our proved reserves used in our full cost ceiling limitation calculation. As noted above under ~~Operating costs and expenses~~, the ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.

~~Long-Term Debt~~

~~Long-term debt at year-end 2016 and 2015~~2018 consisted of the following:

December 31, 2016

December 31, 2015

Unamortized Debt

Long-term

Unamortized Debt

Long-term

(in thousands)

Principal

Issuance Costs

Debt, net

Principal

Issuance Costs

Debt, net

5.875% Senior Notes

$
750,000

$
(5,691
)
$
744,309

$
750,000

$
(6,978
)
$
743,022

4.375% Senior Notes

750,000

(6,370
)
743,630

750,000

(7,402
)
742,598

Total long-term debt

$
1,500,000

$
(12,061
)
$
1,487,939

$
1,500,000

$
(14,380
)
$
1,485,620

~~At each~~



	December 31, 2019							December 31, 2018
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)			Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discount (1)			Long-term Debt, net
4.375% notes due 2024	$	750,000	$	(3,535	)	$	746,465	$	750,000	$	(4,439	)	$	745,561
3.90% notes due 2027	750,000		(6,289		)	743,711		750,000		(7,007		)	742,993
4.375% notes due 2029	500,000		(4,930		)	495,070		—		—			—
Total long-term debt	$	2,000,000	$	(14,754	)	$	1,985,246	$	1,500,000	$	(11,446	)	$	1,488,554

________________________________________

(1)

The 4.375% notes due 2024 were issued at par, therefore, the amounts shown in the table are for unamortized debt issuance costs only. At December 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% notes were $4.8 million and $1.5 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 4.375% notes due 2029 were $4.3 million and $0.6 million, respectively. At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.4 million and $1.6 million, respectively.

Table of ~~December 31, 2016 and 2015 we had no bank debt outstanding. All of our long-term debt is senior unsecured debt and is, therefore,~~ ~~pari passu~~ ~~with other unsecured debt with respect to the payment of both principal and interest.~~

Contents

Bank Debt

~~In October 2015,~~

On February 5, 2019, we entered into ~~a new~~an Amended and Restated Credit Agreement for our senior unsecured revolving credit facility ~~(Credit Facility)~~(“Credit Facility”). Among other things, the amended and restated credit facility increased the aggregate commitments to $1.25 billion with an ~~initial aggregate commitment from the lenders of $1.0 billion. We have the~~ option for us to increase the ~~commitment~~aggregate commitments to ~~$1.25~~$1.5 billion, ~~at any time. Unlike~~and extended the ~~prior credit facility, the new Credit Facility~~maturity date to February 5, 2024. There is ~~not a~~no borrowing base ~~facility~~ subject to the discretion of the lenders ~~and is not~~ based on the value of our proved ~~reserves.~~

Atreserves under the Credit Facility. As of December 31, ~~2016,~~2019, we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit ~~outstanding~~ of $2.5 million ~~under the Credit Facility,~~outstanding, leaving an unused borrowing availability of ~~$997.5 million. We did not have any bank~~$1.248 billion. During the year ended December 31, 2019, we borrowed and repaid an aggregate of $2.12 billion, on the Credit Facility to meet cash requirements as needed.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR (or an alternate rate determined by the administrative agent for the Credit Facility in accordance with the Credit Facility when LIBOR is no longer available) plus 1.125 - 2.0% based on the credit rating for our senior unsecured long-term debt, ~~outstanding during 2016. In 2015, we had average daily bank debt outstanding~~or (b) a base rate (as defined in the credit agreement) plus 0.125 - 1.0%, based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of ~~$27.4 thousand and~~0.125 - 0.35%, based on the ~~highest amount of bank borrowings outstanding during 2015 was $10.0 million in May.~~

credit rating for our senior unsecured long-term debt.

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. ~~For further information regarding~~As of December 31, 2019, we were in compliance with all of the ~~terms~~financial and non-financial covenants.

At December 31, 2019 and 2018, we had $4.0 million and $2.2 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in “Other assets” in our balance sheets. The costs are being amortized to interest expense ratably over the life of the Credit ~~Facility see Note 3 to the Consolidated Financial Statements~~Facility. We incurred $3.0 million in ~~Item 8 of this report.~~

additional debt issuance costs in amending our Credit Facility.

Senior Notes

~~Our 5.875%~~

On March 8, 2019, we issued $500.0 million aggregate principal amount of 4.375% senior unsecured notes due March 15, 2029 at 99.862% of par to yield 4.392% per annum. We received $494.7 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs. The notes bear an annual interest rate of 4.375% and interest is payable semiannually on March 15 and September 15, with the first payment made on September 15, 2019. We used the net proceeds to repay borrowings under our Credit Facility that were used to help fund the Resolute acquisition on March 1, 2019. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.50%.

In April 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured at 99.748% of par to yield 3.93% per annum. These notes are due May ~~1, 2022~~15, 2027 and ~~our~~interest is payable semiannually on May 15 and November 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.01%.

In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, ~~2024. Interest~~2024 and interest is payable semiannually on June 1 and December 1. The effective interest rate on these notes, including the amortization of debt issuance costs, is 4.50%.

Each of our senior ~~notes is payable semi-annually. Each of the senior~~unsecured notes is governed by an indenture containing ~~customary~~certain covenants, events of default, and other restrictive ~~provisions. For further information regarding~~provisions with which we were in compliance as of December 31, 2019.

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Working Capital Analysis

At December 31, 2019, we had a working capital deficit of $137.1 million, a decrease of $852.6 million, or 119% from a working capital surplus of $715.4 million at December 31, 2018. Our working capital decreased primarily due to the decrease in Cash and cash equivalents of $705.9 million, which was a result of cash consideration paid for our ~~senior notes see~~acquisition of Resolute and subsequent repayment of long-term debt and other liabilities acquired with Resolute. See Note 313 to the Consolidated Financial Statements for more information regarding the acquisition. In addition to the decrease in ~~Item 8 of this report.~~

~~Working Capital Analysis~~

~~Our~~cash, other significant changes to working capital consisted primarily of the following:

Our net current asset derivative instrument position decreased by $73.0 million. The fair value of derivative instruments fluctuates primarily as a result of our realized commodity prices, increases or decreases in our production volumes, changes in receivables and payables related to our operating and E&D activities, changes in our oil and gas well equipment and supplies andbased on changes in the ~~carrying value of our derivative instruments.~~

~~At December 31, 2016, we had working capital of $447.0 million, a decrease of $220.9 million (33%)~~underlying price indices as compared to ~~working capital~~the contracted prices included in the derivative instruments.

The January 1, 2019 adoption of ~~$667.9~~Topic 842 increased our current liabilities by $73.3 million at December 31, ~~2015.~~

~~Working capital decreases consisted~~2019. This amount represents the estimated current future lease payments, primarily for office space, well-head compressors, pipeline compressors, and artificial lift mechanisms. See Note 10 to the Consolidated Financial Statements for more information regarding our lease liabilities and the adoption of ~~the following:~~

· ~~Cash and cash equivalents decreased by $126.5 million.~~

· ~~Net derivative instrument liability increased $60.1 million.~~

· ~~Operations-related accounts payable and accrued liabilities increased $37.3 million.~~

· ~~Accrued liabilities related to our E&D expenditures increased by $25.6 million.~~

· ~~Oil and gas well equipment and supplies decreased by $21.2 million.~~

~~Decreases in working capital were partially offset by the following:~~

· ~~Operations-related accounts receivable increased $49.2 million~~

Topic 842.

Accounts receivable are a major component of our working capital and include amounts due from a diverse group of companies comprised of major energy companies, pipeline companies, local distribution companies, and other end-users. ~~The collection of receivables has historically been timely and~~Historically, losses associated with uncollectible receivables have not been significant.

Dividends

A quarterly cash dividend has been paid ~~to stockholders~~on our common stock every quarter since the first quarter of 2006. During 2019, our Board of Directors declared four $0.20 per common share cash dividends, totaling $81.4 million. In ~~February 2016,~~March 2019, in conjunction with the ~~quarterly dividend was decreased to $0.08 per share from $0.16~~Resolute acquisition, we issued 62.5 thousand shares of 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share. During 2019, our Board of Directors declared four cash dividends of $20.3125 per preferred share, totaling $5.1 million. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Years Ended December 31,

2016

2015

2014

Dividends declared from Retained earnings (in millions)

$
7.5

$
59.3

$
55.7

Dividends declared from Paid-in capital (in millions)

$
22.8

$
—

$
—

Dividends per share

$
0.32

$
0.64

$
0.64

See Note 2 to the Consolidated Financial Statements ~~in Item 8 of this report~~ for further information regarding ~~dividends.~~

our stock and Note 13 to the Consolidated Financial Statements for further information regarding the Resolute acquisition.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, ~~2016,~~2019, our material off-balance sheet arrangements ~~included~~consisted of operating lease agreements ~~which are customary in~~with lease terms at commencement of 12 months or less. As an accounting policy, we have elected not to apply the ~~oil and gas industry.~~

recognition requirements of Topic 842 to these leases. As such, we have not recorded any lease liabilities associated with these leases.

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Contractual Obligations and Material Commitments

At December 31, ~~2016,~~2019, we had the following contractual obligations and material ~~commitments.~~

Payments Due by Period

1 Year or

More than

Contractual obligations:

Total

Less

2 - 3 Years

4 - 5 Years

5 Years

(in thousands)

Long-term debt (1)

$
1,500,000

$
—

$
—

$
—

$
1,500,000

Fixed-rate interest payments (1)

478,542

76,876

153,750

153,750

94,166

Operating leases

96,923

9,585

21,208

21,949

44,181

Drilling commitments (2)

157,505

157,505

—

—

—

Asset retirement obligation (3)

154,523

13,753

—

—

—

Other liabilities (4)

177,455

88,793

54,905

6,956

26,801

Firm transportation

26,383

7,655

6,549

4,427

7,752

commitments:

~~(1)~~ ~~See Item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt.~~

~~(2)~~



	Payments Due by Period
Contractual obligations (in thousands):	Total		1/1/20 - 12/31/20		1/1/21 - 12/31/22			1/1/23 - 12/31/24			1/1/25 and Thereafter
Long-term debt-principal (1)	$	2,000,000	$	—	$	—		$	750,000		$	1,250,000
Long-term debt-interest (1)	574,905		81,868		167,875			151,469			173,693
Operating leases (2)	108,451		26,950		32,488			24,708			24,305
Unconditional purchase obligations (3)	84,436		21,567		21,381			18,542			22,946
Derivative liabilities	17,699		16,681		1,018			—			—
Asset retirement obligation (4)	181,869		27,824		—		(4)	—		(4)	—		(4)
Other long-term liabilities (5)	42,493		1,564		5,862			2,991			32,076
	$	3,009,853	$	176,454	$	228,624		$	947,710		$	1,503,020

________________________________________


(1)	The interest payments presented above include the accrued interest payable on our long-term debt as of December 31, 2019 as well as future payments calculated using the long-term debt’s fixed rates, stated maturity dates, and principal amounts outstanding as of December 31, 2019. See Note 3 to the Consolidated Financial Statements for additional information regarding our debt.


(2)	Operating leases include the estimated remaining contractual payments under lease agreements as of December 31, 2019. These lease agreements are primarily comprised of leases for commercial real estate, which consists primarily of office space, and compressor equipment.


(3)	Of the total unconditional purchase obligations, $20.2 million represents obligations for the purchase of sand for well completions and $64.0 million represents obligations for firm transportation agreements for gas and oil pipeline capacity.


(4)	We have excluded the presentation of the timing of the cash flows associated with our long-term asset retirement obligations because we cannot make a reasonably reliable estimate of the future period of cash settlement. The long-term asset retirement obligation is included in the total asset retirement obligation presented.


(5)	Other long-term liabilities include contractual obligations associated with our employee supplemental savings plan, gas balancing liabilities, and other miscellaneous liabilities. All of these liabilities are accrued on our Consolidated Balance Sheet. The current portion associated with these long-term liabilities is also presented in the table above.

The following discusses various commercial commitments that we have ~~drilling~~made that may include potential future cash payments if we fail to meet various performance obligations. These are not reflected in the table above, unless otherwise noted.

At December 31, 2019, we had estimated commitments of ~~$157.5~~approximately: (i) $321.7 million ~~consisting of obligations~~ to finish drilling, completing, or performing other work on wells and ~~completing wells~~various other infrastructure projects in progress ~~at December 31, 2016.~~

~~(3)~~ ~~We have not included the long-term asset retirement obligations because we are not able~~and (ii) $6.6 million to ~~precisely predict the timing of these amounts.~~

~~(4)~~ ~~Other includes the estimated value of our commitments associated with our benefit obligations, derivative obligations, and other miscellaneous commitments.~~

finish gathering system construction in progress.

At December 31, ~~2016,~~2019, we had firm sales contracts to deliver approximately ~~46.4~~703.7 Bcf of ~~natural~~ gas over the next ~~twenty-two months.~~11.5 years. If we do not deliver this gas, ~~is not delivered,~~ our estimated financial commitment, calculated using the January 2020 index prices, would be approximately ~~$164.8 million. This~~$1.03 billion. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

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In connection with gas gathering and processing agreements, we have volume commitments over the next ~~ten~~9.0 years. If nowe do not deliver the committed gas ~~is delivered,~~or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2019, would be approximately ~~$220.0~~$697.2 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments ~~in connection~~associated with agreements to reimburse connection costs to various pipelines. ~~The~~If we do not deliver this gas, or oil, as the case may be, the estimated maximum amount that would be payable ~~if no gas is delivered~~under these commitments, calculated as of December 31, 2019, would be approximately ~~$7.9~~$117.6 million. Of this total, we have accrued a liability of ~~$2.1 million. We may~~$4.5 million representing the estimated amount we will have ~~additional liabilities associated with these delivery commitments~~to pay due to insufficient forecasted volumes at particular connection points. This accrual is reflected in the ~~future depending on our production levels and drilling results.~~

~~We have other various transportation, delivery, and facilities commitments~~table above in ~~the normal course of business, which approximate $35.7 million. We currently anticipate meeting these obligations.~~

Other long-term liabilities.

All of the noted commitments were routine and made in the ~~normal~~ordinary course of our business.

Taking into account current commodity prices and anticipated levels of production, we believe that our net cash flow generated from operations and our other capital resources will be adequate to meet future obligations.

2~~017 Outlook~~

For 2017, our total production is projected to average 1.06 — 1.11 Bcfe per day, an increase of 13% at the midpoint from 2016 production levels. First quarter 2017 production is expected to average 1.01 — 1.05 Bcfe per day. Oil production in the first quarter is expected to increase approximately 10% from fourth quarter 2016 levels, with natural gas and NGL production expected to increase 4 — 5% sequentially.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Discussion and analysis of our financial condition and results of operation are based on our Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of ~~America, or GAAP.~~America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. We analyze and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

~~A complete list of our~~

Our significant accounting policies are described in Note 1 to our Consolidated Financial ~~Statements in Item 8 of this report.~~Statements. We have identified the following policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management.

Oil and Gas Reserves

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time due to numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

At year-end ~~2016, 21%~~2019, 14% of our total proved reserves are categorized as proved undeveloped ~~reserves, or PUDs.~~reserves. Our ~~reserve~~ engineers review and revise these reserve estimates regularly, as new information becomes available.

We use the units-of-production method to amortize the cost associated with our oil and gas properties. Changes in estimates of reserve quantities and commodity prices will cause corresponding changes in depletion expense, or in some cases, a full cost ceiling impairment charge in the period of the revision. See Full Cost Accounting below for further information regarding the ceiling limitation calculation. See SUPPLEMENTAL INFORMATION ON OIL AND GAS ~~INFORMATION~~PRODUCING ACTIVITIES (UNAUDITED) in Item 8 ~~of this report~~ for additional reserve data.

Table of Contents

Full Cost Accounting

We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the acquisition, exploration, and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also ~~are~~ capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

~~Companies that follow~~

Under the full cost method of accounting, ~~method~~we are required to ~~make a~~perform quarterly ceiling test ~~calculation. This~~calculations to test ~~requires companies to record an impairment to the extent that total capitalized costs for~~our oil and gas properties ~~(net~~for possible impairment. If the net capitalized cost of ~~accumulated DD&A~~our oil and ~~all related deferred~~gas properties, as adjusted for income ~~taxes) exceed~~taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum ofof: (i) the present value discounted at 10% of estimated future net ~~cash flows~~revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, ~~and (iv) all related tax effects.~~as adjusted for income taxes. We currently do not have any unproven properties that are being amortized. ~~Revenue calculations used to estimate~~Estimated future net ~~cash flows from proved reserves~~revenues are determined based on ~~the unweighted~~trailing twelve-month average ~~first-day-of-the-month~~ commodity ~~price for the prior 12 months. Changes in~~prices and estimated proved reserve ~~estimates (including those based upon quantity revisions or changes in commodity price) will cause corresponding changes to the full cost~~quantities, operating costs, and capital expenditures.

The quarterly ceiling ~~limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be expensed. Any impairment of oil and gas properties~~test is ~~not reversible at a later date.~~

~~Quarterly ceiling tests are~~ primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes. ~~For each~~If pricing conditions decline, or if there is a negative impact on one or more of the ~~first three quarters~~other components of ~~2016,~~ the ~~carrying value of our oil and gas properties subject to the~~calculation, we may incur a full cost ceiling test ~~exceeded the~~impairment. The calculated ~~value of the~~ ceiling limitation and we recognized aggregate impairments of $757.7 million ($481.4 million, net of tax). These impairments resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas and NGLs utilized in determining the future net cash flows from proved reserves. At December 31, 2016, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. However, a decline of approximately 7% or more in the value of the ceiling limitation would have resulted in an impairment. Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation. See ~~Operating costs and expenses~~ above for a complete discussion of our 2016 ceiling impairments. See Note 1 to our Consolidated Financial statements in Item 8 of this report for information regarding the effect of a ceiling impairment on our depletion rate.

~~The ceiling limitation calculation~~ is not intended to be indicative of the fair marketvalue of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.

Any impairment of oil and gas properties is not reversible at a later date.

Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities and ~~commodity prices~~impairment of oil and gas properties will cause corresponding changes in depletion expense in periods subsequent to these changes.

The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors.

~~Goodwill~~

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. We first assess qualitative factors to determine whether it is more likely than not (with a greater than 50% threshold) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If goodwill is determined to be impaired, then it is written down to a calculated fair value by charging the impairment to expense.

We evaluate our goodwill for impairment in the fourth quarter of each year and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our qualitative assessment at December 31, 2016, goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors become unfavorable.

~~Contingencies~~

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies to determine if we should record losses. Actual costs can vary from our estimates for a variety of reasons. See Note 10 to the Consolidated Financial Statements in Item 8 of this report for further information regarding litigation and other commitments and contingencies.

At December 31, 2016, we had not made any material accruals related to environmental remediation costs. However, we may be required to make such estimates in future periods if applicable laws and regulations change or if the interpretation or administration of laws and regulations change. Other factors, such as unanticipated construction problems or identification of areas of contaminated soil or groundwater, could also cause us to accrue for such costs.

~~Asset Retirement Obligation~~

Our asset retirement obligation represents the estimated present value of the amount we will incur to retire long-lived assets at the end of their productive lives, in accordance with applicable state laws. Our asset retirement obligation is determined by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of inception with an offsetting increase in the carrying amount of the related long-lived asset. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset or depleted using the units-of-production method.

Asset retirement liability is determined using significant assumptions including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of assets and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity of assumptions, the costs to ultimately retire our wells may vary significantly from prior estimates. See Note 8 to the Consolidated Financial Statements in Item 8 of this report for additional information regarding our asset retirement obligations.

Income Taxes

Our oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, which is affected by factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the tax asset would be reduced by a valuation allowance. ~~Numerous judgments and assumptions are inherent in the determination~~

Table of ~~future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).~~

~~The company~~Contents

We regularly ~~assesses~~assess and, if required, ~~establishes~~establish accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 to the Consolidated Financial Statements ~~in Item 8 of this report~~ for additional information regarding our income taxes.

~~Recently Issued Accounting Standards~~

~~See Note 1, Basis of Presentation and Summary of Significant Accounting Policies —~~ ~~Recently Issued Accounting Standards~~, ~~to the Consolidated Financial Statements in Item 8 of this report for a discussion of recent accounting pronouncements and their anticipated effect on our business.~~

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~Market~~

We are exposed to market risk ~~refers to~~including the risk of loss arising from adverse changes in commodity prices and interest rates. ~~The disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses.~~

Price Fluctuations

Our major market risk is pricing applicable to our oil, gas, and NGL production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil, gas, and NGL production has been volatile and unpredictable. ~~Oil sales contributed 52% of~~During 2019, our total production revenue ~~for 2016. Gas and NGL~~was comprised of 72% oil sales, ~~accounted for 32%~~12% gas sales, and 16%~~, respectively, of~~ NGL sales. The following table shows how hypothetical changes in the realized prices we receive for our ~~2016 production revenue. A $1.00 per barrel change in our realized oil price would~~commodity sales may have resulted in a $16.5 million change in revenues. A $0.10 per Mcf change in our realized gas price would have resulted in a $16.8 million change in our gas revenues. A $1.00 per barrel change in NGL prices would have changed revenues by $14.2 million.impacted revenue for the periods indicated. See MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Market Conditions ~~in Item 7 of this report~~ for further ~~information.~~

information regarding prices.



			Impact on Revenue
	Change in Realized Price		Year Ended December 31, 2019
			(in thousands)
Oil	± $1.00	per barrel	± $31,463
Gas	± $0.10	per Mcf	± $25,157
NGL	± $1.00	per barrel	± $28,254
			± $84,874

We periodically enter into ~~financial~~ derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. At December 31, ~~2016,~~2019, we had oil and gas ~~collars~~derivatives covering a portion of our ~~2017~~2020 and ~~2018~~2021 production, which were recorded as ~~short~~current and ~~long-term~~non-current assets and liabilities. ~~The fair value liability of~~At December 31, 2019, our oil and gas ~~collars was $29.0~~derivatives had a gross asset fair value of $18.5 million and ~~$23.0 million, respectively.~~a gross liability fair value of $17.7 million. See Note 4 to the Consolidated Financial Statements ~~in Item 8 of this report~~ for additional information regarding our derivative instruments.

While these contracts limit the downside risk of adverse price movements, they may also limit future ~~revenues~~cash flow from favorable price movements. ~~For the oil contracts described above, a~~The following table shows how hypothetical ~~$1.00 change~~changes in the ~~price below or above the~~ forward ~~price~~prices used to calculate the fair value ~~would result in a decrease~~ of ~~$4.8 million or an increase of $5.0 million, respectively, to~~our derivatives may have impacted the fair value ~~liability~~as of ~~the derivatives at~~ December 31, ~~2016. For the gas contracts described above, a hypothetical $0.10 change in the price below or above the forward price used to calculate the fair value would result in a decrease~~2019.



		Impact on Fair Value
	Change in Forward Price	December 31, 2019
		(in thousands)
Oil	-$1.00	$	7,726
Oil	+$1.00	$	(8,115	)
Gas	-$0.10	$	3,276
Gas	+$0.10	$	(3,118	)

Table of ~~$5.1 million or an increase of $5.3 million, respectively, to the fair value liability of the derivatives at December 31, 2016.~~

Contents

Interest Rate Risk

At December 31, ~~2016,~~2019, our long-term debt consisted of $750 million ~~in 5.875% senior notes that will mature on May 1, 2022 and $750 million in~~of 4.375% senior unsecured notes that ~~will~~ mature on June 1, ~~2024.~~2024, $750 million of 3.90% senior unsecured notes that mature on May 15, 2027, and $500 million of 4.375% that mature on March 15, 2029. Because all of our outstanding long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal. ~~This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.~~ See Note 3 and Note 5 to the Consolidated Financial Statements ~~in Item 8 of this report~~ for additional information regarding our debt.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CIMAREX ENERGY CO.

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES

		~~Page~~

	Page
Report of Independent Registered Public Accounting Firm for the years ended December 31, ~~2016, 2015,~~2019, 2018, and ~~2014~~2017	66 63
Consolidated ~~balance sheets~~Balance Sheets as of December 31, ~~2016~~2019 and ~~2015~~2018	67 66
Consolidated ~~statements~~Statements of ~~operations~~Operations and ~~comprehensive income (loss)~~Comprehensive Income (Loss) for the years ended December 31, ~~2016, 2015,~~2019, 2018, and ~~2014~~2017	68 67
Consolidated ~~statements~~Statements of ~~cash flows~~Cash Flows for the years ended December 31, ~~2016, 2015,~~2019, 2018, and ~~2014~~2017	69 68
Consolidated ~~statements~~Statements of ~~stockholders’ equity~~Stockholders’ Equity for the years ended December 31, ~~2016, 2015,~~2019, 2018, and ~~2014~~2017	70 69

Notes to ~~consolidated financial statements~~Consolidated Financial Statements
Note 1 — Basis of Presentation and Summary of Significant Accounting Policies	71 70
Note 2 — Capital Stock	78 76
Note 3 — ~~Long-term~~Long-Term Debt	79 77
Note 4 — Derivative ~~Instruments/Hedging~~Instruments	80 79
Note 5 — Fair Value Measurements	82 83
Note 6 — Stock-Based and Other Compensation	84
Note 7 — Earnings ~~(loss)~~(Loss) per Share	87 88
Note 8 — Asset Retirement Obligations	87 89
Note 9 — Income Taxes	88 90
Note 10 — Commitments and Contingencies	89 92
Note 11 — Related Party Transactions	90 97
Note 12 ~~— Property Sales and Acquisitions~~	90
~~Note 13~~ — Supplemental Cash Flow Information	91 97
Note 13 — Acquisitions and Divestitures	98
~~Supplemental information to consolidated financial statements~~
Supplemental ~~oil and gas information (Unaudited)~~Information to Consolidated Financial Statements	92
Supplemental ~~quarterly financial data~~Information on Oil and Gas Producing Activities (Unaudited)	97 101
Supplemental Quarterly Financial Data (Unaudited)	107

All other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or related notes thereto.

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Report of Independent Registered Public Accounting Firm

~~The~~

To the Stockholders and Board of Directors ~~and Stockholders~~

Cimarex Energy Co.:

Opinion on the ConsolidatedFinancial Statements

We have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, ~~2016~~2019 and ~~2015, and~~2018, the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the ~~three-year~~three‑year period ended December 31, ~~2016.~~ 2019, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2020 expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Financial Accounting Standards Board Accounting Standards Codification Topic 842, Leases.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the ~~Public Company Accounting Oversight Board (United States).~~PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material ~~misstatement. An audit includes~~misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence ~~supporting~~regarding the amounts and disclosures in the consolidated financial statements. ~~An audit~~Our audits also ~~includes assessing~~included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial ~~statement presentation.~~statements. We believe that our audits provide a reasonable basis for our opinion.

~~In our opinion,~~

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements ~~referred~~that were communicated or required to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cimarex Energy Co. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria established in ~~Internal Control – Integrated Framework (2013)~~ ~~issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2017, except for the restatement as~~be communicated to the ~~effectiveness of internal control over financial reporting for the~~audit committee and that: (1) relate to accounts or disclosures that are material weakness related to the full cost ceiling test calculation, as to which the date is May 10, 2017, expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

~~KPMG LLP~~

~~Denver, Colorado~~
~~February 24, 2017, except for the immaterial error correction~~ to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

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Assessment of the effect of estimated oil and gas reserves related to proved oil and gas properties on depletion expense and the ceiling test calculation

As discussed in Note 1 to the consolidated financial statements, the Company calculates depletion expense related to proved oil and gas properties using the units-of-production method. Under such method, capitalized costs, including future estimated development costs and asset retirement costs, are amortized over total estimated proved oil and gas reserves. For the year ended December 31, 2019, the Company recorded depletion expense related to proved oil and gas properties of $817.1 million. The Company recorded a ceiling test impairment of $618.7 million for the year ended December 31, 2019 due to the net capitalized cost of the oil and gas properties exceeding the ceiling limitation. The Company is required to perform a ceiling test calculation on a quarterly basis, and the ~~restatement as~~applicable ceiling limitation is equal to the ~~effectiveness~~sum of: (1) the present value discounted at 10% of estimated future net revenues from proved reserves, (2) the cost of properties not being amortized, and (3) the lower of cost or estimated fair value of unproven properties included in the costs being amortized. The Company’s internal ~~control over financial reporting for~~Corporate Reservoir Engineering group estimates proved oil and gas reserves. The Company also engages an independent petroleum engineering consulting firm to perform an independent evaluation of a portion of those proved oil and gas reserve estimates.

We identified the ~~material weakness~~assessment of the effect of estimated oil and gas reserves related to proved oil and gas properties on both depletion expense and the ~~full cost~~ ceiling test calculation as a critical audit matter. Complex auditor judgment was required in evaluating the Company’s estimate of proved oil and gas reserves. Auditor judgment was also required to ~~which~~evaluate the ~~date is May 10, 2017~~

assumptions used by the Company related to forecasted production, estimated future operating costs, and oil and gas prices inclusive of market differentials because changes to these assumptions could have a significant impact on the estimated oil and gas reserves.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s depletion calculation and ceiling test calculation processes, including certain controls related to the estimation of proved oil and gas reserves used in the respective calculations. We evaluated the competence, capabilities, and objectivity of the Corporate Reservoir Engineering personnel who estimated the proved oil and gas reserves and the independent petroleum engineering consulting firm engaged by the Company. We assessed the methodology used by the Company’s internal Corporate Reservoir Engineering group to estimate proved oil and gas reserves and the methodology used by the independent petroleum engineering consulting firm to evaluate those reserve estimates for compliance with industry and regulatory standards. We evaluated the forecasted production and estimated future operating costs assumptions used by the Company’s internal Corporate Reservoir Engineering group by comparing them to the Company’s historical and current actual results. We evaluated the oil and gas prices used by the Company’s internal Corporate Reservoir Engineering group by comparing them to publicly available prices and tested the relevant market differentials. We read and considered the report of the Company’s independent petroleum engineering consulting firm in connection with our evaluation of the Company’s reserve estimates. We analyzed the depletion expense calculation for compliance with regulatory standards and recalculated it. We also analyzed the ceiling test calculation for compliance with regulatory standards, and recalculated it.

Evaluation of the fair value of oil and gas properties acquired in the Resolute business combination

As discussed in Note 13 to the consolidated financial statements, on March 1, 2019, the Company acquired Resolute Energy Corporation (Resolute) in a business combination. As a result of the transaction, the Company acquired both proved and unproved oil and gas properties. The acquisition-date fair value for the oil and gas properties acquired was $1.7 billion.

We identified the evaluation of the fair value of the oil and gas properties acquired in the Resolute business combination as a critical audit matter. Complex auditor judgment was required in evaluating the results of the discounted cash flow model used to determine the fair value of the proved oil and gas properties. The discounted cash flow model included the following significant assumptions: estimated future oil and gas prices, reserve category risk adjustment factors, forecasted production, estimated future operating costs and weighted-average cost of capital (WACC). In addition, complex auditor judgment was required in evaluating the results of the market based transactions used to determine the fair value of the unproved oil and gas properties.

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The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s acquisition-date valuation process to determine the fair value of the acquired oil and gas properties, including controls over the development of the significant assumptions used in the discounted cash flow model for proved oil and gas properties and the assessment of market based transaction for unproved oil and gas properties. We evaluated the Company’s estimated future oil and gas prices by comparing them to relevant publicly available market price forecasts. We evaluated reserve category risk adjustment factors by comparing them against publicly available industry information. We evaluated the Company’s forecasted production and estimated future operating costs by comparing them to historical actual results of similar Cimarex oil and gas properties. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the Company’s fair value as it relates to proved oil and gas properties by comparing the WACC to a range of WACCs of comparable peers that were independently developed using publicly available market information. As it relates to unproved oil and gas properties, the valuation professionals compared the Company’s estimated fair values by asset group to a range of indicated values of recent similar market transactions that were independently developed using publicly available market information.

KPMG LLP

We have served as the Company’s auditor since 2002.

Denver, Colorado

February 26, 2020

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CIMAREX ENERGY CO.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share information)

December 31,

2016

2015

Assets

Current assets:

Cash and cash equivalents

$
652,876

$
779,382

Accounts receivable:

Trade, net of allowance

42,287

81,888

Oil and gas sales, net of allowance

217,395

136,537

Gas gathering, processing, and marketing, net of allowance

14,888

6,935

Other

27

38

Oil and gas well equipment and supplies

33,342

54,579

Derivative instruments

—

10,745

Prepaid expenses

7,335

7,036

Other current assets

1,154

790

Total current assets

969,304

1,077,930

Oil and gas properties at cost, using the full cost method of accounting:

Proved properties

16,225,495

15,546,948

Unproved properties and properties under development, not being amortized

478,277

440,166

16,703,772

15,987,114

Less—accumulated depreciation, depletion and amortization and impairment

(14,349,505
)
(13,245,832
)
Net oil and gas properties

2,354,267

2,741,282

Fixed assets, net of accumulated depreciation of $246,901 and $207,173

205,465

230,009

Goodwill

620,232

620,232

Deferred income taxes

55,835

—

Derivative instruments

—

501

Other assets, net

32,621

38,468

$
4,237,724

$
4,708,422

Liabilities and Stockholders’ Equity

Current liabilities:

Accounts payable:

Trade

$
49,163

$
53,384

Gas gathering, processing, and marketing

25,323

13,431

Accrued liabilities:

Exploration and development

82,320

56,721

Taxes other than income

18,766

17,545

Other

177,695

173,242

Derivative instruments

49,370

—

Revenue payable

119,715

95,744

Total current liabilities

522,352

410,067

Long-term debt:

Principal

1,500,000

1,500,000

Less—unamortized debt issuance costs

(12,061
)
(14,380
)
Long-term debt, net

1,487,939

1,485,620

Deferred income taxes

—

157,162

Asset retirement obligation

140,770

153,857

Derivative instruments

2,570

—

Other liabilities

41,104

43,359

Total liabilities

2,194,735

2,250,065

Commitments and contingencies (Note 10)

Stockholders’ equity:

Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued

—

—

Common stock, $0.01 par value, 200,000,000 shares authorized, 95,123,525 and 94,820,570 shares issued, respectively

951

948

Paid-in capital

2,763,452

2,762,976

Retained earnings (accumulated deficit)

(722,359
)
(306,008
)
Accumulated other comprehensive income

945

441

2,042,989

2,458,357

$
4,237,724

$
4,708,422

~~The~~



	December 31,
	2019			2018
Assets
Current assets:
Cash and cash equivalents	$	94,722		$	800,666
Accounts receivable, net of allowance:
Trade	57,879			122,065
Oil and gas sales	384,707			315,063
Gas gathering, processing, and marketing	5,998			17,072
Oil and gas well equipment and supplies	47,893			55,553
Derivative instruments	17,944			101,939
Prepaid expenses	10,759			7,554
Other current assets	1,584			4,227
Total current assets	621,486			1,424,139
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	20,678,334			18,566,757
Unproved properties and properties under development, not being amortized	1,255,908			436,325
	21,934,242			19,003,082
Less—accumulated depreciation, depletion, amortization, and impairment	(16,723,544		)	(15,287,752		)
Net oil and gas properties	5,210,698			3,715,330
Fixed assets, net of accumulated depreciation of $389,458 and $324,631, respectively	519,291			257,686
Goodwill	716,865			620,232
Derivative instruments	580			9,246
Other assets	71,109			35,451
	$	7,140,029		$	6,062,084
Liabilities, Redeemable Preferred Stock, and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	36,280		$	76,927
Gas gathering, processing, and marketing	12,740			29,887
Accrued liabilities:
Exploration and development	112,228			124,674
Taxes other than income	54,446			33,622
Other	252,304			221,159
Derivative instruments	16,681			27,627
Revenue payable	207,939			194,811
Operating leases	66,003			—
Total current liabilities	758,621			708,707
Long-term debt:
Principal	2,000,000			1,500,000
Less—unamortized debt issuance costs and discounts	(14,754		)	(11,446		)
Long-term debt, net	1,985,246			1,488,554
Deferred income taxes	338,424			334,473
Asset retirement obligation	154,045			152,758
Derivative instruments	1,018			2,267
Operating leases	184,172			—
Other liabilities	60,742			45,539
Total liabilities	3,482,268			2,732,298
Commitments and contingencies (Note 10)
Redeemable preferred stock - 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, $0.01 par value, 62,500 shares authorized and issued and no shares authorized and issued, respectively (Note 2)	81,620			—
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 102,144,577 and 95,755,797 shares issued, respectively	1,021			958
Additional paid-in capital	3,243,325			2,785,188
Retained earnings	331,795			542,885
Accumulated other comprehensive income	—			755
Total stockholders’ equity	3,576,141			3,329,786
	$	7,140,029		$	6,062,084

See accompanying notes ~~are an integral part~~to Consolidated Financial Statements.

Table of ~~these consolidated financial statements.~~

Contents

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(in thousands, except per share ~~data)~~

Years Ended December 31,

2016

2015

2014

Revenues:

Oil sales

$
632,934

$
809,664

$
1,308,958

Gas sales

388,786

428,227

687,930

NGL sales

199,498

179,647

375,941

Gas gathering and other

36,033

34,688

49,602

Gas marketing, net of related costs of $122,655, $144,673 and $256,836 respectively

94

393

1,745

1,257,345

1,452,619

2,424,176

Costs and expenses:

Impairment of oil and gas properties

757,670

4,033,295

—

Depreciation, depletion and amortization

392,348

731,460

775,577

Asset retirement obligation

7,828

9,121

10,082

Production

232,002

299,374

342,304

Transportation, processing, and other operating

190,725

182,362

195,414

Gas gathering and other

31,785

38,138

35,113

Taxes other than income

61,946

84,764

128,793

General and administrative

73,901

74,688

81,160

Stock compensation

24,523

19,559

15,001

(Gain) loss on derivative instruments, net

55,749

(11,246
)
(3,762
)
Other operating expense, net

755

856

116

1,829,232

5,462,371

1,579,798

Operating income (loss)

(571,887
)
(4,009,752
)
844,378

Other (income) and expense:

Interest expense

83,272

85,746

72,865

Capitalized interest

(21,248
)
(30,589
)
(35,925
)
Other, net

(10,707
)
(13,576
)
(28,907
)
Income (loss) before income tax

(623,204
)
(4,051,333
)
836,345

Income tax expense (benefit)

(214,401
)
(1,471,729
)
309,847

Net income (loss)

$
(408,803
)
$
(2,579,604
)
$
526,498

Earnings (loss) per share to common stockholders:

Basic

Distributed

$
0.32

$
0.64

$
0.64

Undistributed

(4.70
)
(28.39
)
5.37

$
(4.38
)
$
(27.75
)
$
6.01

Diluted

Distributed

$
0.32

$
0.64

$
0.64

Undistributed

(4.70
)
(28.39
)
5.36

$
(4.38
)
$
(27.75
)
$
6.00

Comprehensive income (loss):

Net income (loss)

$
(408,803
)
$
(2,579,604
)
$
526,498

Other comprehensive income (loss):

Change in fair value of investments, net of tax

504

(661
)
(87
)
Total comprehensive income (loss)

$
(408,299
)
$
(2,580,265
)
$
526,411

~~The~~information)



	Years Ended December 31,
	2019			2018			2017
Revenues:
Oil sales	$	1,660,210		$	1,398,813		$	981,646
Gas and NGL sales	661,711			898,832			892,357
Gas gathering and other	42,454			41,180			43,751
Gas marketing	(1,406		)	192			495
	2,362,969			2,339,017			1,918,249
Costs and expenses:
Impairment of oil and gas properties	618,693			—			—
Depreciation, depletion, and amortization	882,173			590,473			446,031
Asset retirement obligation	8,586			7,142			15,624
Production	339,941			296,189			263,349
Transportation, processing, and other operating	238,259			211,463			248,124
Gas gathering and other	23,294			28,327			18,187
Taxes other than income	148,953			125,169			89,864
General and administrative	95,843			77,843			79,996
Stock compensation	26,398			22,895			26,256
Loss (gain) on derivative instruments, net	76,850			(85,959		)	(21,210		)
Other operating expense, net	19,305			18,507			1,314
	2,478,295			1,292,049			1,167,535
Operating (loss) income	(115,326		)	1,046,968			750,714
Other (income) and expense:
Interest expense	93,386			68,224			74,821
Capitalized interest	(56,232		)	(20,855		)	(22,948		)
Loss on early extinguishment of debt	4,250			—			28,187
Other, net	(5,741		)	(22,908		)	(11,342		)
(Loss) income before income tax	(150,989		)	1,022,507			681,996
Income tax (benefit) expense	(26,370		)	230,656			187,667
Net (loss) income	$	(124,619	)	$	791,851		$	494,329

Earnings (loss) per share to common stockholders:
Basic	$	(1.33	)	$	8.32		$	5.19
Diluted	$	(1.33	)	$	8.32		$	5.19

Comprehensive (loss) income:
Net (loss) income	$	(124,619	)	$	791,851		$	494,329
Other comprehensive (loss) income:
Change in fair value of investments, net of tax of $(222), $(425), and $106, respectively	(755		)	(1,444		)	1,254
Total comprehensive (loss) income	$	(125,374	)	$	790,407		$	495,583

See accompanying notes ~~are an integral part~~to Consolidated Financial Statements.

Table of ~~these consolidated financial statements.~~

Contents

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

Years Ended December 31,

2016

2015

2014

Cash flows from operating activities:

Net income (loss)

$
(408,803
)
$
(2,579,604
)
$
526,498

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Impairments and other valuation losses

757,670

4,033,295

—

Depreciation, depletion and amortization

392,348

731,460

775,577

Asset retirement obligation

7,828

9,121

10,082

Deferred income taxes

(213,286
)
(1,486,439
)
309,443

Stock compensation

24,523

19,559

15,001

(Gain) loss on derivative instruments, net

55,749

(11,246
)
(3,762
)
Settlements on derivative instruments

7,437

—

7,641

Changes in non-current assets and liabilities

3,867

23,230

(2,440
)
Other, net

1,805

4,206

(3,828
)
Changes in operating assets and liabilities:

Receivables, net

(49,340
)
186,699

(35,133
)
Other current assets

20,880

37,954

(25,428
)
Accounts payable and other current liabilities

(1,453
)
(276,735
)
45,714

Net cash provided by operating activities

599,225

691,500

1,619,365

Cash flows from investing activities:

Oil and gas expenditures

(699,558
)
(979,044
)
(2,108,250
)
Sales of oil and gas assets

21,487

39,853

449,981

Sales of other assets

7,889

1,178

8,413

Other capital expenditures

(22,228
)
(70,592
)
(90,611
)
Net cash used by investing activities

(692,410
)
(1,008,605
)
(1,740,467
)
Cash flows from financing activities:

Net bank debt borrowings

—

—

(174,000
)
Proceeds from other long-term debt

—

—

750,000

Proceeds from sale of common stock

—

752,100

—

Financing and underwriting fees

(101
)
(24,633
)
(11,616
)
Dividends paid

(38,024
)
(58,281
)
(53,849
)
Proceeds from exercise of stock options and other

4,804

21,439

11,898

Net cash (used) provided by financing activities

(33,321
)
690,625

522,433

Net change in cash and cash equivalents

(126,506
)
373,520

401,331

Cash and cash equivalents at beginning of period

779,382

405,862

4,531

Cash and cash equivalents at end of period

$
652,876

$
779,382

$
405,862

~~The~~



	Years Ended December 31,
	2019			2018			2017
Cash flows from operating activities:
Net (loss) income	$	(124,619	)	$	791,851		$	494,329
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Impairment of oil and gas properties	618,693			—			—
Depreciation, depletion, and amortization	882,173			590,473			446,031
Asset retirement obligation	8,586			7,142			15,624
Deferred income taxes	(26,902		)	233,280			190,479
Stock compensation	26,398			22,895			26,256
Loss (gain) on derivative instruments, net	76,850			(85,959		)	(21,210		)
Settlements on derivative instruments	(13,131		)	(24,429		)	(1,633		)
Loss on early extinguishment of debt	4,250			—			28,187
Changes in non-current assets and liabilities	(2,797		)	(1,779		)	1,891
Other, net	14,639			105			5,677
Changes in operating assets and liabilities:
Accounts receivable	65,128			5,421			(186,157		)
Other current assets	(739		)	(1,957		)	(17,931		)
Accounts payable and other current liabilities	(184,563		)	13,951			115,021
Net cash provided by operating activities	1,343,966			1,550,994			1,096,564
Cash flows from investing activities:
Oil and gas capital expenditures	(1,249,797		)	(1,566,583		)	(1,233,126		)
Acquisition of Resolute Energy, net of cash acquired (Note 13)	(284,441		)	—			—
Other capital expenditures	(73,693		)	(103,459		)	(45,352		)
Sales of oil and gas assets	28,945			580,652			11,680
Sales of other assets	1,104			3,772			901
Net cash used by investing activities	(1,577,882		)	(1,085,618		)	(1,265,897		)
Cash flows from financing activities:
Borrowings of long-term debt	2,619,310			—			748,110
Repayments of long-term debt	(2,990,000		)	—			(750,000		)
Financing, underwriting, and debt redemption fees	(11,798		)	(100		)	(29,312		)
Finance lease payments	(3,869		)	—			—
Dividends paid	(81,709		)	(55,243		)	(30,532		)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards	(5,229		)	(12,142		)	(21,669		)
Proceeds from exercise of stock options	1,267			2,241			394
Net cash used by financing activities	(472,028		)	(65,244		)	(83,009		)
Net change in cash and cash equivalents	(705,944		)	400,132			(252,342		)
Cash and cash equivalents at beginning of period	800,666			400,534			652,876
Cash and cash equivalents at end of period	$	94,722		$	800,666		$	400,534

See accompanying notes ~~are an integral part~~to Consolidated Financial Statements.

Table of ~~these consolidated financial statements.~~

Contents

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in ~~thousands)~~

Retained

Accumulated

Earnings

Other

Total

Common Stock

Paid-in

(Accumulated

Comprehensive

Stockholders’

Shares

Amount

Capital

Deficit)

Income (loss)

Equity

Balance, December 31, 2013

87,152

$
872

$
1,970,113

$
1,862,075

$
1,189

$
3,834,249

Dividends

—

—

—

(55,664
)
—

(55,664
)
Net income

—

—

—

526,498

—

526,498

Unrealized change in fair value of investments, net of tax

—

—

—

—

(87
)
(87
)
Issuance of restricted stock awards

487

4

(4
)
—

—

—

Common stock reacquired and retired

(123
)
(1
)
(13,559
)
—

—

(13,560
)
Restricted stock forfeited and retired

(135
)
(1
)
1

—

—

—

Exercise of stock options

211

2

11,896

—

—

11,898

Stock-based compensation

—

—

28,633

—

—

28,633

Balance, December 31, 2014

87,592

$
876

$
1,997,080

$
2,332,909

$
1,102

$
4,331,967

Dividends

—

—

—

(59,313
)
—

(59,313
)
Net loss

—

—

—

(2,579,604
)
—

(2,579,604
)
Unrealized change in fair value of investments, net of tax

—

—

—

—

(661
)
(661
)
Issuance of common stock

6,900

69

729,468

—

—

729,537

Issuance of restricted stock awards

471

5

(5
)
—

—

—

Common stock reacquired and retired

(194
)
(2
)
(21,238
)
—

—

(21,240
)
Restricted stock forfeited and retired

(90
)
(1
)
1

—

—

—

Exercise of stock options

142

1

8,450

—

—

8,451

Stock-based compensation

—

—

36,232

—

—

36,232

Stock-based compensation tax benefit

—

—

12,988

—

—

12,988

Balance, December 31, 2015

94,821

$
948

$
2,762,976

$
(306,008
)
$
441

$
2,458,357

Dividends

—

—

—

(7,548
)
—

(7,548
)
Dividends in excess of retained earnings

—

—

(22,803
)
—

—

(22,803
)
Net loss

—

—

—

(408,803
)
—

(408,803
)
Unrealized change in fair value of investments, net of tax

—

—

—

—

504

504

Issuance of restricted stock awards

479

5

(5
)
—

—

—

Common stock reacquired and retired

(208
)
(3
)
(26,622
)
—

—

(26,625
)
Restricted stock forfeited and retired

(32
)
—

—

—

—

—

Exercise of stock options

64

1

4,803

—

—

4,804

Stock-based compensation

—

—

45,103

—

—

45,103

Balance, December 31, 2016

95,124

$
951

$
2,763,452

$
(722,359
)
$
945

$
2,042,989

~~The~~thousands, except per share information)



									Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
	Common Stock					Additional Paid-in Capital
	Shares		Amount			Additional Paid-in Capital
Balance, December 31, 2016	95,124		$	951		$	2,763,452		$	(722,359	)	$	945		$	2,042,989
Dividends paid on stock awards subsequently forfeited	—		—			11			32			—			43
Dividends declared ($0.32 per share)	—		—			(30,489		)	—			—			(30,489		)
Net income	—		—			—			494,329			—			494,329
Unrealized change in fair value of investments, net of tax	—		—			—			—			1,254			1,254
Issuance of restricted stock awards	552		5			(5		)	—			—			—
Common stock reacquired and retired	(204	)	(2		)	(21,667		)	—			—			(21,669		)
Restricted stock forfeited and retired	(41	)	—			—			—			—			—
Exercise of stock options	6		—			394			—			—			394
Stock-based compensation	—		—			48,321			—			—			48,321
Cumulative effect adjustment of adopting ASU 2016-09 (Note 6)	—		—			4,393			28,739			—			33,132
Other	—		—			(26		)	—			—			(26		)
Balance, December 31, 2017	95,437		954			2,764,384			(199,259		)	2,199			2,568,278
Dividends paid on stock awards subsequently forfeited	—		—			34			18			—			52
Dividends declared ($0.68 per share)	—		—			(15,196		)	(49,725		)	—			(64,921		)
Net income	—		—			—			791,851			—			791,851
Unrealized change in fair value of investments, net of tax	—		—			—			—			(1,444		)	(1,444		)
Issuance of restricted stock awards	593		6			(6		)	—			—			—
Common stock reacquired and retired	(139	)	—			(12,142		)	—			—			(12,142		)
Restricted stock forfeited or canceled and retired	(168	)	(2		)	2			—			—			—
Exercise of stock options	33		—			2,241			—			—			2,241
Stock-based compensation	—		—			45,871			—			—			45,871
Balance, December 31, 2018	95,756		958			2,785,188			542,885			755			3,329,786
Dividends paid on stock awards subsequently forfeited	—		—			8			18			—			26
Dividends declared on common stock ($0.80 per share)	—		—			61			(81,411		)	—			(81,350		)
Dividends declared on redeemable preferred stock ($81.25 per share)	—		—			—			(5,078		)	—			(5,078		)
Net loss	—		—			—			(124,619		)	—			(124,619		)
Issuance of stock for Resolute Energy acquisition (Note 13)	5,652		56			412,959			—			—			413,015
Unrealized change in fair value of investments, net of tax	—		—			—			—			(755		)	(755		)
Issuance of restricted stock awards	946		9			(9		)	—			—			—
Common stock reacquired and retired	(105	)	(1		)	(5,228		)	—			—			(5,229		)
Restricted stock forfeited or canceled and retired	(133	)	(1		)	1			—			—			—
Exercise of stock options	29		—			1,267			—			—			1,267
Stock-based compensation	—		—			49,078			—			—			49,078
Balance, December 31, 2019	102,145		$	1,021		$	3,243,325		$	331,795		$	—		$	3,576,141

See accompanying notes ~~are an integral part~~to Consolidated Financial Statements.

Table of ~~these consolidated financial statements.~~

Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, and New Mexico.

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation.

Segment Information

We have determined that our business is comprised of only ~~one~~1 segment because our gathering, processing, and marketing activities are ancillary to our oil and gas production ~~operations and are not separately managed.~~

operations.

Use of Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. ~~The more significant areas~~Areas of significance requiring the use of management’s ~~estimates and~~ judgments ~~relate to~~include the estimation of proved oil and gas reserves ~~the use of these oil and gas reserves~~used in calculating depletion, ~~depreciation and amortization (DD&A),~~ the ~~use of the estimates~~estimation of future net revenues used in computing ceiling test limitations, ~~and estimates~~the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill.

Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, lease liabilities, and contingencies. We analyze our estimates and base them on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

~~Estimates and judgments are also required~~

Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Prior Year Reclassifications

Certain amounts in ~~determining~~ the ~~allowance for doubtful accounts, impairments of unproved properties~~prior year financial statements have been reclassified to conform to the 2019 financial statement presentation. These reclassifications include reclassifying certain Gas gathering and other ~~assets, purchase price~~expenses to Transportation, processing, and other operating expense and Production expense. These reclassifications were made to reflect an allocation ~~valuation~~ of ~~deferred tax assets, fair value measurements~~the costs incurred to operate our gas gathering facilities as a cost to transport our equity share of gas produced and ~~commitments and contingencies. We analyze~~operate our ~~estimates, including those related to oil, gas and NGL revenues, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under~~wells. The following table shows the ~~circumstances. Actual results may differ from these estimates under different assumptions or conditions.~~

reclassifications made:

Years Ended December 31,
2018 2017
(in thousands)
Prior
Year Presentation

Current
Year Reclassifications
Current Year Presentation
Prior
Year Presentation

Current
Year Reclassifications
Current Year Presentation
Production $ 293,213
$ 2,976
$ 296,189
$ 262,180
$ 1,169
$ 263,349
Transportation, processing, and other operating $ 200,802
10,661
$ 211,463
$ 231,640
16,484
$ 248,124
Gas gathering and other $ 41,964
(13,637 ) $ 28,327
$ 35,840
(17,653 ) $ 18,187

$ —

$ —

Cash and Cash Equivalents

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities of three months or less. Cash equivalents are stated at cost, which approximates market value.

Oil and Gas Well Equipment and Supplies

~~We carry our inventory~~

Our oil and gas well equipment and supplies are valued at the lower of cost orand net realizable value, where net realizable value is based on estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. ~~We performed an analysis of our oil and gas well equipment and supplies as of December 31, 2016, and no impairment was required. However, the industry-wide decline~~Declines in ~~drilling operations has put downward pressure on~~ the price of oil and gas well equipment and ~~supplies. Declines~~supplies in future periods could cause us to recognize impairments

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.

Oil and Gas Properties

We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the acquisition, exploration, and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

~~Companies that follow~~

Under the full cost method of accounting, ~~method~~we are required to ~~make~~perform quarterly ceiling test ~~calculations. This~~calculations to test ~~requires companies to record an impairment to the extent that total capitalized costs for~~our oil and gas properties ~~(net~~for possible impairment. If the net capitalized cost of ~~accumulated DD&A~~our oil and ~~all related deferred~~gas properties, as adjusted for income ~~taxes) exceed~~taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum ofof: (i) the present value discounted at 10% of estimated future net ~~cash flows~~revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, ~~and (iv) all related tax effects.~~as adjusted for income taxes. We currently do not have any unproven properties that are

Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

being amortized. ~~Revenue calculations used to estimate~~Estimated future net ~~cash flows from proved reserves~~revenues are determined based on ~~the unweighted~~trailing twelve-month average ~~first-day-of-the-month~~commodity prices ~~for the prior 12 months. If net capitalized~~and estimated proved reserve quantities, operating costs, ~~exceed this limit, the excess is charged to expense.~~

~~At December 31, 2016, the carrying value of our oil~~ and gas properties subject to the test did not exceed the calculated value of the ceiling limitation and, therefore, we did not recognize an impairment. However, a decline of approximately 7% or more in the value of the ceiling limitation would have resulted in an impairment. We did recognize impairments in the first three quarters of 2016 totaling $757.7 million ($481.4 million, net of tax). capital expenditures.

For the year ended December 31, ~~2015, full year impairments totaled $4.0 billion ($2.6 billion, net~~2019, we recognized a ceiling test impairment of ~~tax). These impairments~~$618.7 million, all of which was recognized in the fourth quarter. The impairment resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves. We did not recognize a ceiling test impairment during the years ended December 31, 2018 and 2017 because the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation. The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we ~~will~~may incur full cost ceiling test impairments in future quarters. The calculated ceiling ~~calculation~~limitation is not intended to be indicative of the fair marketvalue of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and ~~other~~various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date.

Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities ~~commodity prices~~ and impairment of oil and gas properties will cause corresponding changes in depletion expense in periods subsequent to these changes.

Fixed Assets ~~net~~

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Also included in Fixed assets are operating lease right-of-use assets. See Note 10 for additional information regarding our leases.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. ~~We have one reporting unit for which~~In performing the goodwill test, we ~~first assess qualitative factors to determine whether it is more likely than not (with a greater than 50% threshold) that~~compare the fair value of aour reporting unit ~~is less than~~with its carrying amount. If the carrying amount ~~as a basis for determining whether it is necessary~~of the reporting unit were to ~~perform the two-step goodwill impairment test. If goodwill is determined to be impaired then it is written down to a calculated~~exceed its fair value, ~~by charging~~an impairment charge would be recognized in the ~~impairment~~amount of this excess, limited to ~~expense.~~

the total amount of goodwill allocated to that reporting unit. We evaluate our goodwill for impairment in the fourth quarter of each year and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our ~~qualitative~~ assessment ~~at December~~as of October 31, ~~2016,~~2019, goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors become ~~less favorable.~~

unfavorable.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenue Recognition

Oil, Gas, and NGL Sales

Effective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606, Revenue from Contracts with Customers (“Topic 606”), utilizing the modified retrospective approach, which we applied to contracts that were not completed as of that date. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of Topic 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating in the Consolidated Statements of Operations and Comprehensive Income (Loss) under prior accounting standards are now reflected as deductions from revenue under Topic 606.

Revenue is ~~recorded~~recognized from the sales of oil, gas, and NGLs when the customer obtains control of the product, when we have no further obligations to perform related to the sale, and when collectability is ~~delivered~~probable. All of our sales of oil, gas, and NGLs are made under contracts with customers, which typically include variable consideration based on monthly pricing tied to local indices and monthly volumes delivered. The nature of our contracts with customers does not require us to constrain that variable consideration or to estimate the amount of transaction price attributable to future performance obligations for accounting purposes. As of December 31, 2019, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a ~~fixed~~ point-in-time through monthly delivery of oil, gas, and/or ~~determinable price, title has transferred~~NGLs. Our contracts with customers typically require payment within one month of delivery.

Our gas and ~~collectability~~NGLs are sold under a limited number of contract structure types common in our industry. Under these contracts the gas and its components, including NGLs, may be sold to a single purchaser or the residue gas and NGLs may be sold to separate purchasers. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product. However, depending on the contract structure type, certain transportation, processing, and other charges may be deducted against the prices received for the product. Our oil typically is ~~reasonably assured. There is a ready market~~sold at specific delivery points under contract terms that also are common in our industry.

Gas Gathering

When we transport and/or process third-party gas associated with our equity gas, we recognize revenue for ~~our products and sales occur soon after production.~~

the fees charged to third-parties for such services.

Gas Marketing ~~Sales~~

When we market and sell ~~natural~~ gas for working interest owners, we act as agent under ~~short term~~short-term sales and supply agreements and may earn a fee for such services. Revenues from such services are recognized as gas is ~~delivered and are reflected net~~delivered.

Gas Imbalances

Revenue from the sale of gas ~~purchases on the consolidated statements of operations and comprehensive income (loss).~~

~~Gas Imbalances~~

~~We use the sales method of accounting for gas imbalances. Under this method, revenue~~ is recorded on the basis of gas actually ~~sold. Gas reserves~~sold by us. If our aggregate sales volumes for a well are ~~adjusted~~greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent ~~there are sufficient quantities of natural gas to make up an imbalance. A liability is established in situations where~~ there are insufficient proved reserves available to make-up anthe overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

General and Administrative Expenses

General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting.

Derivatives

Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 4 for additional information regarding our derivative instruments.

Income Taxes

We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. We classify all deferred tax assets and liabilities as ~~noncurrent.~~non-current. We routinely assess the realizability of ~~the~~our deferred tax assets. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, which is affected by factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. If we conclude that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

We regularly assess and, if required, establish accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 for additional information regarding our income taxes.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and determine when we should record losses for these items based on information available to us. See Note 10 for additional information regarding our contingencies.

Asset Retirement Obligations

We recognize the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the abandonment of wells, the removal of facilities and equipment, and site restorations. ~~Subsequent~~In periods subsequent to the initial measurement ~~the~~of an asset retirement obligation at present value, a period-to-period increase in the carrying amount of the liability is ~~required~~recognized as accretion expense, which represents the effect of the passage of time on the amount of the liability. An equivalent amount is added to ~~be accreted each period.~~the carrying amount of the liability. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are included as a component of the DD&A calculations. The current ~~portions~~portion of ~~the~~our asset retirement obligations ~~are~~is recorded in “Accrued liabilities — Other” in the accompanying ~~consolidated balance sheets~~Consolidated Balance Sheets and ~~expenditures~~cash payments for settlements of retirement obligations are classified as cash used in operating activities in the accompanying ~~consolidated statements~~Consolidated Statements of ~~cash flows.~~Cash Flows. See Note 8 for additional information regarding our asset retirement obligations.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-based Compensation

We recognize compensation cost related to all stock-based awards in the financial statements based on their estimated ~~grant-date~~grant date fair value. We grant various types of stock-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions), and restricted stock units. The grant date fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. The grant date fair value of the market condition-based restricted stock ~~is based on~~incorporates the ~~grant-date market value~~effect of the ~~award utilizing a statistical analysis.~~market condition using valuation techniques that take into consideration various share-price paths. Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas acquisition, exploration, and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation expense. See Note 6 for additional information regarding our stock-based compensation.

Earnings ~~(loss)~~(Loss) per Share

We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our unvested ~~share based~~share-based payment awards, consisting of restricted stock and units, qualify as participating securities. See Note 7 for additional information regarding our earnings per share.

~~Recently Issued~~

Lease Accounting ~~Standards~~

In ~~May 2014,~~February 2016, the Financial Accounting Standards Board ~~(FASB)~~(“FASB”) issued Accounting Standards Update ~~(ASU) 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606)~~~~. In July 2015, the FASB deferred the effective date by one year to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting~~

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

period. Early adoption is permitted, but not before the original effective date of reporting periods beginning after December 15, 2016. The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in this update supersedes the revenue recognition requirements in (“ASU”) 2016-02, Leases (“Topic ~~605,~~ ~~Revenue Recognition,~~ ~~and most industry-specific guidance throughout the Industry Topics of the Codification~~. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. We intend to adopt this standard on January 1, 2018, utilizing a modified retrospective approach. Management does not believe the effect of adoption will be material to our financial statements because we follow the sales method of accounting for our oil, gas and NGL production, which is generally consistent with the revenue recognition provisions of the new standard. However, we anticipate the new standard will result in more robust footnote disclosures. We cannot currently determine the extent of the new footnote disclosures as further clarification is needed for certain practices common to the industry.

~~In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases (Topic 842)~~842”). The ~~key provision of this ASU is~~FASB subsequently issued various ASUs that ~~a lessee must~~provided additional implementation guidance. Topic 842 requires lessees to recognize ~~(i)~~lease liabilities ~~to make lease payments~~ and ~~(ii)~~ right-of-use assets on ~~its~~the balance ~~sheet. The ASU permits~~sheet for contracts that provide lessees ~~to make a policy election to not recognize lease assets and liabilities for leases~~ with terms of less than twelve months. Under current GAAP, a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases. Under this ASU, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified ~~asset~~assets for a period of time. The scope of Topic 842 excludes leases to explore for or use minerals, oil, natural gas, and similar nonregenerative resources. We adopted Topic 842 effective January 1, 2019, using the modified retrospective method applied to all leases that existed on that date, which resulted in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. An entity may make a policy election to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and comprehensive income and cash flows, however, both types of leases require the recognition of lease liabilities of $276.9 million and right-of-use assets ~~and liabilities on the balance sheet. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years,~~of $265.0 million. In connection with ~~early~~ adoption ~~permitted. Upon transition, lessees will be required to recognize and measure leases at the beginning~~we made use of the ~~earliest period presented using~~ following practical expedients, which are provided in Topic 842:

a ~~modified retrospective approach. While we~~package of practical expedients to not reassess: 1) whether expired or existing contracts are or contain a lease, 2) lease classification for expired or existing leases, and 3) initial direct costs for existing leases;

an election not to apply the recognition requirements in Topic 842 to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that the ~~process of evaluating the potential impact of adopting this guidance, the primary effect will be~~company is reasonably certain to ~~record assets~~exercise);

a practical expedient that permits combining lease and ~~obligations for contracts currently recognized as operating leases. We do not intend to adopt the standard early.~~

~~In March 2016, the FASB issued ASU 2016-09,~~ ~~Improvements to Employee Share-Based Payment Accounting~~ (ASU 2016-09). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendmentsnonlease components in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The standard contains various amendments, and specifies whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. We will adopt ASU 2016-09 effective January 1, 2017. The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognizedcontract and accounting for ~~forfeitures will be adopted using~~the combination as a ~~modified retrospective method. In accordance with this method, we expect~~lease (elected by asset class); and

a practical expedient to ~~record a cumulative-effect adjustment on that date relating~~not reassess certain land easements in existence prior to ~~those amendments, representing an increase to beginning Deferred income taxes~~January 1, 2019.

Table of approximately $33 million, a reduction to beginning Accumulated deficit of approximately $31 million and an increase to beginning Paid-in capital of approximately $2 million. The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to tax withholdings on the net settlement of equity-classified awards will be adopted using a retrospective method. In accordance with this method, we estimate that Net cash provided by operating activities would have increased and Net cash (used) provided by financing activities would have decreased by approximately $27 million, $34 million and $14 million, for the years ended December 31, 2016, 2015 and 2014, respectively.

~~In January 2017, the FASB issued ASU 2017-04,~~ ~~Intangibles—Goodwill and Other (Topic 350)—Simplifying the Test for Goodwill Impairment~~. This ASU eliminates step two from the goodwill impairment test. Under current guidance, if the fair value of the reporting unit is less than its carrying amount (step 1 of the goodwill impairment test), entities must complete step two to determine the impairment amount, if any. Under step two, the impairment amount is

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

determined by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination, and comparing it to the carrying amount of the goodwill. Under this ASU, the impairment amount is the amount by which the carrying amount of the reporting unit exceeds the reporting unit’s fair value, with the amount of impairment not to exceed the carrying amount of the goodwill. This ASU retains the option to qualitatively assess whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount in order to determine if it is necessary to initiate step 1. This ASU is effective for annual or any interim goodwill impairment tests in the fiscal years beginning after December 15, 2019, with early adoption permitted for testing dates after January 1, 2017. The implementation of this ASU will affect the amount of goodwill impairment we record, if any. We adopted this ASU on January 1, 2017, and will apply its provisions in future periods if we determine our goodwill has been impaired.

~~Subsequent Events~~

~~The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing.~~

~~Correction of Previously Issued Consolidated Financial Statements~~

In the course of preparing our consolidated financial statements for the quarter ended March 31, 2017, we identified an error in the quarterly ceiling test calculations used in prior periods to test our oil and gas properties for possible impairment. Specifically, the calculations did not properly consider the company’s tax net operating loss carryforwards in the calculation of the capitalized costs of net oil and gas properties to be tested for impairment. This error had the effect of incorrectly reporting impairment amounts in prior periods, which resulted in incorrectly reporting depletion expense and income tax expense (benefit) in prior periods.

~~After considering the guidance in Staff Accounting Bulletin (“SAB”) No. 99,~~ ~~Materiality~~~~, and Accounting Standards Codification 250,~~ ~~Accounting Changes and Error Corrections~~, we evaluated the materiality of these amounts quantitatively and qualitatively and concluded that the error was not material to any of the company’s prior annual or interim period financial statements. The consolidated financial statements as of and for the years ended December 31, 2016, 2015 and 2014, and the unaudited interim period consolidated financial statements within the years ended December 31, 2016 and 2015 in this Form 10-K/A, have been revised in accordance with SAB No. 108, ~~Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,~~ in order to reflect these corrections. The corrections reflect the adjustments to impairment amounts, depletion expense and income tax expense (benefit) described above, as well as the resulting adjustments to deferred income taxes, accumulated depreciation, depletion and amortization and impairment, and retained earnings (accumulated deficit). Retained earnings as of December 31, 2013 reflected in the accompanying consolidated statements of stockholders’ equity has been reduced by $188.0 million from its previously reported balance of $2.05 billion to the corrected balance of $1.86 billion to reflect the impact of correcting the errors discussed above for the years ended December 31, 2013 ($102.9 million) and 2012 ($85.1 million). Correction of the errors discussed above impacted certain non-cash line items within the operating cash flow section of the consolidated statements of cash flows; however, the corrections did not change previously reported Net cash provided by operating activities for any period.

In addition to correcting the consolidated financial statements, we have also corrected the Supplemental Quarterly Financial Data (Unaudited) and the following Notes for the effects of the errors discussed above:

· ~~Note 1 — Basis of Presentation and Summary of Significant Accounting Policies~~

· ~~Note 7 — Earnings (Loss) Per Share~~

· ~~Note 9 — Income Taxes~~

The following tables present the effect of the corrections on selected line items from the previously reported consolidated financial statements as of December 31, 2016 and 2015, and for the years ended December 31, 2016, 2015 and 2014.

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Consolidated Balance Sheet
December 31, 2016

(in thousands)

As Previously
Reported

Corrections

As
Corrected

Accumulated depreciation, depletion and amortization and impairment

$
(13,849,701
)
$
(499,804
)
$
(14,349,505
)
Net oil and gas properties

$
2,854,071

$
(499,804
)
$
2,354,267

Total assets

$
4,681,693

$
(443,969
)
$
4,237,724

Deferred income taxes — (asset) liability

$
126,894

$
(182,729
)
$
(55,835
)
Total liabilities

$
2,321,629

$
(126,894
)
$
2,194,735

Retained earnings (accumulated deficit)

$
(405,284
)
$
(317,075
)
$
(722,359
)
Total stockholders’ equity

$
2,360,064

$
(317,075
)
$
2,042,989

Total liabilities and stockholders’ equity

$
4,681,693

$
(443,969
)
$
4,237,724

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2015

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Impairment of oil and gas properties

$
3,716,883

$
316,412

$
4,033,295

Depreciation, depletion and amortization

$
778,923

$
(47,463
)
$
731,460

Total operating expenses

$
5,193,422

$
268,949

$
5,462,371

Operating income (loss)

$
(3,740,803
)
$
(268,949
)
$
(4,009,752
)
Income (loss) before income tax

$
(3,782,384
)
$
(268,949
)
$
(4,051,333
)
Income tax expense (benefit)

$
(1,373,436
)
$
(98,293
)
$
(1,471,729
)
Net income (loss)

$
(2,408,948
)
$
(170,656
)
$
(2,579,604
)
Total comprehensive income (loss)

$
(2,409,609
)
$
(170,656
)
$
(2,580,265
)

Earnings (loss) per share to common stockholders:

Basic

Distributed

$
0.64

$

$
0.64

Undistributed

(26.56
)
(1.83
)
(28.39
)

$
(25.92
)
$
(1.83
)
$
(27.75
)
Diluted

Distributed

$
0.64

$

$
0.64

Undistributed

(26.56
)
(1.83
)
(28.39
)

$
(25.92
)
$
(1.83
)
$
(27.75
)

2. CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At December 31, ~~2016,~~2019, there were no102.1 million shares of common stock and 62.5 thousand shares of preferred stock outstanding. ~~See~~

Redeemable Preferred Stocks

In February 2019, our ~~Consolidated Statements~~Board of ~~Stockholders’ Equity for detailed capital~~Directors created a new series of preferred stock, ~~activity.~~

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

In May 2015, we completed an underwritten public offering of 6,900,000 shares of common stock, which included 900,000 shares of common stock issued pursuant to an overallotment option to purchase additional shares granted to the underwriters. The stock was sold to the public at $109.00par value $0.01 per share, designated as 8.125% Series A Cumulative Perpetual Convertible Preferred Stock (the “Convertible Preferred Stock”) and authorized 62.5 thousand shares. In March 2019, in conjunction with ~~a par value of $0.01, and~~the Resolute acquisition (see Note 13), we ~~received net proceeds of approximately $730 million from the sale~~issued all of these shares of Convertible Preferred Stock. Prior to this issuance, we had not issued any preferred stock. Holders of the Convertible Preferred Stock are entitled to receive, when, as, and if declared by the Board out of funds of Cimarex legally available for payment, cumulative cash dividends at the annual rate of 8.125% of each share’s liquidation preference of $1,000. Dividends on the preferred stock are payable quarterly in arrears and accumulate from the most recent date as to which dividends have been paid. In the event of any liquidation, winding up, or dissolution of Cimarex, whether voluntary or involuntary, each holder will be entitled to receive in respect of its shares and to be paid out of the assets of Cimarex legally available for distribution to its stockholders, after satisfaction of liabilities to Cimarex’s creditors and any senior stock (of which there is currently none) and before any payment or distribution is made to holders of junior stock (including common stock), the liquidation preference of $1,000 per share, with the total liquidation preference being $62.5 million in the aggregate. Each holder has the right at any time, at its option, to convert any or all of such holder’s shares of Convertible Preferred Stock at an initial conversion rate of 8.0421 shares of fully paid and nonassessable shares of our common stock and $471.40 in cash per share of Convertible Preferred Stock. The initial conversion rate of 8.0421 adjusts upon the occurrence of certain events, including the payment of cash dividends to common shareholders, and is 8.13828 as of December 31, 2019. Additionally, at any time on or after ~~deducting underwriting fees.~~

October 15, 2021, we shall have the right, at our option, if the closing sale price of our common stock meets certain criteria, to elect to cause all, and not part, of the outstanding shares of Convertible Preferred Stock to be automatically converted into that number of shares of Cimarex common stock for each share of Convertible Preferred Stock equal to the conversion rate in effect on the mandatory conversion date as such terms are defined in the Certificate of Designations for the Convertible Preferred Stock and $471.40 in cash per share of Convertible Preferred Stock. As a result of the cash redemption features included in the Convertible Preferred Stock conversion option, with such conversion not solely within our control, the instruments are classified as Redeemable preferred stock in temporary equity on the Consolidated Balance Sheet.

Dividends

Common Stock

A quarterly cash dividend has been paid ~~to stockholders in~~on our common stock every quarter since the first quarter of 2006. In ~~February 2016, the quarterly~~each quarter of 2019 a $0.20 per common share dividend was ~~decreased to~~declared. A dividend of $0.18 per common share was declared in both the third and fourth quarters of 2018 while a dividend of $0.16 per common share was declared in the first and second quarters of 2018. In each quarter of 2017 an $0.08 per common share ~~from $0.16 per share.~~dividend was declared. We typically declare dividends in one quarter and pay them in the following quarter. At December 31, 2019, we had dividends payable to common stock of $20.5 million that was included in “Accrued liabilities — Other”. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. All dividends declared during 2019 were recorded as a reduction of retained earnings. During 2018, the dividend declared during the first quarter was recorded as a reduction of additional paid-in capital, while the remaining three dividends declared were recorded as a reduction of retained earnings. All dividends declared during 2017 were recorded as a reduction of additional paid-in capital. Nonforfeitable dividends paid on stock awards that subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to compensation expense in the period in which the forfeitures occur. Dividends accrued and unpaid on performance

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

stock awards that are canceled upon completion of the vesting period due to the performance criteria not being met, are reversed out of retained earnings or additional paid-in capital, as applicable, in the period in which the cancellations occur. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by ~~the~~our Board of Directors.

~~3. LONG-TERM DEBT~~

~~A summary~~

Preferred Stock

In each quarter of 2019 our ~~debt is~~Board of Directors declared a cash dividend of $20.3125 per share of Convertible Preferred Stock. All dividends declared during 2019 were recorded as ~~follows:~~

a reduction of retained earnings. At December 31, ~~2016 and 2015,~~2019, we had ~~no bank~~dividends payable to preferred stock of $1.3 million that was included in “Accrued liabilities — Other”.

3. LONG-TERM DEBT

Long-term debt ~~outstanding. All~~at December 31, 2019 and 2018 consisted of ~~our long-term debt is senior unsecured debt and is, therefore,~~ ~~pari passu~~ ~~with respect to~~ the ~~payment of both principal and interest.~~following:



	December 31, 2019							December 31, 2018
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)			Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discount (1)			Long-term Debt, net
4.375% notes due 2024	$	750,000	$	(3,535	)	$	746,465	$	750,000	$	(4,439	)	$	745,561
3.90% notes due 2027	750,000		(6,289		)	743,711		750,000		(7,007		)	742,993
4.375% notes due 2029	500,000		(4,930		)	495,070		—		—			—
Total long-term debt	$	2,000,000	$	(14,754	)	$	1,985,246	$	1,500,000	$	(11,446	)	$	1,488,554

(1)
The 4.375% notes due 2024 were issued at par, therefore, the amounts shown in the table are for unamortized debt issuance costs only. At December 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% notes were $4.8 million and $1.5 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 4.375% notes due 2029 were $4.3 million and $0.6 million, respectively. At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.4 million and $1.6 million, respectively.

Bank Debt

~~In October 2015,~~

On February 5, 2019, we entered into ~~a new~~an Amended and Restated Credit Agreement for our senior unsecured revolving credit facility ~~(Credit Facility) which matures October 16, 2020. The~~ (“Credit ~~Facility has aggregate commitments of $1.0 billion, with an option to increase~~Facility”). Among other things, the amended and restated credit facility increased the aggregate commitments to $1.25 billion ~~at any time.~~with an option for us to increase the aggregate commitments to $1.5 billion, and extended the maturity date to February 5, 2024. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. As of December 31, ~~2016,~~2019, we had ~~$2.5 million in letters of credit~~0 bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of ~~$997.5 million.~~

$1.248 billion. During the year ended December 31, 2019, we borrowed and repaid an aggregate of $2.12 billion, on the Credit Facility to meet cash requirements as needed.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR (or an alternate rate determined by the administrative agent for the Credit Facility in accordance with the Credit Facility when LIBOR is no longer available) plus 1.125 —- 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 —- 1.0%, based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of 0.125 —- 0.35%, based on the credit rating for our senior unsecured long-term debt.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of December 31, ~~2016,~~2019, we were in compliance with all of the financial ~~and non-financial~~ covenants.

At December 31, ~~2016~~2019 and ~~2015,~~2018, we had ~~$4.5~~$4.0 million and ~~$5.7~~$2.2 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as ~~deferred~~ assets and included in ~~Other assets, net~~“Other assets” in our balance sheets. The costs are being amortized to interest expense ratably over the life of the Credit Facility.

We incurred $3.0 million in additional debt issuance costs in amending our Credit Facility.

Senior Notes

On April 10, 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes due May 15, 2027 at 99.748% of par to yield 3.93% per annum. We received $741.8 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs. The notes bear an annual interest rate of 3.90% and interest is payable semiannually on May 15 and November 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.01%. Along with cash on hand, we used the proceeds to fund the early extinguishment of $750 million aggregate principal amount of 5.875% notes whose original maturity date was May 1, 2022. During the year ended December 31, 2017, we recognized a loss on early extinguishment of debt related to these transactions of $28.2 million, composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.

In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and ~~received net proceeds of $740.9 million, after deducting offering discounts~~interest is payable semiannually on June 1 and ~~costs. The net proceeds were used to pay outstanding bank debt and for general corporate purposes.~~December 1. The effective interest rate on ~~the~~these notes, including the amortization of debt issuance costs, is 4.50%.

In April 2012, we issued $750 million of 5.875% senior notes due 2022 and received net proceeds of $737.0 million, after deducting underwriting discounts and offering costs. We used a portion of the net proceeds to retire our 7.125% senior notes and the remaining proceeds were used to pay outstanding bank debt and for general corporate purposes. The effective interest rate on the notes, including the debt issuance costs, is 6.04%. These senior notes are callable by us beginning May 1, 2017 at a price of 102.938% of face value declining to 100% of face value on May 1, 2020 and thereafter.

Each of our ~~outstanding~~ senior unsecured notes is governed by an indenture containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of December 31, ~~2016. Interest on each~~2019. At December 31, 2019, we had accrued interest related to our notes of ~~the senior notes is payable semi-annually.~~

$12.8 million that was included in “Accrued liabilities — Other”.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. DERIVATIVE ~~INSTRUMENTS/HEDGING~~

INSTRUMENTS

We periodically ~~enter into~~use derivative instruments to mitigate ~~a portion of our potential exposure to a decline~~volatility in commodity ~~prices and the corresponding negative impact on cash flow available for reinvestment.~~prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future ~~revenues~~cash flow from favorable price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our ~~hedging positions. We may hedge up to 50% of our oil and natural gas production on a forward five quarter basis.~~

~~The following tables summarize our~~ derivative ~~contracts as~~positions from current levels.

As of December 31, ~~2016:~~

First

Second

Third

Fourth

Quarter

Quarter

Quarter

Quarter

Total

Oil Collars:

2017:

WTI (1)

Volume (Bbls)

1,800,000

1,820,000

1,472,000

1,012,000

6,104,000

Wtd Avg Price - Floor

$
43.08

$
43.08

$
45.09

$
46.27

$
44.09

Wtd Avg Price - Ceiling

$
52.90

$
52.90

$
55.50

$
56.98

$
54.20

2018:

WTI (1)

Volume (Bbls)

540,000

—

—

—

540,000

Wtd Avg Price - Floor

$
47.33

$
—

$
—

$
—

$
47.33

Wtd Avg Price - Ceiling

$
59.11

$
—

$
—

$
—

$
59.11

~~(1)~~ ~~WTI refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange.~~

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

First

Second

Third

Fourth

Quarter

Quarter

Quarter

Quarter

Total

Gas Collars:

2017:

PEPL (1)

Volume (MMBtu)

9,900,000

10,010,000

8,280,000

5,520,000

33,710,000

Wtd Avg Price - Floor

$
2.52

$
2.52

$
2.61

$
2.79

$
2.59

Wtd Avg Price - Ceiling

$
3.04

$
3.04

$
3.12

$
3.22

$
3.09

Perm EP (1)

Volume (MMBtu)

8,100,000

8,190,000

5,520,000

3,680,000

25,490,000

Wtd Avg Price - Floor

$
2.59

$
2.59

$
2.68

$
2.86

$
2.65

Wtd Avg Price - Ceiling

$
3.10

$
3.10

$
3.16

$
3.28

$
3.14

2018:

PEPL (1)

Volume (MMBtu)

2,700,000

—

—

—

2,700,000

Wtd Avg Price - Floor

$
2.90

$
—

$
—

$
—

$
2.90

Wtd Avg Price - Ceiling

$
3.32

$
—

$
—

$
—

$
3.32

Perm EP (1)

Volume (MMBtu)

1,800,000

—

—

—

1,800,000

Wtd Avg Price - Floor

$
3.00

$
—

$
—

$
—

$
3.00

Wtd Avg Price - Ceiling

$
3.41

$
—

$
—

$
—

$
3.41

~~(1)~~ PEPL refers to the Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC. Perm EP refers to the El Paso Natural Gas Company, Permian Basin Index as quoted in Platt’s Inside FERC.

2019, we have entered into oil and gas collars and oil basis swaps. Under ~~a collar agreement,~~our collars, we receive the difference between the published index price and a floor price if the index price is below the ~~floor. We~~floor price or we pay the difference between the ceiling price and the index price if the index price is above the ~~contracted~~ ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price plus a fixed differential and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI NYMEX (Cushing Oklahoma) price and the WTI Midland price. For our Permian and Mid-Continent gas production, the contract prices in our collars are consistent with the index prices used to sell our production. The following tables summarize our outstanding derivative contracts as of December 31, 2019:



Oil Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
WTI (1)
Volume (Bbls)	3,549,000		2,821,000		2,116,000		2,116,000		10,602,000
Weighted Avg Price - Floor	$	52.40	$	50.43	$	49.80	$	49.80	$	50.84
Weighted Avg Price - Ceiling	$	64.48	$	61.55	$	60.59	$	60.59	$	62.15

2021:
WTI (1)
Volume (Bbls)	1,350,000		455,000		—		—		1,805,000
Weighted Avg Price - Floor	$	49.70	$	50.00	$	—	$	—	$	49.77
Weighted Avg Price - Ceiling	$	59.41	$	60.14	$	—	$	—	$	59.59


(1)	The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”).

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Gas Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
PEPL (1)
Volume (MMBtu)	8,190,000		5,460,000		2,760,000		2,760,000		19,170,000
Weighted Avg Price - Floor	$	1.92	$	1.90	$	1.85	$	1.85	$	1.90
Weighted Avg Price - Ceiling	$	2.36	$	2.28	$	2.31	$	2.31	$	2.32
Perm EP (2)
Volume (MMBtu)	3,640,000		2,730,000		1,840,000		1,840,000		10,050,000
Weighted Avg Price - Floor	$	1.40	$	1.40	$	1.35	$	1.35	$	1.38
Weighted Avg Price - Ceiling	$	1.79	$	1.82	$	1.66	$	1.66	$	1.75
Waha (3)
Volume (MMBtu)	4,550,000		2,730,000		—		—		7,280,000
Weighted Avg Price - Floor	$	1.50	$	1.57	$	—	$	—	$	1.53
Weighted Avg Price - Ceiling	$	1.87	$	1.97	$	—	$	—	$	1.91
2021:
PEPL (1)
Volume (MMBtu)	900,000		—		—		—		900,000
Weighted Avg Price - Floor	$	1.85	$	—	$	—	$	—	$	1.85
Weighted Avg Price - Ceiling	$	2.31	$	—	$	—	$	—	$	2.31


(1)	The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.


(2)	The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.


(3)	The index price for these collars is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.



Oil Basis Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
WTI Midland (1)
Volume (Bbls)	2,639,000		1,911,000		1,288,000		1,288,000		7,126,000
Weighted Avg Differential (2)	$	0.25	$	0.30	$	0.65	$	0.65	$	0.40
2021:
WTI Midland (1)
Volume (Bbls)	540,000		—		—		—		540,000
Weighted Avg Differential (2)	$	0.56	$	—	$	—	$	—	$	0.56


(1)	The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.


(2)	The index price we receive under these basis swaps is WTI as quoted on the NYMEX plus the weighted average differential shown in the table.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes our derivative contracts entered into subsequent to December 31, 2019 through February 19, 2020:



Oil Basis Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
WTI Midland (1)
Volume (Bbls)	300,000		455,000		460,000		460,000		1,675,000
Weighted Avg Differential (2)	$	1.02	$	1.02	$	1.02	$	1.02	$	1.02
2021:
WTI Midland (1)
Volume (Bbls)	450,000		455,000		—		—		905,000
Weighted Avg Differential (2)	$	1.02	$	1.02	$	—	$	—	$	1.02


(1)	The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.


(2)	The index price we receive under these basis swaps is WTI as quoted on the NYMEX less the weighted average differential shown in the table.

Derivative Gains and Losses

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to ~~account for~~designate our derivatives as ~~cash flow hedges. Therefore,~~hedging instruments for accounting purposes and, therefore, we ~~recognize settlements and~~do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of ~~assets~~our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or ~~liabilities relating to our open~~loss on derivative ~~contracts in earnings.~~instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows.

The following table presents the components of Loss (gain) on derivative instruments, net ~~(gains) and losses from settlements and changes in fair value of our derivative contracts, and the (gains) losses from cash settlements during~~for the periods ~~shown below.~~

Years Ended December 31,

(in thousands)

2016

2015

2014

(Gain) loss on derivative instruments, net:

Natural gas contracts

$
20,995

$
(4,472
)
$
6,751

Oil contracts

34,754

(6,774
)
(10,512
)
(Gain) loss on derivative instruments, net

$
55,749

$
(11,246
)
$
(3,761
)
Settlement (gains) losses:

Natural gas contracts

$
(6,467
)
$
—

$
4,287

Oil contracts

(970
)
—

(11,928
)
Settlement (gains) losses

$
(7,437
)
$
—

$
(7,641
)

indicated.



	Years Ended December 31,
(in thousands)	2019			2018			2017
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts	$	(13,114	)	$	15,742		$	(40,226	)
Oil contracts	76,833			(126,130		)	17,383
	63,719			(110,388		)	(22,843		)
Cash payments (receipts) on derivative instruments, net:
Gas contracts	(40,114		)	(13,794		)	(4,557		)
Oil contracts	53,245			38,223			6,190
	13,131			24,429			1,633
Loss (gain) on derivative instruments, net	$	76,850		$	(85,959	)	$	(21,210	)

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Fair Value

Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to ~~enforceable~~ master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty. Our accounting policy is to not offset asset and liability positions in our ~~accompanying~~ balance sheets.

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The following ~~table presents~~tables present the amounts and classifications of our derivative assets and liabilities as of December 31, ~~2016~~2019 and ~~2015,~~2018, as well as the potential effect of netting arrangements on ~~contracts with the same counterparty.~~

December 31, 2016:

(in thousands)

Balance Sheet Location

Asset

Liability

Oil contracts

Current liabilities — Derivative instruments

$
—

$
27,892

Natural gas contracts

Current liabilities — Derivative instruments

—

21,478

Oil contracts

Non-current liabilities — Derivative instruments

—

1,059

Natural gas contracts

Non-current liabilities — Derivative instruments

—

1,511

Total gross amounts presented in accompanying balance sheet

—

51,940

Less: gross amounts not offset in the accompanying balance sheet

—

—

Net amount:

$
—

$
51,940

December 31, 2015:

(in thousands)

Balance Sheet Location

Asset

Liability

Oil contracts

Current assets — Derivative instruments

$
6,774

$
—

Natural gas contracts

Current assets — Derivative instruments

3,971

—

Natural gas contracts

Non-current assets — Derivative instruments

501

—

Total gross amounts presented in accompanying balance sheet

11,246

—

Less: gross amounts not offset in the accompanying balance sheet

—

—

Net amount:

$
11,246

$
—

our recognized derivative asset and liability amounts.



		December 31, 2019
(in thousands)	Balance Sheet Location	Asset			Liability
Oil contracts	Current assets — Derivative instruments	$	1,624		$	—
Gas contracts	Current assets — Derivative instruments	16,320			—
Oil contracts	Non-current assets — Derivative instruments	580			—
Oil contracts	Current liabilities — Derivative instruments	—			16,681
Oil contracts	Non-current liabilities — Derivative instruments	—			824
Gas contracts	Non-current liabilities — Derivative instruments	—			194
Total gross amounts presented in the balance sheet		18,524			17,699
Less: gross amounts not offset in the balance sheet		(9,865		)	(9,865		)
Net amount		$	8,659		$	7,834



		December 31, 2018
(in thousands)	Balance Sheet Location	Asset			Liability
Oil contracts	Current assets — Derivative instruments	$	94,240		$	—
Gas contracts	Current assets — Derivative instruments	7,699			—
Oil contracts	Non-current assets — Derivative instruments	9,246			—
Oil contracts	Current liabilities — Derivative instruments	—			23,378
Gas contracts	Current liabilities — Derivative instruments	—			4,249
Oil contracts	Non-current liabilities — Derivative instruments	—			311
Gas contracts	Non-current liabilities — Derivative instruments	—			1,956
Total gross amounts presented in the balance sheet		111,185			29,894
Less: gross amounts not offset in the balance sheet		(29,894		)	(29,894		)
Net amount		$	81,291		$	—

We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. We mitigate our exposure to any single counterparty by contracting with a number of financial institutions, each of which ~~have~~has a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our ~~hedge~~derivative liability ~~positions. Because some of the member banks have discontinued hedging activities, in~~positions, nor do we require our counterparties to post collateral for our benefit. In the future we may ~~hedge~~enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement ~~date (exit price).~~date. The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

The following table provides fair value measurement information for certain assets and liabilities as of December 31, ~~2016~~2019 and ~~2015.~~

December 31, 2016

December 31, 2015

Book

Fair

Book

Fair

(in thousands)

Value

Value

Value

Value

Financial Assets (Liabilities):

5.875% Notes due 2022

$
(750,000
)
$
(782,835
)
$
(750,000
)
$
(723,750
)
4.375% Notes due 2024

$
(750,000
)
$
(779,453
)
$
(750,000
)
$
(683,318
)
Derivative instruments — assets

$
—

$
—

$
11,246

$
11,246

Derivative instruments — liabilities

$
(51,940
)
$
(51,940
)
$
—

$
—

2018.



	December 31, 2019						December 31, 2018
(in thousands)	Book Value			Fair Value			Book Value			Fair Value
Financial Assets (Liabilities):
4.375% Notes due 2024	$	(750,000	)	$	(792,225	)	$	(750,000	)	$	(744,578	)
3.90% Notes due 2027	$	(750,000	)	$	(778,050	)	$	(750,000	)	$	(701,273	)
4.375% Notes due 2029	$	(500,000	)	$	(530,400	)	$	—		$	—
Derivative instruments — assets	$	18,524		$	18,524		$	111,185		$	111,185
Derivative instruments — liabilities	$	(17,699	)	$	(17,699	)	$	(29,894	)	$	(29,894	)

Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The ~~following methods and assumptions were used to estimate the~~ fair value ~~of the assets and liabilities in the table above.~~

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~Debt~~ (Level 1)

~~The fair value~~ of our ~~4.375% and 5.875%~~ fixed rate notes was based on ~~their last traded value before year end.~~

~~Derivative Instruments (Level 2)~~

quoted market prices. The fair value of our derivative instruments (Level 2) was estimated using discounted cash flow and option pricing models. These models use certain observable variables including forward ~~price and~~prices, volatility curves, interest rates, and ~~the strike prices for the instruments.~~credit ratings and spreads. The fair value estimates are adjusted relative to non-performance risk as appropriate. See Note 4 for further information on the fair value of our derivative instruments.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Included in “Accrued liabilities — ~~other”~~Other” at December 31, ~~2016~~2019 are: (i) accrued operating expenses (e.g. production, transportation, and ~~2015, respectively, are 1) liabilities~~gathering expenses) of approximately ~~$19.3~~$74.7 million and ~~$23.1~~(ii) accrued general and administrative, primarily payroll-related, costs of approximately $43.3 million. Included in “Accrued liabilities — Other” at December 31, 2018 are: (i) accrued operating expenses (e.g. production, transportation, and gathering expenses) of approximately $69.1 million, (ii) accrued general and administrative, primarily payroll-related, costs of approximately $47.4 million, and (iii) an accrual of approximately $35.8 million representing the amount by which checks issued, but not yet presented to our banks, exceeded balances in applicable bank ~~accounts; 2) accrued payroll related costs~~accounts.

Most of ~~$43.5 million and $21.5 million; and 3) accrued operating expenses of $53.9 million and $60.4 million.~~

~~Our~~our accounts receivable balances are ~~primarily~~uncollateralized and result from ~~either purchasers~~transactions with other companies in the oil and gas industry. Concentration of ~~our oil, gas, and NGL production (customers) or from exploration and production companies which own interests in properties we operate. This industry concentration has the potential to~~customers may impact our overall ~~exposure to~~ credit risk ~~either positively or negatively,~~ because our customers ~~and joint working interest owners~~ may be similarly affected by changes in ~~industry conditions.~~

economic or other conditions within the industry.

We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary.

We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the amount of the reserve may be reasonably estimated. At December 31, ~~2016~~2019 and ~~2015,~~2018, the allowance for doubtful accounts totaled ~~$1.6~~$3.6 million and ~~$1.8~~$2.7 million, respectively.

Major Customers

~~Our major customer during 2016 was Sunoco Logistics Partners L.P. (Sunoco), which accounted for 20%~~

In each of the years ended December 31, 2019, 2018, and 2017, we made sales to two customers that each amounted to 10% or more of our consolidated ~~revenues. Sunoco~~revenues for the respective year. Sales to those two customers accounted for 29% and ~~Enterprise Products Partners L.P. (Enterprise) were our major customers in 2015, accounting for 21% and 17%~~25%, respectively, of our consolidated revenues ~~that year. During 2014, Sunoco~~in 2019, 21% and ~~Enterprise each accounted for 19%~~23%, respectively, of our consolidated revenues in 2018, and ~~Oneok Partners, L.P. accounted for 10%~~13% and 21%, respectively, of our consolidated ~~revenues.~~

revenues in 2017.

If ~~Sunoco~~any one of our major customers was to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production with some delay. If multiple significant customers were to discontinue purchasing our ~~product,~~production, we believe there would be challenges initially, but ample markets to handle the disruption.

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

6. STOCK-BASED AND OTHER COMPENSATION

Equity Incentive Plan

Our 2019 Equity Incentive Plan (the “2019 Plan”) was approved by stockholders in May 2019 and no awards will be made under our previous plans. Outstanding awards under the previous plans were not impacted. A total of 6.3 million shares of common stock may be issued under the 2019 Plan, including shares available from the previous plans. The 2019 Plan provides for grants of options, stock appreciation rights, restricted stock, restricted stock units, performance stock units, cash awards, and other stock-based awards.

Stock-based Compensation Cost

We have recognized non-cash stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.

Years Ended December 31,

(in thousands)

2016

2015

2014

Restricted stock awards

Performance stock awards

$
24,183

$
18,991

$
12,141

Service-based stock awards

18,391

14,547

13,607

42,574

33,538

25,748

Stock option awards

2,565

2,803

3,057

45,139

36,341

28,805

Less amounts capitalized to oil and gas properties

(20,616
)
(16,782
)
(13,804
)
Compensation expense

$
24,523

$
19,559

$
15,001



	Years Ended December 31,
(in thousands)	2019			2018			2017
Restricted stock awards:
Performance stock awards	$	21,590		$	23,083		$	26,020
Service-based stock awards	25,611			20,385			19,746
	47,201			43,468			45,766
Stock option awards	1,903			2,456			2,599
Total stock compensation cost	49,104			45,924			48,365
Less amounts capitalized to oil and gas properties	(22,706		)	(23,029		)	(22,109		)
Stock compensation expense	$	26,398		$	22,895		$	26,256

Periodic stock compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards. The increase in ~~2016~~total stock compensation cost in 2019 as compared to 2018 is primarily due to performance stock award forfeitures that occurred during 2018 as well as due to expense on awards granted during the periods more than offsetting the expense on awards that vested during the periods. Our accounting policy is to account for forfeitures in compensation cost when they occur.

Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017. The amendments within ASU 2016-09 related to ~~performance awards granted in December 2015,~~the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a ~~portion of which were amortized during 2016, forfeiture rate adjustments on the service-based stock awards,~~modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by $33.1 million, reduced beginning accumulated deficit by $28.7 million, and ~~the acceleration of expense on a portion of service-based awards for employees who participated in a voluntary early retirement incentive program.~~

~~Equity Incentive Plan~~

~~Our 2014 Equity Incentive Plan (the 2014 Plan) was approved~~increased beginning additional paid-in capital by stockholders in May 2014 and our previous plan was terminated at that time. Outstanding awards under the previous plan were not impacted. A total of 6.6 million shares of common stock may be issued under the 2014 Plan, including shares available from the previous plan. The 2014 Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, dividend equivalents and other stock-based awards.

$4.4 million.

Restricted Stock

The following table provides information about restricted stock awards granted during the last three years.

Years Ended December 31,

2016

2015

2014

Weighted

Weighted

Weighted

Average

Average

Average

Number

Grant-Date

Number

Grant-Date

Number

Grant-Date

of Shares

Fair Value

of Shares

Fair Value

of Shares

Fair Value

Performance stock awards

269,915

$
117.63

263,939

$
87.12

316,441

$
83.22

Service-based stock awards

208,724

$
114.61

207,180

$
114.80

170,402

$
136.72

Total restricted stock awards

478,639

$
116.31

471,119

$
99.29

486,843

$
101.95



	Years Ended December 31,
	2019			2018			2017
	Number of Shares	Weighted Average Grant Date Fair Value		Number of Shares	Weighted Average Grant Date Fair Value		Number of Shares	Weighted Average Grant Date Fair Value
Performance stock awards	264,393	$	47.66	123,533	$	90.26	300,525	$	89.46
Service-based stock awards	681,988	$	45.88	469,438	$	81.29	251,312	$	94.04
Total restricted stock awards	946,381	$	46.38	592,971	$	83.16	551,837	$	91.55

Performance stock awards ~~were~~are granted to eligible executives and are subject to service and market condition-based vesting determined by our stock price performance relative to a defined peer ~~group’s~~groups’ stock price performance. ~~After~~For awards granted prior to 2018, after three years of continued service, an executive will be entitled to vest in 50% to 100% of the ~~award.~~award depending on the stock price performance. For awards granted in 2018 and 2019, after three years of continued service, an executive will be entitled to vest in 0% to 200% of the award depending on the stock price performance. In accordance with Internal Revenue Code Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. Service-based stock awards are granted to ~~other~~ eligible employees and non-employee directors and have vesting schedules ~~of three~~ranging from one to five years.

The majority of our service-based stock awards cliff vest five years from the grant date.

Compensation cost for the performance stock awards is based on the ~~grant-date~~grant date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for the service-based ~~vesting restricted shares~~stock awards is based upon the ~~grant-date~~grant date market value of the award. Such costs are recognized ratably over the applicable vesting period.

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The following table provides information on restricted stock activity during the year.



	Service-based				Performance (subject to market conditions)
	Number of Shares		Weighted Average Grant Date Fair Value		Number of Shares		Weighted Average Grant Date Fair Value
Outstanding as of January 1, 2019	1,135,882		$	99.12	650,096		$	100.42
Vested	(155,751	)	$	126.20	(139,723	)	$	117.63
Granted	681,988		$	45.88	264,393		$	47.66
Canceled (1)	—		$	—	(109,789	)	$	117.63
Forfeited	(23,050	)	$	90.97	—		$	—
Outstanding as of December 31, 2019	1,639,069		$	74.51	664,977		$	72.99

Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Performance

Service-based

(subject to market conditions)

Weighted

Weighted

Average

Average

Number of

Grant-Date

Number of

Grant-Date

Shares

Fair Value

Shares

Fair Value

Outstanding as of January 1, 2016

998,182

$
91.37

829,808

$
82.99

Vested

(243,313
)
$
92.37

(287,108
)
$
81.53

Granted

208,724

$
114.61

269,915

$
117.63

Canceled

(28,870
)
$
110.84

(3,345
)
$
87.14

Outstanding as of December 31, 2016

934,723

$
96.57

809,270

$
96.41

(1) These performance shares were canceled since the market condition was not satisfied as of the end of the performance period.

The total ~~fair~~vest date market value of restricted stock that vested during the years ended December 31, 2019, 2018, and 2017 was ~~$67.9~~$15.1 million, ~~in 2016, $52.2 million in 2015, and~~ $34.1 million, ~~in 2014.~~

and $54.4 million, respectively.

Unrecognized compensation cost related to unvested restricted stock at December 31, ~~2016~~2019 was ~~$96.0~~$96.9 million. We expect to recognize that cost over a weighted average period of ~~2.8~~2.6 years.

Restricted Units

As of December 31, ~~2016~~2019 and ~~2015,~~2018, we had 8,838 restricted units outstanding. These represent restricted units held by a non-employee director who has elected to defer payment of common stock represented by the units until termination of his service on the Board of Directors.

Stock Options

Options ~~that have been granted under the 2014 plan and previous plans~~outstanding as of December 31, 2019 expire seven to ten years from the grant date and have service-based vesting ~~schedules~~whereby the awards vest in increments of one-third on each of the first three ~~to five years.~~anniversary dates of the grant. The exercise price for an option under the ~~2014~~2019 Plan and the plan in effect immediately prior to the 2019 Plan, is at least equal to the closing price of our common stock as reported by the New York Stock Exchange ~~(NYSE)~~(“NYSE”) on the date of grant. The previous plans provided that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the NYSE on the date of grant.

Compensation cost related to stock options is based on the ~~grant-date~~grant date fair value of the award and is recognized ratably over the applicable vesting period. We estimate the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the ~~probability of option exercise,~~ expected years until ~~exercise and potential forfeitures.~~exercise. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.

The following summarizes ~~the~~information regarding options granted, ~~and related information, and~~including the assumptions used to determine the fair value of those options.

Years Ended December 31,

2016

2015

2014

Options granted

89,850

69,000

82,500

Weighted average grant-date fair value

$
33.38

$
37.56

$
41.69

Weighted average exercise price

$
114.07

$
115.28

$
139.02

Total fair value (in thousands)

$
2,999

$
2,592

$
3,439

Expected years until exercise

4.0

5.0

4.0

Expected stock volatility

36.7
%
36.6
%
36.7
%
Dividend yield

0.3
%
0.6
%
0.5
%
Risk-free interest rate

0.96
%
1.6
%
1.8
%



	Years Ended December 31,
	2019			2018			2017
Options granted	132,900			92,050			96,100
Weighted average grant date fair value	$	12.14		$	26.71		$	28.37
Weighted average exercise price	$	42.78		$	83.28		$	92.37
Total fair value (in thousands)	$	1,613		$	2,458		$	2,727
Expected years until exercise	4.9			5.0			4.5
Expected stock volatility	37.1		%	34.7		%	35.0		%
Dividend yield	1.9		%	0.9		%	0.3		%
Risk-free interest rate	1.4		%	2.7		%	1.7		%

Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Information about outstanding stock options is summarized below.

Weighted

Weighted

Aggregate

Average

Average

Intrinsic

Exercise

Remaining

Value

Options

Price

Term

(in thousands)

Outstanding as of January 1, 2016

299,229

$
93.76

Exercised

(63,727
)
$
75.37

Granted

89,850

$
114.07

Canceled

(1,997
)
$
139.02

Forfeited

(15,545
)
$
123.00

Outstanding as of December 31, 2016

307,810

$
101.72

4.6 Years

$
10,846

Exercisable as of December 31, 2016

159,449

$
86.99

3.4 Years

$
7,996



	Number of Options		Weighted Average Exercise Price		Weighted Average Remaining Term	Aggregate Intrinsic Value (in thousands)
Outstanding as of January 1, 2019	420,332		$	99.01
Exercised	(29,222	)	$	43.37
Granted	132,900		$	42.78
Canceled	(10,661	)	$	115.06
Forfeited	(17,811	)	$	90.66
Outstanding as of December 31, 2019	495,538		$	87.17	4.3 years	$	1,201
Exercisable as of December 31, 2019	287,283		$	107.97	2.9 years	$	—

The following table provides information regarding options exercised and the ~~grant-date~~grant date fair value of options vested.

Years Ended December 31,

(in thousands)

2016

2015

2014

Number of options exercised

63,727

141,517

211,258

Cash received from option exercises

$
4,804

$
8,451

$
11,898

Tax benefit from option exercises included in paid-in-capital (1)

$
—

$
4,442

$
—

Intrinsic value of options exercised

$
2,994

$
7,467

$
15,384

Grant-date fair value of options vested

$
2,486

$
2,734

$
4,419

~~(1)~~ ~~No tax benefit is recorded until the benefit reduces current taxes payable. However, in 2015 we recognized tax benefit on prior period option exercises.~~



	Years Ended December 31,
(in thousands)	2019		2018		2017
Cash received from option exercises	$	1,267	$	2,241	$	394
Intrinsic value of options exercised	$	425	$	1,030	$	257
Grant date fair value of options vested	$	2,262	$	2,547	$	2,227

The following summary reflects the status of non-vested stock options as of December 31, ~~2016~~2019 and changes during the year.

Weighted

Weighted

Average

Average

Grant-Date

Exercise

Options

Fair Value

Price

Non-vested as of January 1, 2016

157,041

$
34.77

$
111.58

Vested

(82,985
)
$
29.95

$
101.46

Granted

89,850

$
33.38

$
114.07

Forfeited

(15,545
)
$
19.70

$
123.00

Non-vested as of December 31, 2016

148,361

$
35.58

$
117.55



	Number of Options		Weighted Average Grant Date Fair Value		Weighted Average Exercise Price
Non-vested as of January 1, 2019	170,241		$	28.29	$	91.05
Vested	(77,075	)	$	29.35	$	95.94
Granted	132,900		$	12.14	$	42.78
Forfeited	(17,811	)	$	28.19	$	90.66
Non-vested as of December 31, 2019	208,255		$	17.60	$	58.47

As of December 31, ~~2016,~~2019, there was ~~$3.6~~$2.8 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost ~~on a pro rata basis~~ over a weighted average period of ~~2.0~~2.1 years.

Other Compensation

We maintain and sponsor a contributory 401(k) plan for our employees. ~~Annual matching costs~~Employer contributions related to the plan were ~~$6.7~~$8.7 million, ~~$6.4~~$13.1 million, and ~~$11.0~~$10.4 million for ~~2016, 2015,~~2019, 2018, and ~~2014,~~2017, respectively.

Included in the 2018 and 2017 amounts were accrued employer discretionary contributions. No such employer discretionary contributions were accrued for 2019.

Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. EARNINGS (LOSS) PER SHARE

The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below.

Years Ended December 31,

(in thousands, except per share data)

2016

2015

2014

Basic:

Net income (loss)

$
(408,803
)
$
(2,579,604
)
$
526,498

Participating securities’ share in earnings (1)

—

—

(10,329
)
Net income (loss) applicable to common stockholders

$
(408,803
)
$
(2,579,604
)
$
516,169

Diluted:

Net income (loss)

$
(408,803
)
$
(2,579,604
)
$
526,498

Participating securities’ share in earnings (1)

—

—

(10,314
)
Net income (loss) applicable to common stockholders

$
(408,803
)
$
(2,579,604
)
$
516,184

Shares:

Basic shares outstanding

93,379

92,992

85,679

Dilutive effect of stock options

—

—

131

Fully diluted common stock

93,379

92,992

85,810

Excluded (2)

2,061

2,136

94

Earnings (loss) per share to common stockholders (3):

Basic

$
(4.38
)
$
(27.75
)
$
6.01

Diluted

$
(4.38
)
$
(27.75
)
$
6.00

~~(1)~~ ~~Participating securities are not included in undistributed earnings when a loss exists.~~

~~(2)~~ ~~Inclusion of certain shares would have an anti-dilutive effect.~~

~~(3)~~ Earnings (loss) per share isare based on actual figures rather than the rounded figures presented.



	Year Ended December 31, 2019
(in thousands, except per share information)	Income (Numerator)			Shares (Denominator)	Per-Share Amount
Net loss	$	(124,619	)
Less: dividends attributable to participating securities (1)	(1,519		)
Less: preferred stock dividends	(5,078		)
Basic loss per share
Loss available to common stockholders	(131,216		)	98,789	$	(1.33	)
Effects of dilutive securities
Options (2)	—			—
Diluted loss per share
Loss available to common stockholders and assumed conversions	$	(131,216	)	98,789	$	(1.33	)



	Year Ended December 31, 2018
(in thousands, except per share information)	Income (Numerator)			Shares (Denominator)	Per-Share Amount
Net income	$	791,851
Less: dividends and net income attributable to participating securities	(11,087		)
Basic earnings per share
Income available to common stockholders	780,764			93,793	$	8.32
Effects of dilutive securities
Options (2)	3			27
Diluted earnings per share
Income available to common stockholders and assumed conversions	$	780,767		93,820	$	8.32



	Year Ended December 31, 2017
(in thousands, except per share information)	Income (Numerator)			Shares (Denominator)	Per-Share Amount
Net income	$	494,329
Less: dividends and net income attributable to participating securities	(8,551		)
Basic earnings per share
Income available to common stockholders	485,778			93,466	$	5.19
Effects of dilutive securities
Options (2)	3			43
Diluted earnings per share
Income available to common stockholders and assumed conversions	$	485,781		93,509	$	5.19

Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Participating securities do not have a contractual obligation to share in the losses of the entity, therefore, net losses are not attributable to participating securities.
(2) Inclusion of certain potential common shares would have an anti-dilutive effect, therefore, these shares were excluded from the calculations of diluted earnings per share. Excluded from the calculation for the year ended December 31, 2019 were 495.5 thousand potential common shares from the assumed exercise of employee stock options, 508.6 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock, and 37.4 thousand potential common shares from the assumed vesting of incremental shares of unvested restricted stock awards. Excluded from the calculations for the years ended December 31, 2018 and 2017 were potential common shares from the assumed exercise of employee stock options of 387.7 thousand and 302.9 thousand, respectively. See Note 2 for further information regarding our Convertible Preferred Stock and Note 6 for further information regarding our stock awards.

8. ASSET RETIREMENT OBLIGATIONS

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, ~~2016~~2019 and ~~2015.~~

(in thousands)

2016

2015

Asset retirement obligation at January 1,

$
164,105

$
173,008

Liabilities incurred

3,914

4,114

Liability settlements and disposals

(24,108
)
(25,061
)
Accretion expense

7,595

7,682

Revisions of estimated liabilities

3,017

4,362

Asset retirement obligation at December 31,

154,523

164,105

Less current obligation

13,753

10,248

Long-term asset retirement obligation

$
140,770

$
153,857

~~During 2016~~2018.



(in thousands)	2019				2018
Asset retirement obligation at January 1,	$	166,904			$	169,469
Liabilities incurred	21,511				9,899
Liability settlements and disposals	(19,595		)		(21,550		)
Accretion expense	7,499			��	7,318
Revisions of estimated liabilities	5,550				1,768
Asset retirement obligation at December 31,	181,869				166,904
Less current obligation	27,824				14,146
Long-term asset retirement obligation	$	154,045			$	152,758

For the year ended December 31, 2019, liabilities incurred included $9.4 million for the Resolute acquisition. For the years ended, December 31, 2019 and ~~2015,~~2018, the liability settlements and disposals included ~~$14.9~~$9.3 million and ~~$13.3~~$13.7 million, respectively, related to properties that were sold.

Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. INCOME TAXES

The components of the provision for income taxes are as follows:

Years Ended December 31,

(in thousands)

2016

2015

2014

Current taxes:

Federal expense

$
—

$
14,417

$
—

State (benefit) expense

(1,115
)
293

404

(1,115
)
14,710

404

Deferred taxes:

Federal (benefit) expense

(201,529
)
(1,386,086
)
293,385

State (benefit) expense

(11,757
)
(100,353
)
16,058

(213,286
)
(1,486,439
)
309,443

$
(214,401
)
$
(1,471,729
)
$
309,847



	Years Ended December 31,
(in thousands)	2019			2018			2017
Current taxes:
Federal benefit	$	—		$	(3,007	)	$	(2,810	)
State expense (benefit)	532			383			(2		)
	532			(2,624		)	(2,812		)
Deferred taxes:
Federal (benefit) expense	(24,055		)	211,717			173,859
State (benefit) expense	(2,847		)	21,563			16,620
	(26,902		)	233,280			190,479
	$	(26,370	)	$	230,656		$	187,667

Federal income tax expense (benefit) for the years presented differs from the amounts that would be provided by applying the U.S. federal income tax rate, primarily due to the effect of state income taxes, non-deductible expenses, and ~~revisions.~~changes in tax laws and tax rates enacted in the period. Reconciliations of the income tax expense (benefit) calculated at the federal statutory rate of 21% for 2019 and 2018 and 35% for 2017 to the total income tax expense (benefit) are as follows:

Years Ended December 31,

(in thousands)

2016

2015

2014

Provision at statutory rate

$
(218,122
)
$
(1,417,967
)
$
292,721

Effect of state taxes

(10,237
)
(64,794
)
16,321

Revision of previous balances

7,181

5,997

—

Other permanent differences

5,296

5,035

805

Change in valuation allowance

1,481

—

—

Income tax expense (benefit)

$
(214,401
)
$
(1,471,729
)
$
309,847



	Years Ended December 31,
(in thousands)	2019			2018			2017
Provision at statutory rate	$	(31,708	)	$	214,726		$	238,699
Effect of state taxes	(1,717		)	18,795			10,074
Acquisition-related costs	1,318			—			—
Tax credits and other permanent differences	2,548			1,583			5,442
Change in valuation allowance, net	—			(1,376		)	486
Stock-based compensation	3,189			(3,072		)	(5,888		)
Impact of reduction in federal statutory rate	—			—			(61,146		)
Income tax (benefit) expense	$	(26,370	)	$	230,656		$	187,667

Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As a result of the enactment of H.R.1 (Public Law 115-97) on December 22, 2017, we remeasured our deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the U.S. income tax rate from 35% to 21% for years after 2017. As a result of this remeasurement, we recorded an income tax benefit of $61.1 million and a corresponding $61.1 million decrease in net deferred tax liabilities as of December 31, 2017.

The components of net deferred taxes are as follows:

December 31,

(in thousands)

2016

2015

Assets:

Stock compensation and other accrued amounts

$
58,306

$
32,084

Net operating loss carryforward, net of valuation allowance

399,912

305,506

Credit carryforward

6,016

6,016

464,234

343,606

Liabilities:

Property, plant and equipment

(408,399
)
(500,768
)

Net deferred tax assets (liabilities)

$
55,835

$
(157,162
)



	December 31,
(in thousands)	2019			2018
Assets:
Stock compensation and other accrued amounts	$	31,521		$	8,229
Net operating loss and other carryforwards, net of valuation allowance	454,743			266,011
Credit carryforward, net of valuation allowance	3,936			3,513
	490,200			277,753
Liabilities:
Property, plant and equipment	(828,624		)	(612,226		)
Net deferred tax liabilities	$	(338,424	)	$	(334,473	)

On March 1, 2019, we completed the acquisition of Resolute. For federal income tax purposes, the acquisition was a tax-free merger whereby Cimarex acquired carryover tax basis in Resolute’s tax assets and liabilities. As of December 31, 2019, we recorded a net deferred tax liability of $31.1 million to reflect the difference between the fair value of Resolute’s assets and liabilities recorded in the acquisition and the income tax basis of the assets and liabilities assumed. See Note 13 for more information regarding the preliminary purchase price allocation and subsequent adjustments made to it. The deferred tax liability includes certain deferred tax assets net of valuation allowances.

Because the acquisition resulted in a greater than 50% ownership change in Resolute, the tax attributes Cimarex acquired from Resolute are subject to limitation pursuant to Section 382 of the Internal Revenue Code. Our ability to use the Resolute net operating losses (“NOLs”) and credits acquired is limited to an annual amount plus any built-in gains recognized within five years of the ownership change. The annual limitation amount is $19.6 million and the net unrealized built-in gain is projected to be $253.9 million. The acquired Resolute federal NOLs of $746.3 million have been reduced by a $57.6 million valuation allowance. Additionally, a full valuation allowance was recorded on an acquired capital loss carryforward of $67.7 million and enhanced oil recovery credit carryforwards of $4.0 million to reflect the expected tax effect of the Section 382 limitation. The Resolute federal NOLs will begin to expire in 2032.

At December 31, ~~2016,~~2019, we had a U.S. net tax operating loss carryforward (including Resolute) of approximately ~~$1,182.4 million,~~$1.93 billion, which would expire in years ~~2031~~2032 through ~~2036.~~2039. We believe that the carryforward, net of valuation allowance, will be utilized before it expires. We recorded a ~~$10.4~~$9.7 million increase to the net operating loss carryforward at December 31, ~~2016, for certain state losses~~2019 and a corresponding $9.7 million increase into the valuation allowance related to state net operating ~~loss valuation allowance of $11.9 million. The net decrease in the state net operating losses after reduction for the valuation allowance was $1.5 million.~~losses. The total valuation allowance on state net operating losses at December 31, ~~2016,~~2019 was ~~$82.0~~$119.0 million ~~because~~since it is not more likely than not that these additional state net operating losses will be utilized before they expire. Approximately $90.9 million of the U.S. net tax operating loss carryforward is attributable to deductions taken for employee stock awards on the company’s tax returns in excess of amounts expensed through the company’s income statement. We also had ~~an alternative minimum tax credit carryforward~~enhanced oil recovery and marginal well credits of ~~approximately $6.0 million.~~

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

$3.9 million at December 31, 2019.

At December 31, ~~2016~~2019 and ~~2015,~~2018, we had no0 unrecognized tax benefits that would impact our effective rate and we have made no0 provisions for interest or penalties related to uncertain tax positions. The tax years ~~2013~~2016 through ~~2015~~2018 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open to examination for tax years ~~2012~~2015 through ~~2015.~~

2018. We do not anticipate the need for any significant income tax payments in the near term.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. COMMITMENTS AND CONTINGENCIES

Lease Commitments

Effective January 1, 2019, we began accounting for leases in accordance with Topic 842, which requires lessees to recognize lease liabilities and right-of-use assets on the balance sheet for contracts that provide lessees with the right to control the use of identified assets for periods of greater than 12 months. Prior to January 1, 2019, we accounted for leases in accordance with ASC Topic 840, Leases, under which operating leases were not recorded on the balance sheet.

Real Estate Leases

We have ~~various commitments~~operating leases for office space in various locations that provide us the right to control the use of the specified office space over the term of the contract. These leases require us to make monthly “base rent” payments, as well as “additional payments” for our share of operating expenses and taxes incurred by the landlord. At our option, the terms of these leases can be renewed for varying periods, and in some cases may be terminated early at our option. As of December 31, 2019, these leases had remaining lease terms ranging from 4.4 to 6.7 years. These leases do not contain residual value guarantees, options to purchase the underlying office space, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of office space.

Lease liabilities associated with our real estate leases were recorded at the present value of the estimated future lease payments, after considering the following:

“Base rent” payments are considered fixed lease payments, while “additional payments” are considered variable lease payments.

At commencement of each real estate lease we were not reasonably certain to exercise the option to renew or terminate such lease.

The discount rate used to calculate each lease liability was based on our incremental borrowing rate, which was estimated utilizing trading metrics for our senior unsecured notes as adjusted using relevant market factors to develop a synthetic secured yield curve.

As an accounting policy we have elected not to separate nonlease components from lease components for our real estate class of assets.

Where applicable, we determined that the effect of accounting for the right to use land separately from other lease components would be insignificant.

Production-Related Leases

We have operating leases for equipment used in connection with our oil and gas production operations, including well-head compressors, pipeline compressors, and artificial lift mechanisms. These leases provide us the right to control the use of explicitly or implicitly identified equipment during the term of the contract. These leases often include an “evergreen” provision that allows the contract term to continue on a month-to-month basis following expiration of the initial term stated in the contract. As of December 31, 2019, these leases had remaining lease terms ranging from one month to 10.6 years. These leases require us to make monthly payments of fixed amounts, which cover the cost of renting the equipment and, in some cases, the cost of maintaining the leased equipment. These leases do not typically require us to make variable lease payments. These leases do not contain residual value guarantees, options to purchase the underlying equipment, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of production-related equipment.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Lease liabilities associated with our production-related operating leases were recorded at the present value of the estimated future lease payments, after considering the following:

For leases with an evergreen provision, the term of the lease was determined to be the noncancellable period in the contract plus the period beyond the noncancellable period that we believe it is reasonably certain we will need the equipment for operational purposes, limited to the point in time at which both we and the lessor each have the right to terminate the lease without permission from the other party with no more than an insignificant penalty.

As an accounting policy, we have elected not to separate nonlease components from lease components for our production-related class of assets.

We have one finance lease, which results from a gathering agreement (the “Gathering Agreement”) on a gathering system. Under terms of the Gathering Agreement, we have the option to acquire a portion of the underlying gathering system upon termination of the Gathering Agreement. We make monthly payments under the Gathering Agreement based on the volume of oil gathered and a gathering rate per barrel, which is adjusted periodically. As of December 31, 2019, this lease had a remaining term of 5.9 years.

Exploration and Development-Related Leases

We have operating leases for equipment used in connection with our exploration and development activities, including drilling rigs, pressure pumping equipment, directional drilling tools, well-control devices, and various pieces of support equipment. These leases provide us the right to control the use of explicitly or implicitly identified equipment during the term of the contract. As of December 31, 2019, these leases had remaining lease terms of 12 months or less. These leases typically require us to make payments in amounts based on the usage of the underlying equipment. These leases do not contain residual value guarantees, options to purchase the underlying equipment, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of exploration and development-related equipment.

As an accounting policy, we have elected not to apply the recognition requirements of Topic 842 to our exploration and development-related class of assets with lease terms at commencement of 12 months or less. As such, we have not recorded any lease liabilities associated with our exploration and development-related leases. In addition, as an accounting policy we have elected not to separate nonlease components from lease components for our exploration and development-related class of assets.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheet Presentation

The following tables present the amounts and classifications of our right-of-use assets and estimated lease liabilities as of December 31, 2019:



(in thousands)	Balance Sheet Location	December 31, 2019
Operating lease right-of-use assets	Non-current assets — Fixed assets, net	$	240,263
Finance lease right-of-use asset	Non-current assets — Other assets	24,849
Total right-of-use assets		$	265,112



(in thousands)	Balance Sheet Location	December 31, 2019
Operating lease liabilities — current	Current liabilities — Operating leases	$66,003
Operating lease liabilities — non-current	Non-current liabilities — Operating leases	184,172
Finance lease liability — current	Current liabilities — Accrued liabilities-Other	7,328
Finance lease liability — non-current	Non-current liabilities — Other liabilities	18,749
Total lease liabilities		$276,252

Lease Cost and Cash Flows

The following table summarizes estimated total lease cost, which includes amounts recognized in income and amounts capitalized for the indicated period:



(in thousands)	Year Ended December 31, 2019
Finance lease cost:
Amortization of right-of-use asset	$	4,385
Interest on lease liability	1,719
Operating lease cost: (1)
Production expense	20,965
Transportation, processing, and other operating	17,264
Gas gathering and other expense	5,607
General and administrative expense (2)	12,421
Short-term lease cost (3)	539,110
Total lease cost	$	601,471


(1)	Operating lease cost in the table above is composed of costs incurred under real estate and production-related leases. These costs are included in the indicated captions on the Consolidated Statements of Operations and Comprehensive Income (Loss).


(2)	Includes variable lease costs of $3.1 million.

(3)

Short-term lease cost in the table above is composed of costs incurred under leases with terms of 12 months or less for right-of-use assets used in exploration and development activities. Payments under such leases are typically based on usage of the underlying right-of-use asset and, therefore, are also variable lease payments. These costs are capitalized as part of proved properties on the Consolidated Balance Sheet.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes estimated cash paid for our leases for the indicated period:



(in thousands)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash outflows from finance lease	$	3,869
Operating cash outflows from operating leases	$	54,044

Cash paid for short-term leases and variable lease payments:
Operating cash outflows from operating leases	$	3,103
Investing cash outflows from operating leases	$	551,325

During the year ended December 31, 2019, we recognized $91.7 million in right-of-use assets in connection with new operating leases entered into during the period.

Lease Liability Maturity Analysis

The following table presents the weighted-average remaining lease terms and discount rates of our leases as of the indicated date:



	December 31, 2019
Weighted-average remaining lease term (in years):
Finance lease	5.9
Operating leases	4.1

Weighted-average discount rate:
Finance lease	5.7	%
Operating leases	3.9	%

The following table reflects the undiscounted future cash flows utilized in the calculation of the lease liabilities recorded at December 31, 2019:



	December 31, 2019
(in thousands)	Operating Leases			Finance Lease
January 1, 2020 — December 31, 2020	$	75,102		$	5,944
January 1, 2021 — December 31, 2021	67,027			5,687
January 1, 2022 — December 31, 2022	60,686			5,429
January 1, 2023 — December 31, 2023	38,128			5,171
January 1, 2024 — December 31, 2024	17,851			4,913
Remaining periods	12,426			3,132
Total undiscounted future cash flows	271,220			30,276
Less effects of discounting	(21,045		)	(4,199		)
Lease liabilities recognized	$	250,175		$	26,077

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2018, the following future minimum cash payments were required under leases for office space:



(in thousands)	December 31, 2018
2019	$	9,849
2020	10,790
2021	11,000
2022	11,130
2023	11,433
Remaining periods	20,831
Total future minimum lease payments	$	75,033

In addition, as of December 31, 2018, we had various contractual commitments for compressor equipment under operating lease ~~arrangements. Rent expense for the operating leases totaled $12.9~~arrangements totaling $34.8 million ~~in 2016. Rent expense was $13.2 million and $14.3 million for 2015 and 2014, respectively.~~

~~Shown below are future minimum cash payments required under these leases as of~~with lease terms expiring from 1 - 35 months after December 31, ~~2016.~~

Operating

(in thousands)

Leases

2017

$
9,585

2018

10,531

2019

10,677

2020

10,864

2021

11,085

Later years

44,181

Total future minimum lease payments

$
96,923

2018.

Other Commitments

~~We have~~

At December 31, 2019, we had estimated commitments of ~~$157.5~~approximately: (i) $321.7 million to finish drilling, completing, or performing other work on wells and ~~completing wells~~various other infrastructure projects in progress ~~at December 31, 2016.~~

and (ii) $6.6 million to finish gathering system construction in progress.

At December 31, ~~2016,~~2019, we had firm sales contracts to deliver approximately ~~46.4~~703.7 Bcf of ~~natural~~ gas over the next ~~twenty-two months.~~11.5 years. If we do not deliver this gas, ~~is not delivered,~~ our estimated financial commitment, calculated using the January 2020 index price, would be approximately ~~$164.8 million. This~~$1.03 billion. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next ~~ten~~9.0 years. ~~At December 31, 2016, if no~~If we do not deliver the committed gas ~~is delivered,~~or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2019, would be approximately ~~$220.0~~$697.2 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments ~~in connection~~associated with agreements to reimburse connection costs to various pipelines. ~~At December 31, 2016,~~If we do not deliver this gas, or oil, as the case may be, the estimated maximum amount that would be payable ~~if no gas is delivered~~under these commitments, calculated as of December 31, 2019, would be approximately ~~$7.9~~$117.6 million. Of this total, we have accrued a liability of ~~$2.1 million. We may~~$4.5 million representing the estimated amount we will have ~~additional liabilities associated with these delivery commitments in the future depending on our production levels and drilling results.~~

~~We have other various transportation, delivery, and facilities commitments in the normal course of business, which approximate $35.7 million~~to pay due to insufficient forecasted volumes at particular connection points.

At December 31, ~~2016. We currently anticipate meeting these obligations.~~

2019, we have various firm transportation agreements for gas and oil pipeline capacity with end dates ranging from 2020 - 2028 under which we will have to pay an estimated $64.0 million over the remaining terms of the agreements. These agreements were entered into to support our residue gas and oil marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation.

All of the noted commitments were routine and made in the ~~normal~~ordinary course of our business.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Litigation

In the ~~normal~~ordinary course of business, we ~~have~~are involved with various litigation matters. WeWhen a loss contingency exists, we assess whether it is probable that an asset has been impaired or a liability has been incurred and, if so, we determine if the ~~probability~~amount of ~~estimable amounts related to litigation matters~~loss can be reasonably estimated, all in accordance with guidance established by the FASB, and adjust our accruals

~~CIMAREX ENERGY CO.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

accordingly. Though some of the related claims may be significant, the resolution of them, we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals.

~~H.B. Krug, et al. v.~~ ~~Helmerich & Payne, Inc.~~

~~In 2008, we recorded litigation expense of $119.6 million for the~~ ~~H.B. Krug, et al. v. Helmerich & Payne, Inc.~~ ~~trial court verdict, and began accruing additional post-judgment interest and costs for this case.~~

On December 13, 2013, the Oklahoma Supreme Court reversed the trial court’s $119.6 million verdict and affirmed an alternative jury verdict for $3.65 million. The Supreme Court also remanded the case back to the trial court for consideration of potential prejudgment interest, attorney’s fees and cost awards. Accordingly, on December 31, 2013 we reduced the previously recognized litigation expense, which included related interest and costs, and the associated long-term liability by $142.8 million.

On April 1, 2014, Cimarex paid the Plaintiffs $15.8 million in satisfaction of the $3.65 million damages award, the post-judgment interest award and the payment in lieu of bond, all of which are now final and not appealable. On June 24, 2014, the trial court ruled the Plaintiffs were not entitled to prejudgment interest but were entitled to attorney’s fees and costs, the amount of which will be determined at a subsequent hearing. On November 3, 2015, the Oklahoma Supreme Court affirmed the trial court’s denial of prejudgment interest. The only remaining issue is the amount of Plaintiffs’ award of attorney’s fees, which is subject to future trial and appellate court proceedings and, therefore, cannot be determined at this time.

11. RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. ~~(H&P)~~(“H&P”) provides contract drilling services to Cimarex. ~~Drilling~~Cimarex incurred drilling costs of approximately ~~$18.3~~$72.8 million, ~~were incurred by Cimarex~~$80.1 million, and $52.6 million related to ~~such~~these services ~~for 2016. During 2015~~during the years ended December 31, 2019, 2018, and ~~2014, such~~2017, respectively. The amount incurred in 2019 is included in the short-term lease costs ~~were $7.9 million and $18.4 million, respectively.~~disclosed in Note 10. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.

~~Lisa Stewart, who joined Cimarex’s Board~~

12. SUPPLEMENTAL CASH FLOW INFORMATION



	Years Ended December 31,
(in thousands)	2019		2018		2017
Cash paid during the period for:
Interest expense (net of capitalized amounts of $49,944, $19,969, and $23,113, respectively) (1)	$	50,601	$	45,357	$	52,245
Income taxes	$	1,364	$	—	$	3
Cash received for income tax refunds	$	2,033	$	760	$	111

________________________________________


(1)	The year ended December 31, 2019 includes $17.6 million in interest paid upon the redemption of Resolute’s senior notes and credit facility on March 1, 2019.

Table of ~~Directors in October 2015, is Chairman, President, Chief Executive Officer, and Chief Investment Officer~~Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. ACQUISITIONS AND DIVESTITURES

On August 31, 2018, we closed on the divestiture of Sheridan Production Partners (Sheridan). During 2016, Cimarex paid certain affiliates of Sheridan oil and gas revenues of $177.6 thousand and joint interest billings of $5.2 thousand and received oil and gas revenues of $0.4 thousand and joint interest billings of $73.1 thousand from Sheridan affiliates. During 2015, Cimarex paid certain affiliates of Sheridan oil and gas revenues of $224.2 thousand and joint interest billings of $10.4 thousand and received oil and gas revenues of $4.1 thousand and joint interest billings of $81.5 thousand from Sheridan affiliates.

Jerry Box, a director of Cimarex whose term expired May 2015, was the non-executive Chairman of the Board of Directors of Newpark Resources, Inc. (Newpark) through May 2014. Certain subsidiaries of Newpark provided various drilling services to Cimarex. Costs of such services were $589.2 thousand through May 2014.

~~12. PROPERTY SALES AND ACQUISITIONS~~

~~The following sales and acquisitions were made in the ordinary course of business. All amounts are net of customary purchase price adjustments.~~

~~There were no significant sales and acquisitions in 2016 or 2015. We sold interests in various non-core~~ oil and gas properties principally located in Ward County, Texas for ~~$446.1~~which we received $534.6 million ~~during 2014. Most~~in net cash proceeds in 2018 as adjusted for customary closing adjustments to reflect an effective date of April 1, 2018 and transaction costs. This divestiture did not significantly alter the relationship between capitalized costs and proved reserves, therefore, in accordance with the full cost method of accounting, no gain or loss was recognized.

On March 1, 2019, we completed the acquisition of Resolute Energy Corporation, an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the ~~proceeds~~Permian Basin of west Texas. The principal factors considered by management in making this acquisition included: (i) our expectation that Resolute’s assets’ attractive returns are competitive with those in our existing portfolio, (ii) the opportunity to apply our experience and learnings from already operating in this area to generating productivity gains from Resolute’s properties, (iii) the ability to increase our acreage position in the Delaware Basin, and (iv) the expectation that the acquisition will be financially accretive.

We acquired 100% of the outstanding common shares and voting interests of Resolute in a cash and stock transaction. The acquisition date fair value of the consideration transferred totaled $820.3 million, which consisted of cash, common stock, and a newly created series of preferred stock (see Note 5 for more information on the preferred stock) as follows:



(in thousands)	Fair Value of Consideration Transferred
Cash	$	325,677
Common stock (5,652 shares issued)	413,015
Preferred stock (63 shares issued)	81,620
	$	820,312

The fair value of the common stock issued as part of the consideration was determined on the basis of the closing market price of Cimarex common stock on the acquisition date. The fair value of the preferred stock issued as part of the consideration was determined using a multiple probability simulation model.

Preliminary Purchase Price Allocation

The Resolute acquisition has been accounted for as a business combination, using the acquisition method. The following table presents the preliminary allocation of the Resolute purchase price to the identifiable assets acquired and liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded to goodwill. The table also presents the adjustments to the preliminary purchase price allocation recorded through December 31, 2019. The most significant adjustment was made to reduce the fair value of the unproved oil and gas properties acquired by $30.3 million based on the finalization of the quantity of acres acquired. The tax effect of this adjustment reduced the related deferred tax liability by $6.9 million. The completion of the final Resolute tax returns provided the underlying tax basis of Resolute’s assets and liabilities and net operating losses and resulted in a reduction of the deferred tax liability of $24.4 million. The remaining adjustments were related to ~~sales~~finalization of ~~producing gas wells in southwestern Kansas~~some working capital balances. The offset to all of the adjustments is goodwill. The purchase price allocation remains preliminary as certain data necessary to finalize pre-acquisition working capital balances is not yet available. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and ~~undeveloped acreage in Reagan County, Texas. During 2014, we made property acquisitions totaling $249.7 million, most~~liabilities may be revised as appropriate.

Table of ~~which were in our Cana area in Western Oklahoma.~~

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~13.~~

The following table sets forth the preliminary purchase price allocation:

(in thousands) March 1, 2019 Adjustments December 31, 2019
Cash $ 41,236
$ —
$ 41,236
Accounts receivable 50,739
11,463
62,202
Other current assets 13,280
(1,260 ) 12,020
Proved oil and gas properties 692,600
—
692,600
Unproved oil and gas properties 1,054,200
(30,314 ) 1,023,886
Fixed assets 5,355
(32 ) 5,323
Goodwill 107,341
(10,708 ) 96,633
Other assets 142
—
142
Current liabilities (202,735 ) (486 ) (203,221 )
Long-term debt (870,000 ) —
(870,000 )
Deferred income taxes (62,409 ) 31,337
(31,072 )
Asset retirement obligation (9,437 ) —
(9,437 )
Total identifiable net assets $ 820,312
$ —
$ 820,312

In connection with the acquisition, we assumed, and immediately repaid, $870.0 million principal amount of long-term debt consisting of $600.0 million of senior notes and $270.0 million of credit facility borrowings. On March 1, 2019, we repaid Resolute’s credit facility borrowings, delivered a notice of optional redemption of Resolute’s senior notes for an April 1, 2019 redemption date, and irrevocably deposited with a trustee the full amount of funds to repay the aggregate outstanding senior notes principal balance plus accrued and unpaid interest, incurring a $4.3 million loss on early extinguishment of debt. The cash consideration transferred and the repayment of Resolute’s long-term debt was funded using cash on hand and borrowings on our Credit Facility. We subsequently repaid the borrowings on our Credit Facility using the net proceeds from the March 8, 2019 issuance of $500.0 million aggregate principal amount of 4.375% senior unsecured notes (see Note 3 for more information on our debt issuance).

Goodwill of $96.6 million has been recognized principally as a result of recording net deferred tax liabilities arising from the difference between the tax basis and the purchase price allocated to Resolute’s assets and liabilities, and anticipated opportunities for cost savings through administrative and operational synergies. Goodwill is not expected to be deductible for tax purposes.

Acquisition-related costs incurred were $11.4 million, with $8.4 million expensed in 2019 and $3.0 million expensed in 2018. These costs, which were comprised primarily of advisory and legal fees, are included in the Other operating expense, net line item on our Consolidated Statements of Operations and Comprehensive Income (Loss).

The results of Resolute’s operations have been included in our consolidated financial statements since the March 1, 2019 acquisition date. The amount of revenue and direct operating expenses resulting from the acquisition included in our Consolidated Statements of Operations and Comprehensive Income (Loss) from March 1, 2019 through December 31, 2019 is $203.6 million and $51.0 million, respectively.

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pro Forma Financial Information (Unaudited)

The following supplemental pro forma information for the years ended December 31, 2019 and 2018 has been prepared to give effect to the Resolute acquisition as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of the combined company’s proved oil and gas properties, (ii) the capitalization of interest expense, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by Cimarex of $11.4 million and transaction-related costs incurred by Resolute of $66.6 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by Cimarex to integrate the Resolute assets. The pro forma financial data has not been adjusted to reflect any other acquisitions or dispositions made during the periods presented as their results were not deemed material.

The pro forma information is not necessarily indicative of the results that might have occurred had the transaction actually taken place on January 1, 2018 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities, and other factors.

Years Ended December 31,
(in thousands, except per share information) 2019 2018
Revenue $ 2,416,105
$ 2,667,561
Net (loss) income $ (139,553 ) $ 872,140
Net (loss) income per common share:
Basic $ (1.47 ) $ 8.65
Diluted $ (1.47 ) $ 8.65

100

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CIMAREX ENERGY CO.

SUPPLEMENTAL ~~DISCLOSURE OF CASH FLOW~~ INFORMATION

Years Ended December 31,

(in thousands)

2016

2015

2014

Cash paid during the period for:

Interest expense (including capitalized amounts)

$
79,590

$
80,785

$
66,167

Interest capitalized

$
20,308

$
28,819

$
32,623

Income taxes

$
13

$
558

$
354

Cash received for income tax refunds

$
1,450

$
1,503

$
460

~~SUPPLEMENTAL~~ ON OIL AND GAS ~~INFORMATION~~PRODUCING ACTIVITIES (UNAUDITED)

Oil and Gas Reserve ~~Information~~—Information—Proved reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission ~~(SEC)~~(“SEC”).

Reserve definitions comply with definitions of Rule 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by our internal Corporate Reservoir Engineering group, which is comprised of ~~reservoir~~ engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and production functions of our company. The technical employee primarily responsible for overseeing the reserve estimation process is our ~~company’s~~ Vice President of Corporate Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than 2225 years of practical experience in reserve evaluation. He has been directly involved in the annual reserve reporting process of Cimarex since 2002 and has served in his current role for the past ~~twelve~~15 years.

DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, ~~reviewed~~performed an independent evaluation of our estimated net reserves ~~associated with~~representing greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of December 31, ~~2016.~~2019. The individual primarily responsible for overseeing the ~~review~~evaluation is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over 3735 years of experience in oil and gas reservoir studies and reserves evaluations.

Proved reserves are those quantities of oil, ~~NGL,~~gas, and ~~gas,~~NGLs which, by analysis of geosciences 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.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment, and material balance analysis. Techniques including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also ~~are~~ involved in this estimation process.

The following table summarizes the trailing ~~12-month~~twelve-month index prices used in the ~~reserve~~reserves estimates for ~~2016, 2015,~~2019, 2018, and ~~2014.~~2017. These prices are prior to adjustments for fixed and determinable amounts under provisions in existing contracts, location, grade, and quality.

December 31,

2016

2015

2014

Gas price per Mcf

$
2.48

$
2.59

$
4.35

Oil price per Bbl

$
42.75

$
50.28

$
94.99

NGL price per Bbl

$
14.37

$
14.41

$
30.89



	December 31,
	2019		2018		2017
Gas price per Mcf	$	2.58	$	3.10	$	2.98
Oil price per Bbl	$	55.67	$	65.56	$	51.34
NGL price per Bbl	$	13.27	$	21.03	$	19.09

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CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following ~~reserve data represents~~table sets forth our estimates ~~only~~of our proved, proved developed, and ~~should not be construed~~proved undeveloped oil, gas, and NGL reserves as ~~being exact.~~

Gas

Oil

NGL

Total

(MMcf)

(MBbl)

(MBbl)

(MMcfe)

Total proved reserves:

December 31, 2013

1,293,500

108,533

92,044

2,496,964

Revisions of previous estimates

85,533

(1,039
)
4,262

104,873

Extensions and discoveries

420,442

29,155

36,424

813,911

Purchases of reserves

88,227

1,383

6,186

133,641

Production

(155,128
)
(15,639
)
(11,343
)
(317,022
)
Sales of properties

(65,841
)
(3,401
)
(2,300
)
(100,044
)
December 31, 2014

1,666,733

118,992

125,273

3,132,323

Revisions of previous estimates

(154,390
)
(14,633
)
(5,668
)
(276,192
)
Extensions and discoveries

183,084

22,859

18,079

428,714

Purchases of reserves

15

1

1

25

Production

(168,987
)
(18,663
)
(13,063
)
(359,343
)
Sales of properties

(9,503
)
(758
)
(345
)
(16,120
)
December 31, 2015

1,516,952

107,798

124,277

2,909,407

Revisions of previous estimates

5,888

(4,357
)
6,670

19,761

Extensions and discoveries

123,175

19,419

14,050

323,987

Purchases of reserves

959

1

—

965

Production

(168,227
)
(16,528
)
(14,200
)
(352,591
)
Sales of properties

(7,327
)
(455
)
(164
)
(11,042
)
December 31, 2016

1,471,420

105,878

130,633

2,890,487

Proved developed reserves:

December 31, 2013

1,060,704

86,665

69,089

1,995,233

December 31, 2014

1,263,957

100,050

89,630

2,402,033

December 31, 2015

1,129,490

89,189

87,549

2,189,920

December 31, 2016

1,144,720

92,032

99,176

2,291,966

Proved undeveloped reserves:

December 31, 2013

232,796

21,868

22,955

501,731

December 31, 2014

402,776

18,942

35,643

730,290

December 31, 2015

387,462

18,609

36,728

719,487

December 31, 2016

326,700

13,846

31,457

598,521

~~Year-end~~of December 31, 2019, 2018, 2017, and 2016 and changes in our proved reserves ~~declined by less than 1%~~for the years ended December 31, 2019, 2018, and 2017. All of our proved reserves are located entirely within the U.S.



	Gas (MMcf)		Oil (MBbls)		NGL (MBbls)		Total (MBOE)
Total proved reserves:
December 31, 2016	1,471,420		105,878		130,633		481,748
Revisions of previous estimates	(39,749	)	(1,225	)	(2,099	)	(9,951	)
Extensions and discoveries	363,774		53,464		42,692		156,786
Purchases of reserves	642		42		78		227
Production	(187,468	)	(20,861	)	(17,374	)	(69,479	)
Sales of reserves	(984	)	(60	)	(70	)	(294	)
December 31, 2017	1,607,635		137,238		153,860		559,037
Revisions of previous estimates	(132,577	)	(4,348	)	3,777		(22,667	)
Extensions and discoveries	342,810		53,763		47,614		158,512
Purchases of reserves	3		—		—		1
Production	(205,837	)	(24,710	)	(21,994	)	(81,010	)
Sales of reserves	(20,713	)	(15,405	)	(3,821	)	(22,678	)
December 31, 2018	1,591,321		146,538		179,436		591,195
Revisions of previous estimates	(180,632	)	(8,516	)	(12,038	)	(50,661	)
Extensions and discoveries	247,406		41,193		36,834		119,261
Purchases of reserves	129,435		22,628		18,818		63,019
Production	(251,567	)	(31,463	)	(28,254	)	(101,645	)
Sales of reserves	(3,818	)	(610	)	(328	)	(1,574	)
December 31, 2019	1,532,145		169,770		194,468		619,595
Proved developed reserves:
December 31, 2016	1,144,720		92,032		99,176		381,994
December 31, 2017	1,334,510		114,116		126,227		462,761
December 31, 2018	1,398,729		116,339		151,566		501,027
December 31, 2019	1,358,329		138,783		166,552		531,722
Proved undeveloped reserves:
December 31, 2016	326,700		13,846		31,457		99,754
December 31, 2017	273,125		23,122		27,633		96,276
December 31, 2018	192,592		30,199		27,870		90,168
December 31, 2019	173,816		30,987		27,916		87,873

Year-end 2019 proved reserves increased approximately 5% from year-end ~~2015~~2018 proved reserves, to ~~2.89 Tcfe.~~619.6 MMBOE. Proved ~~natural~~ gas reserves were ~~1.47~~1.53 Tcf, proved oil reserves were ~~0.64 Tcfe,~~169.8 MMBbls, and proved NGL reserves were ~~0.78 Tcfe.~~194.5 MMBbls. Our reserves in the ~~Mid-Continent~~Permian Basin accounted for ~~63%~~68% of total proved reserves, with ~~the majority~~nearly all of the remainder in the ~~Permian Basin.~~

Mid-Continent.

During ~~2016,~~2019, we added ~~324.0 Bcfe~~119.3 MMBOE of proved reserves through extensions and discoveries, primarily in the ~~Mid-Continent and~~ Permian Basin where we added ~~121.6 Bcfe~~99.9 MMBOE, with the remaining 19.4 MMBOE in additions being in the Mid-Continent. Additionally, we added 63.0 MMBOE from purchases of reserves, primarily through the Resolute acquisition (see Note 13 to the Consolidated Financial Statements for further information on the acquisition). We had net negative

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CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

revisions of 50.7 MMBOE, which consisted of 47.2 MMBOE in downward price revisions and ~~198.7 Bcfe, respectively.~~7.0 MMBOE related to increases in operating expenses. In addition, ~~we had net positive~~13.6 MMBOE was associated with the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure. These negative revisions ~~of 19.8 Bcfe. The revisions included increases of 126.2 Bcfe for net performance revisions and 138.5 Bcfe related to decreases in operating expenses,~~were partially offset by ~~negative~~net positive technical revisions of ~~244.9 Bcfe due~~17.1 MMBOE primarily related to ~~lower commodity prices. The performance revisions resulted primarily from positive adjustments to previously booked PUD reserves (72.3 Bcfe) and~~ better than expected performance from wells with initial production in late ~~2015.~~

2018 and positive adjustments to PUD reserves converted to proved developed reserves during 2019.

During ~~2015,~~2018, we added ~~428.7 Bcfe~~158.5 MMBOE of proved reserves through extensions and discoveries, primarily in ~~the Mid-Continent and~~ Permian Basin and Mid-Continent where we added ~~176.8 Bcfe~~120.3 MMBOE and ~~251.1 Bcfe,~~38.0 MMBOE, respectively. ~~During 2015,~~In addition, we had net negative ~~reserve~~ revisions of ~~276.2 Bcfe.~~22.7 MMBOE. The ~~significant decrease in commodity prices seen in 2015 resulted in negative~~ revisions included decreases of ~~398.8 Bcfe due to prices. In addition, 19.1 Bcfe~~38.6 MMBOE for the removal of ~~negative revisions were due~~PUD reserves whose development will likely be delayed beyond five years of initial disclosure and 7.7 MMBOE related to increases in operating ~~expenses, which shortened the economic lives of properties.~~expenses. These decreases were partially offset by increases of 2.7 MMBOE in price-related revisions and 20.9 MMBOE of net ~~positive performance~~technical revisions. The majority of the technical revisions ~~of 141.7 Bcfe, which included 47.4 Bcfe for~~were related to better than expected performance offrom wells with initial production in late 2017 and positive adjustments to PUD reserves converted to proved developed reserves during ~~the year and positive adjustments of 95.3 Bcfe to previously booked PUD reserves.~~

2018.

During ~~2014,~~2017, we added ~~813.9 Bcfe~~156.8 MMBOE of proved reserves through extensions and discoveries, primarily in ~~the~~Permian Basin and Mid-Continent ~~and Permian Basin. In the Mid-Continent,~~where we added ~~80.4 Bcfe from wells drilled~~109.6 MMBOE and ~~added 496.6 Bcfe~~47.2 MMBOE, respectively. In addition, we had net negative revisions of 10.0 MMBOE. The revisions included decreases of 41.5 MMBOE for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure and 7.3 MMBOE related to increases in ~~our Cana area. In the Permian Basin, development drilling added 234.3 Bcfe.~~

~~During 2014, we had~~operating expenses. These decreases were partially offset by increases of 31.2 MMBOE in price-related revisions and 7.6 MMBOE of net ~~positive reserve~~technical revisions ~~of 104.9 Bcfe. Performance revisions were a net positive of approximately 113.4 Bcfe. This net increase was due~~related primarily to better than expected performance of PUD reserves converted to proved developed reserves during the year (124.7 Bcfe) and positive adjustments to previously booked PUD reserves (10.1 Bcfe), offset by 21.4 Bcfe of net negative revisions primarily attributed to Cana areafrom wells ~~impacted by infill drilling. Additionally, there were positive price revisions of 16.1 Bcfe, offset by negative revisions of 24.6 Bcfe due to increases~~with initial production in ~~operating expenses, which shortened the economic lives of properties.~~

late 2016.

At December 31, ~~2016,~~2019, we had PUD reserves of ~~598.5 Bcfe,~~87.9 MMBOE, down ~~121.0 Bcfe,~~2.3 MMBOE, or ~~17%~~3%, from ~~719.5 Bcfe~~90.2 MMBOE of PUD reserves at December 31, ~~2015.~~2018. Changes in our PUD reserves during 2019 are summarized in the table ~~below (in Bcfe).~~

below.



	PUD Reserves (MMBOE)
PUD reserves at December 31, ~~2015~~ 2018	90.2	~~719.5~~
Converted to developed	(59.2	~~(104.3~~	)
Additions	71.0	~~35.6~~
Net revisions	(14.1	~~(52.3~~	)
PUD reserves at December 31, ~~2016~~ 2019	87.9	~~598.5~~

During ~~2016,~~2019, we invested ~~$97.7~~$399.5 million to develop and convert ~~14%~~66% of our 2015 PUD reserves to proved developed reserves. Additionally, in 2016 we invested $11.1 million to develop 2015 PUD reserves that were waiting on completion at year-end and had not yet been converted to proved developed reserves. During 2015, we invested $246.5 million to develop PUD reserves, converting 24% of our 20142018 PUD reserves to proved developed reserves. During ~~2014,~~2018, we invested ~~$503.5~~$264.5 million to develop ~~PUD reserves, converting 56%~~and convert 30% of our ~~2013~~2017 PUD reserves to proved developed reserves.

~~All 35.6 Bcfe~~ During 2017, we invested $69.5 million to develop and convert 10% of our 2016 PUD reserves to proved developed reserves.

During 2019, all of our 71.0 MMBOE of PUD reserve additions occurred in the Permian Basin. At December 31, 2019, 92% of our PUD reserves were in the Permian Basin, while the remainder were in our western Oklahoma Cana area. ~~At December 31, 2016, all~~During 2019, we had net negative PUD reserve revisions of ~~our~~14.1 MMBOE. Of this total, 13.6 MMBOE was for the removal of PUD reserves ~~are associated with this area.~~whose development will likely be delayed beyond five years of initial disclosure. We have no PUD reserves that have remained undeveloped for five years or more after initial ~~booking~~disclosure and we have no PUD reserves whose scheduled ~~delay to initiation of~~ development is beyond five years of initial ~~booking.~~

~~During 2016, we had net negative PUD reserve revisions~~disclosure.

103

Table of 52.3 Bcfe. This included 127.3 Bcfe removed due to lower commodity prices partially offset by positive technical adjustments of 72.3 Bcfe to remaining previously booked PUD reserves. Further, negative additional price revisions of 7.8 Bcfe to remaining PUD reserves were more than offset by 10.5 Bcfe of positive revisions due to lower projected operating expenses.

Contents

CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Costs ~~Incurred~~—Incurred—The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities.

Years Ended December 31,

(in thousands)

2016

2015

2014

Costs incurred during the year:

Acquisition of properties

Proved

$
2,678

$
30

$
138,508

Unproved

67,961

41,233

277,099

Exploration

5,814

6,902

50,271

Development

672,842

823,830

1,664,877

Oil and gas expenditures

749,295

871,995

2,130,755

Property sales

(24,687
)
(41,276
)
(446,107
)

724,608

830,719

1,684,648

Asset retirement obligation, net

(7,950
)
(4,818
)
27,243

$
716,658

$
825,901

$
1,711,891

Years Ended December 31,
(in thousands) 2019 2018 2017
Costs incurred during the year:

Acquisition of properties

Proved $ 695,450
$ 62
$ 938
Unproved 1,083,230
102,666
135,565
Exploration 2,321
6,341
11,804
Development 1,181,605
1,487,453
1,140,548
Oil and gas expenditures 2,962,606
1,596,522
1,288,855
Property sales (35,320 ) (581,799 ) (11,680 )
2,927,286
1,014,723
1,277,175
Asset retirement obligation, net 3,874
(2,004 ) 9,416
$ 2,931,160
$ 1,012,719
$ 1,286,591

Aggregate Capitalized ~~Costs~~—Costs—The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at December 31, ~~2016.~~

(in thousands)

Proved properties

$
16,225,495

Unproved properties and properties under development, not being amortized

478,277

16,703,772

Less-accumulated depreciation, depletion, amortization, and impairments

(14,349,505
)
Net oil and gas properties

$
2,354,267

2019.

(in thousands) December 31, 2019
Proved properties $ 20,678,334
Unproved properties and properties under development, not being amortized 1,255,908
21,934,242
Less-accumulated depreciation, depletion, amortization, and impairments (16,723,544 )
Net oil and gas properties $ 5,210,698

Costs Not Being ~~Amortized~~—Amortized—The following table summarizes oil and gas property costs not being amortized at December 31, ~~2016,~~2019, by year that the costs were incurred.

(in thousands)

2016

$
234,905

2015

42,808

2014

114,746

2013 and prior

85,818

$
478,277



(in thousands)	December 31, 2019
2019	$	1,019,651
2018	74,923
2017	76,491
2016 and prior	84,843
	$	1,255,908

Of the costs not being amortized, ~~$173.5~~$158.6 million ~~(36%~~(13%) relates to unevaluated wells in progress and ~~$48.5~~$69.2 million ~~(10%~~(5%) is capitalized interest. The remaining ~~$256.3 million (54%~~$1.03 billion (82%) is for land and seismic expenditures, most of which were for costs invested in ~~our Mid-Continent region~~Permian Basin ($~~136.9~~970.9 million) and ~~our~~Mid-Continent ($48.0 million). The majority of the Permian Basin ~~region ($91.6 million).~~balance stems from the Resolute acquisition. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors. We expect to include these costs in the amortization computation as we continue with our exploration and development plans.

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CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Oil and Gas ~~Operations~~—Operations—The following table contains direct revenue and cost information relating to our oil and gas exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax expense related to our oil and gas operations is computed using the effective tax rate for the ~~period.~~

Years Ended December 31,

(in thousands, except per Mcfe)

2016

2015

2014

Oil, gas and NGL revenues from production

$
1,221,218

$
1,417,538

$
2,372,829

Less operating costs and income taxes:

Impairment of oil and gas properties

757,670

4,033,295

—

Depletion

346,003

689,120

743,373

Asset retirement obligation

7,828

9,121

10,082

Production

232,002

299,374

342,304

Transportation, processing and other operating

210,144

183,134

215,246

Taxes other than income

61,946

84,764

128,793

Income tax expense (benefit)

(135,665
)
(1,410,065
)
345,688

1,479,928

3,888,743

1,785,486

Results of operations from oil and gas producing activities

$
(258,710
)
$
(2,471,205
)
$
587,343

Depletion rate per Mcfe

$
0.98

$
1.92

$
2.34

period, with the 2017 effective tax rate adjusted to remove the impact of the reduction in the federal statutory rate.

Years Ended December 31,
(in thousands, except per BOE) 2019 2018 2017
Oil, gas, and NGL revenues from production $ 2,321,921
$ 2,297,645
$ 1,874,003
Less operating costs and income taxes:

Impairment of oil and gas properties 618,693
—
—
Depletion 817,099
538,919
399,328
Asset retirement obligation 8,586
7,142
15,624
Production 339,941
296,189
263,349
Transportation, processing, and other operating 238,259
211,463
248,124
Taxes other than income 148,953
125,169
89,864
Income tax expense 26,318
252,840
313,066
2,197,849
1,431,722
1,329,355
Results of operations from oil and gas producing activities $ 124,072
$ 865,923
$ 544,648
Depletion rate per BOE $ 8.04
$ 6.65
$ 5.75

Standardized Measure of Future Net Cash ~~Flows~~—Flows—The ~~“Standardized~~Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas ~~Reserves” (Standardized Measure)~~Reserves (“Standardized Measure”) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, varying price and cost assumptions, and risks inherent in reserve estimates.

Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The following summary sets forth our Standardized Measure.

December 31,

(in thousands)

2016

2015

2014

Cash inflows

$
7,576,211

$
8,839,485

$
19,892,471

Production costs

(2,970,891
)
(3,521,881
)
(5,777,710
)
Development costs

(794,298
)
(1,058,020
)
(1,453,860
)
Income tax expense

(507,145
)
(728,029
)
(3,768,780
)
Net cash flow

3,303,877

3,531,555

8,892,121

10% annual discount rate

(1,411,259
)
(1,597,424
)
(4,539,276
)
Standardized measure of discounted future net cash flow

$
1,892,618

$
1,934,131

$
4,352,845



	December 31,
(in thousands)	2019			2018			2017
Future cash inflows	$	11,726,488		$	14,050,367		$	11,967,325
Future production costs	(4,619,438		)	(4,889,601		)	(4,360,599		)
Future development costs	(814,397		)	(1,017,318		)	(948,735		)
Future income tax expenses	(578,675		)	(1,303,762		)	(882,519		)
Future net cash flows	5,713,978			6,839,686			5,775,472
10% annual discount for estimated timing of cash flows	(2,084,952		)	(2,824,499		)	(2,490,471		)
Standardized measure of discounted future net cash flows	$	3,629,026		$	4,015,187		$	3,285,001

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CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The estimates of cash flows ~~and reserve quantities~~ shown above are based upon the unweighted trailing twelve-month average ~~12 month~~ first-day-of-the-month benchmark prices. See table above underOil and Gas Reserve Information for prices used in determining the Standardized Measure. ~~If future gas sales are covered by contracts at specified prices, the contract prices would be used.~~ Prices are market driven and will fluctuate due to supply and demand factors, seasonality, and geopolitical and economic factors.

The following are the principal sources of change in the Standardized Measure.

December 31,

(in thousands)

2016

2015

2014

Standardized Measure, beginning of period

$
1,934,131

$
4,352,845

$
3,598,894

Sales, net of production costs

(717,126
)
(850,267
)
(1,686,486
)
Net change in sales prices, net of production costs

(429,956
)
(4,262,261
)
(176,200
)
Extensions and discoveries, net of future production and development costs

517,702

573,373

1,633,285

Changes in future development costs

167,387

280,163

23,025

Previously estimated development costs incurred during the period

110,945

214,749

442,780

Revision of quantity estimates

15,701

(240,063
)
230,673

Accretion of discount

227,904

638,948

520,058

Change in income taxes

115,609

1,691,721

(434,949
)
Purchases of reserves in place

429

20

228,539

Sales of properties

(9,440
)
(26,225
)
(185,326
)
Change in production rates and other

(40,668
)
(438,872
)
158,552

Standardized Measure, end of period

$
1,892,618

$
1,934,131

$
4,352,845



	Years Ended December 31,
(in thousands)	2019			2018			2017
Standardized Measure, beginning of period	$	4,015,187		$	3,285,001		$	1,892,618
Sales, net of production costs	(1,594,768		)	(1,660,649		)	(1,267,229		)
Net change in sales prices and in production costs related to future production	(1,267,223		)	377,178			855,024
Extensions and discoveries, net of future production and development costs	758,685			1,738,993			1,443,577
Changes in estimated future development costs	35,940			194,523			298,819
Previously estimated development costs incurred during the period	640,292			335,954			78,398
Revisions of quantity estimates	(304,217		)	96,783			(65,376		)
Accretion of discount	473,919			372,482			212,192
Change in income taxes	404,681			(284,186		)	(210,519		)
Purchases of reserves in place	568,897			—			2,255
Sales of reserves in place	(18,330		)	(300,592		)	(1,666		)
Change in production rates and other	(84,037		)	(140,300		)	46,908
Standardized Measure, end of period	$	3,629,026		$	4,015,187		$	3,285,001

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CIMAREX ENERGY CO.

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarter

2016

First

Second

Third

Fourth

(in thousands, except per share data)

Revenues

$
240,600

$
298,873

$
335,717

$
382,155

Expenses, net (1)

472,059

513,327

346,390

334,372

Net income (loss)

$
(231,459
)
$
(214,454
)
$
(10,673
)
$
47,783

Earnings (loss) per share to common stockholders:

Basic:

Distributed

$
0.08

$
0.08

$
0.08

$
0.08

Undistributed

(2.57
)
(2.39
)
(0.20
)
0.42

$
(2.49
)
$
(2.31
)
$
(0.12
)
$
0.50

Diluted:

Distributed

$
0.08

$
0.08

$
0.08

$
0.08

Undistributed

(2.57
)
(2.39
)
(0.20
)
0.42

$
(2.49
)
$
(2.31
)
$
(0.12
)
$
0.50

~~(1)~~

The ~~2016~~tables below summarize our quarterly ~~expenses, net include non-cash impairments to our oil~~financial data for 2019 and gas properties of $318.8 million (or $3.43 per diluted share), $333.3 million (or $3.58 per diluted share), and $105.6 million (or $1.13 per diluted share) for the first quarter through the third quarter of 2016, respectively, as discussed in Note 1 to the Consolidated Financial Statements under ~~Oil and Gas Properties~~.

Quarter

2015

First

Second

Third

Fourth

(in thousands, except per share data)

Revenues

$
361,002

$
424,283

$
356,055

$
311,279

Expenses, net (1)

910,572

1,014,768

1,087,355

1,019,528

Net loss

$
(549,570
)
$
(590,485
)
$
(731,300
)
$
(708,249
)
Earnings (loss) per share to common stockholders:

Basic:

Distributed

$
0.16

$
0.16

$
0.16

$
0.16

Undistributed

(6.57
)
(6.52
)
(8.03
)
(7.78
)

$
(6.41
)
$
(6.36
)
$
(7.87
)
$
(7.62
)
Diluted:

Distributed

$
0.16

$
0.16

$
0.16

$
0.16

Undistributed

(6.57
)
(6.52
)
(8.03
)
(7.78
)

$
(6.41
)
$
(6.36
)
$
(7.87
)
$
(7.62
)

~~(1)~~ The 2015 quarterly expenses, net include non-cash impairments to our oil and gas properties of $821.2 million (or $9.57 per diluted share), $966.0 million (or $10.41 per diluted share), $1.1 billion (or $12.31 per diluted share) and $1.1 billion (or $11.85 per diluted share) for the first quarter through the fourth quarter of 2015, respectively, as discussed in Note 1 to the Consolidated Financial Statements under ~~Oil and Gas Properties~~.

2018. The sum of the individual quarterly ~~net income~~earnings (loss) per common share amounts ~~does~~may not agree with year-to-date ~~net income~~earnings (loss) per common share amounts because each quarter’s computation is based on the number of shares outstanding at the end of the applicable quarter using the two-class method.

~~Impact~~

Quarter
2019 First Second Third Fourth
(in thousands, except per share data)
Revenues $ 576,957
$ 546,463
$ 582,305
$ 657,244
Expenses, net 550,641
437,154
458,458
1,041,335
Net income (loss) $ 26,316
$ 109,309
$ 123,847
$ (384,091 )
Earnings (loss) per share to common stockholders:

Basic $ 0.26
$ 1.07
$ 1.21
$ (3.87 )
Diluted $ 0.26
$ 1.07
$ 1.21
$ (3.87 )

In the course of ~~Correcting Adjustments on Unaudited Quarterly Financial Statements (see Note 1)~~

preparing our year-end 2019 oil and gas reserve report, we determined that the September 30, 2019 present value of estimated future net cash flows from proved oil and gas reserves discounted at 10% should have included the cash flows from reserve volumes associated with skim oil and drip liquids produced from our wells and recovered from saltwater disposal facilities and gathering systems at that date. This error caused us to incorrectly report an impairment of oil and gas properties at September 30, 2019.

Expenses, net, Net income (loss), and Earnings (loss) per share to common stockholders for the third quarter 2019 in the table above have been revised from amounts previously reported in our September 30, 2019 Form 10-Q. The ~~following tables present corrected~~revised amounts in the table above reflect the elimination of a full cost ceiling impairment of $108.9 million originally recorded in the third quarter 2019. We recognized a full cost ceiling impairment of $618.7 million in the fourth quarter 2019.

After considering the guidance in Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and Accounting Standards Codification 250, Accounting Changes and Error Corrections, we evaluated the materiality of this amount quantitatively and qualitatively and concluded that the error was not material to the company’s third quarter 2019 interim period financial statements. The unaudited interim period consolidated ~~balance sheets~~financial statements as of ~~March 31, June 30,~~ and ~~September 30, 2016, corrected unaudited consolidated statements of operations and comprehensive income (loss)~~ for the three ~~months ended March 31, June 30,~~ and ~~September 30, 2016 and 2015, the six months ended June 30, 2016, and the nine months~~nine-months ended September 30, ~~2016, and corrected unaudited consolidated statements~~2019, will be revised in accordance with SAB No. 108, Considering the Effects of ~~cash~~

Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, in order to reflect this correction when the company files its third quarter 2020 Form 10-Q.



	Quarter
2018	First		Second		Third		Fourth
(in thousands, except per share data)
Revenues	$	567,134	$	556,274	$	591,488	$	624,121
Expenses, net	380,816		415,277		443,134		307,939
Net income	$	186,318	$	140,997	$	148,354	$	316,182
Earnings per share to common stockholders:
Basic	$	1.96	$	1.48	$	1.56	$	3.32
Diluted	$	1.96	$	1.48	$	1.56	$	3.32

107

~~flows for the three months ended March 31, 2016 and 2015, the six months ended June 30, 2016 and 2015, and the nine months ended September 30, 2016 and 2015.~~

Table of Contents

Condensed Consolidated Balance Sheet
March 31, 2016

(in thousands, except share and per share data)

As Previously
Reported

Corrections

As
Corrected

Assets

Current assets:

Cash and cash equivalents

$
676,639

$

$
676,639

Receivables, net

192,160

192,160

Oil and gas well equipment and supplies

44,648

44,648

Derivative instruments

11,868

11,868

Prepaid expenses

5,425

5,425

Other current assets

350

350

Total current assets

931,090

931,090

Oil and gas properties at cost, using the full cost method of accounting:

Proved properties

15,677,599

15,677,599

Unproved properties and properties under development, not being amortized

466,497

466,497

16,144,096

16,144,096

Less-accumulated depreciation, depletion and amortization and impairment

(13,057,470
)
(606,055
)
(13,663,525
)
Net oil and gas properties

3,086,626

(606,055
)
2,480,571

Fixed assets, net

227,343

227,343

Goodwill

620,232

620,232

Derivative instruments

422

422

Other assets, net

35,548

35,548

$
4,901,261

$
(606,055
)
$
4,295,206

Liabilities and Stockholders’ Equity

Current liabilities:

Accounts payable

$
39,241

$

$
39,241

Accrued liabilities

229,787

229,787

Derivative instruments

3,812

3,812

Revenue payable

84,252

84,252

Total current liabilities

357,092

357,092

Long-term debt:

Principal

1,500,000

1,500,000

Less-unamortized debt issuance costs

(13,789
)

(13,789
)
Long-term debt, net

1,486,211

1,486,211

Deferred income taxes

246,553

(221,406
)
25,147

Other liabilities

197,074

197,074

Total liabilities

2,286,930

(221,406
)
2,065,524

Commitments and contingencies

Stockholders’ equity:

Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued

—

—

Common stock, $0.01 par value, 200,000,000 shares authorized, 94,815,010 shares issued

948

948

Paid-in capital

2,773,254

2,773,254

Retained earnings (accumulated deficit)

(160,397
)
(384,649
)
(545,046
)
Accumulated other comprehensive income

526

526

2,614,331

(384,649
)
2,229,682

$
4,901,261

$
(606,055
)
$
4,295,206

Condensed Consolidated Balance Sheet
June 30, 2016

(in thousands, except share and per share data)

As Previously
Reported

Corrections

As
Corrected

Assets

Current assets:

Cash and cash equivalents

$
641,739

$

$
641,739

Receivables, net

229,634

229,634

Oil and gas well equipment and supplies

37,852

37,852

Derivative instruments

1,119

1,119

Prepaid expenses

5,090

5,090

Other current assets

2,173

2,173

Total current assets

917,607

917,607

Oil and gas properties at cost, using the full cost method of accounting:

Proved properties

15,845,260

15,845,260

Unproved properties and properties under development, not being amortized

458,530

458,530

16,303,790

16,303,790

Less-accumulated depreciation, depletion and amortization and impairment

(13,569,032
)
(518,361
)
(14,087,393
)
Net oil and gas properties

2,734,758

(518,361
)
2,216,397

Fixed assets, net

224,056

224,056

Goodwill

620,232

620,232

Deferred income taxes

—

97,101

97,101

Derivative instruments

—

—

Other assets, net

35,170

35,170

$
4,531,823

$
(421,260
)
$
4,110,563

Liabilities and Stockholders’ Equity

Current liabilities:

Accounts payable

$
55,564

$

$
55,564

Accrued liabilities

220,154

220,154

Derivative instruments

28,399

28,399

Revenue payable

99,209

99,209

Total current liabilities

403,326

403,326

Long-term debt:

Principal

1,500,000

1,500,000

Less-unamortized debt issuance costs

(13,205
)

(13,205
)
Long-term debt, net

1,486,795

1,486,795

Deferred income taxes

92,446

(92,446
)
—

Other liabilities

202,454

202,454

Total liabilities

2,185,021

(92,446
)
2,092,575

Commitments and contingencies

Stockholders’ equity:

Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued

—

—

Common stock, $0.01 par value, 200,000,000 shares authorized, 94,986,852 shares issued

950

950

Paid-in capital

2,775,805

2,775,805

Retained earnings (accumulated deficit)

(430,674
)
(328,814
)
(759,488
)
Accumulated other comprehensive income

721

721

Total stockholders’ equity

2,346,802

(328,814
)
2,017,988

$
4,531,823

$
(421,260
)
$
4,110,563

Condensed Consolidated Balance Sheet
September 30, 2016

(in thousands, except share and per share data)

As Previously
Reported

Corrections

As
Corrected

Assets

Current assets:

Cash and cash equivalents

$
698,696

$

$
698,696

Receivables, net

226,983

226,983

Oil and gas well equipment and supplies

34,909

34,909

Derivative instruments

1,147

1,147

Prepaid expenses

3,453

3,453

Other current assets

1,315

1,315

Total current assets

966,503

966,503

Oil and gas properties at cost, using the full cost method of accounting:

Proved properties

16,013,316

16,013,316

Unproved properties and properties under development, not being amortized

447,071

447,071

16,460,387

16,460,387

Less-accumulated depreciation, depletion and amortization and impairment

(13,756,311
)
(515,071
)
(14,271,382
)
Net oil and gas properties

2,704,076

(515,071
)
2,189,005

Fixed assets, net

214,448

214,448

Goodwill

620,232

620,232

Deferred income taxes

—

100,880

100,880

Derivative instruments

3

3

Other assets, net

33,485

33,485

$
4,538,747

$
(414,191
)
$
4,124,556

Liabilities and Stockholders’ Equity

Current liabilities:

Accounts payable

$
53,428

$

$
53,428

Accrued liabilities

258,551

258,551

Derivative instruments

21,573

21,573

Revenue payable

107,766

107,766

Total current liabilities

441,318

441,318

Long-term debt:

Principal

1,500,000

1,500,000

Less-unamortized debt issuance costs

(12,629
)

(12,629
)
Long-term debt, net

1,487,371

1,487,371

Deferred income taxes

87,523

(87,523
)
—

Other liabilities

189,253

189,253

Total liabilities

2,205,465

(87,523
)
2,117,942

Commitments and contingencies

Stockholders’ equity:

Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued

—

—

Common stock, $0.01 par value, 200,000,000 shares authorized, 94,964,174 shares issued

950

950

Paid-in capital

2,774,804

2,774,804

Retained earnings (accumulated deficit)

(443,480
)
(326,668
)
(770,148
)
Accumulated other comprehensive income

1,008

1,008

Total stockholders’ equity

2,333,282

(326,668
)
2,006,614

$
4,538,747

$
(414,191
)
$
4,124,556

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
March 31, 2016

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Revenues:

Oil sales

$
117,573

$

$
117,573

Gas sales

82,608

82,608

NGL sales

33,352

33,352

Gas gathering and other

7,241

7,241

Gas marketing, net

(174
)

(174
)

240,600

240,600

Costs and expenses:

Impairment of oil and gas properties

230,132

88,654

318,786

Depreciation, depletion and amortization

128,099

(17,463
)
110,636

Asset retirement obligation

2,298

2,298

Production

70,702

70,702

Transportation, processing, and other operating

46,443

46,443

Gas gathering and other

8,080

8,080

Taxes other than income

13,839

13,839

General and administrative

13,897

13,897

Stock compensation

5,528

5,528

(Gain) loss on derivative instruments, net

(428
)

(428
)
Other operating, net

90

90

518,680

71,191

589,871

Operating income (loss)

(278,080
)
(71,191
)
(349,271
)
Other (income) and expense:

Interest expense

20,805

20,805

Capitalized interest

(4,904
)

(4,904
)
Other, net

(1,650
)

(1,650
)
Income (loss) before income tax

(292,331
)
(71,191
)
(363,522
)
Income tax expense (benefit)

(106,200
)
(25,863
)
(132,063
)
Net income (loss)

$
(186,131
)
$
(45,328
)
$
(231,459
)

Earnings (loss) per share to common stockholders:

Basic

$
(2.00
)
$
(0.49
)
$
(2.49
)
Diluted

$
(2.00
)
$
(0.49
)
$
(2.49
)

Dividends per share

$
0.08

$

$
0.08

Comprehensive income (loss):

Net income (loss)

$
(186,131
)
$
(45,328
)
$
(231,459
)
Other comprehensive income (loss)

Change in fair value of investments, net of tax

85

85

Total comprehensive income (loss)

$
(186,046
)
$
(45,328
)
$
(231,374
)

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
June 30, 2016

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Revenues:

Oil sales

$
162,005

$

$
162,005

Gas sales

76,615

76,615

NGL sales

51,939

51,939

Gas gathering and other

8,211

8,211

Gas marketing, net

103

103

298,873

298,873

Costs and expenses:

Impairment of oil and gas properties

399,194

(65,903
)
333,291

Depreciation, depletion and amortization

123,877

(21,791
)
102,086

Asset retirement obligation

1,750

1,750

Production

57,213

57,213

Transportation, processing, and other operating

44,436

44,436

Gas gathering and other

7,492

7,492

Taxes other than income

14,066

14,066

General and administrative

21,424

21,424

Stock compensation

7,490

7,490

(Gain) loss on derivative instruments, net

33,236

33,236

Other operating, net

24

24

710,202

(87,694
)
622,508

Operating income (loss)

(411,329
)
87,694

(323,635
)
Other (income) and expense:

Interest expense

20,824

20,824

Capitalized interest

(5,633
)

(5,633
)
Other, net

(2,011
)

(2,011
)
Income (loss) before income tax

(424,509
)
87,694

(336,815
)
Income tax expense (benefit)

(154,219
)
31,858

(122,361
)
Net income (loss)

$
(270,290
)
$
55,836

$
(214,454
)

Earnings (loss) per share to common stockholders:

Basic

$
(2.91
)
$
0.60

$
(2.31
)
Diluted

$
(2.91
)
$
0.60

$
(2.31
)

Dividends per share

$
0.08

$

$
0.08

Comprehensive income (loss):

Net income (loss)

$
(270,290
)
$
55,836

$
(214,454
)
Other comprehensive income (loss)

Change in fair value of investments, net of tax

195

195

Total comprehensive income (loss)

$
(270,095
)
$
55,836

$
(214,259
)

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Six Months Ended
June 30, 2016

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Revenues:

Oil sales

$
279,578

$

$
279,578

Gas sales

159,223

159,223

NGL sales

85,291

85,291

Gas gathering and other

15,452

15,452

Gas marketing, net

(71
)

(71
)

539,473

539,473

Costs and expenses:

Impairment of oil and gas properties

629,326

22,751

652,077

Depreciation, depletion and amortization

251,976

(39,254
)
212,722

Asset retirement obligation

4,048

4,048

Production

127,915

127,915

Transportation, processing, and other operating

90,879

90,879

Gas gathering and other

15,572

15,572

Taxes other than income

27,905

27,905

General and administrative

35,321

35,321

Stock compensation

13,018

13,018

(Gain) loss on derivative instruments, net

32,808

32,808

Other operating, net

114

114

1,228,882

(16,503
)
1,212,379

Operating income (loss)

(689,409
)
16,503

(672,906
)
Other (income) and expense:

Interest expense

41,629

41,629

Capitalized interest

(10,537
)

(10,537
)
Other, net

(3,661
)

(3,661
)
Income (loss) before income tax

(716,840
)
16,503

(700,337
)
Income tax expense (benefit)

(260,419
)
5,995

(254,424
)
Net income (loss)

$
(456,421
)
$
10,508

$
(445,913
)

Earnings (loss) per share to common stockholders:

Basic

$
(4.91
)
$
0.12

$
(4.79
)
Diluted

$
(4.91
)
$
0.12

$
(4.79
)

Dividends per share

$
0.16

$

$
0.16

Comprehensive income (loss):

Net income (loss)

$
(456,421
)
$
10,508

$
(445,913
)
Other comprehensive income (loss)

Change in fair value of investments, net of tax

280

280

Total comprehensive income (loss)

$
(456,141
)
$
10,508

$
(445,633
)

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
September 30, 2016

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Revenues:

Oil sales

$166,079

$

$166,079

Gas sales

109,278

109,278

NGL sales

50,464

50,464

Gas gathering and other

9,824

9,824

Gas marketing, net

72

72

335,717

335,717

Costs and expenses:

Impairment of oil and gas properties

89,816

15,777

105,593

Depreciation, depletion and amortization

109,344

(19,067
)
90,277

Asset retirement obligation

2,033

2,033

Production

52,976

52,976

Transportation, processing, and other operating

48,706

48,706

Gas gathering and other

7,905

7,905

Taxes other than income

15,974

15,974

General and administrative

20,118

20,118

Stock compensation

5,764

5,764

(Gain) loss on derivative instruments, net

(9,758
)

(9,758
)
Other operating, net

179

179

343,057

(3,290
)
339,767

Operating income (loss)

(7,340
)
3,290

(4,050
)
Other (income) and expense:

Interest expense

20,931

20,931

Capitalized interest

(5,421
)

(5,421
)
Other, net

(3,828
)

(3,828
)
Income (loss) before income tax

(19,022
)
3,290

(15,732
)
Income tax expense (benefit)

(6,204
)
1,145

(5,059
)
Net income (loss)

$(12,818
)
$2,145

$(10,673
)

Earnings (loss) per share to common stockholders:

Basic

$(0.14
)
$0.02

$(0.12
)
Diluted

$(0.14
)
$0.02

$(0.12
)

Dividends per share

$0.08

$

$0.08

Comprehensive income (loss):

Net income (loss)

$(12,818
)
$2,145

$(10,673
)
Other comprehensive income (loss)

Change in fair value of investments, net of tax

287

287

Total comprehensive income (loss)

$(12,531
)
$2,145

$(10,386
)

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Nine Months Ended
September 30, 2016

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Revenues:

Oil sales

$
445,657

$

$
445,657

Gas sales

268,501

268,501

NGL sales

135,755

135,755

Gas gathering and other

25,276

25,276

Gas marketing, net

1

1

875,190

875,190

Costs and expenses:

Impairment of oil and gas properties

719,142

38,528

757,670

Depreciation, depletion and amortization

361,320

(58,321
)
302,999

Asset retirement obligation

6,081

6,081

Production

180,891

180,891

Transportation, processing, and other operating

139,585

139,585

Gas gathering and other

23,477

23,477

Taxes other than income

43,879

43,879

General and administrative

55,439

55,439

Stock compensation

18,782

18,782

(Gain) loss on derivative instruments, net

23,050

23,050

Other operating, net

293

293

1,571,939

(19,793
)
1,552,146

Operating income (loss)

(696,749
)
19,793

(676,956
)
Other (income) and expense:

Interest expense

62,560

62,560

Capitalized interest

(15,958
)

(15,958
)
Other, net

(7,489
)

(7,489
)
Income (loss) before income tax

(735,862
)
19,793

(716,069
)
Income tax expense (benefit)

(266,623
)
7,140

(259,483
)
Net income (loss)

$
(469,239
)
$
12,653

$
(456,586
)

Earnings (loss) per share to common stockholders:

Basic

$
(5.04
)
$
0.14

$
(4.90
)
Diluted

$
(5.04
)
$
0.14

$
(4.90
)

Dividends per share

$
0.24

$

$
0.24

Comprehensive income (loss):

Net income (loss)

$
(469,239
)
$
12,653

$
(456,586
)
Other comprehensive income (loss)

Change in fair value of investments, net of tax

567

567

Total comprehensive income (loss)

$
(468,672
)
$
12,653

$
(456,019
)

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
March 31, 2015

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Revenues:

Oil sales

$
196,005

$

$
196,005

Gas sales

110,962

110,962

NGL sales

45,600

45,600

Gas gathering and other

8,270

8,270

Gas marketing, net

165

165

361,002

361,002

Costs and expenses:

Impairment of oil and gas properties

603,599

217,585

821,184

Depreciation, depletion and amortization

216,778

(7,107
)
209,671

Asset retirement obligation

1,736

1,736

Production

82,211

82,211

Transportation, processing, and other operating

39,642

39,642

Gas gathering and other

8,864

8,864

Taxes other than income

21,981

21,981

General and administrative

15,938

15,938

Stock compensation

5,155

5,155

(Gain) loss on derivative instruments, net

—

—

Other operating, net

524

524

996,428

210,478

1,206,906

Operating income (loss)

(635,426
)
(210,478
)
(845,904
)
Other (income) and expense:

Interest expense

21,256

21,256

Capitalized interest

(9,417
)

(9,417
)
Other, net

(3,585
)

(3,585
)
Income (loss) before income tax

(643,680
)
(210,478
)
(854,158
)
Income tax expense (benefit)

(228,739
)
(75,849
)
(304,588
)
Net income (loss)

$
(414,941
)
$
(134,629
)
$
(549,570
)

Earnings (loss) per share to common stockholders:

Basic

$
(4.84
)
$
(1.57
)
$
(6.41
)
Diluted

$
(4.84
)
$
(1.57
)
$
(6.41
)

Dividends per share

$
0.16

$

$
0.16

Comprehensive income (loss):

Net income (loss)

$
(414,941
)
$
(134,629
)
$
(549,570
)
Other comprehensive income (loss)

Change in fair value of investments, net of tax

101

101

Total comprehensive income (loss)

$
(414,840
)
$
(134,629
)
$
(549,469
)

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
June 30, 2015

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Revenues:

Oil sales

$
259,344

$

$
259,344

Gas sales

106,374

106,374

NGL sales

49,477

49,477

Gas gathering and other

9,141

9,141

Gas marketing, net

(53
)

(53
)

424,283

424,283

Costs and expenses:

Impairment of oil and gas properties

967,287

(1,270
)
966,017

Depreciation, depletion and amortization

217,451

(14,176
)
203,275

Asset retirement obligation

2,042

2,042

Production

70,600

70,600

Transportation, processing, and other operating

43,713

43,713

Gas gathering and other

11,306

11,306

Taxes other than income

25,980

25,980

General and administrative

14,054

14,054

Stock compensation

4,988

4,988

(Gain) loss on derivative instruments, net

—

—

Other operating, net

260

260

1,357,681

(15,446
)
1,342,235

Operating income (loss)

(933,398
)
15,446

(917,952
)
Other (income) and expense:

Interest expense

21,297

21,297

Capitalized interest

(8,570
)

(8,570
)
Other, net

(3,854
)

(3,854
)
Income (loss) before income tax

(942,271
)
15,446

(926,825
)
Income tax expense (benefit)

(342,056
)
5,716

(336,340
)
Net income (loss)

$
(600,215
)
$
9,730

$
(590,485
)

Earnings (loss) per share to common stockholders:

Basic

$
(6.47
)
$
0.11

$
(6.36
)
Diluted

$
(6.47
)
$
0.11

$
(6.36
)

Dividends per share

$
0.16

$

$
0.16

Comprehensive income (loss):

Net income (loss)

$
(600,215
)
$
9,730

$
(590,485
)
Other comprehensive income (loss)

Change in fair value of investments, net of tax

(292
)

(292
)
Total comprehensive income (loss)

$
(600,507
)
$
9,730

$
(590,777
)

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
September 30, 2015

(in thousands, except per share data)

As Previously
Reported

Corrections

As
Corrected

Revenues:

Oil sales

$
192,501

$

$
192,501

Gas sales

114,649

114,649

NGL sales

40,159

40,159

Gas gathering and other

8,754

8,754

Gas marketing, net

(8
)

(8
)

356,055

356,055

Costs and expenses:

Impairment of oil and gas properties

1,180,649

(36,188
)
1,144,461

Depreciation, depletion and amortization

185,654

(13,756
)
171,898

Asset retirement obligation

2,615

2,615

Production

69,334

69,334

Transportation, processing, and other operating

46,290

46,290

Gas gathering and other

8,429

8,429

Taxes other than income

19,717

19,717

General and administrative

20,413

20,413

Stock compensation

4,737

4,737

(Gain) loss on derivative instruments, net

(1,968
)

(1,968
)
Other operating, net

60

60

1,535,930

(49,944
)
1,485,986

Operating income (loss)

(1,179,875
)
49,944

(1,129,931
)
Other (income) and expense:

Interest expense

21,416

21,416

Capitalized interest

(7,100
)

(7,100
)
Other, net

(2,375
)

(2,375
)
Income (loss) before income tax

(1,191,816
)
49,944

(1,141,872
)
Income tax expense (benefit)

(428,532
)
17,960

(410,572
)
Net income (loss)

$
(763,284
)
$
31,984

$
(731,300
)

Earnings (loss) per share to common stockholders:

Basic

$
(8.21
)
$
0.34

$
(7.87
)
Diluted

$
(8.21
)
$
0.34

$
(7.87
)

Dividends per share

$
0.16

$

$
0.16

Comprehensive income (loss):

Net income (loss)

$
(763,284
)
$
31,984

$
(731,300
)
Other comprehensive income (loss)

Change in fair value of investments, net of tax

(609
)

(609
)
Total comprehensive income (loss)

$
(763,893
)
$
31,984

$
(731,909
)

Condensed Consolidated Statement of Cash Flows
for the Three Months Ended
March 31, 2016

(in thousands)

As Previously
Reported

Corrections

As
Corrected

Cash flows from operating activities:

Net income (loss)

$
(186,131
)
$
(45,328
)
$
(231,459
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Impairment of oil and gas properties

230,132

88,654

318,786

Depreciation, depletion and amortization

128,099

(17,463
)
110,636

Asset retirement obligation

2,298

2,298

Deferred income taxes

(106,200
)
(25,863
)
(132,063
)
Stock compensation

5,528

5,528

(Gain) loss on derivative instruments

(428
)

(428
)
Settlements on derivative instruments

5,068

5,068

Changes in non-current assets and liabilities

1,863

1,863

Other, net

1,362

1,362

Changes in operating assets and liabilities:

Receivables, net

33,147

33,147

Other current assets

11,982

11,982

Accounts payable and other current liabilities

(41,660
)

(41,660
)
Net cash provided by operating activities

85,060

85,060

Cash flows from investing activities:

Oil and gas expenditures

(176,395
)

(176,395
)
Sales of oil and gas assets and other assets

13,059

13,059

Other capital expenditures

(9,477
)

(9,477
)
Net cash used by investing activities

(172,813
)

(172,813
)
Cash flows from financing activities:

Dividends paid

(15,104
)

(15,104
)
Proceeds from exercise of stock options and other

114

114

Net cash provided by (used in) financing activities

(14,990
)

(14,990
)
Net change in cash and cash equivalents

(102,743
)

(102,743
)
Cash and cash equivalents at beginning of period

779,382

779,382

Cash and cash equivalents at end of period

$
676,639

$
676,639

Condensed Consolidated Statement of Cash Flows
for the Six Months Ended
June 30, 2016

(in thousands)

As Previously
Reported

Corrections

As
Corrected

Cash flows from operating activities:

Net income (loss)

$
(456,421
)
$
10,508

$
(445,913
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Impairment of oil and gas properties

629,326

22,751

652,077

Depreciation, depletion and amortization

251,976

(39,254
)
212,722

Asset retirement obligation

4,048

4,048

Deferred income taxes

(260,419
)
5,995

(254,424
)
Stock compensation

13,018

13,018

(Gain) loss on derivative instruments

32,808

32,808

Settlements on derivative instruments

8,927

8,927

Changes in non-current assets and liabilities

2,548

2,548

Other, net

2,644

2,644

Changes in operating assets and liabilities:

Receivables, net

(4,327
)

(4,327
)
Other current assets

17,328

17,328

Accounts payable and other current liabilities

(27,752
)

(27,752
)
Net cash provided by operating activities

213,704

213,704

Cash flows from investing activities:

Oil and gas expenditures

(325,058
)

(325,058
)
Sales of oil and gas assets and other assets

12,854

12,854

Other capital expenditures

(17,774
)

(17,774
)
Net cash used by investing activities

(329,978
)

(329,978
)
Cash flows from financing activities:

Financing and underwriting fees

(1
)

(1
)
Dividends paid

(22,655
)

(22,655
)
Proceeds from exercise of stock options and other

1,287

1,287

Net cash provided by (used in) financing activities

(21,369
)

(21,369
)
Net change in cash and cash equivalents

(137,643
)

(137,643
)
Cash and cash equivalents at beginning of period

779,382

779,382

Cash and cash equivalents at end of period

$
641,739

$
641,739

Condensed Consolidated Statement of Cash Flows
for the Nine Months Ended
September 30, 2016

(in thousands)

As Previously
Reported

Corrections

As
Corrected

Cash flows from operating activities:

Net income (loss)

$
(469,239
)
$
12,653

$
(456,586
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Impairment of oil and gas properties

719,142

38,528

757,670

Depreciation, depletion and amortization

361,320

(58,321
)
302,999

Asset retirement obligation

6,081

6,081

Deferred income taxes

(265,508
)
7,140

(258,368
)
Stock compensation

18,782

18,782

(Gain) loss on derivative instruments

23,050

23,050

Settlements on derivative instruments

9,718

9,718

Changes in non-current assets and liabilities

4,121

4,121

Other, net

2,931

2,931

Changes in operating assets and liabilities:

Receivables, net

(1,723
)

(1,723
)
Other current assets

23,034

23,034

Accounts payable and other current liabilities

(2,378
)

(2,378
)
Net cash provided by operating activities

429,331

429,331

Cash flows from investing activities:

Oil and gas expenditures

(485,114
)

(485,114
)
Sales of oil and gas assets

19,013

19,013

Sales of other assets

5,718

5,718

Other capital expenditures

(24,013
)

(24,013
)
Net cash used by investing activities

(484,396
)

(484,396
)
Cash flows from financing activities:

Financing and underwriting fees

(1
)

(1
)
Dividends paid

(30,243
)

(30,243
)
Proceeds from exercise of stock options and other

4,623

4,623

Net cash provided by (used in) financing activities

(25,621
)

(25,621
)
Net change in cash and cash equivalents

(80,686
)

(80,686
)
Cash and cash equivalents at beginning of period

779,382

779,382

Cash and cash equivalents at end of period

$
698,696

$
698,696

Condensed Consolidated Statement of Cash Flows
for the Three Months Ended
March 31, 2015

(in thousands)

As Previously
Reported

Corrections

As
Corrected

Cash flows from operating activities:

Net income (loss)

$
(414,941
)
$
(134,629
)
$
(549,570
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Impairment of oil and gas properties

603,599

217,585

821,184

Depreciation, depletion and amortization

216,778

(7,107
)
209,671

Asset retirement obligation

1,736

1,736

Deferred income taxes

(228,739
)
(75,849
)
(304,588
)
Stock compensation

5,155

5,155

Changes in non-current assets and liabilities

1,046

1,046

Other, net

2,311

2,311

Changes in operating assets and liabilities:

Receivables, net

72,397

72,397

Other current assets

9,894

9,894

Accounts payable and other current liabilities

(156,063
)

(156,063
)
Net cash provided by operating activities

113,173

113,173

Cash flows from investing activities:

Oil and gas expenditures

(371,106
)

(371,106
)
Sales of oil and gas assets and other assets

1,180

1,180

Other capital expenditures

(18,848
)

(18,848
)
Net cash used by investing activities

(388,774
)

(388,774
)
Cash flows from financing activities:

Dividends paid

(13,947
)

(13,947
)
Proceeds from exercise of stock options and other

4,618

4,618

Net cash provided by (used in) financing activities

(9,329
)

(9,329
)
Net change in cash and cash equivalents

(284,930
)

(284,930
)
Cash and cash equivalents at beginning of period

405,862

405,862

Cash and cash equivalents at end of period

$
120,932

$
120,932

Condensed Consolidated Statement of Cash Flows
for the Six Months Ended
June 30, 2015

(in thousands)

As Previously
Reported

Corrections

As
Corrected

Cash flows from operating activities:

Net income (loss)

$
(1,015,156
)
$
(124,899
)
$
(1,140,055
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Impairment of oil and gas properties

1,570,886

216,315

1,787,201

Depreciation, depletion and amortization

434,229

(21,283
)
412,946

Asset retirement obligation

3,778

3,778

Deferred income taxes

(570,795
)
(70,133
)
(640,928
)
Stock compensation

10,143

10,143

Changes in non-current assets and liabilities

2,942

2,942

Other, net

3,276

3,276

Changes in operating assets and liabilities:

Receivables, net

92,473

92,473

Other current assets

16,121

16,121

Accounts payable and other current liabilities

(177,352
)

(177,352
)
Net cash provided by operating activities

370,545

370,545

Cash flows from investing activities:

Oil and gas expenditures

(599,222
)

(599,222
)
Sales of oil and gas assets and other assets

9,233

9,233

Other capital expenditures

(35,882
)

(35,882
)
Net cash used by investing activities

(625,871
)

(625,871
)
Cash flows from financing activities:

Proceeds from sale of common stock

752,100

752,100

Financing and underwriting fees

(22,563
)

(22,563
)
Dividends paid

(28,129
)

(28,129
)
Proceeds from exercise of stock options and other

4,936

4,936

Net cash provided by (used in) financing activities

706,344

706,344

Net change in cash and cash equivalents

451,018

451,018

Cash and cash equivalents at beginning of period

405,862

405,862

Cash and cash equivalents at end of period

$
856,880

$
856,880

Condensed Consolidated Statement of Cash Flows
for the Nine Months Ended
September 30, 2015

(in thousands)

As Previously
Reported

Corrections

As
Corrected

Cash flows from operating activities:

Net income (loss)

$
(1,778,440
)
$
(92,915
)
$
(1,871,355
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Impairment of oil and gas properties

2,751,535

180,127

2,931,662

Depreciation, depletion and amortization

619,883

(35,039
)
584,844

Asset retirement obligation

6,393

6,393

Deferred income taxes

(1,014,264
)
(52,173
)
(1,066,437
)
Stock compensation

14,880

14,880

(Gain) loss on derivative instruments

(1,968
)

(1,968
)
Settlements on derivative instruments

—

—

Changes in non-current assets and liabilities

16,343

16,343

Other, net

3,494

3,494

Changes in operating assets and liabilities:

Receivables, net

151,783

151,783

Other current assets

29,634

29,634

Accounts payable and other current liabilities

(222,727
)

(222,727
)
Net cash provided by operating activities

576,546

576,546

Cash flows from investing activities:

Oil and gas expenditures

(771,029
)

(771,029
)
Sales of oil and gas assets

38,343

38,343

Sales of other assets

1,057

1,057

Other capital expenditures

(58,085
)

(58,085
)
Net cash used by investing activities

(789,714
)

(789,714
)
Cash flows from financing activities:

Proceeds from sale of common stock

752,100

752,100

Financing and underwriting fees

(22,663
)

(22,663
)
Dividends paid

(43,211
)

(43,211
)
Proceeds from exercise of stock options and other

20,392

20,392

Net cash provided by (used in) financing activities

706,618

706,618

Net change in cash and cash equivalents

493,450

493,450

Cash and cash equivalents at beginning of period

405,862

405,862

Cash and cash equivalents at end of period

$
899,312

$
899,312

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

~~None.~~

ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

~~In connection with the preparation of our Original Filing of the Annual Report on Form 10-K, an evaluation was carried out by~~

Cimarex’s management, under the supervision and with the participation of the Chief Executive Officer ~~(CEO)~~(“CEO”) and Chief Financial Officer ~~(CFO)~~(“CFO”), ofhave evaluated the effectiveness of Cimarex’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of December 31, ~~2016.~~2019. Disclosure controls and procedures are designed to ~~ensure~~provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods required by the U.S. Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including the CEO and CFO, to allow timely decisions regarding required disclosures.

~~At the time the Original Filing was filed~~ Based on ~~February 24, 2017, our~~this evaluation, Cimarex’s CEO and CFO concluded that ~~the disclosure controls and procedures were effective as of December 31, 2016. Subsequent~~due to that evaluation, management identified an immaterial error in the full cost ceiling test calculation pursuant to SEC Regulation S-X Rule 4-10 (SAB Topic 12) and as a result amended the December 31, 2016 Form 10-K and recorded an immaterial correction of an error in the historical financial statements.

~~As a result of this reassessment and the identification of~~ the material weakness in our internal control over financial reporting described below, ~~our CEO and CFO have, after considering~~ the ~~existence of the material weakness identified, concluded that our~~Company’s disclosure controls and procedures were not effective as of December 31, ~~2016.~~

2019.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Cimarex’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The ~~company’s~~Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. ~~Our~~The Company’s internal control over financial reporting also includes those policies and procedures that:

1) ~~pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets;~~

2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and directors; and

3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.


(1)	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets;


(2)	provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and directors; and


(3)	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the consolidated financial statements.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or combination of deficiencies in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

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As of December 31, 2019, Cimarex’s management assessed the effectiveness of internal control over financial reporting based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in connection with the Original Filing of the Annual Report on Form 10-K on February 24, 2017 and based on that assessment, management concluded that the internal control over financial reporting was effective as of December 31, 2016. In connection with preparation of this Form 10-K/A, our CEO and CFO reassessed the effectiveness of our internal control over financial reporting.. Based on this ~~reassessment, our~~assessment, the Company’s CEO and CFO have concluded that a material weakness in internal control over financial reporting existed as of December 31, ~~2016~~2019 as described below:

The ~~company~~Company did not have an effective process and control in place to ~~verify~~periodically evaluate the ~~completeness~~quantitative effect associated with the inclusion or exclusion of certain inputs, such as skim oil and ~~accuracy of financial information~~drip liquids, in the Company’s oil and gas reserve database used in the ~~full cost~~ ceiling test ~~calculation~~impairment calculations, depletion calculations, and the preparation of the related disclosures included in ~~accordance with SEC Regulation S-X Rule 4-10.~~the supplemental information on oil and gas producing activities (unaudited). The ~~company’s~~material weakness resulted from an ineffective risk assessment process ~~failed~~ to identify ~~necessary modifications to the spreadsheet template when~~and assess changes in ~~business~~the Company’s operations and ~~relevant financial information occurred that impacted~~their impact on the ~~full cost ceiling test calculation.~~

Company’s processes and controls governing preparation of the oil and gas reserve database.

This resulted in the correction of an immaterial ~~misstatements~~misstatement to previously reported impairment expense, ~~depletion expense and income tax expense (benefit)~~ and the related balance sheet accounts as described in ~~Note 1 in~~ the ~~amended~~supplemental quarterly financial data (unaudited) to the consolidated financial statements as of and for the three year period ended December 31, ~~2016~~2019 in this Form ~~10-K/A.~~10-K. However, ~~these~~this control ~~deficiencies~~deficiency created a reasonable possibility that a material misstatement to ~~our~~the consolidated financial statements would not have been prevented or detected on a timely basis, and therefore wethe Company concluded that the ~~deficiencies~~deficiency represented a material weakness in ~~our~~ internal control over financial reporting and that ~~our~~ internal control over financial reporting was not effective as of December 31, ~~2016.~~

~~Our~~2019.

The Company’s independent registered public accounting firm, KPMG LLP, has audited the effectiveness of internal control over financial reporting and has issued an adverse report on the effectiveness of our internal control over financial reporting as of December 31, ~~2016, which~~2019. KPMG LLP’s report is included ~~on page 118 following~~later in this ~~report.~~

Item 9A in this Form 10-K.

MANAGEMENT’S REMEDIATION PLAN

In response to the material weakness identified in Management’s Report on Internal Control over Financial Reporting, ~~the company has~~we have developed a plan with oversight from the Audit Committee of the Board of Directors to remediate the material weakness. The remediation efforts being implemented include the following:

· ~~Enhancement~~

Performance of a quarterly evaluation of the ~~control over the preparation and review of the full cost ceiling test calculation to include examining SEC SAB Topic 12 to reinforce the understanding of the requirements~~quantitative effect associated with ~~appropriately performing this calculation, particularly as it relates to~~ the ~~income tax effects~~inclusion or exclusion of certain inputs in the ~~calculation;~~

· Refinement of the spreadsheet template used to prepare the full cost ceiling test calculation to ensure that the appropriate application of accounting for all components of the full cost ceiling test calculation is embedded within the template;Company’s oil and

· gas reserve database.

Revision and communication of ~~the accounting~~ controls, policies and procedures relating to identifying and assessing changes that could potentially impact the system of internal control governing preparation of the ~~full cost ceiling test calculation.~~

~~Due to the material weakness referred to above, the company’s management performed additional analyses~~oil and procedures in order to conclude that our consolidated financial statements in this Form 10-K/A for the year ended December 31, 2016 are fairly presented, in all material respects, in accordance with accounting principles generally accepted in the United States of America.

gas reserve database.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Other than the identification of the material weakness described above, there was no change in ~~the company’s~~our internal control over financial reporting that occurred during our most recent fiscal quarter ended December 31, ~~2016~~2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Report of Independent Registered Public Accounting Firm

~~The~~

To the Stockholders and Board of Directors ~~and Stockholders~~

Cimarex Energy Co.:

Opinion on Internal Control Over Financial Reporting

We have audited Cimarex Energy Co. and ~~subsidiaries~~subsidiaries’ (the Company) internal control over financial reporting as of December 31, ~~2016,~~2019, based on criteria established in Internal Control –- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway ~~Commission (COSO). Cimarex Energy Co.~~Commission.

In our opinion, because of the effect of the material weakness, described below, on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and ~~subsidiaries’~~2018, the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements), and our report dated February 26, 2020 expressed an unqualified opinion on those consolidated financial statements.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. A material weakness related to an ineffective process and control to periodically evaluate the quantitative effect associated with the inclusion or exclusion of certain inputs, such as skim oil and drip liquids, in the Company’s oil and gas reserve database used in the ceiling test impairment calculations, depletion calculations, and the preparation of the related disclosures included in the supplemental information on oil and gas producing activities (unaudited) resulting from an ineffective risk assessment process to identify and assess changes in the Company’s operations and their impact on the Company’s processes and controls governing preparation of the oil and gas reserve database has been identified and included in management’s assessment. The material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2019 consolidated financial statements, and this report does not affect our report on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on ~~Cimarex Energy Co. and subsidiaries’~~the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the ~~Public Company Accounting Oversight Board (United States).~~PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

~~A material weakness is a deficiency, or a combination~~

KPMG LLP

Denver, Colorado

February 26, 2020

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Table of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. A material weakness related to an ineffective process and control to verify the completeness and accuracy of financial information used in the full cost ceiling test calculation resulting from an ineffective risk assessment process that failed to identify necessary modifications to a spreadsheet template when changes in business operations and relevant financial information occurred has been identified and included in management’s assessment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements for each of the years in the three-year period ended December 31, 2016, and this report does not affect our report dated February 24, 2017, except for the immaterial error correction to the consolidated financial statements discussed in Note 1 and the restatement as to the effectiveness of internal control over financial reporting for the material weakness related to the full cost ceiling test calculation, as to which the date is May 10, 2017, which expressed an unqualified opinion on those consolidated financial statements.

The assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting has been restated by the Company’s management to disclose the aforementioned material weakness and the resultant ineffectiveness of its internal control over financial reporting.

In our opinion, because of the effect of the aforementioned material weakness on the achievement of the objectives of the control criteria, Cimarex Energy Co. and subsidiaries has not maintained effective internal control over financial reporting as of December 31, 2016, based on criteria established in ~~Internal Control – Integrated Framework (2013)~~ ~~issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).~~

~~KPMG LLP~~

~~Denver, Colorado~~
February 24, 2017, except for the immaterial error correction to the consolidated financial statements discussed in Note 1 and the restatement as to the effectiveness of internal control over financial reporting for the material weakness related to the full cost ceiling test calculation, as to which the date is May 10, 2017

Contents

ITEM 9B. OTHER INFORMATION

None.

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~~None.~~

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information concerning the directors of Cimarex required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May ~~11, 2017~~6, 2020 Annual Meeting of Shareholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than 120 days subsequent to December 31, ~~2016.~~2019. The executive officers of Cimarex as of February ~~24, 2017~~26, 2020 were:

~~Name~~			~~Age~~	~~Office~~

Name	Age	Office
Thomas E. Jorden	59 62	Chairman of the Board, Chief Executive Officer and President
Joseph R. Albi	58 61	Executive Vice President — Operations, Chief Operating Officer
Stephen P. Bell	62 65	Executive Vice President — Business Development
G. Mark Burford	49 52	Senior Vice President and Chief Financial Officer
Francis B. Barron	54 57	Senior Vice President — General Counsel
John A. Lambuth	54 57	Senior Vice President — Exploration
Christopher H. Clason	53	Vice President and Chief Human Resources Officer
Gary R. Abbott	44 47	Vice President — Corporate Engineering
~~Krista L. Johnson~~	46	~~Vice President — Human Resources, Governmental Relations, and External Affairs~~
Timothy A. Ficker	49 52	Vice President — Controller, Chief Accounting Officer, and Assistant Secretary

There are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he or she was selected as an executive officer.

THOMAS E. JORDEN was elected Chairman of the Board effective August 14, 2012 after being named President and Chief Executive Officer effective September 30, 2011. Since December 8, 2003, Mr. Jorden served as Executive Vice President of Exploration and had served in a similar capacity since September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as Vice President of Exploration (October 1999 to September 2002) and Chief Geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources.

JOSEPH R. ALBI was named Executive Vice President and Chief Operating Officer effective September 30, 2011. Mr. Albi served as Executive Vice President of Operations since March 1, 2005. Since December 8, 2003, Mr. Albi served as Senior Vice President of Corporate Engineering. From September 30, 2002 to December 8, 2003, he served as Vice President of Engineering. From June 1994 to September 2002, Mr. Albi was with Key Production Company, Inc. where he served as Vice President of Engineering and Manager of Engineering.

STEPHEN P. BELL was named Executive Vice President, Business Development effective September 13, 2012. Since September 2002, Mr. Bell served as Senior Vice President of Business Development and Land. Prior to its merger with Cimarex, Mr. Bell was with Key Production Company, Inc. since February 1994. In September 1999, he was appointed Senior Vice President, Business Development and Land. From February 1994 to September 1999, he served as Vice President, Land.

G. MARK BURFORDwas named Senior Vice President and Chief Financial Officer in March 2019. Mr. Burford was appointed Vice President and Chief Financial Officer in September ~~2015. He was appointed~~2015 and Vice President, Capital Markets and Planning in December 2010. Mr. Burford joined Cimarex in April 2005 as Director of Capital Markets. Prior to joining Cimarex, he was Director of Investor Relations for Whiting Petroleum and Tom ~~Brown, Inc.~~Brown. His experience also includes equity research with Petrie Parkman & Co., an investment banking firm and public accounting.

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FRANCIS B. BARRON joined Cimarex as Senior Vice President, General Counsel in July 2013. From February 2004 until July 2013, Mr. Barron served in various capacities at Bill Barrett Corporation, a publicly traded, Denver-based oil and gas exploration and development company, including as Executive Vice President, General

Counsel, and Secretary. He also served as Chief Financial Officer from November 2006 until March 2007. Prior to February 2004, Mr. Barron was a partner at the Denver, Colorado office of the law firm of Patton Boggs LLP as well as a partner at Bearman Talesnick & Clowdus Professional Corporation. Mr. Barron’s practice included corporate, securities, and business law for publicly traded oil and gas companies.

JOHN A. LAMBUTH was named Senior Vice President of Exploration in December 2015. Prior to his promotion, he served as the Company’s Vice President of Exploration since September 2012 and Chief Geophysicist, a position he held since joining Cimarex in 2004. Mr. Lambuth began his career in 1985 with Shell Oil Co., where he held various positions in exploration and in research and development. Immediately prior to joining Cimarex, he spent three years as onshore Exploration Manager of El Paso Energy Company.

CHRISTOPHER H. CLASON joined Cimarex as Vice President and Chief Human Resources Officer in April 2019. From February 2016 until April 2019, Mr. Clason was Director of MBA Career Management and Employer Relations at the Marriott School of Business at Brigham Young University. Prior to his work in higher education, he was Senior Vice President and Chief Human Resources Officer at ProBuild LLC, a Devonshire Investors company. From 2001 until 2014, Mr. Clason held various global HR executive leadership roles at Honeywell International, including Vice President Human Resources and Communications at Honeywell Aerospace. His background includes extensive international experience at Citigroup and early career work at Chevron.

GARY R. ABBOTT was ~~elected~~named Vice President of Corporate Engineering March 1, 2005. Since January 2002, Mr. Abbott served as manager, Corporate Reservoir Engineering. From April 1999 to January 2002, Mr. Abbott was a ~~reservoir~~senior engineer with Key Production Company, Inc.

~~KRISTA L. JOHNSON~~ joined Cimarex as Vice President of Governmental and External Affairs in November 2014. Previously she served at Shell Oil Company since 2006, her last role as Vice President, International Organizations. Prior to joining Shell, she spent eight years with Western Gas Resources, most recently as Director of Government and Media Relations. Her experience also includes private practice in oil and gas law, client based energy advocacy in Washington, work in the Federal Relations Department of the American Petroleum Institute, and in the office of former U.S. Senator Conrad Burns.

TIMOTHY A. FICKER was appointed Vice President, Controller, Chief Accounting Officer, and Assistant Secretary in December 2016 to be effective in February 2017 and previously served as the Company’s Controller since September 2016. ~~From February 2015 until September 2016,~~Prior to joining Cimarex, he ~~served as~~was the Chief Financial Officer ~~and Principal~~ of Alcova Management LLC, ~~a start-up oil and gas exploration and production company concentrating on the Powder River Basin of Wyoming. Mr. Ficker served as Chief Financial Officer of~~ Venoco, Inc., and ~~in other capacities from March 2007 to November 2014. From May 2005 to March 2007, he served as Vice President, Chief Financial Officer, Principal Accounting Officer and Secretary of~~ Infinity Energy Resources Inc. Mr. Ficker previously served as an audit partner in KPMG LLP’s energy audit practice in Denver and as an audit partner for Arthur Andersen LLP, where he served clients primarily in the energy industry. ~~His energy clients at KPMG and Arthur Andersen were principally domestic exploration and production companies.~~

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ITEM 11. EXECUTIVE COMPENSATION

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May ~~11, 2017~~6, 2020 Annual Meeting of Shareholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than 120 days subsequent to December 31, ~~2016.~~

2019.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

~~Information~~

The following table sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the company at December 31, 2019:



Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants, and rights	(b) Weighted-average exercise price of outstanding options, warrants, and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	495,538	$	87.17	3,744,357
Equity compensation plans not approved by security holders	—	—		—
Total	495,538	$	87.17	3,744,357

The remaining information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May ~~11, 2017~~6, 2020 Annual Meeting of Shareholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than 120 days subsequent to December 31, ~~2016.~~

2019.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

2019.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

2019.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

				~~Page~~

			Page
(a) (1)		The following financial statements are included in Item 8 to this 10-K:
		Consolidated ~~balance sheets~~Balance Sheets as of December 31, ~~2016~~2019 and ~~2015~~2018	67 66
		Consolidated ~~statements~~Statements of ~~operations~~Operations and ~~comprehensive income (loss)~~Comprehensive Income (Loss) for the years ended December 31, ~~2016, 2015,~~2019, 2018, and ~~2014~~2017	68 67
		Consolidated ~~statements~~Statements of ~~cash flows~~Cash Flows for the years ended December 31, ~~2016, 2015,~~2019, 2018, and ~~2014~~2017	69 68
		Consolidated ~~statements~~Statements of ~~stockholders’ equity~~Stockholders’ Equity for the years ended December 31, ~~2016, 2015,~~2019, 2018, and ~~2014~~2017	70 69
		Notes to ~~consolidated financial statements~~Consolidated Financial Statements	71 70
~~(2)~~ (2	)	Financial statement schedules—None
~~(3)~~ (3	~~Exhibits:~~ )	Exhibits:

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.

All management contracts or compensatory plans or arrangements are designated by a plus sign (+).

~~Exhibit~~			~~Title~~
~~3.1~~
Exhibit		Title
2.1		Agreement and Plan of Merger dated as of November 18, 2018, by and among Cimarex Energy Co., CR Sub 1 Inc., CR Sub 2 LLC and Resolute Energy Corporation (filed as Exhibit 2.1 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).

3.1		Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant’s Form 8-K (Commission File ~~no.~~No. 001-31446) dated June 7, 2005 and incorporated herein by reference).

3.2	~~Amended and Restated By-laws of Cimarex Energy Co. dated December 11, 2013 (filed on December 16, 2013 (Commission File No. 001-31446) and incorporated herein by reference).~~

~~3.3~~	Amended and Restated By-laws of Cimarex Energy Co. dated November 11, 2015 (filed as Exhibits 3.1 and 3.2 to the Current Report on Form 8-K filed on November 12, 2015 (Commission File No. 001-31446) and incorporated herein by reference).

4.1		Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.3 to Registration Statement on Form S-3 filed September 17, 2012 (Registration No. 333-183939) and incorporated herein by reference).

4.2		Debt Securities Indenture dated as of April 5, 2012, by and among Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on April 5, 2012 (Commission File No. 001-31446) and incorporated herein by reference.

4.3		First Supplemental Indenture dated as of April 5, 2012, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee included as Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 5, 2012 (Commission File No. 001-31446) and incorporated herein by reference.

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~~4.4~~
Exhibit			Title
4.4			Form of 5.875% Senior Notes due 2022 included in Exhibit ~~4.3~~4.2 to the Registrant’s Current Report on Form 8-K filed on April 5, 2012 (Commission File No. 001-31446) and incorporated herein by reference.

4.5			Indenture dated as of June 4, 2014, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on June 4, 2014 (Commission File No. 001-31446) and incorporated herein by reference.

4.6			First Supplemental Indenture dated as of June 4, 2014, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee included as Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on June 4, 2014 (Commission File No. 001-31446) and incorporated herein by reference.

4.7			Form of 4.375% Senior Notes due 2024 included in Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on June 4, 2014 (Commission File No. 001-31446) and incorporated herein by reference.

~~4.8~~
4.8			Form of Indenture by and among Cimarex Energy Co. and U.S. Bank National Association, as trustee (filed as Exhibit 4.7 to Registration Statement on Form S-3 filed September 21, 2015 (Registration No. 333-183939) and incorporated herein by reference).

~~10.1~~ 4.9			Indenture dated as of April 10, 2017, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on April 10, 2017 (Commission File No. 001-31446) and incorporated herein by reference.

4.10			First Supplemental Indenture dated as of April 10, 2017, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 10, 2017 (Commission File No. 001-31446) and incorporated herein by reference.

4.11			Form of 3.90% Senior Notes due 2027 included in Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on April 10, 2017 (Commission File No. 001-31446) and incorporated herein by reference.

4.12			Certificate of Designations of 8⅛% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co., dated February 28, 2019 (filed on March 1, 2019 as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).

4.13			Second Supplemental Indenture dated as of March 8, 2019, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee (filed on March 8, 2019 as Exhibit 4.2 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).

4.14			Form of 4.375% Senior Notes due 2029 (filed on March 8, 2019 as Exhibit 4.3 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).

4.15			Description of Registrant’s Securities *

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Exhibit		Title
10.1		Credit Agreement dated as of July 14, 2011, among Cimarex, the Administrative Agent, the Co-Syndication Agents, the Co-Documentation Agents and the Lenders filed on July 18, 2011 (Commission File No. 001-31446) as Exhibit 10.l to the Registrant’s Current Report on Form 8-K and incorporated herein by reference.

10.2		First Amendment to Credit Agreement dated as of July 19, 2012, among Cimarex, the Guarantors, the Administrative Agent, and the Lenders filed on May 5, 2014 (Commission File No. 001-31446) as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K and incorporated herein by reference.

10.3		Second Amendment to Credit Agreement dated as of May 1, 2014, among Cimarex, the Guarantors, the Administrative Agent, and the Lenders filed on May 5, 2014 (Commission File No. 001-31446) as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K and incorporated herein by reference.

10.4	Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).

~~10.5~~	Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Paul Korus (filed as Exhibit 10.9 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference).

~~10.6~~	Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +

~~10.7~~ 10.5		Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Thomas E. Jorden (filed as Exhibit 10.11 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.8~~ 10.6		Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +

~~10.9~~ 10.7		Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Stephen P. Bell (filed as Exhibit 10.13 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.10~~ 10.8		Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +

~~10.11~~ 10.9		Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Joseph R. Albi (filed as Exhibit 10.15 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.12~~ 10.10		Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. effective January 1, 2009 (filed as Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001- 31446) and incorporated herein by reference). +

~~10.13~~ 10.11		2011 Equity Incentive Plan adopted May 18, 2011 (filed as Appendix A to the Definitive Proxy Statement 14-A filed on March 23, 2011 (Commission File No. 001-31446) and incorporated herein by reference). +

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~~10.14~~

Exhibit			Title
10.12			Form of Notice of Grant of Award of Performance Stock and Award Agreement (filed as Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 filed on August 4, 2011 (Commission File no. 001-31446) and incorporated herein by reference). +

~~10.15~~ 10.13			Form of Notice of Grant of Restricted Stock and Award Agreement (filed as Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 filed on August 4, 2011 (Commission File no. 001-31446) and incorporated herein by reference). +

~~10.16~~ 10.14			Form of Notice of Grant of Nonqualified Stock Option and Award Agreement (filed as Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 filed on August 4, 2011 (Commission File no. 001-31446) and incorporated herein by reference). +

~~10.17~~ 10.15			Form of Notice of Grant and Award Agreement (Other Stock Award with performance conditions) (filed as Exhibit 10.15 to the Annual Report on Form 10-K for the year ended December 31, 2013 filed on February 26, 2014 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.18~~ 10.16			2014 Equity Incentive Plan adopted May 15, 2014 (filed as Appendix A to the Definitive Proxy Statement 14-A filed on April 1, 2014 (Commission File No. 001-31446) and incorporated herein by reference. +

~~10.19~~ 10.17			Form of Notice of Grant of Restricted Stock (Director) and Award Agreement (filed as Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August 6, 2014 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.20~~ 10.18			Form of Notice of Grant of Nonqualified Stock Option and Award Agreement (filed as Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August 6, 2014 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.21~~ 10.19			Form of Notice of Grant of Restricted Stock and Award Agreement (filed as Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August 6, 2014 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.22~~ 10.20			Form of Notice of Grant of Restricted Stock and Award Agreement (Performance Award) (filed as Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August 6, 2014 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.23~~ 10.21			Form of Notice of Grant of Restricted Stock and Award Agreement (Performance Award) (filed as Exhibit 10.23 to the Annual Report on Form 10-K for the year ended December 31, 2014 filed on February 25, 2015 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.24~~ 10.22			Deferred Compensation Plan for Nonemployee Directors adopted May 19, 2004, as amended and restated effective January 1, 2009 (filed as Exhibit 10.18 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.25~~ 10.23			Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective January 1, 2009) (filed as Exhibit 10.19 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001- 31446) and incorporated herein by reference). +

118

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~~10.26~~
Exhibit			Title
10.24			Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005, amended and restated effective January 1, 2009 (filed as Exhibit 10.20 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.27~~
10.25		Amendment to Cimarex Energy Co. Change in Control Severance Plan dated effective March 19, 2013 (filed as Exhibit 10.1 to the Current Report on Form 8-K filed on March 20, 2013 (Commission File No. 001- 31446) and incorporated herein by reference). +

~~10.28~~ 10.26		Form of Indemnification Agreement between Cimarex Energy Co. and each of its executive officers and directors (filed as Exhibit 10.20 to the Annual Report on Form 10-K for the year ended December 31, 2012 filed on February 26, 2013 (Commission File No. 001-31446) and incorporated herein by reference). +

~~10.29~~ 10.27	Retention Agreement dated June 9, 2010 (filed as Exhibit 10.21 to the Annual Report on Form 10-K for the year ended December 31, 2013 filed on February 26, 2014 (Commission File No. 001-31446) and incorporated herein by reference).

~~10.30~~	Credit Agreement Dated as of October 16, 2015, by and among Cimarex, the Administrative Agent, the Syndication Agent, the Documentation Agents, and the Lenders (filed on October 19, 2015 as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).

~~10.31~~ 10.28		Form of Notice of Grant of Restricted Stock (Director) and Award Agreement (filed as Exhibit 10.2 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 2, 2015 and incorporated herein by reference). +

~~10.32~~ 10.29	~~Succession~~	Form of Notice of Grant of Restricted Stock (Director) and Award Agreement ~~dated August 17, 2015~~ (filed as Exhibit ~~10.2~~10.1 to Registrant’s Quarterly Report on Form 10-Q ~~for the quarter ended September 30, 2015~~ filed on ~~November 4, 2015~~August 9, 2017 (Commission File No. 001-31446) and incorporated herein by reference). +

~~14.1~~ 10.30	~~Code of Ethics for Chief Executive Officer~~	Purchase and ~~Senior Financial Officers~~Sale Agreement dated May 23, 2018 between Cimarex Energy Co., Prize Energy Resources, Inc., and Magnum Hunter Production, Inc. (collectively, as “Seller”) and Callon Petroleum Operating Company as Buyer (filed as Exhibit ~~14.1~~10.1 to Registrant’s Current Report on Form 8-K filed on May 24, 2018 (Commission File No. 001-31446) and incorporated herein by reference).

10.31		Form of Notice of Grant of Restricted Stock and Award Agreement (Performance Award) (filed as Exhibit 10.35 to the Annual Report on Form 10-K for the year ended December 31, ~~2003~~2018 filed on ~~March 11, 2004~~February 20, 2019 (Commission File No. 001-31446) and incorporated herein by reference). +

~~14.2~~ 10.32		Amended and Restated Credit Agreement Dated as of February 5, 2019, by and among Cimarex, as Borrower, the Administrative Agent, the Syndication Agent, the Co-Documentation Agents, the Lenders, and the Lead Arrangers and Bookrunners (filed on February 7, 2019 as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).

10.33		Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and Monarch Alternative Capital LP, MDRA GP LP and Monarch GP LLC (filed as Exhibit 10.1 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).

10.34		Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co., John C. Goff and certain other related entities thereto (filed as Exhibit 10.2 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).

119

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Exhibit		Title
10.35		Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and RR Advisors, LLC (filed as Exhibit 10.3 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).

10.36		Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and Richard Betz (filed as Exhibit 10.4 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).

10.37		Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and Nicholas J. Sutton (filed as Exhibit 10.5 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).

10.38		Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and Theodore Gazulis (filed as Exhibit 10.6 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).

10.39		Amended and Restated Credit Agreement Dated as of February 5, 2019, by and among Cimarex, as Borrower, the Administrative Agent, the Syndication Agent, the Co-Documentation Agents, the Lenders, and the Lead Arrangers and Bookrunners (filed on February 7, 2019 as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).

10.40		Form of Notice of Grant of Restricted Stock (Director) and Award Agreement (filed on May 29, 2019 as Exhibit 10.2 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference). +

10.41		2019 Equity Incentive Plan (filed on May 30, 2019 as Exhibit 99.1 to the Registration Statement on Form S-8 (Commission File No. 001-31446) and incorporated herein by reference). +

10.42		Form of Notice of Grant of Restricted Stock and Award Agreement (filed on August 5, 2019 as Exhibit 10.4 to the Quarterly Report on Form 10-Q (Commission File No. 001-31446) and incorporated herein by reference). +

10.43		Form of Notice of Grant of Nonqualified Stock Option and Award Agreement (filed on August 5, 2019 as Exhibit 10.5 to the Quarterly Report on Form 10-Q (Commission File No. 001-31446) and incorporated herein by reference). +

10.44		Director Emeritus Agreement dated September 30, 2019 between Cimarex Energy Co. and Michael J. Sullivan (filed on September 23, 2019 as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference). +

14.1		Revised Code of Business Conduct and Ethics for Directors, Officers, and Employees dated August 30, 2016 (filed as Exhibit 14.1 and 14.2 to the Current Report on Form 8-K filed September 1, 2016 (Commission File No. 001-31446) and incorporated herein by reference).

21.1	~~Subsidiaries~~	Significant subsidiaries of the Registrant.*

23.1		Consent of KPMG LLP.*

120

Table of Contents


~~23.2~~
Exhibit			Title
23.2			Consent of DeGolyer and MacNaughton.*

24.1			Power of Attorney of directors of the Registrant.*

31.1			Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

31.2			Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

32.1			Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

32.2			Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

~~99.1~~
99.1			Letter dated January ~~16, 2017~~28, 2020 from DeGolyer and MacNaughton, independent petroleum engineering consulting firm, reporting the results of its audit of Cimarex reserves as of December 31, ~~2016~~2019 of certain selected properties.*

101.INS			XBRL Instance Document. * Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH			Inline XBRL Taxonomy Extension Schema Document. *

101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase Document. *

101.LAB			Inline XBRL Taxonomy Extension Label Linkbase Document. *

101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase Document. *

101.DEF			Inline XBRL Taxonomy Extension Definition Linkbase Document. *

104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

ITEM 16. FORM 10-K SUMMARY

None.

121

~~None.~~

Table of Contents

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: ~~May 10, 2017~~

February 26, 2020



	CIMAREX ENERGY CO.

	By:	/s/ Thomas E. Jorden
		Thomas E. Jorden Chairman of the Board, Chief Executive Officer, and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

~~Signature~~			~~Title~~	~~Date~~

Signature	Title	Date

/s/ Thomas E. Jorden	Chairman of the Board, Director, Chief Executive Officer,
Thomas E. Jorden	~~Chief Executive Officer,~~ and President (Principal Executive Officer)	~~May 10, 2017~~ February 26, 2020

*	Director, Executive Vice President — Operations,
Attorney-in-Fact	~~Operations,~~ Chief Operating Officer	~~May 10, 2017~~ February 26, 2020
Joseph R. Albi

/s/ G. Mark Burford	Senior Vice President and Chief Financial Officer
G. Mark Burford	~~Financial Officer (Principal~~(Principal Financial Officer)	~~May 10, 2017~~ February 26, 2020

/s/ Timothy A. Ficker	Vice President, Controller, Chief Accounting Officer
Timothy A. Ficker	~~Accounting Officer (Principal~~(Principal Accounting Officer)	~~May 10, 2017~~ February 26, 2020

*
Attorney-in-Fact	Director	~~May 10, 2017~~ February 26, 2020
~~Hans Helmerich~~ Paul N. Eckley

*
Attorney-in-Fact	Director	~~May 10, 2017~~ February 26, 2020
~~David A. Hentschel~~ Hans Helmerich

*
Attorney-in-Fact	Director	~~May 10, 2017~~ February 26, 2020
Harold R. Logan, Jr.

*
~~Attorney-in-Fact~~	~~Director~~	~~May 10, 2017~~
*
Attorney-in-Fact	Director	February 26, 2020
Kathleen A. Hogenson

*
Attorney-in-Fact	Director	February 26, 2020
Floyd R. Price

*
Attorney-in-Fact	Director	~~May 10, 2017~~ February 26, 2020
Monroe W. Robertson

*
~~Attorney-in-Fact~~		~~Director~~	~~May 10, 2017~~
*
Attorney-in-Fact		Director	February 26, 2020
Lisa A. Stewart

*
Attorney-in-Fact		Director	~~May 10, 2017~~ February 26, 2020
~~Michael J. Sullivan~~ Frances M. Vallejo

* By:
~~Attorney-in-Fact~~		~~Director~~	~~May 10, 2017~~
~~L. Paul Teague~~


*By:	/s/ G. Mark Burford	Senior Vice President and Chief Financial Officer
	G. Mark Burford Attorney-in-Fact	~~Financial Officer (Principal~~(Principal Financial Officer)	~~May 10, 2017~~ February 26, 2020

~~129~~

122

	Consolidated Balance Sheet December 31, 2016
(in thousands)	As Previously Reported			Corrections			As Corrected
Accumulated depreciation, depletion and amortization and impairment	$	(13,849,701	)	$	(499,804	)	$	(14,349,505	)
Net oil and gas properties	$	2,854,071		$	(499,804	)	$	2,354,267
Total assets	$	4,681,693		$	(443,969	)	$	4,237,724
Deferred income tax (asset) liability	$	126,894		$	(182,729	)	$	(55,835	)
Total liabilities	$	2,321,629		$	(126,894	)	$	2,194,735
Retained earnings (accumulated deficit)	$	(405,284	)	$	(317,075	)	$	(722,359	)
Total stockholders’ equity	$	2,360,064		$	(317,075	)	$	2,042,989
Total liabilities and stockholders’ equity	$	4,681,693		$	(443,969	)	$	4,237,724

	Consolidated Statement of Operations and Comprehensive Income (Loss) for the Year Ended December 31, 2016
(in thousands, except per share data)	As Previously Reported			Corrections			As Corrected
Impairment of oil and gas properties	$	719,142		$	38,528		$	757,670
Depreciation, depletion and amortization	$	465,936		$	(73,588	)	$	392,348
Total operating expenses	$	1,864,292		$	(35,060	)	$	1,829,232
Operating income (loss)	$	(606,947	)	$	35,060		$	(571,887	)
Income (loss) before income tax	$	(658,264	)	$	35,060		$	(623,204	)
Income tax expense (benefit)	$	(227,215	)	$	12,814		$	(214,401	)
Net income (loss)	$	(431,049	)	$	22,246		$	(408,803	)
Total comprehensive income (loss)	$	(430,545	)	$	22,246		$	(408,299	)

Earnings (loss) per share to common stockholders:
Basic
Distributed	$	0.32		$			$	0.32
Undistributed	(4.94		)	0.24			(4.70		)
	$	(4.62	)	$	0.24		$	(4.38	)
Diluted
Distributed	$	0.32		$			$	0.32
Undistributed	(4.94		)	0.24			(4.70		)
	$	(4.62	)	$	0.24		$	(4.38	)

Item		Page
Glossary
	Part I
1.& 2.	Business and Properties	10
1A.	Risk Factors	19
1B.	Unresolved Staff Comments	35
3.	Legal Proceedings	35
4.	Mine Safety Disclosures	35
	Part II
5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
6.	Selected Financial Data	38
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
7A.	Quantitative and Qualitative Disclosures About Market Risk	64
8.	Financial Statements and Supplementary Data	65
9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	116
9A.	Controls and Procedures	116
9B.	Other Information	119
	Part III
10.	Directors, Executive Officers and Corporate Governance	120
11.	Executive Compensation	121
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	121
13.	Certain Relationships and Related Transactions, and Director Independence	121
14.	Principal Accounting Fees and Services	122
	Part IV
15.	Exhibits, Financial Statement Schedules	123
16.	Form 10-K Summary	127

	December 31,
	2016	2015	2014
Total Proved Reserves:
Gas (Bcf)	1,471.4	1,517.0	1,666.7
Oil (MMBbls)	105.9	107.8	119.0
NGL (MMBbls)	130.6	124.3	125.3
Equivalent (Bcfe)	2,890.5	2,909.4	3,132.3
% Developed	79	75	77

	Production Volumes				Net Average Daily Volumes
	Gas	Oil	NGL	Total	Gas	Oil	NGL	Total
Years Ended December 31,	(MMcf)	(MBbls)	(MBbls)	(MMcfe)	(MMcf)	(MBbls)	(MBbls)	(MMcfe)
2016
Permian Basin	65,191	13,183	6,677	184,351	178.1	36.0	18.2	503.7
Mid-Continent	102,501	3,283	7,508	167,243	280.1	9.0	20.5	456.9
Other	535	62	15	997	1.4	0.2	0.1	2.8
Total Company	168,227	16,528	14,200	352,591	459.6	45.2	38.8	963.4
Cana area	82,423	2,848	6,855	140,647	225.2	7.8	18.7	384.3
2015
Permian Basin	66,006	15,719	6,220	197,644	180.8	43.1	17.0	541.5
Mid-Continent	100,801	2,746	6,757	157,821	276.2	7.5	18.5	432.4
Other	2,180	198	86	3,878	6.0	0.5	0.3	10.6
Total Company	168,987	18,663	13,063	359,343	463.0	51.1	35.8	984.5
Cana area	77,882	2,206	5,957	126,865	213.4	6.0	16.3	347.6
2014
Permian Basin	45,200	12,552	4,187	145,636	123.8	34.4	11.5	399.0
Mid-Continent	106,711	2,682	6,980	164,682	292.4	7.3	19.1	451.2
Other	3,217	405	176	6,704	8.8	1.1	0.5	18.4
Total Company	155,128	15,639	11,343	317,022	425.0	42.8	31.1	868.6
Cana area	76,915	1,903	5,937	123,952	210.7	5.2	16.3	339.6

	Average Realized Price						Production
	Gas		Oil		NGL		Cost
Years Ended December 31,	(per Mcf)		(per Bbl)		(per Bbl)		(per Mcfe)
2016
Permian Basin	$	2.35	$	38.45	$	12.32	$	0.86
Mid-Continent	$	2.29	$	37.65	$	15.59	$	0.43
Other	$	2.00	$	38.86	$	14.80	$	1.59
Total Company	$	2.31	$	38.30	$	14.05	$	0.66
Cana area	$	2.28	$	37.73	$	15.80	$	0.23
2015
Permian Basin	$	2.55	$	43.58	$	11.94	$	1.06
Mid-Continent	$	2.51	$	41.90	$	15.41	$	0.52
Other	$	3.16	$	48.01	$	14.72	$	1.72
Total Company	$	2.53	$	43.38	$	13.75	$	0.83
Cana area	$	2.51	$	41.54	$	15.59	$	0.26
2014
Permian Basin	$	4.48	$	82.44	$	30.04	$	1.58
Mid-Continent	$	4.42	$	88.23	$	35.03	$	0.58
Other	$	4.40	$	92.82	$	32.09	$	2.31
Total Company	$	4.43	$	83.70	$	33.14	$	1.08
Cana area	$	4.32	$	88.21	$	34.89	$	0.24

			Gross	Net	%
	E&D		Wells	Wells	Completed
	Capital		Drilled	Drilled	As Producers
	(in millions)
Permian Basin	$	433	48	30.3	100
Mid-Continent	291		106	30.7	99
Other	11		—	—	—
	$	735	154	61.0	99

	Wells Completed
	2016		2015		2014
	Gross	Net	Gross	Net	Gross	Net
Exploratory
Productive	—	—	—	—	1	0.4
Dry	—	—	—	—	1	0.5
Total	—	—	—	—	2	0.9
Developmental
Productive	153	61.0	219	98.7	309	173.6
Dry	1	—	3	1.7	1	0.1
Total	154	61.0	222	100.4	310	173.7

					% of
	Gas	Oil	NGL	Total	Total Proved
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)	Reserves
Mid-Continent	1,095.2	31.4	89.6	1,821.3	63
Permian Basin	372.4	74.3	41.0	1,064.0	37
Other	3.8	0.2	—	5.2	—
	1,471.4	105.9	130.6	2,890.5	100

		% of
		Total	Average	Approximate
		Proved	Working	Average Depth
Field	Region	Reserves	Interest%	(feet)	Primary Formation

Watonga-Chickasha	Mid-Continent	57.1	34.1	13,000'	Woodford
Ford, West	Permian Basin	8.4	56.9	9,500'	Wolfcamp
Dixieland	Permian Basin	6.1	96.8	11,000'	Wolfcamp
Lusk	Permian Basin	3.9	54.8	9,500'	Bone Spring
Cottonwood Draw	Permian Basin	2.6	73.7	3,000' - 10,000'	Delaware/Wolfcamp
Grisham	Permian Basin	1.8	100.0	11,000'	Wolfcamp
Phantom	Permian Basin	1.7	57.5	11,500'	Bone Spring
Two Georges	Permian Basin	1.7	90.5	11,500'	Bone Spring
Sandbar	Permian Basin	1.4	58.8	7,500'	Bone Spring
Quail Ridge	Permian Basin	1.0	36.5	8,000' - 13,000'	Bone Spring/Morrow
		85.7

	Acreage
	Undeveloped		Developed		Total
	Gross	Net	Gross	Net	Gross	Net
Mid-Continent
Kansas	18,231	18,191	—	—	18,231	18,191
Oklahoma	107,015	71,658	686,489	295,176	793,504	366,834
Texas	22,045	11,301	133,839	56,708	155,884	68,009
	147,291	101,150	820,328	351,884	967,619	453,034
Permian Basin
New Mexico	73,882	52,669	175,842	119,597	249,724	172,266
Texas	81,443	63,289	201,078	147,829	282,521	211,118
	155,325	115,958	376,920	267,426	532,245	383,384
Other
Arizona	2,097,201	2,097,201	17,847	—	2,115,048	2,097,201
California	383,647	383,647	—	—	383,647	383,647
Colorado	41,992	18,867	40,800	1,642	82,792	20,509
Gulf of Mexico	25,000	13,000	28,848	6,381	53,848	19,381
Louisiana	3,533	484	2,877	170	6,410	654
Michigan	26,491	26,414	1,183	1,183	27,674	27,597
Montana	34,381	9,167	7,688	1,721	42,069	10,888
Nevada	1,007,167	1,007,167	440	1	1,007,607	1,007,168
New Mexico	1,641,206	1,633,821	18,371	2,436	1,659,577	1,636,257
Texas	10,478	3,724	27,174	6,167	37,652	9,891
Utah	80,527	59,433	32,552	1,575	113,079	61,008
Wyoming	97,157	13,744	43,626	4,197	140,783	17,941
Other	194,398	171,229	9,734	3,460	204,132	174,689
	5,643,178	5,437,898	231,140	28,933	5,874,318	5,466,831
Total	5,945,794	5,655,006	1,428,388	648,243	7,374,182	6,303,249

	Acreage
	2017		2018		2019		2020		2021
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Mid-Continent	22,804	18,383	11,288	6,462	1,695	1,525	—	—	—	—
Permian Basin	17,025	17,005	5,527	5,527	8,360	8,198	40	40	598	598
Other	51,036	50,281	30,709	29,992	63,334	59,092	28,867	28,652	7,042	6,953
	90,865	85,669	47,524	41,981	73,389	68,815	28,907	28,692	7,640	7,551
% of undeveloped acreage	1.5	1.5	0.8	0.7	1.2	1.2	0.5	0.5	0.1	0.1

					Dividends
					Declared Per
2016	High		Low		Share
First Quarter	$	100.07	$	72.77	$	0.08
Second Quarter	$	123.48	$	93.21	$	0.08
Third Quarter	$	136.95	$	112.19	$	0.08
Fourth Quarter	$	146.96	$	118.59	$	0.08

				(c)
				Number of securities
	(a)			remaining available
	Number of securities	(b)		for future issuance
	to be issued upon	Weighted-average		under equity
	exercise of	exercise price of		compensation plans
	outstanding options,	outstanding options,		(excluding securities
Plan Category	warrants, and rights	warrants, and rights		reflected in column (a))
Equity compensation plans approved by security holders	307,810	$	101.72	3,287,830
Equity compensation plans not approved by security holders	—	—		—
Total	307,810	$	101.72	3,287,830



Period	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
January 1-31, 2019	1,162	$	70.46	—	—
February 1-28, 2019	—	—		—	—
March 1-31, 2019	8,393	68.16		—	—
April 1-30, 2019	—	—		—	—
May 1-31, 2019	—	—		—	—
June 1-30, 2019	—	—		—	—
July 1-31, 2019	34,607	50.67		—	—
August 1-31, 2019	—	—		—	—
September 1-30, 2019	—	—		—	—
October 1-31, 2019	—	—		—	—
November 1-30, 2019	—	—		—	—
December 1-31, 2019	61,374	45.97		—	—
Total	105,536	$	49.55	—	—

	12/2011		12/2012		12/2013		12/2014		12/2015		12/2016
Cimarex Energy Co.	$	100.00	$	93.95	$	171.90	$	174.58	$	148.03	$	225.95
S&P 500	$	100.00	$	116.00	$	153.58	$	174.60	$	177.01	$	198.18
Dow Jones US Exploration & Production	$	100.00	$	105.82	$	139.52	$	124.48	$	94.94	$	118.19
S&P Oil & Gas Exploration & Production	$	100.00	$	103.65	$	132.14	$	118.15	$	77.80	$	103.36

	December 31, 2016
	Gas	Oil	NGL	Total
	(MMcf)	(MBbl)	(MBbl)	(MMcfe)
Permian Basin	372,371	74,295	40,977	1,064,000
Mid-Continent	1,095,194	31,399	89,615	1,821,278
Other	3,855	184	41	5,209
Total	1,471,420	105,878	130,633	2,890,487

	December 31, 2015
	Gas	Oil	NGL	Total
	(MMcf)	(MBbl)	(MBbl)	(MMcfe)
Permian Basin	378,516	78,482	36,598	1,069,002
Mid-Continent	1,134,434	29,048	87,639	1,834,554
Other	4,002	268	40	5,851
Total	1,516,952	107,798	124,277	2,909,407

							Percent
	Years Ended						Change
	December 31,						Between		Price / Volume Change
Production Revenue	2016			2015			2016 / 2015		Price			Volume			Total
(in thousands or as indicated)
Oil sales	$	632,934		$	809,664		(22	)%	$	(83,962	)	$	(92,768	)	$	(176,730	)
Gas sales	388,786			428,227			(9	)%	(37,010		)	(2,431		)	(39,441		)
NGL sales	199,498			179,647			11	%	4,260			15,591			19,851
Total production revenue	$	1,221,218		$	1,417,538		(14	)%	$	(116,712	)	$	(79,608	)	$	(196,320	)
Total oil volume — MBbls	16,528			18,663			(11	)%
Oil volume — barrels per day	45,158			51,132			(12	)%
Oil percentage of total production	28		%	31		%
Average oil price — per barrel	$	38.30		$	43.38		(12	)%
Total gas volume — MMcf	168,227			168,987			0	%
Gas volume — MMcf per day	459.6			463.0			(1	)%
Gas percentage of total production	48		%	47		%
Average gas price — per Mcf	$	2.31		$	2.53		(9	)%
Total NGL volume — MBbls	14,200			13,063			9	%
NGL volume — barrels per day	38,797			35,789			8	%
NGL percentage of total production	24		%	22		%
Average NGL price — per barrel	$	14.05		$	13.75		2	%
Total production — MMcfe	352,591			359,343			(2	)%
Total production — MMcfe per day	963.4			984.5			(2	)%

						Variance
	Years Ended December 31,					Between			Per Mcfe
Operating Costs and Expenses	2016		2015			2016 / 2015			2016		2015
(in thousands)
Impairment of oil and gas properties	$	757,670	$	4,033,295		$	(3,275,625	)	N/A		N/A
DD&A	392,348		731,460			(339,112		)	$	1.11	$	2.04
Asset retirement obligation	7,828		9,121			(1,293		)	$	0.02	$	0.03
Production	232,002		299,374			(67,372		)	$	0.66	$	0.83
Transportation, processing and other operating	190,725		182,362			8,363			$	0.54	$	0.51
Gas gathering and other	31,785		38,138			(6,353		)	$	0.09	$	0.11
Taxes other than income	61,946		84,764			(22,818		)	$	0.18	$	0.24
General and administrative	73,901		74,688			(787		)	$	0.21	$	0.21
Stock compensation	24,523		19,559			4,964			$	0.07	$	0.05
(Gain) loss on derivative instruments, net	55,749		(11,246		)	66,995			N/A		N/A
Other operating (income) expense, net	755		856			(101		)	N/A		N/A
	$	1,829,232	$	5,462,371		$	(3,633,139	)

	Years Ended December 31,
Gas Gathering and Marketing (in thousands):	2015		2014
Gas gathering and other revenues	$	34,688	$	49,602
Gas marketing revenues, net of related costs	$	393	$	1,745

	December 31, 2016							December 31, 2015
			Unamortized Debt			Long-term				Unamortized Debt			Long-term
(in thousands)	Principal		Issuance Costs			Debt, net		Principal		Issuance Costs			Debt, net
5.875% Senior Notes	$	750,000	$	(5,691	)	$	744,309	$	750,000	$	(6,978	)	$	743,022
4.375% Senior Notes	750,000		(6,370		)	743,630		750,000		(7,402		)	742,598
Total long-term debt	$	1,500,000	$	(12,061	)	$	1,487,939	$	1,500,000	$	(14,380	)	$	1,485,620

	Payments Due by Period
			1 Year or						More than
Contractual obligations:	Total		Less		2 - 3 Years		4 - 5 Years		5 Years
(in thousands)
Long-term debt (1)	$	1,500,000	$	—	$	—	$	—	$	1,500,000
Fixed-rate interest payments (1)	478,542		76,876		153,750		153,750		94,166
Operating leases	96,923		9,585		21,208		21,949		44,181
Drilling commitments (2)	157,505		157,505		—		—		—
Asset retirement obligation (3)	154,523		13,753		—		—		—
Other liabilities (4)	177,455		88,793		54,905		6,956		26,801
Firm transportation	26,383		7,655		6,549		4,427		7,752

									Retained			Accumulated
									Earnings			Other			Total
	Common Stock					Paid-in			(Accumulated			Comprehensive			Stockholders’
	Shares		Amount			Capital			Deficit)			Income (loss)			Equity
Balance, December 31, 2013	87,152		$	872		$	1,970,113		$	1,862,075		$	1,189		$	3,834,249
Dividends	—		—			—			(55,664		)	—			(55,664		)
Net income	—		—			—			526,498			—			526,498
Unrealized change in fair value of investments, net of tax	—		—			—			—			(87		)	(87		)
Issuance of restricted stock awards	487		4			(4		)	—			—			—
Common stock reacquired and retired	(123	)	(1		)	(13,559		)	—			—			(13,560		)
Restricted stock forfeited and retired	(135	)	(1		)	1			—			—			—
Exercise of stock options	211		2			11,896			—			—			11,898
Stock-based compensation	—		—			28,633			—			—			28,633
Balance, December 31, 2014	87,592		$	876		$	1,997,080		$	2,332,909		$	1,102		$	4,331,967
Dividends	—		—			—			(59,313		)	—			(59,313		)
Net loss	—		—			—			(2,579,604		)	—			(2,579,604		)
Unrealized change in fair value of investments, net of tax	—		—			—			—			(661		)	(661		)
Issuance of common stock	6,900		69			729,468			—			—			729,537
Issuance of restricted stock awards	471		5			(5		)	—			—			—
Common stock reacquired and retired	(194	)	(2		)	(21,238		)	—			—			(21,240		)
Restricted stock forfeited and retired	(90	)	(1		)	1			—			—			—
Exercise of stock options	142		1			8,450			—			—			8,451
Stock-based compensation	—		—			36,232			—			—			36,232
Stock-based compensation tax benefit	—		—			12,988			—			—			12,988
Balance, December 31, 2015	94,821		$	948		$	2,762,976		$	(306,008	)	$	441		$	2,458,357
Dividends	—		—			—			(7,548		)	—			(7,548		)
Dividends in excess of retained earnings	—		—			(22,803		)	—			—			(22,803		)
Net loss	—		—			—			(408,803		)	—			(408,803		)
Unrealized change in fair value of investments, net of tax	—		—			—			—			504			504
Issuance of restricted stock awards	479		5			(5		)	—			—			—
Common stock reacquired and retired	(208	)	(3		)	(26,622		)	—			—			(26,625		)
Restricted stock forfeited and retired	(32	)	—			—			—			—			—
Exercise of stock options	64		1			4,803			—			—			4,804
Stock-based compensation	—		—			45,103			—			—			45,103
Balance, December 31, 2016	95,124		$	951		$	2,763,452		$	(722,359	)	$	945		$	2,042,989

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
Oil Collars:
2017:
WTI (1)
Volume (Bbls)	1,800,000		1,820,000		1,472,000		1,012,000		6,104,000
Wtd Avg Price - Floor	$	43.08	$	43.08	$	45.09	$	46.27	$	44.09
Wtd Avg Price - Ceiling	$	52.90	$	52.90	$	55.50	$	56.98	$	54.20

2018:
WTI (1)
Volume (Bbls)	540,000		—		—		—		540,000
Wtd Avg Price - Floor	$	47.33	$	—	$	—	$	—	$	47.33
Wtd Avg Price - Ceiling	$	59.11	$	—	$	—	$	—	$	59.11

December 31, 2016:
(in thousands)	Balance Sheet Location	Asset		Liability
Oil contracts	Current liabilities — Derivative instruments	$	—	$	27,892
Natural gas contracts	Current liabilities — Derivative instruments	—		21,478
Oil contracts	Non-current liabilities — Derivative instruments	—		1,059
Natural gas contracts	Non-current liabilities — Derivative instruments	—		1,511
Total gross amounts presented in accompanying balance sheet		—		51,940
Less: gross amounts not offset in the accompanying balance sheet		—		—
Net amount:		$	—	$	51,940

December 31, 2015:
(in thousands)	Balance Sheet Location	Asset		Liability
Oil contracts	Current assets — Derivative instruments	$	6,774	$	—
Natural gas contracts	Current assets — Derivative instruments	3,971		—
Natural gas contracts	Non-current assets — Derivative instruments	501		—
Total gross amounts presented in accompanying balance sheet		11,246		—
Less: gross amounts not offset in the accompanying balance sheet		—		—
Net amount:		$	11,246	$	—

	December 31, 2016						December 31, 2015
	Book			Fair			Book			Fair
(in thousands)	Value			Value			Value			Value
Financial Assets (Liabilities):
5.875% Notes due 2022	$	(750,000	)	$	(782,835	)	$	(750,000	)	$	(723,750	)
4.375% Notes due 2024	$	(750,000	)	$	(779,453	)	$	(750,000	)	$	(683,318	)
Derivative instruments — assets	$	—		$	—		$	11,246		$	11,246
Derivative instruments — liabilities	$	(51,940	)	$	(51,940	)	$	—		$	—

					Performance
	Service-based				(subject to market conditions)
			Weighted				Weighted
			Average				Average
	Number of		Grant-Date		Number of		Grant-Date
	Shares		Fair Value		Shares		Fair Value
Outstanding as of January 1, 2016	998,182		$	91.37	829,808		$	82.99
Vested	(243,313	)	$	92.37	(287,108	)	$	81.53
Granted	208,724		$	114.61	269,915		$	117.63
Canceled	(28,870	)	$	110.84	(3,345	)	$	87.14
Outstanding as of December 31, 2016	934,723		$	96.57	809,270		$	96.41


(1)	These performance shares were canceled since the market condition was not satisfied as of the end of the performance period.