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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
ý
☒		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedDecember 31, 20172020
OR
o☐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.
(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
1700 Lincoln Street, Suite 3700DenverColorado80203(Address of principal executive offices)(Zip Code)
(303) 295-3995
(Registrant’s telephone number)
Securities Registered Pursuantregistered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock ($0.01 par value)XECNew 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 ý NO oYes ☒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 ýYes ☐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 ý NO oYes ☒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 ý 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. oYes ☒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 filer☒Accelerated filer ☐Non-accelerated filer☐Smaller reporting company ☐
Large accelerated filer ý
Accelerated filer o
Emerging Growth Company
Non-accelerated filer o
(Do not check if a
smaller reporting company)
Smaller reporting company o
Emerging growth company o
☐
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.                          ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO ýYes ☐No ☒
Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 20172020 was approximately $8.82$2.75 billion.
Number of shares of Cimarex Energy Co. common stock outstanding as of January 31, 20182021 was 95,438,121.102,807,656.
Documents Incorporated by Reference: Portions of the Registrant’s Proxy Statement for its 20182021 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.


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TABLE OF CONTENTS
DESCRIPTION


Item Page
 
 
Part I
 
1. & 2.
7
1A.
19
1B.
34
3.
34
4.
34
 
Part II
 
5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
35
6.
37
7.
38
7A.
62
8.
64
9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
111
9A.
111
9B.
114
 
Part III
 
10.
115
11.
117
12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
117
13.
117
14.
117
 
Part IV
 
15.
118
16.
124


Item  Page
Glossary
   
  
Part I
 
1. & 2.
 
Business and Properties
6
1A.
 
Risk Factors
15
1B.
 
Unresolved Staff Comments
30
3.
 
Legal Proceedings
30
4.
 
Mine Safety Disclosures
30
  
Part II
 
5.
 
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
31
6.
 
Selected Financial Data
33
7.
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
34
7A.
 
Quantitative and Qualitative Disclosures About Market Risk
56
8.
 
Financial Statements and Supplementary Data
57
9.
 
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
91
9A.
 
Controls and Procedures
91
9B.
 
Other Information
93
  
Part III
 
10.
 
Directors, Executive Officers and Corporate Governance
94
11.
 
Executive Compensation
95
12.
 
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
95
13.
 
Certain Relationships and Related Transactions, and Director Independence
95
14.
 
Principal Accounting Fees and Services
95
  
Part IV
 
15.
 
Exhibits, Financial Statement Schedules
96
16.
 
Form 10-K Summary
100


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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—Billion cubic feet equivalent(of natural gas)
Btu—British thermal unitBOE—Barrels of oil equivalent
GAAP—Generally accepted accounting principles in the U.S.
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
MBOE—Thousand barrels of oil equivalent
Mcf—Thousand cubic feet (of natural gas)
Mcfe—Thousand cubic feet equivalent
MMBbls—Million barrels
MMBtu—Million British thermal units
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 or Net Wells—The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.
Net Production—Gross production multiplied by net revenue interest
NGL or NGLs—Natural gas liquids
PUD—Proved undeveloped
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.


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PART I
 
CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

Throughout this Form 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 provide projections of our 20182021 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.10-K for the year ended December 31, 2020. All the risks disclosed in this Form 10-K may be amplified by the COVID-19 pandemic and its unpredictable nature. 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, which may be exacerbated by the demand destruction resulting from the highly transmissible and pathogenic coronavirus known as severe acute respiratory syndrome coronavirus 2 (SARS-CoV-2) that causes the disease known as COVID-19;
Operating
•Disruptions to the availability of workers and contractors due to illness and stay-at-home orders related to the COVID-19 pandemic;

•Cost and availability of gathering, pipeline, refining, transportation and other midstream and downstream activities and our ability to sell oil, gas, and NGLs, which may be negatively impacted by the COVID-19 pandemic and other risks and lead to a lack of any available markets;

•Availability of supply chains and critical equipment and supplies, which may be negatively impacted by the COVID-19 pandemic and other risks;

•Higher than expected costs and expenses, including the availability and cost of services and materials, which may be negatively impacted by the COVID-19 pandemic;

•Compliance with environmental and other expenses;regulations, including new regulations that may result from the recent change in federal and state administrations and legislatures;

•Legislative or regulatory changes, including initiatives related to hydraulic fracturing, emissions, and disposal of produced water, which may be negatively impacted by the recent change in Presidential administration or legislatures;

•The ability to receive drilling and other permits or approvals and rights-of-way in a timely manner (or at all), which may be negatively impacted by the impact of COVID-19 restrictions on regulatory employees who process and approve permits, other approvals and rights-of-way and which may be restricted by new Presidential and Secretarial orders and regulation and legislation;

•Reductions in the quantity of oil, gas, and NGLs sold and prices received because of decreased demand and/or curtailments in production relating to mechanical, transportation, storage, capacity, marketing, weather, the COVID-19 pandemic, or other problems;

•Declines in the SEC PV10 value of our oil and gas properties resulting in full cost ceiling test impairments to the carrying values of our oil and gas properties;

•The effectiveness of our internal control over financial reporting;

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•Success of the company’s risk management activities;

•Availability of financing and access to capital markets;

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

•Greater than expected production decline rates;

•Timing and amount of future production of oil, gas, and NGLs;
Reductions in
•Cybersecurity threats, technology system failures, and data security issues;

•The inability to transport, process, and store oil and gas;

•Hedging activities and the quantity of oil, gas, and NGLs sold 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; 
The effectivenessviability of our internal control over financial reporting; hedging counterparties, many of whom have been negatively impacted by the COVID-19 pandemic;

•Economic and competitive conditions;

•Lack of available insurance;

•Cash flow and anticipated liquidity;
Amount, nature,
•Continuing compliance with the financial covenant contained in our amended and timingrestated credit agreement;

•The loss of capital expenditures; certain federal income tax deductions;
Availability of financing and access to capital markets; 
Administrative, legislative, and regulatory changes; •Litigation;
Operating and capital expenditures that are either significantly higher
•Environmental liabilities;

•New federal regulations regarding species 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; habitats;

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

•Drilling of wells;

•Development drilling and testing results;

•Performance of acquired properties and newly drilled wells;

•Ability to obtain industry partners to jointly explore certain prospects, and the willingness and ability of those partners to meet capital obligations when requested;

•Unexpected future capital expenditures;

•Amount, nature, and timing of capital expenditures;

•Proving up undeveloped acreage and maintaining production on leases;

•Unforeseen liabilities associated with acquisitions and dispositions;

•Establishing valuation allowances against our net deferred tax assets;

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•Potential payments for failing to meet minimum oil, gas, NGL, or water delivery or sales commitments;

•Increased financing costs due to a significant increase in interest rates;
De-risking
•Risks associated with concentration of acreage;operations in one major geographic area;

•Availability and cost of capital;
Full cost ceiling test impairments
•Title to properties;

•Ability to complete property sales or other transactions; and

•Other factors discussed in the carrying values of our oilcompany’s reports filed with the Securities and gas properties. Exchange Commission (“SEC”).

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, demand, capacity, 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, andproduction type curves, well spacing, timing of development expenditures, and other risks described herein. Many of these risks can be exacerbated by epidemics and pandemics including the current COVID-19 pandemic.


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ReserveReservoir 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 acquisitions, including our acquisition of Resolute Energy Corporation in 2019, include, among others: unknown liabilities related to the acquired properties or entities; 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 Annual Report on Form 10-K for the year ended December 31, 2020 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 or incorporated by reference into this Form 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 with the Securities and Exchange Commission,SEC, except as required by law.



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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 entirely within the United States of America, 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.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 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 growincrease shareholder value through the profitable growth of our proved reserves and production for the long-term benefit of our shareholders while seeking to minimize our impact on the communities in which we operate for the long-term. Our strategy centers on maximizing cash flow from producing properties to reinvestfor reinvestment in exploration and development opportunities.activities and for providing cash returns to shareholders through dividends and debt reduction. We consider merger and acquisition opportunities that enhance our competitive position and we occasionally divest non-corenon-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 ofrank investment decisions;

•Tracking predicted versus actual results in a centralized exploration management system providingto 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 20132016 - 2017.2020.


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Proved Oil and Gas Reserves

Our December 31, 20172020 total proved reserves grew 16%decreased 14% from prior year-end. Proved undeveloped reserves as a percentage of total proved reserves decreasedincreased to 17%16% from 21%14% a year ago. WeDuring 2020, we added 940.7 Bcfe56.6 MMBOE of new reserves through extensions and discoveries. Netdiscoveries and had net negative revisions that totaled 59.7 Bcfe, which52.4 MMBOE. These revisions consisted primarily of a decrease of 248.8 Bcfe for70.3 MMBOE in downward price revisions and 10.0 MMBOE associated with the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure, partially offset by an increase of 187.2 Bcfe30.7 MMBOE in positive revisions related to improved commodity prices.decreases in operating expenses. The change in our proved reserves is as follows (in Bcfe):follows:

Proved Reserves
(MBOE)
Reserves at December 31, 201620192,890.5619,595 
Revisions of previous estimates(59.7(52,430))
Extensions and discoveries940.756,575 
Purchases of reserves1.4
Production(416.9(92,412))
Sales of reserves(1.8(307))
Reserves at December 31, 201720203,354.2531,021 
 

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

 December 31,
 2017 2016 2015
Proved reserves: 
  
  
Gas (Bcf)1,607.6
 1,471.4
 1,517.0
Oil (MMBbls)137.2
 105.9
 107.8
NGL (MMBbls)153.9
 130.6
 124.3
Total (Bcfe)3,354.2
 2,890.5
 2,909.4
Percent developed83% 79% 75%
 December 31,
 202020192018
Proved reserves:   
Gas (MMcf)1,362,842 1,532,145 1,591,321 
Oil (MBbls)144,063 169,770 146,538 
NGL (MBbls)159,818 194,468 179,436 
Total (MBOE)531,021 619,595 591,195 
Percent developed84 %86 %85 %
 
At December 31, 2017, 52% of our total proved reserves were located in the Mid-Continent region and 48% were in the Permian Basin. The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2017.2020.

Gas
(MMcf)		Oil
(MBbls)		NGL
(MBbls)		Total
(MBOE)		% of
Total Proved
Reserves
Mid-Continent570,578 17,491 56,130 168,717 32 %
Permian Basin790,750 126,327 103,606 361,725 68 %
Other1,514 245 82 579 — %
 1,362,842 144,063 159,818 531,021 100 %
 
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MMcfe)
 
% of
Total Proved
Reserves
Mid-Continent1,032,695
 31,853
 85,292
 1,735,565
 52%
Permian Basin573,757
 105,198
 68,530
 1,616,126
 48%
Other1,183
 187
 38
 2,531
 —%
 1,607,635
 137,238
 153,860
 3,354,222
 100%
See SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) in Item 8 for further information regarding our reserves.
 


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Production Volumes, Prices, and Costs

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

Our 20172020 production volumes totaled 1,142 MMcfe252.5 MBOE per day, a 19% increase9% decrease from 2016,2019, and were comprised of 45%42% gas, 30% oil, and 25%28% NGLs. The following tables show by regiontable presents our total and average daily production volumes by region.

 Total Production VolumesAverage Daily Production Volumes
Years Ended December 31,Gas
(MMcf)		Oil
(MBbls)		NGL
(MBbls)		Total
(MBOE)		Gas
(MMcf)		Oil
(MBbls)		NGL
(MBbls)		Total
(MBOE)
2020        
Permian Basin148,227 24,810 17,831 67,345 405.0 67.8 48.7 184.0 
Mid-Continent84,016 3,219 7,700 24,922 229.6 8.8 21.0 68.1 
Other382 58 23 145 1.0 0.1 0.1 0.4 
Total company232,625 28,087 25,554 92,412 635.6 76.7 69.8 252.5 
2019        
Permian Basin145,612 26,376 18,973 69,618 398.9 72.3 52.0 190.8 
Mid-Continent105,515 5,033 9,263 31,882 289.1 13.8 25.4 87.3 
Other440 54 18 145 1.2 0.1 — 0.4 
Total company251,567 31,463 28,254 101,645 689.2 86.2 77.4 278.5 
2018        
Permian Basin92,593 19,104 11,499 46,035 253.7 52.3 31.5 126.1 
Mid-Continent112,697 5,530 10,474 34,787 308.8 15.2 28.7 95.3 
Other547 76 21 188 1.4 0.2 0.1 0.5 
Total company205,837 24,710 21,994 81,010 563.9 67.7 60.3 221.9 

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At December 31, 2020, we had three fields that contained 15% or more of our total proved reserves. These fields were Watonga-Chickasha in the Cana area of the Mid-Continent, Dixieland in the Permian Basin in Reeves County, Texas, and Ford West in the Permian Basin in Culberson County, Texas. At December 31, 2020, the Watonga-Chickasha, Dixieland, and Ford West fields contained approximately 29%, 22%, and 16%, respectively, of our total proved reserves. At December 31, 2019, these same three fields contained 15% or more of our total proved reserves. At December 31, 2018, we had two fields that contained 15% or more of our total proved reserves, the Watonga-Chickasha and Ford West fields. Production for these fields is presented in the following table.

 Total Production VolumesAverage Daily Production Volumes
Years Ended December 31,Gas
(MMcf)		Oil
(MBbls)		NGL
(MBbls)		Total
(MBOE)		Gas
(MMcf)		Oil
(MBbls)		NGL
(MBbls)		Total
(MBOE)
2020        
Watonga-Chickasha70,434 2,917 7,201 21,858 192.4 8.0 19.7 59.7 
Dixieland45,463 8,478 5,397 21,453 124.2 23.2 14.7 58.6 
Ford West42,832 4,485 5,095 16,719 117.0 12.3 13.9 45.7 
2019        
Watonga-Chickasha90,148 4,643 8,689 28,357 247.0 12.7 23.8 77.7 
Dixieland42,658 8,938 5,934 21,982 116.9 24.5 16.3 60.2 
Ford West41,087 5,042 5,212 17,102 112.6 13.8 14.3 46.9 
2018        
Watonga-Chickasha96,043 5,072 9,809 30,889 263.1 13.9 26.9 84.6 
Dixieland11,940 2,902 1,538 6,430 32.7 7.9 4.2 17.6 
Ford West30,976 3,777 3,823 12,763 84.9 10.3 10.5 35.0 

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The following table presents 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.by region.

 Average Realized PriceProduction Cost (per BOE)
Years Ended December 31,Gas
(per Mcf)		Oil
(per Bbl)		NGL
(per Bbl)
2020    
Permian Basin$0.69 $35.66 $9.64 $3.14 
Mid-Continent$1.67 $34.97 $12.60 $2.92 
Other$1.98 $41.15 $9.42 $6.13 
Total company$1.05 $35.59 $10.53 $3.09 
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 
  Total Production Volumes Average Daily Production Volumes
  Gas Oil NGL Total Gas Oil NGL Total
Years Ended December 31, (MMcf) (MBbls) (MBbls) (MMcfe) (MMcf) (MBbls) (MBbls) (MMcfe)
2017  
  
  
  
  
  
  
  
Permian Basin 79,521
 16,271
 8,858
 230,293
 217.9
 44.6
 24.3
 630.9
Mid-Continent 107,463
 4,547
 8,503
 185,761
 294.4
 12.5
 23.3
 508.9
Other 484
 43
 13
 821
 1.3
 0.1
 —
 2.3
Total company 187,468
 20,861
 17,374
 416,875
 513.6
 57.2
 47.6
 1,142.1
                 
Cana area 89,471
 4,168
 7,813
 161,354
 245.1
 11.4
 21.4
 442.1
                 
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

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  Average Realized Price Production Cost (per Mcfe)
Years Ended December 31, 
Gas
(per Mcf)
 
Oil
(per Bbl)
 
NGL
(per Bbl)
 
2017  
  
  
  
Permian Basin $2.72
 $46.96
 $20.25
 $0.78
Mid-Continent $2.78
 $47.42
 $23.02
 $0.43
Other $2.74
 $46.53
 $23.11
 $1.51
Total Company $2.76
 $47.06
 $21.61
 $0.63
         
Cana area $2.76
 $47.44
 $23.27
 $0.28
         
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

Acquisitions and Divestitures

In 2017,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 sold interestscan use to supplement funding of capital expenditures and acquisitions of strategic assets.

On September 30, 2020, we closed on the sale of certain water infrastructure assets in various non-coreEddy County, New Mexico, for which we received net cash proceeds of $68.7 million during 2020, as adjusted for customary closing adjustments and transaction costs. See Note 13 to the Consolidated Financial Statements for further information on this divestiture.

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. We paid $325.7 million in cash and issued common and preferred stock valued at an aggregate of $494.6 million, for cash proceedstotal consideration transferred of $12$820.3 million. In addition, we assumed $870.0 million and made various oil and gas property acquisitionsof Resolute’s long-term debt, which we immediately repaid. See Note 13 to the Consolidated Financial Statements for $8 million.further information on this acquisition.


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Exploration and Development Overview

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

xec-20201231_g1.jpg

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A summary of our 20172020 exploration and development activity by regionand capital investments is as follows:

Capital InvestmentGross Productive Wells CompletedNet
Productive Wells Completed
 (in thousands)  
Exploration and development:
Permian Basin$503,304 92 48.1 
Mid-Continent40,825 57 2.9 
Other727 — — 
 544,856 149 51.0 
Saltwater disposal/Midstream32,297 
Total capital investment$577,153 
 
E&D
Capital
 
Gross
Wells
Completed
 
Net
Wells
Completed
 
%
Completed
As Producers
 (in millions)      
Permian Basin$760
 97
 55.2
 98%
Mid-Continent500
 222
 42.8
 99%
Other21
 —
 —
 —%
 $1,281
 319
 98.0
 98%

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 2017, we2020, our development activity primarily focused on drilling horizontal wells that yielded oil and liquids-rich gas from the Wolfcamp shale formation in Culberson and the Bone Spring formation. Cimarex saw improved resultsReeves Counties in itsTexas and Lea and Eddy Counties in New Mexico. The Wolfcamp shaleis being developed with horizontal 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.primarily using two-mile laterals.

The Permian Basin produced 630.9 MMcfe184.0 MBOE per day in 2017,2020, which was 55%73% of our total company production. Total production from the region increased 25%decreased 3% in 2017 over 2016.2020 from 2019. In 2017,2020, we invested $760$503.3 million, or 59%92%, of our total E&D investment, in the Permian Basin.


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Our Mid-Continent region consists of Oklahoma and the Texas Panhandle. Our activity in 20172020 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 2017,2020, production from the Mid-Continent averaged 508.9 MMcfe68.1 MBOE per day, or 45%27% of total company production. Total production from the region increased 11%decreased 22% in 2017 over 2016.2020 as compared to 2019. In 2017,2020, we invested $500$40.8 million, or 39%8% of our total E&D investment, in the Mid-Continent.

Drilling Activity

In 2017,2020, we completed or participated in the completion of 319149 gross (98.0(51.0 net) productive wells, of which we operated 11861 gross (77.7(47.6 net) wells. At year-end, we were in the process of drilling or participating in 2910 gross (13(4.3 net) wells and there were 9177 gross (33.7(39.6 net) wells waiting on completion.

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

 Wells Completed
 202020192018
 GrossNetGrossNetGrossNet
Development      
Productive149 51.0 289 90.2 349 122.1 
Dry2 1.5 2 1.9 — — 
Total151 52.5 291 92.1 349 122.1 
 Wells Completed
 2017 2016 2015
 Gross Net Gross Net Gross Net
Developmental 
  
  
  
  
  
Productive314
 96.4
 153
 61.0
 219
 98.7
Dry5
 1.6
 1
 —
 3
 1.7
Total319
 98.0
 154
 61.0
 222
 100.4

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At December 31, 2017,2020, we owned an interest in 10,37310,061 gross (3,083(2,765 net) productive oil and gas wells. We had working interests in the following number of productive wells by region as of December 31, 2017:2020:

GasOil
GrossNetGrossNet
Mid-Continent3,876 1,449 869 175 
Permian Basin705 310 4,495 827 
Other103 3 13 1 
4,684 1,762 5,377 1,003 


 Gas Oil
 Gross Net Gross Net
Mid-Continent3,920
 1,501
 698
 181
Permian Basin760
 338
 4,885
 1,053
Other95
 8
 15
 2
 4,775
 1,847
 5,598
 1,236
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Significant Properties
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 approximately 80% of our proved reserves. In 2017, proved reserves in the Cana area of the Watonga-Chickasha field were approximately 46% of Cimarex’s total proved reserves. No other field had 15% or more of our total proved reserves.
At December 31, 2017, our ten largest fields by future net revenue discounted at 10% comprised 85% of our total proved reserves. Information regarding each of these fields is as follows:
Field Region 
% of
Total
Proved
Reserves
 
Average
Working
Interest%
 
Approximate
Average Depth
(feet)
 Primary Formation
Watonga-Chickasha Mid-Continent 46.5% 26.6% 13,000’ Woodford
Ford, West Permian Basin 12.4% 57.7% 9,500’ Wolfcamp
Grisham Permian Basin 8.0% 98.3% 11,000’ Wolfcamp
Dixieland Permian Basin 5.9% 96.0% 11,000’ Wolfcamp
Lusk Permian Basin 4.2% 53.5% 8,000’ - 11,000’ Bone Spring/Avalon
Cottonwood Draw Permian Basin 2.5% 62.9% 3,000’ - 10,000’ Delaware/Wolfcamp
Phantom Permian Basin 1.8% 39.1% 11,500’ Bone Spring
Two Georges Permian Basin 1.6% 90.9% 11,500’ Bone Spring
Stateline Permian Basin 1.4% 48.5% 7,500’ Bone Spring
Quail Ridge Permian Basin 1.0% 47.0% 8,000’ - 13,000’ Bone Spring/Morrow
    85.3%      

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Acreage

The following table sets forth the gross and net acres of both developed and undeveloped leases held by Cimarex as of December 31, 2017. 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.2020.

 Acreage
 UndevelopedDevelopedTotal
 GrossNetGrossNetGrossNet
Mid-Continent      
Kansas16,822 16,782 — — 16,822 16,782 
Oklahoma156,179 47,624 774,542 306,849 930,721 354,473 
Texas22,544 9,317 108,536 52,676 131,080 61,993 
 195,545 73,723 883,078 359,525 1,078,623 433,248 
Permian Basin      
New Mexico123,460 49,306 175,144 120,106 298,604 169,412 
Texas45,962 26,971 222,445 134,233 268,407 161,204 
 169,422 76,277 397,589 254,339 567,011 330,616 
Other      
Arizona2,097,841 2,097,841 17,212 17,207 2,115,053 2,115,048 
California383,487 383,487 — — 383,487 383,487 
Colorado38,092 18,767 43,459 1,642 81,551 20,409 
Gulf of Mexico20,000 11,000 26,345 6,381 46,345 17,381 
Nevada1,007,167 1,007,167 440 1 1,007,607 1,007,168 
New Mexico1,640,153 1,634,459 18,538 2,436 1,658,691 1,636,895 
Texas6,487 2,616 10,831 4,866 17,318 7,482 
Utah66,380 58,933 42,458 1,445 108,838 60,378 
Wyoming79,640 18,557 51,947 3,980 131,587 22,537 
Other235,647 182,286 21,770 4,827 257,417 187,113 
 5,574,894 5,415,113 233,000 42,785 5,807,894 5,457,898 
5,939,861 5,565,113 1,513,667 656,649 7,453,528 6,221,762 
 Acreage
 Undeveloped Developed Total
 Gross Net Gross Net Gross Net
Mid-Continent 
  
  
  
  
  
Kansas18,231
 18,191
 —
 —
 18,231
 18,191
Oklahoma90,275
 60,230
 692,853
 302,409
 783,128
 362,639
Texas22,845
 12,101
 131,119
 55,796
 153,964
 67,897
 131,351
 90,522
 823,972
 358,205
 955,323
 448,727
Permian Basin 
  
  
  
  
  
New Mexico77,297
 56,796
 173,756
 118,355
 251,053
 175,151
Texas79,453
 56,745
 210,873
 148,554
 290,326
 205,299
 156,750
 113,541
 384,629
 266,909
 541,379
 380,450
Other 
  
  
  
  
  
Arizona2,097,201
 2,097,201
 17,847
 —
 2,115,048
 2,097,201
California383,487
 383,487
 —
 —
 383,487
 383,487
Colorado40,488
 18,867
 41,384
 1,642
 81,872
 20,509
Gulf of Mexico25,000
 13,000
 28,848
 6,381
 53,848
 19,381
Louisiana12,112
 9,064
 2,875
 168
 14,987
 9,232
Michigan4,702
 4,624
 1,183
 1,183
 5,885
 5,807
Montana31,422
 7,687
 7,688
 1,721
 39,110
 9,408
Nevada1,007,167
 1,007,167
 440
 1
 1,007,607
 1,007,168
New Mexico1,641,206
 1,633,821
 18,371
 2,436
 1,659,577
 1,636,257
Texas10,476
 3,722
 27,115
 6,107
 37,591
 9,829
Utah80,527
 59,433
 32,552
 1,575
 113,079
 61,008
Wyoming96,837
 13,744
 43,826
 4,217
 140,663
 17,961
Other194,359
 171,191
 9,772
 3,499
 204,131
 174,690
 5,624,984
 5,423,008
 231,901
 28,930
 5,856,885
 5,451,938
Total5,913,085
 5,627,071
 1,440,502
 654,044
 7,353,587
 6,281,115

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
 20212022202320242025
 GrossNetGrossNetGrossNetGrossNetGrossNet
Mid-Continent8,074 6,583 3,101 1,946 1,233 465 420 330 — — 
Permian Basin10,835 4,878 4,394 1,978 960 960 40 40 — — 
Other124,148 120,590 34,413 31,592 6,840 5,729 1,302 1,241 — — 
 143,057 132,051 41,908 35,516 9,033 7,154 1,762 1,611 — — 
% of total undeveloped acreage2.4 2.4 0.7 0.6 0.2 0.1 — — — — 
 Acreage
 2018 2019 2020 2021 2022
 Gross Net Gross Net Gross Net Gross Net Gross Net
Mid-Continent5,608
 3,244
 4,869
 4,152
 5,878
 5,865
 667
 667
 220
 220
Permian Basin5,322
 4,563
 16,999
 16,837
 8,744
 6,584
 4,318
 4,318
 2,148
 2,148
Other31,869
 31,152
 64,652
 60,510
 34,811
 34,596
 7,392
 7,303
 29,223
 28,468
 42,799
 38,959
 86,520
 81,499
 49,433
 47,045
 12,377
 12,288
 31,591
 30,836
                    
% of undeveloped acreage0.7
 0.7
 1.5
 1.4
 0.8
 0.8
 0.2
 0.2
 0.5
 0.5

At December 31, 2017,2020, we had no proved undeveloped reserves booked on undeveloped acreage that were scheduled for development beyond the expiration dates of ourthe undeveloped acreage.


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Title to Oil and Gas Properties
Marketing
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 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 NGLs to a broad portfolio of customers. Our major customers during 2017 were Energy Transfer Partners, L.P. and Plains All American Pipeline, L.P., which accounted for 21% and 13%, respectively, of our consolidated revenues.
If 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 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.
Corporate Headquarters and Employees
Our corporate headquarters is located at 1700 Lincoln St., Suite 3700, Denver, Colorado 80203. On December 31, 2017 and 2016, Cimarex had 910 and 856 employees, respectively. None of our employeesproperties are subject to collective bargaining agreements.customary royalty interests, liens incidental to operating agreements, tax liens, and other burdens and minor encumbrances, easements, and restrictions.

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 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.

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, andsenior management, including 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.

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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, reviewedperformed an independent evaluation of our estimated net reserves associated withrepresenting greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of December 31, 2017.2020. The individual primarily responsible for overseeing

15

the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over 3310 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 2326 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 1316 years.

Title to Oil and Gas PropertiesMarketing

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 propertiesproduction is sold under an assortment of short-term and long-term arrangements at market-responsive prices. We sell our oil at prices tied to NYMEX pricing with customary adjustments for quality and location. Our gas sales are subjecttied to customary royalty interests, liens incidentaleither monthly or daily index pricing and we sell the majority of our NGLs at prices tied to operating agreements, tax liens,monthly index prices less an applicable transportation and fractionation cost.

We sell our oil, gas, and NGLs to a broad portfolio of customers, including major energy companies, pipeline companies, local distribution companies, and other burdensend-users. In 2020, we made sales to two customers that each amounted to 10% or more of our consolidated revenues for 2020. Sales to those two customers accounted for 26% and minor encumbrances, easements,23%, respectively, of our consolidated revenues for 2020. If 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. If multiple significant customers were to discontinue purchasing our production, we believe there could be some initial challenges, but we have ample alternative markets to handle any sales disruption.

We regularly monitor the credit worthiness of all our customers and restrictions.may require parent company guarantees, letters of credit, or prepayments when deemed necessary. Historically, losses associated with uncollectible receivables have not been significant.

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. 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

16

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. Transportation. The Federal Energy Regulatory Commission (“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.

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Under the Natural Gas Policy Act (“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.

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”), U.S. Environmental Protection Agency (“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 therethey will because any material undisclosed impact on our capital expenditures, earnings, or competitive position.

Human Capital Resources

As of December 31, 2020, Cimarex employed 747 highly talented and committed individuals across our field operations and business offices. Our employee base was reduced in 2020 by approximately 24% from December 31, 2019 as a result of a voluntary early retirement incentive program we offered to employees who met certain eligibility criteria in the first quarter of 2020 and an involuntary reduction in workforce program we carried out in the third quarter of 2020. These programs were initiated to ensure the size of our workforce is consistent with our expected future activity levels.


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Fostering a healthy culture built upon transparency, trust, collaboration, and results is an area of emphasis for Cimarex leadership. Key areas of Cimarex Human Capital focus are:

Health and Safety

The health and safety of every Cimarex employee is our top priority. In 2020, Cimarex hired a third-party to conduct an extensive safety assessment so that we could determine key areas of focus and improvement. The assessment results have helped us direct our efforts to improve our safety record from positive to “best in class”. We created an Executive Safety Council made up of senior operational leadership to take action and continue building our safety culture. Throughout COVID-19, Cimarex has implemented policies and practices to keep our offices and field operations free from transmission of the virus. The Cimarex COVID-19 task force was formed in February 2020 and meets weekly to actively manage decisions and communication. We have provided significant remote work flexibility and extensive use of video conferencing technology, have eliminated in-person group gatherings, limited all business-related travel to essential only, and have implemented office and field employee protocols requiring masks, physical distancing, and cleaning.

Leadership Development, Succession Planning, and Talent Management

The CEO and Chief Human Resources Officer are critically focused on the next generation of Cimarex’s senior leadership. Formal and informal development, mentoring, and coaching of high potential staff is a recognized role for all of our executive leaders. We also expose our Board of Directors to Cimarex’s high potential future leaders which facilitates more informed discussions during our annual succession planning. We consistently refresh our talent base with a robust college internship and full-time recruiting program. We continued our full scale college recruiting program in 2020 during the COVID-19 downturn and enabled all of our interns to work and be mentored remotely.

Compensation and Benefits

Cimarex’s compensation programs are intended to attract, retain, and motivate top talent and reward great results with top pay. We align short and long-term incentives of our executives and the broader workforce with both company results and shareholder interests. Cimarex also provides top-notch health care and retirement benefits so that our employees can focus on excellence in their work. For example, Cimarex contributes more than 90% of the total cost of employee health care benefits.

Diversity and Inclusion

Cimarex is working to become more diverse and inclusive so that every employee can contribute to their fullest potential and can confidently share ideas that drive value. Through a thorough regular pay equity analysis we ensure that all employees are paid equitably. The Cimarex Board of Directors contains diverse backgrounds and perspectives, in addition to gender and ethnic diversity. Female employees constitute 29% of our total workforce and in 2019, female leaders at Cimarex initiated a women’s network which expanded in 2020 and now includes formal mentoring. We currently are defining 2021 objectives to improve our hiring, development, and promotion of ethnic minorities.

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 23, 2018.2021.



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ITEM 1A. RISK FACTORS

The following risks and uncertainties, together with other information set forth in this Form 10-K for the year ended December 31, 2020, should be carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. AdditionalThere are unknown risks and uncertainties, presently unknown to us or risks we currently deemeddeem immaterial, that also may impair our business operations or financial condition, which in turn could negatively impact the value of our securities. While many of the risks below relate to the COVID-19 pandemic, given the unpredictable and unprecedented nature of the pandemic, it is impossible to identify all potential risks and estimate the ultimate adverse impact on our business. The COVID-19 pandemic, and mutations of the virus or other outbreaks of communicable diseases, may amplify the risks disclosed in this Form 10-K. These risk factors speak only as of the filing date of this Form 10-K and are subject to change without notice as we cannot predict all risks relating to this quickly evolving set of events.

Outbreaks of communicable diseases could adversely affect our business, financial condition, and results of operations.

Global or national health concerns, including a widespread outbreak of contagious diseases, can negatively impact the global economy, reduce demand and lower pricing for oil, gas, and NGLs, lead to operational disruptions and limit our ability to execute our business plan, which could materially and adversely affect our business, financial condition, and results of operations. For example, the current COVID-19 pandemic, including the measures being taken to address and limit its spread, have adversely affected the economies and financial markets of many countries, resulting in an economic downturn that has negatively impacted, and may continue to negatively impact, global demand and prices for oil, gas, and NGLs. If the COVID-19 outbreak worsens, we also may experience further disruptions to the commodities markets, as well as disruptions to the equipment supply chains and the availability of our workforce as well as the workforces of contractors and regulators, any of which could adversely affect our ability to conduct our business and operations. The occurrencenumerous uncertainties regarding the COVID-19 pandemic, such as the ultimate geographic spread, duration, and severity of one or morethe outbreak, the impact of mutations of the virus, and governmental restrictions and business closures, prevent us from being able to fully assess potential impacts on our business and operations. However, these risks or uncertainties could materially and adversely affect our business, financial condition, and results of operations.

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 gas we produce as well as reductions in the availability of capital.

Studies have found that emission of certain gases, commonly referred to as greenhouse gases (“GHGs”), impact the earth’s climate. 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. On January 20, 2021, President Biden’s first day in office, he signed an executive order on climate action and reconvened an interagency working group to establish interim and final social costs of three GHGs: carbon dioxide, nitrous oxide, and methane. Carbon dioxide is released during the combustion of fossil fuels, including oil, natural gas, and NGLs, and methane is a primary component of natural gas. The Biden administration stated it will use updated social cost figures to inform federal regulations and major agency actions and to justify aggressive climate action as the United States moves toward a “100% clean energy” economy with net-zero GHG emissions. These actions could result in increased costs and reduced demand for our products. Also on January 20, 2021, the Acting Secretary of the Interior issued an order suspending for 60 days the authority for Department Bureaus and Offices to, among other things, grant rights-of-way or easements, which are necessary for pipelines and roads used in oil, gas, and NGL production, and to issue new permits to drill. During this 60-day period, these permits, which were typically approved at the regional office level, can only be approved by the Secretary of Interior, Deputy Secretary, Solicitor, or various Assistant Secretaries. These new requirements may lead to delays in obtaining approvals necessary for our operations.


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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”) 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 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 gas production operations, but also completions and workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines.

While the U.S. Congress has considered legislation to reduce emissions of GHGs in recent years, it has not adopted any significant GHG legislation. This is expected to change with the Democratic Party now in control of the House of Representatives, the Senate, and the office of the President. In the absence of federal GHG legislation, a number of state and regional efforts have emerged, aimed at tracking and/or reducing GHG emissions through cap-and-trade programs, which typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in turnreturn for emitting GHGs. Any future laws or regulations that require reporting of, or otherwise limit emissions of, GHGs from our equipment and operations could require us to both develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, and monitor and report GHG emissions associated with our operations, any of which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. At this time, it is not possible to quantify the impact of such future laws and regulations on our business.

Several policy makers and political candidates have made, or expressed support for, a variety of more comprehensive proposals, such as cap-and-trade or carbon tax programs, as well as the more sweeping “green new deal” resolutions the U.S. Congress introduced in early 2019. As generally proposed, the “green new deal” includes (i) a cap-and-trade program capping overall GHG emissions on an economy-wide basis and requiring major sources of GHG emissions or major fuel producers to acquire and surrender emission allowances and (ii) a carbon tax, which would impose taxes based on emissions from our operations and the downstream uses of our products. The “green new deal” calls for a 10-year national mobilization effort to, among other things, transition 100% of the U.S. power demand to zero-emission sources and overhaul the U.S. transportation systems so that GHG emissions are eliminated as much as is technologically feasible. The enactment of any such legislation would have a material adverse effect on our business and operations.

We are subject to various climate-related risks.

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

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

Policy and Legal Risks. Policy risks include actions that seek to lessen activities that contribute to adverse effects of climate change or to promote adaptation to climate change. These policy actions could be accelerated by the recent change from a Republican to a Democratic party in control of Congress and the Presidency. Examples of policy actions that would increase the costs of our operations or lower demand for our oil and gas include implementing carbon-pricing mechanisms, shifting energy use toward lower emission sources, adopting energy-efficiency solutions, encouraging greater water efficiency measures, and promoting more sustainable land-use practices. Policy actions also may include restrictions or bans on oil and gas activities, like the January 2021 Presidential and Secretarial orders, and the potential banning of hydraulic fracturing, which could lead to write-downs or impairments of our assets. Legal 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.

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Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil, gas, and NGL operations constitute a public nuisance under federal and state law. Private individuals or public entities also could attempt to enforce environmental laws and regulations against us and could seek personal injury and property damages or other remedies. While we are currently not a party to any such litigation, unfavorable rulings against us in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Technology Risks. 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 in renewable energy, battery storage, and energy efficiency may lower demand for oil and gas, resulting in lower prices and revenues, and higher costs. In addition, many automobile manufacturers have announced plans to shift production from internal combustion engine to electric powered vehicles, and states and foreign countries have announced bans on sales of internal combustion engine vehicles beginning as early as 2025, which would reduce demand for oil.

Market Risks. 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. Lower demand for our oil and gas production could result 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 addition, investment advisers, banks, and certain sovereign wealth, pension, and endowment funds recently have been promoting divestment of investments in fossil fuel companies and pressuring lenders to limit funding to companies engaged in the extraction, production, and sale of oil and gas. In October 2020, JP Morgan Chase & Co. announced that it was adopting a financing commitment that is aligned to the goals of the Paris climate accord of 2015 (the “Paris Agreement”). Other banks have made climate-related pledges for various causes, such as stopping the financing of Arctic drilling and coal companies. These initiatives by activists and banks, including certain banks in our credit facility, could interfere with our business activities, operations, and ability to access capital.

Reputation Risk. Climate change is a potential source of reputational risk, which is tied to changing customer or community perceptions of an organization’s contribution to, or detraction from, the transition to a lower-carbon economy. These changing perceptions could lower demand for our oil and gas production, resulting in lower prices and lower revenues as consumers avoid carbon-intensive industries, and could also pressure banks and investment managers to shift investments and reduce lending as described above.

Physical Risks.Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, droughts, 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 and also could include changes in water availability, sourcing, and quality, which could impact drilling and completions operations. These physical risks could cause increased costs, production disruptions, lower revenues, and substantially increase the cost or limit the availability of insurance.

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

We use hydraulic fracturing for the valuecompletion of almost all of our securities.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 areas 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.


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Certain federal agencies have asserted regulatory authority over aspects of the hydraulic fracturing process. The EPA, for example, has issued regulations under the federal Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing. In 2016, the EPA finalized regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants and 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 regulate hydraulic fracturing on federal lands but subsequently issued a repeal of those regulations in 2017. States in which we operate also have adopted, or have stated intentions to adopt, laws or regulations that mandate further restrictions on hydraulic fracturing, such as imposing more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations and establishing standards for the capture of air emissions released during hydraulic fracturing. In addition to states, local land use restrictions, such as city ordinances, may restrict drilling in general or hydraulic fracturing in particular.

Moreover, as stated above, policy makers have proposed implementing stricter restrictions on hydraulic fracturing, including banning the process outright. For example, it is expected that the Biden administration will attempt to limit or prohibit hydraulic fracturing on federal lands, which would adversely impact our operations in the Permian Basin, as well as other areas where we operate under federal leases. As of December 31, 2020, approximately 3% of our total net leasehold resides on federal lands, and approximately 31% of our total net leasehold in the Permian Basin is located on federal lands. Although it is not possible at this time to predict the outcome of any restrictive proposals, any new restrictions on hydraulic fracturing 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 impossible for us to perform hydraulic fracturing to stimulate production from future wells. Restrictions on hydraulic fracturing also could reduce the amount of oil and gas that we are ultimately able to produce from our reserves

Oil, gas, and NGL prices fluctuate due to a number of 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, gas, and gasNGL 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, gas, and gas,NGLs, the level of domestic and global oil, gas, and gasNGL exploration and production activity, pipeline capacity constraints limiting takeaway and increasing basis differentials, geopolitical instability, the actions of the Organization of the Petroleum Exporting Countries (“OPEC”) and other cooperating countries, global or national health concerns including the outbreak of pandemic or contagious diseases such as COVID-19, weather conditions, technological advances affecting energy consumption, governmental regulations and taxes, changes in administrations and legislative control at federal and state levels, and the price and technological advancement of alternative fuels. Demand for oil, gas, and NGLs has severely diminished because of the COVID-19 pandemic, and the resulting restrictions on and closure of factories and businesses, significant travel restrictions and stay-at-home orders, causing lower commodity prices. Oil prices also can decrease if OPEC increases supply, as it did in the first quarter of 2020 at a time when global demand was decreasing. If any of these conditions persist, our financial results could be adversely affected by the reduction in production revenues, and our inability to collect amounts owed by purchasers of our production.

Our proved oil and gas reserves and production volumes will decrease unless we replace 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 commodity 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

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

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If commodity prices decrease,remain at current levels or decline further, we maywill be required to take additional write-downs of the carrying valuesvalue of our oil and gas properties and/or our goodwill.properties.


Accounting rules require that we periodically review the carrying value of our oil and gas properties and goodwill for possible impairment.
In 2016 and 2015, we We recognized ceiling test impairments totaling $757.7$1.64 billion during the year ended December 31, 2020 and $618.7 million ($481.4 million, net of tax) and $4.03 billion ($2.56 billion, net of tax), respectively.during the year ended December 31, 2019. The impairments resulted primarily from the impact of decreases in the trailing twelve-month average prices for oil, gas, and NGLs utilized in determining the estimated future net cash flows from proved reserves. At December 31, 2017, the calculated value of theIf commodity pricing conditions stay at current levels or decline further, we may incur further 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 19% or moreimpairments in the value of the ceiling limitation would have resulted in an impairment.future quarters. Because the ceiling calculation uses trailing twelve-month average commodity prices, the effect of increases and decreasesdeclining prices is a lower ceiling value each quarter. This results in period-over-periodongoing impairments each quarter until prices can significantly impact the ceiling limitation calculation.stabilize or improve. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.

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, at December 31, 2016, 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, there is no guarantee that we won’t experience material weaknesses in our internal control over financial reporting in the future or that we will be able to implement new controls to address such material weaknesses as necessary, which 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 business conditions. Deteriorating economic conditions, including those resulting from the COVID-19 pandemic, could have a negative impact on our lenders, our hedging counterparties, 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 propertiesproved 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.


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Our drilling operations may be curtailed, delayed, or canceled for many reasons. Factors, such asin addition to those enumerated above, include 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.

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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 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;

•governmental regulation;

•access to assets restricted by local government action;

•operating costs;

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

•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, reviewedengineering consulting firm, performed an independent evaluation of our reserve estimates for properties that comprised at leastestimated net reserves representing greater than 80% of the discountedtotal future net cash flows before income taxes, using arevenue discounted at 10% discount rate,, as of December 31, 2017.2020.

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 twelve 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.


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The inability to obtain rights-of-way from federal agencies may lead to our inability to transport our oil, gas, and NGLs from drilled wells for which we have spent drilling and completion capital and deprive us of revenues from sales of those products.

The inability for us or our third party gatherers to obtain rights-of-way to build gathering lines to move our produced oil, gas, and NGLs from our wells to markets could prevent us from receiving production revenues after expending capital on drilling and completing those wells. This is of particular concern on federal lands for the reasons noted above in, “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 gas we produce as well as reductions in the availability of capital.” The Biden administration’s restrictions may lead to delays in obtaining approvals necessary for our operations and lead to losses.

We may be subject to information technology system failures, network disruptions, and breaches in data security and 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 cybersecurity threats. Cyberattacks 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.

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 cyberattacks, 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 cyberattack 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, or other strategic 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 an accidental discharge;

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

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

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These events could damage our reputation and lead to monetary losses, or a loss of business, 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. With large numbers of employees (industry-wide and at Cimarex) working remotely during the COVID-19 pandemic, there may be heightened vulnerability to cyberattacks.

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 gas production depends in large part on the proximity and capacity of pipeline systems, as well as storage, processing, transportation, processing and fractionation facilities, most of which are owned by third parties. TheOil, refined products, and gas storage reached historically high levels due to reduced demand from the COVID-19 pandemic, which places price pressure across all commodities. We do not anticipate the inability to transport one commodity, such asour commodities; however, should that occur, our production could be curtailed, which would impact drilling plans. Curtailments of production could lead to payment being required where we fail to deliver oil, gas, could also impair our ability to produce and sell other commodities, such as oil and NGLs produced from the same wells. The lack ofto meet minimum volume commitments. These availability or the lack ofand capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. This isissues are more likely to occur in remote areas with less established infrastructure, such as our Delaware Basin area where we and competitors have significant development activities. The lackoil and gas production. Any of these availability of or capacity in these facilities orissues, whether resulting from the lossCOVID-19 pandemic, construction delays, government restrictions, such as occurred with the revocation of these facilities due to construction delays,the permit for the Keystone XL Pipeline on the first day of the Biden administration, weather, fire, or other reasons, for an extended period of time could negatively affect our operations and revenues.
A limited number of companies purchase a majority of our oil, gas, and NGLs. 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 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.

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

To limit our exposure to price risk, we enter into derivative agreements from time to 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 derivatives.

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

•the counterparties to our derivative agreements fail to perform;

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

•there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the derivative agreement.

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

The adoption

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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 derivative 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 derivative counterparties exit the market.
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.

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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 inIn remote areas where vendors also can charge higher rates due to that remoteness and the inability to attract employees to those areas as well asand the vendors’ ability to deploy their resources in easier-to-access areas.

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, and cement failures. Other risks include theft, vandalism, and environmental hazards such as gas leaks, oil and produced water spills, and discharges of toxic gases. Any of these risks can cause substantial losses or costs resulting from:

•injury or loss of life;

•damage to, loss of, or destruction of, property and equipment;

•pollution and other environmental damages;

•regulatory investigations, civil litigation, and penalties;

•damage to our reputation; and

•suspension of our operations.

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 losses or damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of our existing insurance coverage. The occurrence of an event that is not fully covered by our insurance could harm our financial condition and results of operations. The cost of insurance may increase, and the availability of insurance may decrease, as a result of climate change or other factors.

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

As of December 31, 2020, our long-term debt consisted of $750 million of 4.375% senior notes due in 2024, $750 million of 3.90% senior notes due in 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, capital expenditures, operating expenses, and contractual commitments.


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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. The current COVID-19 pandemic initially resulted in limited availability of public debt markets. 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.

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. Our cash flow has been impacted by the reduced commodity prices and lower production resulting from diminished demand caused by the COVID-19 pandemic. 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 may limit our ability to, among other things:

•create certain liens; or

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

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%. While we were in compliance with this covenant at December 31, 2020, net losses in the future driven by ceiling test impairments could cause us to exceed this ratio.

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.


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Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be limited or eliminated as a result of 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, allows for the expensing of capital expenditures, and eliminates the corporate Alternative Minimum Tax. In addition, various proposals have been made recommending the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. While the tax law changes approved in December 2017 did not eliminate any of these incentives, new legislation may be introduced in Congress which would implement many of these proposals. These changes include, but are not limited 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 gas exploration and development, and any such change could have an adverse effect on our financial position, results of operations, and cash flows, including the payment of cash taxes earlier than expected.

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 are involved with various lawsuits and related disputed claims, including but not limited to claims concerning title, validity of leases, royalty payments, environmental issues, personal injuries, labor issues, 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 with the discovery of facts not presently known to us or as a result of 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.

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 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.
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.
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 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 (for the reasons described elsewhere in these Risk Factors), which may delay or interrupt our operations and limit our growth and revenue. These permits and other regulatory approvals also may be negatively impacted by COVID-19

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restrictions on regulatory employees responsible for regulatory approvals.

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. 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.

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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“CERCLA” or the Superfund“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”), 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”), 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”), which governs the discharge of pollutants, including natural gas wastes, into federal and state waters;

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

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

We believe we are in substantial compliance with the above requirements of CERCLA, OPA, RCRA, 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 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.


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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”) 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”) 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 gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on federal oil and 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”), 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”) 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.

On February 9, 2018, the FWS announced the listing of the Texas Hornshell, a fresh waterfreshwater mussel species in areas including New Mexico and Texas where we operate in the Permian Basin, as an endangered species.

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We also intend to enter 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, listingListing petitions continue to be filed with the FWS which could impact our operations. Many non-governmental organizations (“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 exampleand the Dunes Sagebrush Lizard in the Permian Basin, are examples of the NGOs’ influence on ESA listing decisions.

On December 1 2020, the FWS announced the petitioning of the Peppered Chub to be listed as endangered or threatened under the ESA. The Peppered Chub is a freshwater fish that historically was found in the South Canadian, Cimarron, and Arkansas rivers within New Mexico, Texas, Oklahoma, and Kansas. Cimarex has operations near the South Canadian river in Oklahoma that could be impacted if the Peppered Chub is either listed as threatened or endangered under the ESA or if the FWS declares the basins of the South Canadian river to be critical habitat. The increase in endangered species listings, such as the Peppered Chub, may impactlimit 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.


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We use hydraulic fracturing for the completion of almost allhave 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 wells. Hydraulic fracturing is a process that involves pumping fluidundeveloped acreage may decline and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gaswe may incur impairment charges if drilling results are unsuccessful.

New 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 stateemerging oil and gas commissions, the practice has become increasingly controversialresource plays have limited or no production history. Consequently, in certain parts of the country, resulting in increased scrutinythose new areas it is difficult to predict our future drilling costs and regulation from federal agencies. For example, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities under the SDWA involving the use of diesel fuelsresults, so our drilling, completing, and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Although the EPA has delegated the permitting authority for the SDWA’s Underground Injection Control Class II programs in Oklahoma, Texas, and New Mexico where we maintain operational acreage, the EPA is encouraging state programs to review and consider use of such draft guidance.
In addition, on March 26, 2015, the federal BLM published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in 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 prepared 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 impose more stringent permitting, public disclosure, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether.
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 or costly for us to perform 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 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 could also reduce the amount of oil and gas that we are ultimately able to produce from our reserves.

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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 gas we produce as well as reductions in availability of capital.
Studies have suggested that emission of certain gases, commonly referred to as greenhouse gases (“GHGs”), may be impacting the earth’s climate. Methane, a primary componenthigher than initially expected and our production may be lower than initially expected. The value 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”) 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 emissionsour undeveloped acreage 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 monitoringdecline if our results are unsuccessful, and, reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and 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 gas production operations, but also completions and workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines.
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 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 gas that we produce.
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, 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.

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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.
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.
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 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 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 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, 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 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.
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 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 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 damagewe may have to persons and property.

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A substantial portionimpair the carrying value of our producing properties are located in limited geographic areas, making us vulnerable to risks associated with having geographically concentrated operations.undeveloped acreage.
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 55% and 45%, respectively, of our oil, gas, and NGL production and approximately 62% and 38%, respectively, of our oil, gas, and NGL revenues for the year ended December 31, 2017. Approximately 48% of our estimated proved reserves were located in the Permian Basin and approximately 52% of our estimated proved reserves were located in the Mid-Continent region as of December 31, 2017.
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 oil and 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 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.
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 of 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 propertiesWe have no control over offsetting operators, who 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 wellwellbore 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, which could cause a depletion of our proved reserves and may inhibit

24

our ability to further develop our proved reserves. The possibility for these impacts may increase with respect to wells that we shut in as a response to lower commodity prices or the lack of pipeline and storage capacity such as occurred during the COVID-19 pandemic. In addition, completion operations and other activities conducted on adjacent orother nearby wells could cause production fromus, in order to protect our existing wells, to be shut in production for indefinite periods of time,time. Shutting in our wells and damage to our wells from offset completions could result in increased lease operating expensescosts and could adversely affect the reserves and re-commenced production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.such shut in wells.
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.
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 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.

25


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, 2017,2020, other companies operated approximately 19%12% 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.
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 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.
We may not be able to generate enough cash flow to meet our debt obligations.
At December 31, 2017, our long-term debt consisted of $750 million of 4.375% senior notes due in 2024 and $750 million of 3.90% senior notes due in 2027. In addition to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, capital expenditures, operating expenses, and 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.

26

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.

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

32

undertaken. Furthermore, the seller may be unwilling or unable, such as in a corporate acquisition like 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 develop Resolute’s assets or otherwise realize the expected benefits of the acquisition of Resolute. In addition, our business may be negatively impacted if Resolute has liabilities that were not disclosed.
27


We may lose leases if production is not established within the time periods specified in the leases.leases or if we do not maintain production in paying quantities.

UnlessWe could lose leases under certain circumstances if we do not maintain 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 expirein paying quantities or meet other lease requirements, and the amounts we spent for those leases willcould be lost. As we shut in wells in response to lower commodity prices or a lack of pipeline and storage capacity as a result of the COVID-19 pandemic, we may face claims that we are not complying with lease provisions. As noted above, the Biden administration also may impose new restrictions and regulations affecting our ability to drill, conduct hydraulic fracturing operations, and obtain necessary rights-of-way on federal lands, which could, in turn, result in the loss of federal leases. The combined net acreage expiring in the next three years represents approximately 3.0%3.1% of our total net undeveloped acreage at December 31, 2017.2020. At that date, we had leases representing 38,959132,051 net acres expiring in 2018, 81,4992021, 35,516 net acres expiring in 2019,2022, and 47,0457,154 net acres expiring in 2020.2023. 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-corenon-strategic assets in order to increase capital resources available for other corestrategic assets and to create organizational and operational efficiencies. We also occasionally sell interests in corestrategic assets for the purpose of accelerating the development of and increasing efficiencies in such corestrategic 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 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 companyus from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, the companywe 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.
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 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 oil and gas 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, allows for the expensing of capital expenditures, and eliminates the corporate Alternative Minimum Tax. In addition, various proposals have been made recommending the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. While the tax law changes approved in December 2017 did not eliminate any of these incentives, in the future legislation may be introduced in Congress which would implement many of these proposals. These changes include, but are not limited 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.


28

33



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 gas exploration and development, and any such change could have an adverse effect on our financial position, results of operations, and cash flows, including the payment of cash taxes earlier than expected.


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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.


ITEM 3. LEGAL PROCEEDINGS

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


ITEM 4. MINE SAFETY DISCLOSURES
 
Not applicable.



34
30

PART II
 
ITEM 5. MARKET FOR 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”) under the symbol XEC. A cash dividend was paid to our common stockholders in each quarter of 2017.2020. 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 tables set 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.
2017 High Low 
Dividends
Declared Per
Share
First Quarter $144.30
 $114.72
 $0.08
Second Quarter $123.92
 $91.22
 $0.08
Third Quarter $116.43
 $89.49
 $0.08
Fourth Quarter $127.89
 $109.55
 $0.08
2016 High Low 
Dividends
Declared Per
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

The closing price of Cimarex stock as reported on the NYSE on January 31, 2018,29, 2021, was $112.20.$42.18. At January 31, 2018,2021, Cimarex’s 95,438,121102,807,656 shares of outstanding common stock were held by approximately 1,6551,174 stockholders of record.

Issuer Purchases of Equity Compensation Plan InformationSecurities

The following table sets forth information with respect toregarding repurchases of our common stock during the equity compensation plans available to directors, officers, and employees of the company atyear ended December 31, 2017:2020. 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.

PeriodTotal number of shares purchasedAverage price paid per shareTotal number of shares purchased as part of publicly announced plans or programsMaximum number of shares that may yet be purchased under the plans or programs
January 1-31, 2020— $— — — 
February 1-29, 2020— — — — 
March 1-31, 202012,199 13.56 — — 
April 1-30, 20201,160 20.53 — — 
May 1-31, 2020— — — — 
June 1-30, 2020— — — — 
July 1-31, 202094,245 24.57 — — 
August 1-31, 2020— — — — 
September 1-30, 2020— — — — 
October 1-31, 2020— — — — 
November 1-30, 20201,468 31.25 — — 
December 1-31, 202052,620 36.21 — — 
Total161,692 $26.73 — — 


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 382,688
 $100.17
 1,991,731
Equity compensation plans not approved by security holders —
 —
 —
Total 382,688
 $100.17
 1,991,731
35

31



Stock Performance Graph


The following graph comparesshows the cumulative 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, 20122015 to December 31, 2017.2020. The stock price performance included in this graph is not necessarily indicative of future stock price performance.


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
xec-20201231_g2.jpg
* $100 invested inon 12/31/1215 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.

 201520162017201820192020
Cimarex Energy Co.$100.00 $152.64 $137.42 $69.88 $60.39 $44.43 
S&P 500$100.00 $111.96 $136.40 $130.42 $171.49 $203.04 
Dow Jones US Exploration & Production$100.00 $124.48 $126.10 $103.69 $115.51 $76.64 
S&P Oil & Gas Exploration & Production$100.00 $132.86 $124.48 $100.20 $112.25 $72.49 


36
 2012 2013 2014 2015 2016 2017
Cimarex Energy Co.$100.00
 $182.98
 $185.83
 $157.57
 $240.50
 $216.52
S&P 500$100.00
 $132.39
 $150.51
 $152.59
 $170.84
 $208.14
Dow Jones US Exploration & Production$100.00
 $131.84
 $117.64
 $89.72
 $111.69
 $113.14
S&P Oil & Gas Exploration & Production$100.00
 $127.49
 $113.99
 $75.06
 $99.72
 $93.43


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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,
20202019201820172016
(in thousands, except per share amounts)
Operating results:     
Oil, gas, and NGL sales$1,512,688 $2,321,921 $2,297,645 $1,874,003 $1,221,218 
Total revenues (1)$1,558,595 $2,362,969 $2,339,017 $1,918,249 $1,257,345 
Net (loss) income (2)$(1,967,458)$(124,619)$791,851 $494,329 $(408,803)
Earnings (loss) per common share:     
Basic$(19.73)$(1.33)$8.32 $5.19 $(4.38)
Diluted$(19.73)$(1.33)$8.32 $5.19 $(4.38)
Cash dividends declared per common share$0.88 $0.80 $0.68 $0.32 $0.32 
Cash flow data:     
Net cash provided by operating activities$904,167 $1,343,966 $1,550,994 $1,096,564 $625,849 
Net cash used by investing activities$(578,875)$(1,577,882)$(1,085,618)$(1,265,897)$(692,410)
Net cash used by financing activities$(146,869)$(472,028)$(65,244)$(83,009)$(59,945)
December 31,
20202019201820172016
(in thousands, except proved reserves amounts)
Balance sheet data:     
Cash and cash equivalents (3)$273,145 $94,722 $800,666 $400,534 $652,876 
Oil and gas properties, net (2) (3)$3,436,669 $5,210,698 $3,715,330 $3,241,530 $2,354,267 
Goodwill (3)$— $716,865 $620,232 $620,232 $620,232 
Total assets (2) (3)$4,621,989 $7,140,029 $6,062,084 $5,042,639 $4,237,724 
Deferred income tax (asset) liability$(20,472)$338,424 $334,473 $101,618 $(55,835)
Long-term obligations:
Long-term debt (principal) (4)$2,000,000 $2,000,000 $1,500,000 $1,500,000 $1,500,000 
Operating and finance leases (5)$154,436 $202,921 $— $— $— 
Other$229,794 $197,056 $200,564 $206,249 $184,444 
Redeemable preferred stock (3)$36,781 $81,620 $— $— $— 
Stockholders’ equity (2)$1,553,454 $3,576,141 $3,329,786 $2,568,278 $2,042,989 
Proved Reserves:     
Oil (MBbls)144,063 169,770 146,538 137,238 105,878 
Gas (Bcf)1,363 1,532 1,591 1,608 1,471 
NGL (MBbls)159,818 194,468 179,436 153,860 130,633 
Total (MBOE)531,021 619,595 591,195 559,037 481,748 

 Years Ended December 31,
 2017 2016 2015 2014 2013
 (in millions, except per share amounts)
Operating results: 
  
  
  
  
Oil, gas, and NGL sales$1,874
 $1,221
 $1,418
 $2,373
 $1,953
Total revenues (1)$1,918
 $1,257
 $1,453
 $2,424
 $1,998
Net income (loss) (2)$494
 $(409) $(2,580) $526
 $462
          
Earnings (loss) per share to common stockholders: 
  
  
  
  
Basic$5.19
 $(4.38) $(27.75) $6.01
 $5.30
Diluted$5.19
 $(4.38) $(27.75) $6.00
 $5.29
Cash dividends declared per share$0.32
 $0.32
 $0.64
 $0.64
 $0.56
          
Cash flow data: 
  
  
  
  
Net cash provided by operating activities (3)$1,097
 $626
 $726
 $1,633
 $1,334
Net cash used by investing activities$(1,266) $(692) $(1,009) $(1,740) $(1,531)
Net cash (used) provided by financing activities (3)$(83) $(60) $656
 $508
 $132
37
 December 31,
 2017 2016 2015 2014 2013
 (in millions, except proved reserves amounts)
Balance sheet data: 
  
  
  
  
Cash and cash equivalents$401
 $653
 $779
 $406
 $5
Oil and gas properties, net (2)$3,242
 $2,354
 $2,741
 $6,638
 $5,669
Goodwill$620
 $620
 $620
 $620
 $620
Total assets (2) (4)$5,043
 $4,238
 $4,708
 $8,443
 $6,947
Deferred income tax liability (asset)$102
 $(56) $157
 $1,657
 $1,351
Long-term obligations: 
  
  
  
  
Long-term debt (principal)$1,500
 $1,500
 $1,500
 $1,500
 $924
Other$206
 $184
 $197
 $194
 $164
Stockholders’ equity$2,568
 $2,043
 $2,458
 $4,332
 $3,834
          
Proved Reserves: 
  
  
  
  
Oil (MBbls)137,238
 105,878
 107,798
 118,992
 108,533
Gas (Bcf)1,608
 1,471
 1,517
 1,667
 1,294
NGL (MBbls)153,860
 130,633
 124,277
 125,273
 92,044
Total (Bcfe)3,354
 2,890
 2,909
 3,132
 2,497

(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 to do so.
(2)During 2016, 2015, and 2013, we recorded non-cash full cost ceiling test impairments of our oil and gas properties totaling $757.7 million ($481.4 million, net of tax), $4.03 billion ($2.56 billion, net of tax), and $190.2 million ($120.8 million, net of tax), respectively.

33



(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.
(3)
We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017. Pursuant to ASU 2016-09, we adjusted the statements of cash flows for all prior periods presented. For the years ended December 31, 2016, 2015, 2014, and 2013, we decreased cash outflows for operating activities and cash inflows for financing activities by $26.6 million, $34.2 million, $13.6 million, and $10.1 million, respectively, for the payment of employee tax withholdings on the net settlement of equity-classified awards and for excess tax benefits, as applicable. See Note 6 to the Consolidated Financial Statements for further discussion regarding our adoption of ASU 2016-09.
(4)At December 31, 2015, we adopted new accounting 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.

(2)    During 2020, 2019, and 2016, we recorded non-cash full cost ceiling test impairments of our oil and gas properties totaling $1.64 billion, $618.7 million, and $757.7 million, 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 preferred stock. The final purchase price allocation included $1.72 billion to oil and gas properties and $94.2 million to goodwill. We concluded that goodwill was fully impaired at March 31, 2020 and recorded a $714.4 million impairment at that time. During 2020, we repurchased some of the preferred stock. See Notes 1, 2, and 13 to the Consolidated Financial Statements for further information regarding goodwill, the preferred stock, and the 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 leases and their financial statement impacts.

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 in Item 1A of this report. This discussion also includes forward-looking statements. Refer to CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in Part I of this report for important information about these types of statements. Discussion and analysis regarding 2020 and 2019 is provided below. For discussion and analysis regarding 2018, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2019 as previously filed with the SEC.

OVERVIEW

Cimarex is an independent oil and gas exploration and production company. Our operations are located entirely located inwithin the United States of America, 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 growincrease shareholder value through the profitable growth of our proved reserves and production for the long-term benefit of our stockholders through a balanced and abundant drilling inventory while seeking to minimize our impact on the communities in which we operate for the long-term. Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flowfor reinvestment in exploration and development activities.activities and for providing cash returns to shareholders through dividends and debt reduction. We consider property acquisitions, dispositions,merger and occasional mergers toacquisition opportunities that enhance our competitive position.position and we occasionally divest non-strategic assets.


38

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. 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, occasionalfrom time to time, public financing based on our monitoring of capital markets and our balance sheet. Conservative use

In the first quarter of leverage has long been2020, the highly transmissible and pathogenic coronavirus known as severe acute respiratory syndrome coronavirus 2 (SARS-CoV-2) that causes the disease known as COVID-19 began to spread globally. In February 2020, we created a partmulti-disciplinary task force to address the potential impacts of COVID-19 on our financial strategy. We believe that maintaining a strong balance sheet mitigates financial riskemployees and enables usoperations. The task force developed health and safety protocols to withstand unpredictable fluctuations in commodity prices.protect employees and augmented our business interruption plans to address potential impacts on our business from COVID-19.

Market Conditions

The oil and gas industry is cyclical and commodity prices can fluctuate significantly. We expect this volatility to persist. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, inventory storage levels, weather conditions, and other factors.
Oil prices have improved from early 2016; however, they continue to be volatile and we expect this volatility to persist. During 2017, average NYMEX oil and gas prices were $50.94 per barrel and $3.11 per Mcf, respectively, representing an increase of 18% and 26%, respectively, from the average NYMEX oil and gas prices for 2016. Further, local Local market prices for oil and gas can be impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials.

The reduction in economic activity from the COVID-19 pandemic resulted in unprecedented demand destruction and inventory increases for oil and natural gas liquids. In addition, in early March 2020, members of the Organization of the Petroleum Exporting Countries (“OPEC”) and other countries failed to reach an agreement on oil production limits and Saudi Arabia unilaterally reduced the sales price of its oil and announced that it would increase its oil production. As a result of these actions and the COVID-19 pandemic, WTI oil prices dropped from an average of $57.53 per barrel in January 2020 to $16.70 per barrel in April 2020. Since April 2020, average WTI oil prices have risen to $47.07 per barrel in December 2020. The oil price improvement and or stabilization has coincided with some recovery of global economic activity, lower supply from major oil producing countries, and moderating inventory levels.

In response to the decline in oil prices in the second quarter 2020, we took immediate steps to reduce our capital investment, including releasing all but one drilling rig by mid-May and deferring well completion activity. This resulted in a reduction in exploration, development, and acquisition capital expenditures from $255.9 million in the first quarter of 2020 to $83.8 million in the second quarter of 2020, $80.5 million in the third quarter of 2020, and $136.5 million in the fourth quarter of 2020. As a result, total exploration, development, and acquisition capital expenditures for 2020 were $556.7 million. This level of capital expenditures was less than our cash flow from operating activities, which has allowed us to build our cash balance and not incur any incremental borrowings this year. With the subsequent improvement in oil prices, we exited 2020 running five drilling rigs and completing wells with one completion crew.

39

The table below presents average NYMEX prices and our company-wide average realized prices and basis differentials for 2020 and 2019. The average NYMEX and realized prices have declined for all products, while the average basis differentials have improved.

 Years Ended December 31,Variance Between
2020 / 2019
 20202019
Average NYMEX price   
Oil — per barrel$39.40 $57.03 (31)%
Gas — per Mcf$2.08 $2.63 (21)%
Average realized price   
Oil — per barrel$35.59 $52.77 (33)%
Gas — per Mcf$1.05 $1.11 (5)%
NGL — per barrel$10.53 $13.55 (22)%
Average price differential   
Oil — per barrel$(3.81)$(4.26)11%
Gas — per Mcf$(1.03)$(1.52)32%

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
YearFourth
Quarter		Third
Quarter		Second
Quarter		First
Quarter
2020
Oil
Permian Basin$(3.74)$(2.79)$(2.71)$(8.12)$(2.00)
Mid-Continent$(4.43)$(0.99)$(5.06)$(9.53)$(2.02)
Total Company$(3.81)$(2.57)$(2.99)$(8.28)$(1.99)
Gas
Permian Basin$(1.39)$(1.34)$(1.15)$(1.09)$(1.85)
Mid-Continent$(0.41)$(0.36)$(0.31)$(0.31)$(0.57)
Total Company$(1.03)$(0.98)$(0.84)$(0.80)$(1.40)
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)


40

Pipeline expansion projects in the Permian Basin and Mid-Continent region gasreduced drilling activity and production growth has resulted in higher differentialshave eased take away constraints and improved price differentials. However, if pipeline projects are delayed, production increases faster than capacity increases, or the basin experiences pipeline disruptions or other constraints, remain, higher differentials will persist orcould potentially worsen.

34

Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and gas production. Compared to 2016, ourproduction and can be adversely affected by realized oil price for 2017 increased 23% to $47.06 per barrel. Similarly, our realized gas price increased 19% to $2.76 per Mcf, while our realized NGL price increased 54% to $21.61 per barrel. See RESULTS OF OPERATIONSRevenues below for further information regarding our realized commodity prices.decreases.

2017 Summary of Operating and Financial Results for the year ended December 31, 2020 as compared to the year ended December 31, 2019

The following is a summary of certain 2017 operating and financial results: 
•Total daily production volumes increased 19%decreased 9% to 1,142.1 MMcfe252.5 MBOE per day.

•Oil volumes increased 27%decreased 11% to 57.276.7 MBbls per day.

•Gas volumes increased 12%decreased 8% to 513.6635.6 MMcf per day.

•NGL volumes increased 23%decreased 10% to 47.669.8 MBbls per day.

•Total production revenue increased 53%decreased 35% to $1.87$1.51 billion.

•Year-end proved reserves increaseddecreased 14% to 3.35 Tcfe,531.0 MMBOE, as compared to 2.89 Tcfe619.6 MMBOE at year-end 2016.2019.

•Exploration and development capital investments were $1.28 billion,$544.9 million, as compared to $734.8 million$1.24 billion in 2016.2019.

•Cash flow provided by operating activities increased 75%decreased 33% to $1.10 billion.$904.2 million.
Total debt at December 31, 2017 and 2016 consisted
•Net loss of $1.50$1.97 billion of senior notes. During the second quarter 2017, we repaid our 5.875% $750 million notes due 2022 and issued 3.90% $750 million notes due 2027. Our 4.375% $750 million notes are due 2024.
Cash on hand at December 31, 2017 was $400.5 million.
For the year ended December 31, 2017, we had net income of $494.3 million ($5.1919.73 per diluted share), as compared to a net loss of $408.8$124.6 million ($4.381.33 per diluted share) in 2016. Production revenue in 2017 was positively2019.

All of the above results were impacted by increased realized commoditythe demand destruction and lower prices and production volumes. Lower commodity prices negatively impacted 2016, including resulting in $757.7 million2020 that occurred primarily due to the COVID-19 pandemic. Further discussion of impairmentsthese results is provided below.


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Proved Reserves

Our proved reserves by region at December 31, 20172020 and 20162019 were as follows:

December 31, 2017December 31, 2020
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MMcfe)
Gas
(MMcf)		Oil
(MBbls)		NGL
(MBbls)		Total
(MBOE)
Permian Basin573,757
 105,198
 68,530
 1,616,126
Permian Basin790,750 126,327 103,606 361,725 
Mid-Continent1,032,695
 31,853
 85,292
 1,735,565
Mid-Continent570,578 17,491 56,130 168,717 
Other1,183
 187
 38
 2,531
Other1,514 245 82 579 
Total1,607,635
 137,238
 153,860
 3,354,222
1,362,842 144,063 159,818 531,021 

December 31, 2019
Gas
(MMcf)		Oil
(MBbls)		NGL
(MBbls)		Total
(MBOE)
Permian Basin870,208 147,662 130,007 422,703 
Mid-Continent660,161 21,848 64,377 196,252 
Other1,776 260 84 640 
1,532,145 169,770 194,468 619,595 
 December 31, 2016
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MMcfe)
Permian Basin372,371
 74,295
 40,977
 1,064,000
Mid-Continent1,095,194
 31,399
 89,615
 1,821,278
Other3,855
 184
 41
 5,209
Total1,471,420
 105,878
 130,633
 2,890,487


35

Year-end 20172020 proved reserves increaseddecreased approximately 16%14% to 3.35 Tcfe,531.0 MMBOE, compared to 2.89 Tcfe619.6 MMBOE at year-end 2016. Proved2019. At December 31, 2020, proved gas reserves were 1.611.36 Tcf, proved oil reserves were 0.82 Tcfe,144.1 MMBbls, and proved NGL reserves were 0.92 Tcfe.159.8 MMBbls. Reserves in our Mid-Continent regionthe Permian Basin accounted for 52%68% of our total proved reserves with nearly all of the remainder in the Permian Basin.
During 2017, we added 940.7 Bcfe of new reserves through extensions and discoveries. Net negative revisions totaled 59.7 Bcfe, which consisted primarily of a decrease of 248.8 Bcfe for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure, offset by an increase of 187.2 Bcfe related to improved commodity prices.our Mid-Continent region. See SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) in Item 8 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 decisionsJudgment and interpretation 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 for a discussion of our reserve estimation process and Item 1A RISK FACTORS, which includes a discussion of factors that affect our proved reserves estimates.




42

RESULTS OF OPERATIONS


2017 Compared to 2016Revenues


Revenue
Almost all our revenue isOur 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, economic, and economicother factors. See Item 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Production volumes and realized prices were lower for more information regardingall products during the sensitivity of our revenues to price fluctuations. Realized prices and production volumes were higher in 2017year ended December 31, 2020 as compared to 2016, which causedthe year ended December 31, 2019. Subsequent to the first quarter of 2020, we reduced our revenue to increase by $652.8 million,drilling and completion activities and curtailed or 53%,shut in production in certain areas as a result of the unprecedented demand destruction and resulting severe price decreases for oil stemming from the priorCOVID-19 pandemic. Prices improved in the latter part of the year. The following table shows our production revenuerevenues by product for the years indicated2020 and 2019 as well as the change in revenuerevenues due to changes in prices and volumes.

Years Ended
December 31,		Price / Volume Variance
Production Revenue (in thousands)
20202019Variance Between
2020 / 2019		PriceVolumeTotal
Oil sales$999,682 $1,660,210 $(660,528)(40)%$(482,534)$(177,994)$(660,528)
Gas sales243,932 278,776 (34,844)(12)%(13,958)(20,886)(34,844)
NGL sales269,074 382,935 (113,861)(30)%(77,172)(36,689)(113,861)
$1,512,688 $2,321,921 $(809,233)(35)%$(573,664)$(235,569)$(809,233)


43
  Years Ended
December 31,		     Price / Volume Variance
Production Revenue (in thousands)
 2017 2016 Variance Between
2017 / 2016		 Price Volume Total
Oil sales $981,646
 $632,934
 $348,712
 55% $182,742
 $165,970
 $348,712
Gas sales 516,936
 388,786
 128,150
 33% 84,361
 43,789
 128,150
NGL sales 375,421
 199,498
 175,923
 88% 131,347
 44,576
 175,923
  $1,874,003
 $1,221,218
 $652,785
 53% $398,450
 $254,335
 $652,785

The table below presents our production volumes by commodity, our average realized commodity prices, and certain major U.S. index prices. The sale of 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 20172020 and 2016, 78%2019, 88% and 80%84%, respectively, of our oil production was in the Permian Basin and 22% and 20%, respectively, was in the Mid-Continent region.Basin. Our realized prices do not include settlements of commodity derivative contracts.


Years Ended
December 31,		Variance Between
2020 / 2019
20202019
Oil
Total volume — MBbls28,087 31,463 (3,376)(11)%
Total volume — MBbls per day76.7 86.2 (9.5)(11)%
Percentage of total production30 %31 %
Average realized price — per barrel$35.59 $52.77 $(17.18)(33)%
Average WTI Midland price — per barrel$39.71 $55.53 $(15.82)(28)%
Average WTI Cushing price — per barrel$39.40 $57.03 $(17.63)(31)%
Gas
Total volume — MMcf232,625 251,567 (18,942)(8)%
Total volume — MMcf per day635.6 689.2 (53.6)(8)%
Percentage of total production42 %41 %
Average realized price — per Mcf$1.05 $1.11 $(0.06)(5)%
Average Henry Hub price — per Mcf$2.08 $2.63 $(0.55)(21)%
NGL
Total volume — MBbls25,554 28,254 (2,700)(10)%
Total volume — MBbls per day69.8 77.4 (7.6)(10)%
Percentage of total production28 %28 %
Average realized price — per barrel$10.53 $13.55 $(3.02)(22)%
Total
Total production — MBOE92,412 101,645 (9,233)(9)%
Total production — MBOE per day252.5 278.5 (26.0)(9)%
Average realized price — per BOE$16.37 $22.84 $(6.47)(28)%
36

  Years Ended
December 31,		 Variance Between
2017 / 2016
  2017 2016 
Oil        
Total volume — MBbls 20,861
 16,528
 4,333
 26%
Total volume — MBbls per day 57.2
 45.2
 12.0
 27%
Percentage of total production 30% 28%    
Average realized price — per barrel $47.06
 $38.30
 $8.76
 23%
Average WTI Midland price — per barrel $50.45
 $43.34
 $7.11
 16%
Average WTI Cushing price — per barrel $50.94
 $43.32
 $7.62
 18%
         
Gas        
Total volume — MMcf 187,468
 168,227
 19,241
 11%
Total volume — MMcf per day 513.6
 459.6
 54.0
 12%
Percentage of total production 45% 48%    
Average realized price — per Mcf $2.76
 $2.31
 $0.45
 19%
Average Henry Hub price — per Mcf $3.11
 $2.46
 $0.65
 26%
         
NGL        
Total volume — MBbls 17,374
 14,200
 3,174
 22%
Total volume — MBbls per day 47.6
 38.8
 8.8
 23%
Percentage of total production 25% 24%    
Average realized price — per barrel $21.61
 $14.05
 $7.56
 54%
         
Total        
Total production — MMcfe 416,875
 352,591
 64,284
 18%
Total production — MMcfe per day 1,142.1
 963.4
 178.7
 19%
Average realized price — per Mcfe $4.50
 $3.46
 $1.04
 30%
Our 20172020 daily production volumes were 1,142.1 MMcfe,252.5 MBOE, a 19% increase9% decrease from 2016.2019. This increasedecrease is the result of increased drillingour intentional reduction in capital spending and completion activity during 2017 as comparedcurtailing and shutting in production in certain areas due to 2016.the demand destruction caused primarily by the COVID-19 pandemic. 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.


44

Other Revenues

WeGas gathering and other is revenue earned when we transport, process, and market some third-party gas that is associated with our equity gas. WeGas marketing is comprised of the fees we earn when we act as agent under short-term sales and supply agreements and market and sell gas for other working interest owners, under short term agreements and may earnnet of the related expenses. Gas marketing also includes net pipeline settlements incurred as a fee for such services.result of these activities. The table below reflects incomerevenues from third-party gas gathering and processingother and our net marketing margin for marketing third-party gas.other working interest owners’ gas for the periods indicated.

Years Ended December 31,Variance
Between
2020 / 2019
Gas Gathering and Marketing Revenues (in thousands)
20202019
Gas gathering and other$47,842 $42,454 $5,388 
Gas marketing$(1,935)$(1,406)$(529)
  Years Ended December 31, 
Variance
Between
2017 / 2016
Gas Gathering and Marketing (in thousands):
 2017 2016 
Gas gathering and other $43,751
 $36,033
 $7,718
Gas marketing $495
 $94
 $401

Fluctuations in revenues from gas gathering and gas marketing activities are primarily a function of increases and decreases in volumes, commodity prices, and gathering rate charges. The increases from 2016 are primarily due to an increase in prices.

37


Operating Costs and Expenses


Costs associated with producing oil and gas are substantial. Among other factors, some of these costs vary with commodity prices, some trend with the volume of production, otherssome are a function of the number of wells we own, and some depend on the prices charged by service companies.companies, and some fluctuate based on a combination of the foregoing.


Total operating costs and expenses of $1.17$3.84 billion in 20172020 were 36% lower55% higher than the $1.83$2.48 billion incurred in 2016. Most of2019. The primary reasons for the decrease resulted fromincrease were: (i) the $1.64 billion in ceiling test impairments of our oil and gas properties of $757.7 million recordedincurred in 2016; we recorded no2020, which was $1.02 billion greater than the ceiling test impairmentsimpairment incurred in 2017. Also contributing to2019 and (ii) the $714.4 million impairment of goodwill incurred during 2020, partially offset by (iii) the $186.2 million decrease was the net gain on derivative instruments in 2017 compared to a net lossdepreciation, depletion, and amortization in 2016. Otherwise, all other categories of operating costs and expenses increased in 2017.2020. The following table shows our operating costs and expenses for the years indicated and a discussion of year-over-year differencesthe operating costs and expenses follows.

 Years Ended December 31,Variance
Between
2020 / 2019		Per BOE
Operating Costs and Expenses
(in thousands, except per BOE)
2020201920202019
Impairment of oil and gas properties$1,638,329 $618,693 $1,019,636 N/AN/A
Depreciation, depletion, and amortization695,954 882,173 (186,219)$7.53 $8.68 
Asset retirement obligation14,653 8,586 6,067 $0.16 $0.08 
Impairment of goodwill714,447 — 714,447 N/AN/A
Production285,324 339,941 (54,617)$3.09 $3.34 
Transportation, processing, and other operating213,366 238,259 (24,893)$2.31 $2.34 
Gas gathering and other23,591 23,294 297 $0.26 $0.23 
Taxes other than income79,699 148,953 (69,254)$0.86 $1.47 
General and administrative111,005 95,843 15,162 $1.20 $0.94 
Stock-based compensation29,895 26,398 3,497 $0.32 $0.26 
Loss on derivative instruments, net35,534 76,850 (41,316)N/AN/A
Other operating expense, net839 19,305 (18,466)N/AN/A
 $3,842,636 $2,478,295 $1,364,341   


45

  Years Ended December 31, 
Variance
Between
2017 / 2016
 Per Mcfe
Operating Costs and Expenses (in thousands, except per Mcfe)
 2017 2016  2017 2016
Impairment of oil and gas properties $—
 $757,670
 $(757,670) N/A
 N/A
Depreciation, depletion, and amortization 446,031
 392,348
 53,683
 $1.07
 $1.11
Asset retirement obligation 15,624
 7,828
 7,796
 $0.04
 $0.02
Production 262,180
 232,002
 30,178
 $0.63
 $0.66
Transportation, processing, and other operating 231,640
 190,725
 40,915
 $0.56
 $0.54
Gas gathering and other 35,840
 31,785
 4,055
 $0.09
 $0.09
Taxes other than income 89,864
 61,946
 27,918
 $0.22
 $0.18
General and administrative 79,996
 73,901
 6,095
 $0.19
 $0.21
Stock compensation 26,256
 24,523
 1,733
 $0.06
 $0.07
(Gain) loss on derivative instruments, net (21,210) 55,749
 (76,959) N/A
 N/A
Other operating expense, net 1,314
 755
 559
 N/A
 N/A
  $1,167,535
 $1,829,232
 $(661,697)  
  
Impairment of Oil and Gas Properties
Ceiling Test Impairment
We use the full cost method of accounting for our oil and gas operations. Accounting rules require usUnder this method, we are required to perform a quarterly ceiling test calculationcalculations to test our capitalized oil and gas property costsproperties for possible impairment.  If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense.  The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net 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, as adjusted for income taxes.  We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.
At each quarter-end date during the year ended December 31, 2017, the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we did not recognize a
The quarterly ceiling test impairment during the year. Theis primarily impacted by commodity prices, usedchanges in the December 31, 2017 ceiling calculation, based on the required trailing twelve-month average prices, were $2.98 per Mcf of gasestimated reserve quantities, reserves produced, overall exploration and $51.34 per barrel of oil.  A decline of approximately 19% or more in the value of the ceiling limitation would have resulted in an impairment at December 31, 2017.  During the year ended December 31, 2016, we recognized ceiling test impairments totaling $757.7 million ($481.4 million, net of tax).  These impairments were primarily the result of decreases in the trailing twelve-month average prices for oil, gas, and NGLs utilized in determining the estimated future net revenues from proved reserves. Because the ceiling calculation uses trailing twelve-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation.  In addition, other factors that 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.  Dependingdeferred taxes.  If pricing conditions decline, or if there is a negative impact on fluctuations in these factors, including a decline in prices,one or more of the other components of the calculation, we may incur a full cost ceiling test impairments in future quarters. 
impairment. The calculated ceiling 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 various components of our balance sheet.  Any impairment of oil and gas properties is not reversible at a later date.


38
TableDuring 2020, we recognized ceiling test impairments totaling $1.64 billion.  The impairments resulted primarily from the impact of Contentsdecreases in the 12-month average trailing prices for oil, gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves. We may recognize additional ceiling test impairments in the future.



Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization (“DD&A”) consisted of the following for the periods indicated:

 Years Ended December 31,Variance
Between
2020 / 2019		Per BOE
DD&A Expense (in thousands, except per BOE)
2020201920202019
Depletion$625,481 $817,099 $(191,618)$6.77 $8.04 
Depreciation70,473 65,074 5,399 0.76 0.64 
 $695,954 $882,173 $(186,219)$7.53 $8.68 

Depletion of our 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 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 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. Depletion is calculated quarterly before theOur depletion expense decreased during 2020 as compared to 2019 primarily due to a decrease in our depletable basis mostly resulting from ceiling test impairment calculation.  While prices have increasedimpairments recognized at December 31, 2019, March 31, 2020, June 30, 2020, and September 30, 2020. In addition, our depletion expense decreased as a result of a decrease in 2017our production resulting from 2016, thus increasinga reduction in drilling and completion activity subsequent to the first quarter 2020 and curtailment or shut in of production in certain areas stemming from the demand destruction caused by the COVID-19 pandemic. These causes for decreased depletion expense were partially offset by a decrease in our reserves, so too have our exploration and development expenditures and activities, thus increasing our proved oil and gas properties and future development costs, causing an overall increaseprimarily due to a decrease in the trailing twelve month prices used to calculate reserves, which increased depletion expense.


46

Fixed assets consist primarily of gas gathering and plant facilities, water infrastructure, 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. Depreciation, depletion, and amortization (“DD&A”) consistedAlso included in our depreciation expense is the depreciation of the following for the years indicated:right-of-use asset associated with our finance lease gathering system. The increase in depreciation expense during 2020 as compared to 2019 is primarily due to increased depreciation on our gathering and plant facilities due to ongoing expenditures on this infrastructure and projects being placed into service.
  Years Ended December 31, 
Variance
Between
2017 / 2016
 Per Mcfe
DD&A Expense (in thousands, except per Mcfe)
 2017 2016  2017 2016
Depletion $399,328
 $346,003
 $53,325
 $0.96
 $0.98
Depreciation 46,703
 46,345
 358
 0.11
 0.13
  $446,031
 $392,348
 $53,683
 $1.07
 $1.11

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 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 asset retirement obligation expense are gains and losses recognized on the settlement of asset retirement obligation liabilities.
Asset Accretion expense for the year ended December 31, 2020, also included $4.9 million to increase our estimated asset retirement obligation expense includes $10.5 million in 2017 for the estimated liability to decommission twocertain offshore properties in the Gulf of Mexico in which we were a prior lessee. In JanuaryAs a result of the current lessee defaulting on its obligation to decommission the properties, in 2018 the Bureau of Safety and Environmental Enforcement (“BSEE”) notified us and other prior lessees that the current lessee of the properties had filed a petition for relief under the bankruptcy code and, as a result, had defaulted on its obligation to decommission the properties. Consequently, BSEE ordered us and other prior lessees to decommission all wells, pipelines, platforms, and other facilities related to thesethe properties. Our estimate

Impairment of our liability may change as we refine our understandingGoodwill

We concluded that goodwill was impaired at March 31, 2020 and expensed the entire balance of $714.4 million at that time. See Note 1 to the extent of our obligations under the orders from BSEE and obtainConsolidated Financial Statements for additional information on decommissioning costs.regarding the impairment of goodwill.

Production

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

Years Ended December 31,Variance
Between
2020 / 2019		Per BOE
 Years Ended December 31, 
Variance
Between
2017 / 2016
 Per Mcfe
Production Expense (in thousands, except per Mcfe)
 2017 2016 2017 2016
Production Expense (in thousands, except per BOE)
Production Expense (in thousands, except per BOE)
20202019Variance
Between
2020 / 2019		20202019
Lease operating expense $215,148
 $189,291
 $25,857
 $0.52
 $0.54
Lease operating expense$244,397 $273,092 $2.65 $2.68 
Workover expense 47,032
 42,711
 4,321
 0.11
 0.12
Workover expense40,927 66,849 (25,922)0.44 0.66 
 $262,180
 $232,002
 $30,178
 $0.63
 $0.66
 $285,324 $339,941 $(54,617)$3.09 $3.34 



39

Through efficiency gains and increasing daily production by 19% during 2017 asLease operating expense decreased 11%, or $28.7 million, in 2020 compared to 2016, we reduced2019. The decrease is primarily related to the reduction in activity and our per unit lease operatingcost saving efforts such as our initiative to reduce the use of outside labor, our voluntary early retirement incentive program and involuntary reduction in workforce, delaying non-essential work, shutting in wells, and decreasing drilling and completion, which has led to fewer wells coming online.

Workover expense by 4% between these two periods. On an absolute basis, lease operating expense in 2017 increased 14%decreased 39%, or $25.9 million, compared to 2016.  The increase was primarily caused by: (i) increased saltwater disposal costs primarily attributed to the addition of new wells and recompleted wells; (ii) increased labor costs primarily due to additional employees and salary and bonus increases; (iii) increased equipment maintenance costs, primarily the result of the addition of new wells; (iv) increased gas lift and fuel compression costs; and (v) increased chemicals and treating costs.
Workover expense increased 10%, or $4.3 million, during 20172020 as compared to 2016. During 2017, we2019. We had costlier major wellfewer workover projects than during 2016, which increased expense. This increase was partially offset by the receipt2020 as compared to 2019 as a result of partial insurance proceeds during 2017 relateda concerted effort to a flooding event in 2015reduce activity and the subsequent remediation and repairs, the bulkdelay non-essential work.


47

Transportation, Processing, and Other Operating

Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, including gathering, fuel, compression, and processing costs. Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs, and the structure of sales contracts. 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.
Transportation, processing, and other operating costs in 20172020 were 21%10%, or $40.9$24.9 million, higherlower than in 2016.  This increase was2019 primarily due to increaseda decrease in production volumes and, to a lesser extent, increased transportation and processing rates in 2017 as compared to 2016.volumes.

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 20172020 was 13%, or $4.1 million,minimally higher than in 2016.  This increase was primarily due to higher product costs associated with processing third-party production due to higher commodity prices. These increased product costs were offset by increases in associated revenue.2019. 

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. The following table presents taxes other than income for the years indicated.  

 Years Ended December 31,Variance
Between
2020 / 2019
Taxes Other than Income (in thousands)
20202019
Production$64,075 $111,819 $(47,744)
Ad valorem14,500 36,291 (21,791)
Other1,124 843 281 
$79,699 $148,953 $(69,254)
Taxes other than income as a percentage of production revenue5.3 %6.4 %

Taxes other than income decreased 46%, or $69.3 million, in 2020 as compared to 2019.  Production taxes make up the majority of this expense for us, with revenue-based production taxes being the largest component of these taxes.  In 2017,our taxes other than income increased 45%, or $27.9 million, from 2016.  These increases areand they decreased primarily due to the increasedecreases in revenue seen between the comparable periods.  Taxesoil and NGL prices. Ad valorem taxes also decreased primarily due to decreased valuations based on decreased commodity prices. Other taxes other than income were 4.8%are comprised of franchise and 5.1%consumer use and sales taxes.


48

General and Administrative

General and administrative (“G&A”) expense consists primarily of salaries and related benefits, office rent, legal and consultantconsulting fees, systems costs, and other administrative costs incurred that are 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.  The amount of expense capitalized varies and depends on whether the cost incurred can be directly identified with acquisition, exploration, and development activities. The percentage of gross G&A capitalized was 49%34% and 50%44% during 20172020 and 2016,2019, respectively. In response to low oil prices and demand destruction in 2020, we reduced our acquisition, exploration, and development activities and, therefore, the percentage of gross G&A capitalized decreased from 2019. The table below shows our G&A costs.
  Years Ended December 31, 
Variance
Between
2017 / 2016
General and Administrative Expense (in thousands):
 2017 2016 
Gross G&A $156,389
 $146,432
 $9,957
Less amounts capitalized to oil and gas properties (76,393) (72,531) (3,862)
G&A expense $79,996
 $73,901
 $6,095


Years Ended December 31,Variance
Between
2020 / 2019
General and Administrative Expense (in thousands)
20202019
Gross G&A$168,815 $170,757 $(1,942)
Less amounts capitalized to oil and gas properties(57,810)(74,914)17,104 
G&A expense$111,005 $95,843 $15,162 
40


G&A expense during 2017 was 8%increased 16%, or $6.1$15.2 million, higher than during 2016.in 2020 as compared to 2019. This increase is primarily due to the following increases: (i) other employee compensation, primarily due to increased incentive bonus expense; (ii) insurance; (iii) consulting; (iv) salaries and wages, due to additional employees and salary increases; and (v) charitable donations. These increases were partially offset by decreased$28.7 million in severance expense, due to anone of which was capitalized, associated with the voluntary early retirement incentive program which included severance pay, that waswe offered to employees who met certain employees during 2016.  eligibility criteria in the first quarter of 2020 and the involuntary reduction in workforce program that we carried out in the third quarter of 2020. These programs reduced our headcount by approximately 24% from December 31, 2019 and we expect G&A expense related to salaries and wages to be lower in future periods as a result. The increase in G&A expense due to the severance expense was partially offset by decreases in salaries and wages, health insurance, annual bonus, consulting, and travel expenses.
Stock
Stock-based Compensation
Stock
Stock-based 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:

Years Ended December 31,Variance
Between
2020 / 2019
 Years Ended December 31, 
Variance
Between
2017 / 2016
Stock Compensation Expense (in thousands):
 2017 2016 
Stock-based Compensation Expense (in thousands)
Stock-based Compensation Expense (in thousands)
20202019Variance
Between
2020 / 2019
Restricted stock awards:  
  
  
Restricted stock awards:  
Performance stock awards $26,020
 $24,183
 $1,837
Performance stock awards$17,338 $21,590 $(4,252)
Service-based stock awards 19,746
 18,391
 1,355
Service-based stock awards26,014 25,611 403 
 45,766
 42,574
 3,192
 43,352 47,201 (3,849)
Stock option awards 2,599
 2,565
 34
Stock option awards1,460 1,903 (443)
Total stock compensation cost 48,365
 45,139
 3,226
Total stock-based compensation costTotal stock-based compensation cost44,812 49,104 (4,292)
Less amounts capitalized to oil and gas properties (22,109) (20,616) (1,493)Less amounts capitalized to oil and gas properties(14,917)(22,706)7,789 
Stock compensation expense $26,256
 $24,523
 $1,733
Stock-based compensation expenseStock-based compensation expense$29,895 $26,398 $3,497 

Periodic stockstock-based 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 total stock compensation cost in 2017 as compared to 2016Our accounting policy is primarily due to awards granted either during or subsequent to 2016. These increases were partially offset by awards vesting prior to or during 2017.
We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017 pursuant to which we made an accounting policy election to account for forfeitures in compensation cost when they occur, rather than including an estimateoccur. The amount capitalized to oil and gas properties decreased as a percentage of total stock-based compensation cost in 2020 as compared to 2019 due to reduced acquisition, exploration, and development activities in 2020 as a result of the number of awards that are expected to vestlow oil prices and demand destruction experienced in our compensation cost.  See Note 6 to2020 stemming from the Consolidated Financial Statements for further discussion regarding ourCOVID-19 pandemic and OPEC and other countries’ actions. The decreased capitalization caused the overall stock-based compensation including our adoptionexpense to increase.

49
(Gain)
Loss 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 cash settlements (if any) of the instruments.  We have 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.  Consequently, changes in the fair value of 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 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 components of (Gain) loss“Loss on derivative instruments, netnet” for the periodsyears indicated.  See Note 4 to the Consolidated Financial Statements for additional information regarding our derivative instruments.


Years Ended December 31,Variance
Between
2020 / 2019
Loss on Derivative Instruments, Net (in thousands)
20202019
Decrease (increase) in fair value of derivative instruments, net:   
Gas contracts$56,475 $(13,114)$69,589 
Oil contracts98,306 76,833 21,473 
154,781 63,719 91,062 
Cash (receipts) payments on derivative instruments, net:   
Gas contracts(15,476)(40,114)24,638 
Oil contracts(103,771)53,245 (157,016)
(119,247)13,131 (132,378)
Loss on derivative instruments, net$35,534 $76,850 $(41,316)
41
Other Operating Expense, Net

TableOther operating expense, net decreased $18.5 million in 2020 as compared to 2019. This expense is typically comprised primarily of Contentslitigation settlements and allowance for credit losses adjustments. Other operating expense, net in 2019 included $10.0 million in litigation settlements and $8.4 million in acquisition-related costs incurred to effect the Resolute acquisition. The acquisition-related costs consisted primarily of advisory and legal fees.


  Years Ended December 31, 
Variance
Between
2017 / 2016
(Gain) Loss on Derivative Instruments (in thousands):
 2017 2016 
Change in fair value of derivative instruments, net:  
  
  
Gas contracts $(40,226) $27,462
 $(67,688)
Oil contracts 17,383
 35,724
 (18,341)
  (22,843) 63,186
 (86,029)
Cash (receipts) payments on derivative instruments, net:  
  
  
Gas contracts (4,557) (6,467) 1,910
Oil contracts 6,190
 (970) 7,160
  1,633
 (7,437) 9,070
(Gain) loss on derivative instruments, net $(21,210) $55,749
 $(76,959)

Other Income and Expense

Years Ended December 31,Variance
Between
2020 / 2019
 Years Ended December 31, 
Variance
Between
2017 / 2016
Other Income and Expense (in thousands):
 2017 2016 
Other Income and Expense (in thousands)
Other Income and Expense (in thousands)
20202019Variance
Between
2020 / 2019
Interest expense $74,821
 $83,272
 $(8,451)Interest expense$92,914 $93,386 
Capitalized interest (22,948) (21,248) (1,700)Capitalized interest(50,030)(56,232)6,202 
Loss on early extinguishment of debt 28,187
 —
 28,187
Loss on early extinguishment of debt— 4,250 (4,250)
Other, net (11,342) (10,707) (635)Other, net(540)(5,741)5,201 
 $68,718
 $51,317
 $17,401
 $42,344 $35,663 $6,681 

The majority of our interest expense relates to interest on the borrowings under our senior unsecured notes.notes, with such interest totaling $83.9 million and $79.9 million during 2020 and 2019, respectively. Also included in interest expense is interest expense on our Credit Facility borrowings, the amortization of debt issuance costs and discounts, interest expense on our finance lease, and miscellaneous interest expense. See LIQUIDITY AND CAPITAL RESOURCES Long-Term Debt below for further information regarding our debt. The decrease in interest expense in 2017 as compared to 2016 is due to the completion$4.3 million

50

loss on early extinguishment of debt incurred during 20172019 was also associated with the debt tender offer and redemption. The loss was composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3$600.0 million of unamortized debt issuance costs.  The original maturity date of the 5.875%8.5% senior notes wasdue May 1, 2022.2020 that we acquired with Resolute on March 1, 2019 and elected to immediately repay.

We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing qualifiedmidstream assets.  Capitalized interest will fluctuate based primarily on the amount of costs subject to interest capitalization and based on the rates applicable to borrowings outstanding during the period and theperiod. The amount of costs on whichsubject to interest is capitalized. There have been higher capitalized costs upon which to capitalize interestcapitalization was lower in 20172020 as compared to 2016 due to our increased capitalized expenditures. However, the impact of this increase in capitalized interest has been largely offset by the lower interest rate on borrowings outstanding2019, primarily due to the replacement of our 5.875% notes with 3.90% notesdecrease in the second quarterbalance of 2017.non-producing leasehold costs as a result of transfers to proved properties as well as due to a decrease in the in-progress costs of drilling and completing wells and constructing midstream assets due to decreased activity in 2020.
Components
Other, net includes interest income of $0.7 million and $3.3 million in 2020 and 2019, respectively. The decrease in interest income in 2020 is primarily due to the decrease in our investable cash balance after acquiring Resolute on March 1, 2019. Other components of Other, net consist ofinclude miscellaneous income and expense items that will vary from period to period, including gain or loss related to the sale or value of oil and gas well equipment and supplies, gain or loss on miscellaneous fixed asset sales, interest income, and income and expense associated with other non-operating activities.

Income Tax Expense (Benefit)Benefit

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

  Years Ended December 31, 
Variance
Between
2017 / 2016
Income Tax Expense (Benefit) (in thousands):
 2017 2016 
Current tax benefit $(2,812) $(1,115) $(1,697)
Deferred tax expense (benefit) 190,479
 (213,286) 403,765
  $187,667
 $(214,401) $402,068
       
Combined federal and state effective income tax rate 27.5% 34.4%  
 Years Ended December 31,Variance
Between
2020 / 2019
Income Tax Benefit (in thousands)
20202019
Current tax (benefit) expense$(31)$532 $(563)
Deferred tax benefit(358,896)(26,902)(331,994)
 $(358,927)$(26,370)$(332,557)
Combined federal and state effective income tax rate15.4 %17.5 %


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Table of Contents


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, allows for the expensing of capital expenditures, and eliminates the corporate Alternative Minimum Tax. We remeasured the 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 and, as a result of this remeasurement, we recorded an income tax benefit of $61.1 million and a corresponding $61.1 million decrease in the net deferred tax liabilities as of December 31, 2017. We believe the accounting for the effects of H.R.1 recognized in the December 31, 2017 financial statements is materially complete. However, evolving analyses and interpretations of the law may cause a change to the amounts presented. Any such changes that may arise will be recognized in the period determined, but no later than December 31, 2018. It is not expected any such change will be material to the financial statements. As a result of H.R.1, we expect our effective tax rate in future periods will be lower than in periods prior to enactment. In addition, the limitations on utilization of net operating losses and deductibility of interest and executive compensation may result in the payment of cash taxes earlier than expected.

Our combined federal and state effective tax rates, as shown above, differ from the statutory rate of 35% primarily due to state income taxes, non-deductible expenses, revisions, and the impact of changes in tax law.laws and tax rates enacted in the period, and changes in valuation allowances. See Note 9 to the Consolidated Financial Statements for further information regarding our income taxes.

RESULTS OF OPERATIONS

2016 Compared to 2015
Summary

For the year ended December 31, 2016, we had a net loss of $408.8 million ($4.38 per diluted share), down from a net loss of $2.58 billion ($27.75 per diluted share) in 2015. Production revenues in 2016 and 2015 were adversely affected by low realized commodity prices, which also brought about impairments of our oil and gas properties and net losses for each year. Although production revenue in 2016 was lower than in 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 as follows. Also refer to the “2017 Compared to 2016” section above for general information regarding various statement of operations line items.
Revenue
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 realized prices and production volumes for NGLs. The following table shows our production revenue for the years indicated as well as the change in revenue due to changes in prices and volumes.
  Years Ended
December 31,		     Price / Volume Variance
Production Revenue (in thousands)
 2016 2015 Variance Between
2016 / 2015		 Price Volume Total
Oil sales $632,934
 $809,664
 $(176,730) (22)% $(83,962) $(92,768) $(176,730)
Gas sales 388,786
 428,227
 (39,441) (9)% (37,010) (2,431) (39,441)
NGL sales 199,498
 179,647
 19,851
 11 % 4,260
 15,591
 19,851
  $1,221,218
 $1,417,538
 $(196,320) (14)% $(116,712) $(79,608) $(196,320)
The table below presents our production volumes by commodity, our average realized commodity prices, and certain major U.S. index prices. The sale of 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 and 2015, 80% and 84%, respectively, of our oil production was in the Permian Basin and 20% and 15%, respectively, was in the Mid-Continent region. Our realized prices do not include settlements of commodity derivative contracts.

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Table of Contents


  Years Ended
December 31,		 Variance Between
2016 / 2015
  2016 2015 
Oil        
Total volume — MBbls 16,528
 18,663
 (2,135) (11)%
Total volume — MBbls per day 45.2
 51.1
 (5.9) (12)%
Percentage of total production 28% 31%    
Average realized price — per barrel $38.30
 $43.38
 $(5.08) (12)%
Average WTI Midland price — per barrel $43.34
 $48.39
 $(5.05) (10)%
Average WTI Cushing price — per barrel $43.32
 $48.80
 $(5.48) (11)%
         
Gas        
Total volume — MMcf 168,227
 168,987
 (760) — %
Total volume — MMcf per day 459.6
 463.0
 (3.4) (1)%
Percentage of total production 48% 47%    
Average realized price — per Mcf $2.31
 $2.53
 $(0.22) (9)%
Average Henry Hub price — per Mcf $2.46
 $2.67
 $(0.21) (8)%
         
NGL        
Total volume — MBbls 14,200
 13,063
 1,137
 9 %
Total volume — MBbls per day 38.8
 35.8
 3.0
 8 %
Percentage of total production 24% 22%    
Average realized price — per barrel $14.05
 $13.75
 $0.30
 2 %
         
Total        
Total production — MMcfe 352,591
 359,343
 (6,752) (2)%
Total production — MMcfe per day 963.4
 984.5
 (21.1) (2)%
Average realized price — per Mcfe $3.46
 $3.94
 $(0.48) (12)%
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 income from third-party gas gathering and processing and our net marketing margin for marketing third-party gas.
  Years Ended December 31, 
Variance
Between
2016 / 2015
Gas Gathering and Marketing (in thousands):
 2016 2015 
Gas gathering and other $36,033
 $34,688
 $1,345
Gas marketing $94
 $393
 $(299)
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.
Operating Costs and Expenses

Total operating costs and expenses of $1.83 billion in 2016 were 67% lower than the $5.46 billion incurred in 2015. Most of the decrease resulted from lower ceiling test impairments of our oil and gas properties and lower DD&A expense. The following table shows our operating costs and expenses for the years indicated and a discussion of year-over-year differences follows.

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  Years Ended December 31, 
Variance
Between
2016 / 2015
 Per Mcfe
Operating Costs and Expenses (in thousands, except per Mcfe)
 2016 2015  2016 2015
Impairment of oil and gas properties $757,670
 $4,033,295
 $(3,275,625) N/A
 N/A
Depreciation, depletion, and amortization 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 expense, net 755
 856
 (101) N/A
 N/A
  $1,829,232
 $5,462,371
 $(3,633,139)  
  
Ceiling Test Impairment
During the first three quarters of 2016, we recognized ceiling test impairments totaling $757.7 million ($481.4 million net of tax). We recognized ceiling test impairments in 2015 totaling $4.03 billion ($2.56 billion net of tax). The impairments resulted primarily from the impact of decreases in the trailing twelve-month average prices for oil, gas, and NGLs utilized in determining the estimated future net revenues 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 7% or more in the value of the ceiling limitation would have resulted in an impairment.
Depreciation, Depletion, and Amortization
Depletion expense in 2016 decreased compared to 2015 due to the quarterly impairments of our oil and gas properties from the first quarter of 2015 through the third quarter of 2016. Depletion expense generally decreases following ceiling test impairments due to the decrease in the net proved properties balance. DD&A consisted of the following for the years indicated:
  Years Ended December 31, 
Variance
Between
2016 / 2015
 Per Mcfe
DD&A Expense (in thousands, except per Mcfe)
 2016 2015  2016 2015
Depletion $346,003
 $689,120
 $(343,117) $0.98
 $1.92
Depreciation 46,345
 42,340
 4,005
 0.13
 0.12
  $392,348
 $731,460
 $(339,112) $1.11
 $2.04
Production

Production costs consist of lease operating expense and workover expense as follows:
  Years Ended December 31, 
Variance
Between
2016 / 2015
 Per Mcfe
Production Expense (in thousands, except per Mcfe)
 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 saltwater disposal costs due to implementation of operational efficiencies as well as lower costs associated with labor, rental equipment, and property divestitures.

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Workover expense decreased by 14% in 2016 compared to 2015. Generally, these costs will fluctuate based on the amount of maintenance and remedial activity performed during the period.
Transportation, Processing, and Other Operating
Our 2016 transportation, processing, and other operating costs were 5%, or $8.4 million, higher than those of 2015. These costs will vary by product type and region. The increase in 2016 is primarily a result of more gas production and higher fees associated with our Mid-Continent region.
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. The 17%, or $6.4 million, year-over-year decrease is primarily attributable to higher repair and maintenance activities occurring in 2015.
Taxes Other than Income
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 are the largest components of these taxes. The 27%, or $22.8 million, decrease 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 consisted of the following for the years indicated:
  Years Ended December 31, 
Variance
Between
2016 / 2015
General and Administrative Expense (in thousands):
 2016 2015 
Gross G&A $146,432
 $133,020
 $13,412
Less amounts capitalized to oil and gas properties (72,531) (58,332) (14,199)
G&A expense $73,901
 $74,688
 $(787)
G&A expense decreased slightly during 2016 as compared to 2015. The percentage of gross G&A capitalized was 50% and 44% during 2016 and 2015, respectively. The increased capitalization in 2016 offset the increase in gross G&A costs, which increased due to 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. These increases were partially offset by lower salaries and wages and lower corporate contributions and consulting fees.
Stock Compensation
We have recognized stock-based compensation cost as follows:
  Years Ended December 31, 
Variance
Between
2016 / 2015
Stock Compensation Expense (in thousands):
 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)
Total stock compensation cost 45,139
 36,341
 8,798
Less amounts capitalized to oil and gas properties (20,616) (16,782) (3,834)
Stock compensation expense $24,523
 $19,559
 $4,964

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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 stock compensation is primarily related to performance awards granted in December 2015, a portion of which were amortized during 2016, forfeiture rate adjustments on the service-based stock awards, and acceleration 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 the value of future awards may vary from historical amounts.
(Gain) Loss on Derivative Instruments, Net
The following table presents the components of (Gain) loss on derivative instruments, net for the periods indicated.  See Note 4 to the Consolidated Financial Statements for additional information regarding our derivative instruments.
  Years Ended December 31, 
Variance
Between
2016 / 2015
(Gain) Loss on Derivative Instruments (in thousands):
 2016 2015 
Change in fair value of derivative instruments, net:  
  
  
Gas contracts $27,462
 $(4,472) $31,934
Oil contracts 35,724
 (6,774) 42,498
  63,186
 (11,246) 74,432
Cash (receipts) payments on derivative instruments, net:  
  
  
Gas contracts (6,467) —
 (6,467)
Oil contracts (970) —
 (970)
  (7,437) —
 (7,437)
(Gain) loss on derivative instruments, net $55,749
 $(11,246) $66,995
Other Income and Expense
  Years Ended December 31, 
Variance
Between
2016 / 2015
Other Income and Expense (in thousands):
 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
The majority of our interest expense relates to interest on our senior unsecured notes. See LIQUIDITY AND CAPITAL RESOURCES Long-Term Debt below for further information regarding our debt.
We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing qualified assets.  Capitalized interest will fluctuate based on the rates applicable to borrowings outstanding during the period and the amount of costs on which interest is capitalized. The 31%, or $9.3 million, decrease in year-over-year capitalized interest expense resulted from lower average unproved property costs in 2016.
Components of Other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss related to the sale or value of oil and gas well equipment and supplies, gain or loss on miscellaneous asset sales, interest income, and income and expense associated with other non-operating activities. The 21%, or $2.9 million, decrease in 2016 income was primarily due to lower net gains on transactions related to oil and gas well equipment and supplies.

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Income Tax Expense (Benefit)
The components of our provision for income taxes are as follows:
  Years Ended December 31, 
Variance
Between
2016 / 2015
Income Tax Expense (Benefit) (in thousands):
 2016 2015 
Current tax (benefit) expense $(1,115) $14,710
 $(15,825)
Deferred tax benefit (213,286) (1,486,439) 1,273,153
  $(214,401) $(1,471,729) $1,257,328
       
Combined federal and state effective income tax rate 34.4% 36.3%  
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 for further information regarding our income taxes.

LIQUIDITY AND CAPITAL RESOURCES

Overview

With the volatility in commodity prices and recognizing the U.S. oil volume growth impact on the overall world oil supply and demand balance, we have adjusted our approach to our reinvestment rates to target 70 to 80% of operating cash flow. With this investment approach, we will have 20 to 30% of cash flow available to increase cash on our balance sheet, which we plan to initially target to reduce debt and continue to fund and increase our regular common stock cash dividend.

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, and proceeds from sales of non-core assets, and occasional public financings based on our monitoringnon-strategic assets.


51
Table of capital markets and our balance sheet.Contents

Our liquidity is highly dependent on the prices we receive for the oil, gas, and NGLs we produce.  PricesThe 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 RESULTS OF OPERATIONS RevenueRevenues above for further information regarding the impact realized prices have had on our 20172020 earnings.

We deal withaddress 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 enablesenable us to respond quickly to industry volatility. Based on current economic conditions,In response to the decline in oil prices in the second quarter of 2020, we took immediate steps to reduce our 2018capital investment, including releasing all but one drilling rig by mid-May 2020 and deferring well completion activity. As a result, total exploration, development, and development (“E&D”)acquisition capital expenditures are projectedfor 2020 were $556.7 million. This level of capital expenditures was less than our cash flow from operating activities, which has allowed us to range from $1.6 billion to $1.7 billion.  Investmentsbuild our cash balance and not incur any incremental borrowings this year. With the subsequent improvement in gathering, processing,oil prices, we exited 2020 running five drilling rigs and other infrastructure are expected to approximate an additional $80 million to $90 million for 2018.completing wells with one completion crew. See Capital Expenditures below for information regarding our 2017 E&D activities.2020 capital expenditures and our projected 2021 expenditures.

We periodically use derivative instruments to mitigate volatility in commodity prices.  At December 31, 2017,2020, we had derivative contracts covering a portion of our 20182021 and 20192022 production.  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 derivative positions from current levels.  See Note 4 to the Consolidated Financial Statements 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, 20172020 were $400.5$273.1 million.  At December 31, 2017,2020, our long-term debt consisted of $1.50$2.0 billion of senior unsecured notes, with $750 million 4.375% notes due in 2024, and $750 million 3.90% notes due in 2027.  During the second quarter of 2017, we completed a tender offer2027, and redemption of all of our $750$500 million 5.875%4.375% notes due in 2022 and issued the aforementioned 3.90% notes.2029.  At December 31, 2017,2020, we had no borrowings and $2.5 million in letters of credit outstanding under our credit facility, leaving an unused borrowing availability of $997.5 million.$1.248 billion.  See Long-Term Debt below for more information regarding our debt.
Our debt
In December 2020, we paid $43.0 million to total capitalization ratio at December 31, 2017 was 37%, downrepurchase 55% of the outstanding shares of our preferred stock and we may, from 42% at December 31, 2016.  This ratio is calculated by dividing the principal amounttime to time, seek to repurchase additional shares of long-term debt by the sum of (i) the principal amount of long-term debtour outstanding 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 (ii) total stockholders’ equity, with all numbers coming directly fromother factors. See Note 2 to the Consolidated Balance Sheet.  Management uses this ratio as one indicator ofFinancial Statements for information regarding our financial condition and believes professional research analysts and rating agencies use this ratio for this purpose and to compare our financial condition to other companies’ financial conditions.  Additionally, our credit facility includes a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%.preferred stock.

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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 2018 and beyond.for the next twelve months.

Analysis of Cash Flow Changes

The following table presents the totals of the major cash flow classification categories from our Consolidated Statements of Cash Flows for the periods indicated.

 Years Ended December 31,
(in thousands)20202019
Net cash provided by operating activities$904,167 $1,343,966 
Net cash used by investing activities$(578,875)$(1,577,882)
Net cash used by financing activities$(146,869)$(472,028)


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  Years Ended December 31,
(in thousands) 2017 2016 2015
Net cash provided by operating activities $1,096,564
 $625,849
 $725,728
Net cash used by investing activities $(1,265,897) $(692,410) $(1,008,605)
Net cash (used) provided by financing activities $(83,009) $(59,945) $656,397
Net cash provided by operating activities in 20172020 was $1.10 billion, up $470.7$904.2 million, down $439.8 million, or 75%33%, from $625.8 million for 2016.$1.34 billion in 2019. The increase was primarily a result of higher revenue due to higher realized prices and production volumes in 2017. This increase was partially offset by increased operating expenses and an increased investment in working capital. In 2016, net cash provided by operating activities was $99.9 million, or 14%, lower than 2015, resultingdecrease resulted primarily from a decrease in revenuerevenues due to lower realized pricesthe price collapses and production volumesdemand destruction seen in 2016.2020 as a result of the COVID-19 pandemic and actions of OPEC and other countries. This decrease was partially offset by lowerby: (i) increased cash inflows for settlements of derivative instruments, (ii) decreased overall operating costsexpenses (e.g. production, taxes other than income, and transportation, processing, and other operating expenses) primarily as a result of decreased activity, production, and revenues, and (iii) a decreased investment in working capital. See RESULTS OF OPERATIONS above for more information regarding year-over-yearthe changes in revenue and operating expenses.

In 2017,Net cash used by investing activities was $578.9 million and $1.58 billion in 2020 and 2019, respectively. The majority of our cash flows used by investing activities are for oil and gas capital expenditures, which totaled $594.8 million and $1.25 billion in 2020 and 2019, respectively. Our 2020 oil and gas capital expenditures decreased as compared to 2019 due to deliberate actions taken by us to reduce our capital investment in response to the decline in oil prices and demand experienced in 2020. Net cash used by investing activities also includes net cash outflows for oil and gas property acquisitions, which were minimal in 2020 at $11.9 million, but in 2019 included the $325.7 million cash portion of the consideration paid for the Resolute acquisition, net of the $41.2 million in cash acquired with Resolute. Our other capital expenditures, which are primarily for midstream assets, were $44.3 million and $73.7 million in 2020 and 2019, respectively, with 2020 decreasing due to the overall decrease in capital investments in 2020. Included in net cash used by investing activities was $1.27 billion, compared to $692.4are proceeds from other asset sales, which are generally for the divestiture of non-strategic oil and gas properties and totaled $72.1 million and $1.01 billion in 2016 and 2015, respectively. Prevailing commodity prices have a significant impact on the amount of cash flow available to invest in E&D activities, which comprise the majority of our cash used by investing activities. Our E&D capital expenditures, as reflected in the statements of cash flows, were $1.23 billion, $699.6 million, and $979.0$30.0 million in 2017, 2016,2020 and 2015,2019, respectively. OurProceeds from other capital expenditures were $45.4 million, $22.2 million, and $70.6 million in 2017, 2016, and 2015, respectively. These other capital expenditures are primarily for our gathering facilities. Capital expenditures were partially offset by proceeds from asset sales in 2020 included net cash proceeds of $12.6$68.7 million $29.4 million, and $41.0 millionfrom the sale of certain water infrastructure assets in 2017, 2016, and 2015, respectively. From time-to-time we sell interests in various non-core assets.Eddy County, New Mexico.

Net cash used by financing activities in 2017 was $83.0$146.9 million and includes $772.9$472.0 million used for the early extinguishmentin 2020 and 2019, respectively. During 2020, we paid $43.0 million to repurchase some of the $750our outstanding preferred stock. During 2020, we borrowed and repaid an aggregate of $172.0 million 5.875%on our credit facility to meet cash requirements as needed. During 2020, we amended our credit facility, paying $1.5 million in financing costs. During 2019, we issued $500.0 million aggregate principal amount of 4.375% senior unsecured notes due 2022, which included $22.6March 15, 2029 at 99.862% of par for proceeds of $499.3 million, paying $4.6 million in underwriting fees and financing costs. Additionally in 2019, we borrowed and repaid an aggregate of tender$2.12 billion on our credit facility to assist in funding the Resolute acquisition and redemption premiums.  Additionally,thereafter to meet cash requirements as needed. In connection with the 2017 period includes $741.8acquisition of Resolute, we assumed $870.0 million proceeds, netin principal amount of underwriters’ fees, discount, and issuance costs,long-term debt that we received for the issuanceimmediately repaid, incurring a redemption fee of $750$4.3 million. During 2019, we amended our credit facility, paying $3.0 million 3.90% senior notes due 2027.  The other primary components of netin financing costs. Net cash used by financing activities in 2017 areduring both years included: (i) the payment of dividends, of $30.5 million (consisting of four quarterly $0.08 per share dividends) and(ii) the payment of $21.7 million of income tax withholdings made on behalf of our employees upon the net settlement of employeeequity-classified stock awards.  Netawards, and (iii) finance lease payments. During 2020 and 2019, we declared cash used by financing activitiesdividends on both our common and preferred stock quarterly, paying them in 2016 of $59.9 million consisted primarily of $38.0 million of dividendsthe quarter following declaration. During 2020, we paid (consisting of one quarterly dividend of $0.16$0.20 per share dividend and three quarterly$0.22 per share dividends on our common stock and four $20.3125 per share dividends on our preferred stock, totaling $93.0 million. During 2019, we paid one $0.18 per share dividend and three $0.20 per share dividends on our common stock and three $20.3125 per share dividends on our preferred stock, totaling $81.7 million. Future dividend payments will depend on our level of $0.08 per share)earnings, financial requirements, and the paymentother factors considered relevant by our Board of $26.6 million ofDirectors. We paid employee income tax withholdings made on behalf of our employees upon the net settlement of employeeequity-classified stock awards. Net cash provided by financing activitiesawards totaling $4.5 million and $5.2 million in 2015 was $656.42020 and 2019, respectively. We paid finance lease payments of $4.8 million which was comprised primarily of $729.5and $3.9 million of net proceeds from the sale of common stockin 2020 and $8.5 million of proceeds from the exercise of stock options. These sources of cash were partially offset by $58.3 million of dividends paid (consisting of four quarterly dividends of $0.16 per share) and the payment of $21.2 million of income tax withholdings made on behalf of our employees upon the net settlement of employee stock awards.2019, respectively.


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Capital Expenditures

The following table reflectspresents capitalized expenditures for oil and gas acquisitions,property acquisition, exploration, and development activities, net of property sales:activities.

 Years Ended December 31,
(in thousands)20202019
Acquisitions:  
Proved$11,878 $695,450 
Unproved— 1,025,376 
 11,878 1,720,826 
Exploration and development:  
Land and seismic48,468 60,175 
Exploration and development496,388 1,181,605 
 544,856 1,241,780 
Total acquisition, exploration, and development capital expenditures$556,734 $2,962,606 
  Years Ended December 31,
(in thousands) 2017 2016 2015
Acquisitions:  
  
  
Proved $938
 $2,678
 $30
Unproved 6,853
 11,865
 6,666
Net purchase price adjustments (1) —
 —
 (11,653)
  7,791
 14,543
 (4,957)
Exploration and development:  
  
  
Land and seismic 140,516
 61,870
 52,049
Exploration —
 40
 1,073
Development 1,140,548
 672,842
 823,830
  1,281,064
 734,752
 876,952
Property sales (11,680) (24,687) (41,276)
  $1,277,175
 $724,608
 $830,719

 ________________________________________
(1)  The 2015 net purchase price adjustments relate to acquisitions occurring prior to 2015.
Capital expendituresAmounts in the table above are presented on an accrual basis. Oil and gas capital expenditures and salesacquisitions of oil and gas assetsproperties in the Consolidated Statements of Cash Flows reflect capital expendituresactivities on a cash basis, when payments are madebasis.

On March 1, 2019, we completed the acquisition of Resolute. The fair value of the proved and proceeds received.unproved properties recorded in the purchase price allocation for this acquisition was $1.72 billion.

BecauseOur 2020 total capital expenditures were originally forecast to range from $1.25-$1.35 billion, with the majority expected to be invested in the Permian Basin. In response to the decline in oil prices in the second quarter 2020, we took immediate steps to reduce our capital investment, including releasing all but one drilling rig by mid-May and deferring well completion activity. This resulted in total acquisition, exploration, and development capital expenditures for 2020 of higher commodity prices, we increased our 2017 E&D expenditures 74% to $1.28 billion compared to $734.8 million in 2016.$556.7 million. Approximately 59%92% of our 2017 E&D2020 exploration and development expenditures were in the Permian Basin and 39%8% were in our Mid-Continent region.the Mid-Continent. During 2017,2020, we completed or participated in the completion of 319149 gross (98.0(51.0 net) productive wells, of which we operated 11861 gross (77.7(47.6 net) wells. With the subsequent improvement in oil prices, we exited 2020 running five drilling rigs and completing wells with one completion crew. See Items 1 and 2 of this report for further information regarding our oil and gas properties.

Approximately 70%In 2020, the level of our planned 2018 E&D capital investment of $1.6 billion to $1.7 billion is expected to be invested in the Permian Basin and most of the remainder in the Mid-Continent region.
As has been our historical practice, we regularly review 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.
was less than our cash flow from operating activities, which allowed us to build our cash balance and not incur any incremental borrowings. We intend to fund our 20182021 capital investment program with cash flow from our operating activities and cash on hand. Salespotential sales of non-core assets and borrowings under our Credit Facility may also be used to supplement funding of capital expenditures.non-strategic assets. 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 Facilitycredit facility from time-to-time. Based on current economic conditions, our 2021 total capital expenditures are projected to range from $650 million to $750 million.  This includes drilling and completion capital of approximately $500 million to $600 million, investments in saltwater disposal/midstream infrastructure of approximately $40 million, and investments in other, including capitalized G&A and non-producing leasehold, of approximately $110 million. Over 90% of our planned 2021 drilling and completion capital is expected to be invested in the Permian Basin, with the remainder in the Mid-Continent. We regularly review our capital expenditures throughout the year and will adjust our investments based on increases or decreases in our cash flow. See Long-Term Debt—Bank Debt below for further information regarding our credit facility.


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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 orand 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 legislative or regulatory changes that would have a material impact, based on current laws and regulations.impact.  However, compliance with new legislation orand regulations could increase our costs or adverselyand negatively affect demand for oil or gas and result in a material adverse effect on our financial position or operations.  See Item 1A RISK FACTORS for a description of risks related to current and potential future environmental and safety regulations and requirements that could adversely affect our operations and financial condition.

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Long-Term Debt

Long-term debt at December 31, 20172020 and 20162019 consisted of the following:

  December 31, 2017 December 31, 2016
(in thousands)

 Principal 
Unamortized Debt
Issuance Costs and Discount (1)
 
Long-term
Debt, net
 Principal 
Unamortized Debt
Issuance Costs
 
Long-term
Debt, net
5.875% Senior Notes $—
 $—
 $—
 $750,000
 $(5,691) $744,309
4.375% Senior Notes 750,000
 (5,383) 744,617
 750,000
 (6,370) 743,630
3.90% Senior Notes 750,000
 (7,697) 742,303
 —
 —
 —
Total long-term debt $1,500,000
 $(13,080) $1,486,920
 $1,500,000
 $(12,061) $1,487,939
 December 31, 2020December 31, 2019
(in thousands)

PrincipalUnamortized Debt
Issuance Costs and Discounts (1)		Long-term
Debt, net		PrincipalUnamortized Debt
Issuance Costs and Discounts (1)		Long-term
Debt, net
4.375% notes due 2024$750,000 $(2,672)$747,328 $750,000 $(3,535)$746,465 
3.90% notes due 2027750,000 (5,541)744,459 750,000 (6,289)743,711 
4.375% notes due 2029500,000 (4,488)495,512 500,000 (4,930)495,070 
Total long-term debt$2,000,000 $(12,701)$1,987,299 $2,000,000 $(14,754)$1,985,246 
 ________________________________________
(1)At December 31, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.9 million and $1.8 million, respectively.  The 4.375% notes were issued at par.
(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, 2020, the unamortized debt issuance costs and discount related to the 3.90% notes due 2027 were $4.3 million and $1.3 million, respectively. At December 31, 2020, the unamortized debt issuance costs and discount related to the 4.375% notes due 2029 were $3.9 million and $0.6 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% notes due 2027 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.

Bank Debt

In October 2015,On June 3, 2020, we entered into a newthe First Amendment to Amended and Restated Credit Agreement (the “First Amendment”) dated as of February 5, 2019 for our senior unsecured revolving credit facility (“Credit Facility”) which matures October 16, 2020.. The Credit Facility has aggregate commitments of $1.0$1.25 billion with an option for us to increase the aggregate commitments to $1.25$1.5 billion, at any time.and matures on 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. The First Amendment, among other things: (i) allows up to $3.5 billion of non-cash impairment charge add-backs to Shareholders’ Equity for covenant calculation purposes, (ii) institutes traditional anti-cash hoarding provisions (if borrowings are outstanding under the Credit Facility) at a consolidated cash threshold of $175.0 million, (iii) reduces the priority lien debt basket from 15% of Consolidated Net Tangible Assets (as defined in the credit agreement) to a $50.0 million cap, and (iv) adds an acknowledgement and consent to European Union bail-in legislation. As of December 31, 2017,2020, we had no 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, 2020, we borrowed and repaid an aggregate of $172.0 million on the Credit Facility to meet cash requirements as needed.


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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.

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-capitaldebt-to-capitalization ratio of no greater than 65%. As of December 31, 2017,2020, we were in compliance with all of the financial and non-financial covenants.

At December 31, 20172020 and 2016,2019, we had $3.4$4.3 million and $4.5$4.0 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, thatwhich were recorded as deferred assets and included in Other assets, net“Other assets” in our balance sheets.Consolidated Balance Sheets. During the year ended December 31, 2020, we incurred $1.5 million in fees paid to the lenders and third-party costs for the First Amendment. The debt issuance costs are being amortized to interest expense ratably over the life of the Credit Facility.

Senior Notes

On April 10, 2017,March 8, 2019, we completed a cash tender offer to purchase any of our 5.875% senior unsecured notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5issued $500 million aggregate principal amount of the4.375% senior unsecured notes validly tendered.  We settledat 99.862% of par to yield 4.392% per annum. The notes are due March 15, 2029 and interest is payable semiannually on March 15 and September 15. The effective interest rate on these tendered notes, for $268.1 million, including accrued interest.  On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including the redemption date, settling the notes for $512.0 million, including accrued interest.  We recognized a loss on early extinguishmentamortization of debt related to these transactions of $28.2 million, composed primarily of tenderissuance costs and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.  The original maturity date of the 5.875% notes was May 1, 2022.discount, is 4.50%.
On
In 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.  TheThese notes bear an annual interest rate of 3.90%are due May 15, 2027 and interest is payable semiannually on May 15 and November 15, with15.  The effective interest rate on these notes, including the first payment occurring November 15, 2017.  Along with cash on hand, we used the proceeds to fund the settlementamortization of the tendereddebt issuance costs and redeemed 5.875% notes. discount, is 4.01%.

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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 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
Our senior unsecured notes isare governed by an indentureindentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of December 31, 2017. The effective interest rate on the 4.375% notes and the 3.90% notes, including the amortization2020.


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Table of debt issuance costs and discount, as applicable, is 4.50% and 4.01%, respectively.Contents

Working Capital Analysis

At December 31, 2020, we had a working capital deficit of $2.9 million, a change of $134.2 million, or 98% from a working capital deficit of $137.1 million at December 31, 2019. Our working capital fluctuatesdeficit decreased 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, and changes in the carrying value of our derivative instruments.
At December 31, 2017, we had working capital of $256.1 million, a decrease of $190.9 million, or 43%, compared to working capital of $447.0 million at December 31, 2016.
Working capital decreases consisted primarily of the following:


Working Capital Increases

•Cash and cash equivalents decreased $252.3 million.increased by $178.4 million as a result of maintaining capital expenditures at a level below our cash flows from operations in order to increase cash on our balance sheet, which we plan to use to initially target debt reduction and continue to fund and increase our regular common stock cash dividend.

•Operations-related accounts payable and accrued liabilities increased $131.1 million.
Accrued liabilities related to our E&D expenditures increased $33.4 million.
Decreases in working capital were partially offsetdecreased by the following primary increases:
•Operations-related accounts receivable increased $185.6 million.
•Net derivative instrument current liability decreased $22.5 million.
•Oil and gas well equipment and supplies increased $16.4 million.
Cash on hand was used during 2017, along with cash flow from operations, primarily to fund our capital expenditures.  Accounts receivable are a major component of our working capital and include a diverse group of companies comprised of major energy companies, pipeline companies, local distribution companies, and other end-users.  Historically, losses associated with uncollectible receivables have not been significant.  Our accounts receivable and operations-related accounts payable and accrued liabilities have increased$153.4 million, primarily due to increased commoditydecreases in: (i) revenue payable due to declines in revenues, (ii) taxes other than income accruals due to decreased prices causing lower production and ad valorem taxes, (iii) trade accounts payable due to decreased activity, and (iv) current asset retirement obligations due to changes in the estimated timing of retirement activities.

•Exploration and development and midstream capital accruals decreased by $66.6 million as a result of our decision to reduce capital expenditures in response to the decline in oil prices and production volumes, as well as duedemand.

Working Capital Decreases

•A decrease of $139.8 million from a net current derivative asset to increased E&D activity. Our accrued liabilities related to our E&D expenditures also increased due to increased E&D activity.a net current derivative liability. The fair value of derivative instruments fluctuates based on changes in the underlying price indices as compared to the contracted prices included in the derivative instruments.

•Accounts receivable decreased by $116.1 million, primarily due to declines in prices lowering our oil and gas sales receivable.

•Oil and gas well equipment and supplies decreased by $10.7 million.

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. 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. For properties we operate, we have the right to realize amounts due to us from non-operators by netting the non-operators’ share of production revenues from those properties. We routinely assess the recoverability of all material accounts receivable and accrue a reserve to the allowance for credit losses based on our estimation of expected losses over the life of the receivables. Historically, losses associated with uncollectible receivables have not been significant. However, most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry, such as those currently impacting the industry as a result of the COVID-19 pandemic and low commodity prices.


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Dividends

A quarterly cash dividend has been paid to stockholderson our common stock every quarter since the first quarter of 2006. In February 2016, the quarterly dividendDuring 2020, our Board of Directors declared was decreased to $0.08four cash dividends of $0.22 per common share, where it has remained through the fourth quartertotaling approximately $90.0 million. During 2020, our Board of 2017, from $0.16Directors declared four cash dividends of $20.3125 per share.preferred share, totaling approximately $4.9 million. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors. See Note 2 to the Consolidated Financial Statements for further information regarding dividends.our stock.

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, 2017,2020, our material off-balance sheet arrangements consisted of operating lease agreements which are includedfor equipment used in connection with our exploration and development activities with lease terms at commencement of 12 months or less. As an accounting policy, we have elected not to apply the table below.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, 2017,2020, we had the following contractual obligations and material commitments:

Payments Due by Period
 Payments Due by Period
Contractual obligations (in thousands):
 Total 1 Year or Less 
2-3
Years
 
4-5
Years
 More than 5 Years 
Long-term debt-principal (1)
 $1,500,000
 $—
 $—
 $—
 $1,500,000
 
Long-term debt-interest (1)
 491,075
 60,844
 124,125
 124,125
 181,981
 
Contractual obligations
(in thousands)
Contractual obligations
(in thousands)
Total 1/1/21 - 12/31/21 1/1/22 - 12/31/23 1/1/24 - 12/31/25 1/1/26 and Thereafter 
Long-term debt - principal (1)Long-term debt - principal (1)$2,000,000  $—  $—  $750,000  $1,250,000  
Long-term debt - interest (1)Long-term debt - interest (1)490,967  81,868  167,875  118,656  122,568  
Operating leases (2)
 94,676
 15,410
 24,346
 22,275
 32,645
 Operating leases (2)101,749  27,255  31,736  23,687  19,071  
Unconditional purchase obligations (3)
 38,269
 8,943
 9,469
 8,675
 11,182
 Unconditional purchase obligations (3)18,903  7,854  6,167  4,882  —  
Derivative liabilities 46,334
 42,066
 4,268
 —
 —
 Derivative liabilities163,147  145,398  17,749  —  —  
Asset retirement obligation (4)
 169,469
 11,048
 —
(4)—
(4)—
(4)Asset retirement obligation (4)177,867  12,272  — (4)— (4)— (4)
Other long-term liabilities (5)
 35,280
 1,844
 3,320
 2,855
 27,261
 Other long-term liabilities (5)49,318  4,460  11,028  10,324  23,506  
 $2,375,103
 $140,155
 $165,528
 $157,930
 $1,753,069
  $3,001,951  $279,107  $234,555  $907,549  $1,415,145  
 ________________________________________
(1)The interest payments presented above include the accrued interest payable on our long-term debt as of December 31, 2017 as well as future payments calculated using the long-term debt’s fixed rates and principal amounts outstanding as of December 31, 2017.  See Note 3 to the Consolidated Financial Statements for additional information regarding our debt.
(2)Operating leases include various commitments for office space and compressor equipment.
(3)Of the total Unconditional purchase obligations, $36.5 million represents obligations for firm transportation agreements for 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 in the “1 Year or Less” column.
(1)The interest payments presented above include the accrued interest payable on our long-term debt as of December 31, 2020 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, 2020.  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, 2020. 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, $2.3 million represents obligations for the purchase of sand for well completions and $16.6 million represents obligations for firm transportation agreements for gas pipeline capacity. 
(4)We have excluded the presentation of the timing of the cash flows associated with our $165.6 million 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

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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 whichmade that may include potential future cash payments if we fail to meet various performance obligations.  These are not reflected in the table above. above, unless otherwise noted.

At December 31, 2017,2020, we had estimated commitments of approximately: (i) $252.6$224.2 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $33.3$4.3 million to finish gathering systemmidstream construction in progress.

At December 31, 2017,2020, we had firm sales contracts to deliver approximately 217.6470.3 Bcf of natural gas over the next 7.110.5 years.  If we do not deliver this gas, our estimated financial commitment, calculated using the January 20182021 index price,prices, would be approximately $476.7$908.1 million.  The value of this commitment will fluctuate due to price volatility and actual volumes delivered.  However, we believe no material financial commitment will be due based on our current proved reserves and production levels and our ability to make market purchases to fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next 8.0 years.  If we do not deliver the committed gas or NGLs, as applicable, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2020, would be approximately $640.7 million.  However, we believe no material 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 8.3 years.  If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2017, would be approximately $298.3 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 associated with agreements to reimburse connection costs to various pipelines.  If we do not deliver this gas or oil, as applicable, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2017,2020, would be approximately $11.4$104.7 million.  Of this total, we have accrued a liability of $4.3 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points. This accrual is reflected in the table above in Other long-term liabilities.

We have minimum volume water delivery commitments associated with a water services agreement, which ends in 2030, that was entered into in connection with the sale of certain water infrastructure assets in Eddy County, New Mexico (see Note 13 to the Consolidated Financial Statements for further information regarding this sale). If the water volumes are not delivered by us or third parties, the estimated maximum amount that would be payable by us under this commitment, calculated as of December 31, 2020, would be approximately $64.1 million. However, we believe no material financial commitment will be due based on our current proved reservesforecasted volumes of water delivery and production levels from which we can fulfill these volumetric obligations.potential delivery of water volumes by third parties.

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

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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.



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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. 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.

Our significant accounting policies are described in Note 1 to our Consolidated Financial 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 decisionsjudgment and interpretation 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 2017, 17%2020, 16% of our total proved reserves are categorized as proved undeveloped 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.charge. See Full Cost Accounting below for further information regarding the ceiling limitation calculation. See SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) in Item 8 for additional reserve data.

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 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.

Under the full cost method of accounting, we are required to perform quarterly ceiling test calculations to test our oil and gas properties for possible impairment.  If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense.  The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net 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, as adjusted for income taxes.  We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing

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twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.


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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 may incur a full cost ceiling test impairments in future quarters.impairment.  The calculated ceiling 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 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.

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.

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.

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 to the Consolidated Financial Statements for additional information regarding our income taxes.

Recently Issued Accounting Standards
See Note 1 to the Consolidated Financial Statements for a discussion of recent accounting pronouncements and their anticipated effect on our business.



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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk including the risk of loss arising from adverse changes in commodity prices and interest rates.

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. During 2017,2020, our total production revenue was comprised of 52%66% oil sales, 28%16% gas sales, and 20%18% NGL sales. The following table shows how hypothetical changes in the realized prices we receive for our commodity sales wouldmay have impacted revenue for the periodsperiod indicated. See MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Market Conditions for further information regarding prices.


Impact on Revenue
Change in Realized PriceYear Ended

December 31, 20172020
(in thousands)
Oil± $1.00per barrel± $20,861$28,087
Gas± $0.10per Mcf± $18,747$23,263
NGL± $1.00per barrel± $17,374$25,554
± $56,982$76,904


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, 2017,2020, we had oil and gas derivatives covering a portion of our 20182021 and 20192022 production, which were recorded as current and non-current assets and liabilities.liabilities on our Consolidated Balance Sheet. At December 31, 2017, these2020, our oil and gas derivatives had a gross asset fair value of $17.2$9.2 million and a gross liability fair value of $46.3$163.1 million. See Note 4 to the Consolidated Financial Statements for additional information regarding our derivative instruments.

While these contracts limit the downside risk of adverse price movements, they may also limit future cash flow from favorable price movements. The following table shows how a hypothetical changes± 10% change in the underlying forward prices used to calculate the fair value of our derivatives wouldmay have impacted the fair value as of December 31, 2017.2020.

Impact on Fair Value
Change in Forward PriceDecember 31, 2020
(in thousands)
Oil-10%$71,853 
Oil+10%$(74,237)
Gas-10%$23,760 
Gas+10%$(24,515)


62
    Impact on Fair Value
  Change in Forward Price December 31, 2017
    (in thousands)
Oil -$1.00 $7,288
Oil +$1.00 $(7,528)
Gas -$0.10 $5,388
Gas +$0.10 $(5,160)
Table of Contents

Interest Rate Risk

At December 31, 2017,2020, our long-term debt consisted of $750 million of 4.375% senior unsecured notes that will mature on June 1, 2024, and $750 million of 3.90% senior unsecured notes that will mature on May 15, 2027.2027, and $500 million of 4.375% senior unsecured notes 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. See Note 3 and Note 5 to the Consolidated Financial Statements 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
Report of Independent Registered Public Accounting Firm for the years ended December 31, 2017, 2016, and 2015
5865
Consolidated Balance Sheets as of December 31, 20172020 and 20162019
5967
Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended December 31, 2017, 2016,2020, 2019, and 20152018
6068
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016, 2020, 2019, and 20152018
6169
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2017, 2016, 2020, 2019, and 20152018
6270
Note 1 — Basis of Presentation and Summary of Significant Accounting Policies
6371
Note 2 — Capital Stock
6876
Note 3 — Long-Term Debt
6878
Note 4 — Derivative Instruments
6980
Note 5 — Fair Value Measurements
7485
Note 6 — Stock-Based and Other Compensation
7586
Note 7 — Earnings (Loss) per Share
7991
Note 8 — Asset Retirement Obligations
7992
Note 9 — Income Taxes
8093
Note 10 — Commitments and Contingencies
8195
Note 11 — Related Party Transactions
83100
Note 12 — Supplemental Cash Flow Information
83100
Note 13 — Acquisitions and Divestitures
101
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
84104
Supplemental Quarterly Financial Data (Unaudited)
90110
 
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
To the Stockholders and Board of Directors
Cimarex Energy Co.:

Opinion on the ConsolidatedFinancial Statements

We have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the “Company”)Company) as of December 31, 20172020 and 2016,2019, the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three‑yearthree-year period ended December 31, 2017,2020, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of   December 31, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the years in the three‑yearthree-year period ended December 31, 2017,2020, 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”)(PCAOB), the Company’s internal control over financial reporting as of December 31, 2017,2020, 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 23, 20182021 expressed an unqualified 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 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, 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 regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.


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Impact 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 for its proved oil and gas properties using the units-of-production method whereby capitalized costs, including estimated future development costs and asset retirement costs, are amortized over total estimated proved reserves. The Company is required to perform a ceiling test calculation on a quarterly basis, and the applicable ceiling limitation is equal to the 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, as adjusted for income taxes. If the net capitalized cost of oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. For the year ended December 31, 2020, the Company recorded depletion expense related to proved oil and gas properties of $625.5 million and recorded ceiling test impairments of $1,638.3 million. The Company’s internal Corporate Reservoir Engineering group prepares estimates of the Company’s 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 impact of the estimate of proved oil and gas reserves used in the determination of depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and gas reserves as auditor judgment was required to evaluate the assumptions used by the Company related to forecasts of production, future operating costs and future development costs, and oil and gas prices inclusive of market differentials.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the process for estimating oil and gas reserves for proved oil and gas properties, including controls over the development of the forecasts of production, future operating costs and future development costs, and oil and gas prices. We evaluated (1) the professional qualifications of the internal Corporate Reservoir Engineering group as well as the engineer assigned to the Company by the independent petroleum engineering consulting firm engaged by the Company, (2) the knowledge, skills, and ability of the Company’s internal Corporate Reservoir Engineering group and the independent petroleum engineering consulting firm and the engineer assigned to the Company and (3) the objectivity of the independent petroleum engineering consulting firm and the engineer assigned to 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 consistency with industry and regulatory standards. We evaluated the assumptions of forecasts of production, future operating costs and future development costs used by the Company’s internal Corporate Reservoir Engineering group by comparing them to the Company’s historical 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 the findings 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 impairment calculation for compliance with regulatory standards. In addition, we performed a calculation of the ceiling test impairment and compared our results with the Company’s results.

/s/ KPMG LLP


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

Denver, Colorado
February 23, 2018


2021
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CIMAREX ENERGY CO.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share information)

December 31, December 31,
2017 2016 20202019
Assets 
  
Assets  
Current assets: 
  
Current assets:  
Cash and cash equivalents$400,534
 $652,876
Cash and cash equivalents$273,145 $94,722 
Accounts receivable, net of allowance: 
  
Accounts receivable, net of allowance:  
Trade100,356
 42,287
Trade49,650 57,879 
Oil and gas sales344,552
 217,395
Oil and gas sales271,141 384,707 
Gas gathering, processing, and marketing15,266
 14,888
Gas gathering, processing, and marketing11,694 5,998 
Oil and gas well equipment and supplies49,722
 33,342
Oil and gas well equipment and supplies37,150 47,893 
Derivative instruments15,151
 —
Derivative instruments6,848 17,944 
Prepaid expenses8,518
 7,335
Prepaid expenses7,113 10,759 
Other current assets1,536
 1,181
Other current assets597 1,584 
Total current assets935,635
 969,304
Total current assets657,338 621,486 
Oil and gas properties at cost, using the full cost method of accounting: 
  
Oil and gas properties at cost, using the full cost method of accounting:  
Proved properties17,513,460
 16,225,495
Proved properties21,281,840 20,678,334 
Unproved properties and properties under development, not being amortized476,903
 478,277
Unproved properties and properties under development, not being amortized1,142,183 1,255,908 
��17,990,363
 16,703,772
22,424,023 21,934,242 
Less—accumulated depreciation, depletion, amortization, and impairment(14,748,833) (14,349,505)Less—accumulated depreciation, depletion, amortization, and impairment(18,987,354)(16,723,544)
Net oil and gas properties3,241,530
 2,354,267
Net oil and gas properties3,436,669 5,210,698 
Fixed assets, net of accumulated depreciation of $290,114 and $246,901, respectively210,922
 205,465
Fixed assets, net of accumulated depreciation of $455,815 and $389,458, respectivelyFixed assets, net of accumulated depreciation of $455,815 and $389,458, respectively436,101 519,291 
Goodwill620,232
 620,232
Goodwill0 716,865 
Derivative instruments2,086
 —
Derivative instruments2,342 580 
Deferred income taxes—
 55,835
Deferred income taxes20,472 0 
Other assets32,234
 32,621
Other assets69,067 71,109 
$5,042,639
 $4,237,724
 $4,621,989 $7,140,029 
Liabilities and Stockholders’ Equity 
  
Liabilities, Redeemable Preferred Stock, and Stockholders’ EquityLiabilities, Redeemable Preferred Stock, and Stockholders’ Equity  
Current liabilities: 
  
Current liabilities:  
Accounts payable: 
  
Accounts payable:  
Trade$68,883
 $49,163
Trade$21,902 $36,280 
Gas gathering, processing, and marketing29,503
 25,323
Gas gathering, processing, and marketing22,388 12,740 
Accrued liabilities: 
  
Accrued liabilities:  
Exploration and development115,762
 82,320
Exploration and development50,014 112,228 
Taxes other than income23,687
 18,766
Taxes other than income29,051 54,446 
Other212,400
 177,695
Other201,784 252,304 
Derivative instruments42,066
 49,370
Derivative instruments145,398 16,681 
Revenue payable187,273
 119,715
Revenue payable130,637 207,939 
Operating leasesOperating leases59,051 66,003 
Total current liabilities679,574
 522,352
Total current liabilities660,225 758,621 
Long-term debt: 
  
Long-term debt:  
Principal1,500,000
 1,500,000
Principal2,000,000 2,000,000 
Less—unamortized debt issuance costs and discount(13,080) (12,061)
Less—unamortized debt issuance costs and discountsLess—unamortized debt issuance costs and discounts(12,701)(14,754)
Long-term debt, net1,486,920
 1,487,939
Long-term debt, net1,987,299 1,985,246 
Deferred income taxes101,618
 —
Deferred income taxes0 338,424 
Asset retirement obligation158,421
 140,770
Asset retirement obligation165,595 154,045 
Derivative instruments4,268
 2,570
Derivative instruments17,749 1,018 
Operating leasesOperating leases134,705 184,172 
Other liabilities43,560
 41,104
Other liabilities66,181 60,742 
Total liabilities2,474,361
 2,194,735
Total liabilities3,031,754 3,482,268 
Commitments and contingencies (Note 10)

 

Commitments and contingencies (Note 10)00
Redeemable preferred stock - 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, $0.01 par value, 28,165 shares authorized and issued and 62,500 shares authorized and issued, respectively (Note 2)Redeemable preferred stock - 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, $0.01 par value, 28,165 shares authorized and issued and 62,500 shares authorized and issued, respectively (Note 2)36,781 81,620 
Stockholders’ equity: 
  
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, 95,437,434 and 95,123,525 shares issued, respectively954
 951
Common stock, $0.01 par value, 200,000,000 shares authorized, 102,866,806 and 102,144,577 shares issued, respectivelyCommon stock, $0.01 par value, 200,000,000 shares authorized, 102,866,806 and 102,144,577 shares issued, respectively1,029 1,021 
Additional paid-in capital2,764,384
 2,763,452
Additional paid-in capital3,211,562 3,243,325 
Retained earnings (accumulated deficit)(199,259) (722,359)
Accumulated other comprehensive income2,199
 945
(Accumulated deficit) retained earnings(Accumulated deficit) retained earnings(1,659,137)331,795 
Total stockholders’ equity2,568,278
 2,042,989
Total stockholders’ equity1,553,454 3,576,141 
$5,042,639
 $4,237,724
 $4,621,989 $7,140,029 
See accompanying notes to Consolidated Financial Statements.

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CIMAREX ENERGY CO.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(in thousands, except per share data)information)
 
 Years Ended December 31,
 202020192018
Revenues:   
Oil sales$999,682 $1,660,210 $1,398,813 
Gas and NGL sales513,006 661,711 898,832 
Gas gathering and other47,842 42,454 41,180 
Gas marketing(1,935)(1,406)192 
 1,558,595 2,362,969 2,339,017 
Costs and expenses:   
Impairment of oil and gas properties1,638,329 618,693 0 
Depreciation, depletion, and amortization695,954 882,173 590,473 
Asset retirement obligation14,653 8,586 7,142 
Impairment of goodwill714,447 0 0 
Production285,324 339,941 296,189 
Transportation, processing, and other operating213,366 238,259 211,463 
Gas gathering and other23,591 23,294 28,327 
Taxes other than income79,699 148,953 125,169 
General and administrative111,005 95,843 77,843 
Stock-based compensation29,895 26,398 22,895 
Loss (gain) on derivative instruments, net35,534 76,850 (85,959)
Other operating expense, net839 19,305 18,507 
 3,842,636 2,478,295 1,292,049 
Operating (loss) income(2,284,041)(115,326)1,046,968 
Other (income) and expense:   
Interest expense92,914 93,386 68,224 
Capitalized interest(50,030)(56,232)(20,855)
Loss on early extinguishment of debt0 4,250 0 
Other, net(540)(5,741)(22,908)
(Loss) income before income tax(2,326,385)(150,989)1,022,507 
Income tax (benefit) expense(358,927)(26,370)230,656 
Net (loss) income$(1,967,458)$(124,619)$791,851 
Earnings (loss) per share to common stockholders:   
Basic$(19.73)$(1.33)$8.32 
Diluted$(19.73)$(1.33)$8.32 
Comprehensive (loss) income:   
Net (loss) income$(1,967,458)$(124,619)$791,851 
Other comprehensive (loss) income:   
Change in fair value of investments, net of tax of $0, $(222), and $(425), respectively0 (755)(1,444)
Total comprehensive (loss) income$(1,967,458)$(125,374)$790,407 
 Years Ended December 31,
 2017 2016 2015
Revenues: 
  
  
Oil sales$981,646
 $632,934
 $809,664
Gas sales516,936
 388,786
 428,227
NGL sales375,421
 199,498
 179,647
Gas gathering and other43,751
 36,033
 34,688
Gas marketing495
 94
 393
 1,918,249
 1,257,345
 1,452,619
Costs and expenses: 
  
  
Impairment of oil and gas properties—
 757,670
 4,033,295
Depreciation, depletion, and amortization446,031
 392,348
 731,460
Asset retirement obligation15,624
 7,828
 9,121
Production262,180
 232,002
 299,374
Transportation, processing, and other operating231,640
 190,725
 182,362
Gas gathering and other35,840
 31,785
 38,138
Taxes other than income89,864
 61,946
 84,764
General and administrative79,996
 73,901
 74,688
Stock compensation26,256
 24,523
 19,559
(Gain) loss on derivative instruments, net(21,210) 55,749
 (11,246)
Other operating expense, net1,314
 755
 856
 1,167,535
 1,829,232
 5,462,371
Operating income (loss)750,714
 (571,887) (4,009,752)
Other (income) and expense: 
  
  
Interest expense74,821
 83,272
 85,746
Capitalized interest(22,948) (21,248) (30,589)
Loss on early extinguishment of debt28,187
 —
 —
Other, net(11,342) (10,707) (13,576)
Income (loss) before income tax681,996
 (623,204) (4,051,333)
Income tax expense (benefit)187,667
 (214,401) (1,471,729)
Net income (loss)$494,329
 $(408,803) $(2,579,604)
      
Earnings (loss) per share to common stockholders: 
  
  
Basic$5.19
 $(4.38) $(27.75)
Diluted$5.19
 $(4.38) $(27.75)
      
Dividends declared per share$0.32
 $0.32
 $0.64
      
Comprehensive income (loss): 
  
  
Net income (loss)$494,329
 $(408,803) $(2,579,604)
Other comprehensive income (loss): 
  
  
Change in fair value of investments, net of tax of $106, $289, and ($380), respectively1,254
 504
 (661)
Total comprehensive income (loss)$495,583
 $(408,299) $(2,580,265)






See accompanying notes to Consolidated Financial Statements.

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CIMAREX ENERGY CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
 Years Ended December 31,
 202020192018
Cash flows from operating activities:   
Net (loss) income$(1,967,458)$(124,619)$791,851 
Adjustments to reconcile net (loss) income to net cash provided by operating activities:   
Impairment of oil and gas properties1,638,329 618,693 0 
Depreciation, depletion, and amortization695,954 882,173 590,473 
Asset retirement obligation14,653 8,586 7,142 
Impairment of goodwill714,447 0 0 
Deferred income taxes(358,896)(26,902)233,280 
Stock-based compensation29,895 26,398 22,895 
Loss (gain) on derivative instruments, net35,534 76,850 (85,959)
Settlements on derivative instruments119,247 (13,131)(24,429)
Loss on early extinguishment of debt0 4,250 0 
Changes in non-current assets and liabilities7,189 (2,797)(1,779)
Other, net15,305 14,639 105 
Changes in operating assets and liabilities:   
Accounts receivable116,492 65,128 5,421 
Other current assets5,134 (739)(1,957)
Accounts payable and other current liabilities(161,658)(184,563)13,951 
Net cash provided by operating activities904,167 1,343,966 1,550,994 
Cash flows from investing activities:   
Oil and gas capital expenditures(594,796)(1,245,457)(1,540,305)
Acquisition of oil and gas properties(11,878)(288,781)(26,278)
Other capital expenditures(44,302)(73,693)(103,459)
Sales of oil and gas assets69,983 28,945 580,652 
Sales of other assets2,118 1,104 3,772 
Net cash used by investing activities(578,875)(1,577,882)(1,085,618)
Cash flows from financing activities:   
Borrowings of long-term debt172,000 2,619,310 0 
Repayments of long-term debt(172,000)(2,990,000)0 
Financing, underwriting, and debt redemption fees(1,566)(11,798)(100)
Finance lease payments(4,842)(3,869)0 
Dividends paid(92,976)(81,709)(55,243)
Repurchase of redeemable preferred stock(43,029)0 0 
Employee withholding taxes paid upon the net settlement of equity-classified stock awards(4,456)(5,229)(12,142)
Proceeds from exercise of stock options0 1,267 2,241 
Net cash used by financing activities(146,869)(472,028)(65,244)
Net change in cash and cash equivalents178,423 (705,944)400,132 
Cash and cash equivalents at beginning of period94,722 800,666 400,534 
Cash and cash equivalents at end of period$273,145 $94,722 $800,666 
 Years Ended December 31,
 2017 2016 2015
Cash flows from operating activities: 
  
  
Net income (loss)$494,329
 $(408,803) $(2,579,604)
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
  
  
Impairment of oil and gas properties—
 757,670
 4,033,295
Depreciation, depletion, and amortization446,031
 392,348
 731,460
Asset retirement obligation15,624
 7,828
 9,121
Deferred income taxes190,479
 (213,286) (1,486,439)
Stock compensation26,256
 24,523
 19,559
(Gain) loss on derivative instruments, net(21,210) 55,749
 (11,246)
Settlements on derivative instruments(1,633) 7,437
 —
Loss on early extinguishment of debt28,187
 —
 —
Changes in non-current assets and liabilities1,891
 3,867
 23,230
Other, net5,677
 1,805
 4,206
Changes in operating assets and liabilities: 
  
  
Accounts receivable(186,157) (49,340) 186,699
Other current assets(17,931) 20,880
 37,954
Accounts payable and other current liabilities115,021
 25,171
 (242,507)
Net cash provided by operating activities1,096,564
 625,849
 725,728
Cash flows from investing activities: 
  
  
Oil and gas capital expenditures(1,233,126) (699,558) (979,044)
Other capital expenditures(45,352) (22,228) (70,592)
Sales of oil and gas assets11,680
 21,487
 39,853
Sales of other assets901
 7,889
 1,178
Net cash used by investing activities(1,265,897) (692,410) (1,008,605)
Cash flows from financing activities: 
  
  
Borrowings of long-term debt748,110
 —
 —
Repayments of long-term debt(750,000) —
 —
Proceeds from sale of common stock—
 —
 752,100
Financing and underwriting fees(29,312) (101) (24,633)
Dividends paid(30,532) (38,024) (58,281)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards(21,669) (26,624) (21,240)
Proceeds from exercise of stock options394
 4,804
 8,451
Net cash (used) provided by financing activities(83,009) (59,945) 656,397
Net change in cash and cash equivalents(252,342) (126,506) 373,520
Cash and cash equivalents at beginning of period652,876
 779,382
 405,862
Cash and cash equivalents at end of period$400,534
 $652,876
 $779,382



See accompanying notes to Consolidated Financial Statements.

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CIMAREX ENERGY CO.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)thousands, except per share information)

Additional Paid-in CapitalRetained
Earnings (Accumulated Deficit)		Accumulated
Other Comprehensive Income (Loss)		Total Stockholders’ Equity
      
Retained
Earnings (Accumulated Deficit)
 
Accumulated
Other Comprehensive Income (Loss)
 Total Stockholders’ Equity Common Stock
Common Stock Additional Paid-in Capital  SharesAmount
Shares Amount 
Retained
Earnings (Accumulated Deficit)
Accumulated
Other Comprehensive Income (Loss)
Balance, December 31, 201487,592
 $876
 $1,997,080
 $2,332,909
$1,102
$4,331,967
Balance, December 31, 2017Balance, December 31, 201795,437 $954 $2,764,384 $(199,259)$2,199 $2,568,278 
Dividends paid on stock awards subsequently forfeited—
 —
 —
 109
 —
 109
Dividends paid on stock awards subsequently forfeited— — 34 18 — 52 
Dividends—
 —
 —
 (59,422) —
 (59,422)
Net loss—
 —
 —
 (2,579,604) —
 (2,579,604)
Unrealized change in fair value of investments, net of tax—
 —
 —
 —
 (661) (661)
Issuance of common stock6,900
 69
 729,468
 —
 —
 729,537
Issuance of restricted stock awards471
 5
 (5) —
 —
 —
Common stock reacquired and retired(194) (2) (21,238) —
 —
 (21,240)
Restricted stock forfeited and retired(90) (1) 1
 —
 —
 —
Exercise of stock options142
 1
 8,450
 —
 —
 8,451
Stock-based compensation—
 —
 36,232
 —
 —
 36,232
Stock-based compensation tax benefit—
 —
 12,988
 —
 —
 12,988
Balance, December 31, 201594,821
 948
 2,762,976
 (306,008) 441
 2,458,357
Dividends paid on stock awards subsequently forfeited—
 —
 2
 35
 —
 37
Dividends—
 —
 —
 (7,583) —
 (7,583)
Dividends in excess of retained earnings—
 —
 (22,805) —
 —
 (22,805)
Net loss—
 —
 —
 (408,803) —
 (408,803)
Unrealized change in fair value of investments, net of tax—
 —
 —
 —
 504
 504
Issuance of restricted stock awards479
 5
 (5) —
 —
 —
Common stock reacquired and retired(208) (3) (26,622) —
 —
 (26,625)
Restricted stock forfeited and retired(32) —
 —
 —
 —
 —
Exercise of stock options64
 1
 4,803
 —
 —
 4,804
Stock-based compensation—
 —
 45,103
 —
 —
 45,103
Balance, December 31, 201695,124
 951
 2,763,452
 (722,359) 945
 2,042,989
Dividends paid on stock awards subsequently forfeited—
 —
 11
 32
 —
 43
Dividends in excess of retained earnings—
 —
 (30,489) —
 —
 (30,489)
Dividends declared on common stock ($0.68 per share)Dividends declared on common stock ($0.68 per share)— — (15,196)(49,725)— (64,921)
Net income—
 —
 —
 494,329
 —
 494,329
Net income— — — 791,851 — 791,851 
Unrealized change in fair value of investments, net of tax—
 —
 —
 —
 1,254
 1,254
Unrealized change in fair value of investments, net of tax— — — — (1,444)(1,444)
Issuance of restricted stock awards552
 5
 (5) —
 —
 —
Issuance of restricted stock awards593 6 (6)— — 0 
Common stock reacquired and retired(204) (2) (21,667) —
 —
 (21,669)Common stock reacquired and retired(139)0 (12,142)— — (12,142)
Restricted stock forfeited and retired(41) —
 —
 —
 —
 —
Restricted stock forfeited or canceled and retiredRestricted stock forfeited or canceled and retired(168)(2)2 — — 0 
Exercise of stock options6
 —
 394
 —
 —
 394
Exercise of stock options33 — 2,241 — — 2,241 
Stock-based compensation—
 —
 48,321
 —
 —
 48,321
Stock-based compensation— — 45,871 — — 45,871 
Cumulative effect adjustment of adopting ASU 2016-09 (Note 6)—
 —
 4,393
 28,739
 —
 33,132
Other—
 —
 (26) —
 —
 (26)
Balance, December 31, 201795,437
 $954
 $2,764,384
 $(199,259) $2,199
 $2,568,278
Balance, December 31, 2018Balance, December 31, 201895,756 958 2,785,188 542,885 755 3,329,786 
Dividends paid on stock awards subsequently forfeitedDividends paid on stock awards subsequently forfeited— — 8 18 — 26 
Dividends declared on common stock ($0.80 per share)Dividends declared on common stock ($0.80 per share)— — 61 (81,411)— (81,350)
Dividends declared on redeemable preferred stock ($81.25 per share)Dividends declared on redeemable preferred stock ($81.25 per share)— — — (5,078)— (5,078)
Net lossNet loss— — — (124,619)— (124,619)
Issuance of stock for Resolute Energy acquisition (Note 13)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 taxUnrealized change in fair value of investments, net of tax— — — — (755)(755)
Issuance of restricted stock awardsIssuance of restricted stock awards946 9 (9)— — 0 
Common stock reacquired and retiredCommon stock reacquired and retired(105)(1)(5,228)— — (5,229)
Restricted stock forfeited or canceled and retiredRestricted stock forfeited or canceled and retired(133)(1)1 — — 0 
Exercise of stock optionsExercise of stock options29 — 1,267 — — 1,267 
Stock-based compensationStock-based compensation— — 49,078 — — 49,078 
Balance, December 31, 2019Balance, December 31, 2019102,145 1,021 3,243,325 331,795 0 3,576,141 
Dividends paid on stock awards subsequently forfeitedDividends paid on stock awards subsequently forfeited— — 32 124 — 156 
Dividends declared on common stock ($0.88 per share)Dividends declared on common stock ($0.88 per share)— — (67,658)(22,329)— (89,987)
Dividends declared on redeemable preferred stock ($81.25 per share)Dividends declared on redeemable preferred stock ($81.25 per share)— — (3,592)(1,269)— (4,861)
Return from repurchase of redeemable preferred stockReturn from repurchase of redeemable preferred stock— — 1,810 — — 1,810 
Net lossNet loss— — — (1,967,458)— (1,967,458)
Issuance of restricted stock awardsIssuance of restricted stock awards1,159 13 (13)— — 0 
Common stock reacquired and retiredCommon stock reacquired and retired(162)(2)(4,454)— — (4,456)
Restricted stock forfeited or canceled and retiredRestricted stock forfeited or canceled and retired(275)(3)3 — — 0 
Stock-based compensationStock-based compensation— — 42,109 — — 42,109 
Balance, December 31, 2020Balance, December 31, 2020102,867 $1,029 $3,211,562 $(1,659,137)$0 $1,553,454 



See accompanying notes to Consolidated Financial Statements.

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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 located entirely within the United States of America, mainly located in Texas, Oklahoma,New Mexico, and New Mexico.Oklahoma.

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. Certain amounts in the prior year financial statements have been reclassified to conform to the 20172020 financial statement presentation.

Segment Information

We have determined that our business is comprised of only one1 segment because our gathering, processing, and marketing activities are ancillary to our oil and gas production 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. Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, 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,credit losses, 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 decisionsjudgment and interpretation 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.

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

Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is based on estimated selling prices in the ordinary course of business, less reasonably


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predictable costs of completion, disposal, and transportation. Declines in the price of oil and gas well equipment and supplies in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.

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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.

Under the full cost method of accounting, we are required to perform quarterly ceiling test calculations to test our oil and gas properties for possible impairment.  If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense.  The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net 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, as adjusted for income taxes.  We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.

At December 31, 2017, 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 19% or more in the value of the ceiling limitation would have resulted in an impairment. ForDuring the years ended December 31, 20162020 and 2015, full year2019, we recognized ceiling test impairments totaled $757.7totaling $1.64 billion and $618.7 million, ($481.4 million, net of tax) and $4.03 billion ($2.56 billion, net of tax), respectively. TheseThe impairments resulted primarily from the impact of decreases in the 12-month average trailing twelve-month average prices for oil, natural gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net revenuescash flows from proved reserves. We did 0t recognize a ceiling test impairment during the year ended December 31, 2018 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 may incur full cost ceiling test impairments in future quarters.  The calculated ceiling 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 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.

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.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fixed Assets

Fixed assets consist primarily of gas gathering and plant facilities, water infrastructure, 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. 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. In performing the goodwill test, we compare the fair value of our reporting unit with its carrying amount. If the carrying amount of the reporting unit were to exceedexceeds its fair value, an impairment charge would beis recognized in the amount of this excess, limited to the total amount of goodwill allocated to that reporting unit.

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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. We have historically tested goodwill for impairment as of December 31 each year; however, in 2017 we elected to change the date of our annual goodwill impairment test to October 31. We do not believe a change in the goodwill impairment testing date represents a material change to a method of applying an accounting principle because the change in impairment testing date does not have a material effect on our financial statements in light of the internal controls and requirements to assess goodwill impairment upon certain triggering events. Based upon our assessment as of October 31, 2017,2019, goodwill was not impaired. It is possibleHowever, during the three months ended March 31, 2020 the company’s market capitalization declined significantly, caused by macroeconomic and geopolitical conditions including the collapse of oil prices driven by surplus supply and decreased demand caused by the COVID-19 pandemic. In addition, the uncertainty related to oil demand significantly impacted our investment and operating decisions. As a result, we concluded that a triggering event had occurred and we performed an interim quantitative impairment test for goodwill as of March 31, 2020. As a result of that quantitative impairment test, which utilized quoted market prices for our common stock as a basis for determining the fair value of our reporting unit, we concluded that goodwill could becomewas fully impaired at March 31, 2020.

The following table reflects components of the change in the future if commodity prices or other economic factors become unfavorable.carrying amount of goodwill for the year ended December 31, 2020:

(in thousands)Year Ended
December 31, 2020
Goodwill balance at January 1, 2020$716,865 
Resolute acquisition purchase price adjustments (Note 13)(2,418)
Impairment(714,447)
Goodwill balance at December 31, 2020$0 

Revenue Recognition

Oil, Gas, and NGL Sales

Revenue is 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 deliveredprobable. 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, 2020, 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, and collectability is reasonably assured. There is a ready market for our products and sales occur soon after production.NGLs. Our contracts with customers typically require payment within one month of delivery.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our gas is sold under various contracts. Under these contracts the gas and its components, including residue gas and NGLs, may be sold to a single purchaser or separate purchasers. Regardless of the contract, we are compensated for the value of the residue gas and NGLs at current market prices for each product. Depending on the specific contract terms, certain gathering, treating, transportation, processing, and other charges may be deducted against the prices we receive for the products. Our oil typically is sold at specific delivery points under contract terms that are common in our industry.

Gas Gathering

When we transport, process, and/or processmarket third-party gas associated with our equity gas, we recognize revenue for the fees charged to third-parties for such services.

Gas Marketing

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

Gas Imbalances

We use the sales method of accounting for gas imbalances. Revenue from the sale of gas is recorded on the basis of gas actually sold by or for us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

General and Administrative Expenses

General and administrative expenses are reported net of amounts reimbursed to us by other working interest owners of the oil and gas properties operated by Cimarexwe operate and net of amounts capitalized pursuant to the full cost method of accounting. General and administrative expense for the year ended December 31, 2020 included $28.7 million in severance expense associated with the voluntary early retirement incentive program that we offered to employees who met certain eligibility criteria in the first quarter of 2020 and the involuntary reduction in workforce program that we carried out in the third quarter of 2020. All of the expense for these programs was recognized in 2020. The remaining liability for these programs at December 31, 2020 is $11.3 million. The majority of this amount will be paid out in 2021, with the final payments expected to be made in 2022.

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 non-current. We routinely assess the realizability of our deferred tax assets. 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 or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. We regularly assess and, if required, establish accruals for tax


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contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 for additional information regarding

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our income taxes, including the impact of H.R.1, commonly referred to as the Tax Cuts and Jobs Act, which the U.S. enacted on December 22, 2017.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 liability includes costs related to the plugging and abandonment of wells, the removal of facilities and equipment, and site restorations. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs relatedasset and are depleted or depreciated as applicable. Subsequent to the abandonment of wells, the removal of facilities and equipment, and site restorations. In periods subsequent to the initial measurement of an asset retirement obligation at present value, a period-to-period increase in 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. 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 portion of our asset retirement obligations is recorded in “Accrued liabilities — Other” in the accompanying consolidated balance sheetsConsolidated Balance Sheets and cash payments for settlements of retirement obligations are classified as cash used in operating activities in the accompanying consolidated statementsConsolidated Statements of cash flows.Cash Flows. See Note 8 for additional information regarding our asset retirement obligations.

Stock-based Compensation

We recognize compensation cost related to all stock-based awards in the financial statements based on their estimated grant date fair value. We grant various types of stock-based awards including equity-classified awards such as stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions), and restricted stock units.units, and liability-classified awards such as cash-settled phantom stock. We recognize compensation cost related to equity-classified awards based on the estimated grant date fair value of the awards. The grant date fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-basedThe grant date fair value of service-based restricted stock and units are valued usingis the closing market price of our common stock on the grant date. The grant date fair value of the market condition-based restricted stock is based onincorporates the grant date market valueeffect of the award utilizingmarket condition using a statistical analysis.multiple probability simulation model. Compensation cost related to equity-classified awards is recognized ratably over the applicable vesting period. We recognize compensation cost related to liability-classified awards over the applicable vesting period based on an estimated fair value that is remeasured each reporting period using a multiple probability simulation model. 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 stockstock-based compensation expense. See Note 6 for additional information regarding our stock-based compensation.



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Earnings (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 payment awards, consisting of restricted stock and units, qualify as participating securities. Our participating securities do not have a contractual obligation to share in the losses of the entity and, therefore, net losses are not allocated to them. See Note 7 for additional information regarding our earnings per share.


Lease Accounting
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Recently Issued Accounting Standards
In May 2014,February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606), which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. 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 2016-02, Leases (“Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. Entities can choose to adopt the standard using either the full retrospective approach or a modified retrospective approach. We will adopt the standard effective January 1, 2018, utilizing the modified retrospective approach, which will be applied to contracts that were not completed as of January 1, 2018. The new standard will not have an impact on net income (loss) or cash flows from operations; however, certain costs previously classified as Transportation, processing, and other operating expenses in the statement of operations will be reflected as deductions from revenue under the new standard. Had Topic 606 been in effect for the fourth quarter of 2017, Revenue and Transportation, processing and other operating expenses for the quarter would have each been reduced by an estimated range of $15.0 million to $16.0 million.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)842”).  The key provision of this ASU isFASB subsequently issued various ASUs that a lessee mustprovided additional implementation guidance. Topic 842 requires lessees to recognize (i)lease liabilities to make lease payments and (ii) right-of-use assets on itsthe balance sheet.  The ASU permitssheet 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 assetassets 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 of $265.0 million. In connection with adoption we made use of the following practical expedients, which are provided in Topic 842:

•a 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 liabilities on3) initial direct costs for existing leases;

•an election not to apply the balance sheet.  This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We arerecognition requirements in the process of evaluating the potential impact of adopting this guidance, but believe the primary effect will be to record assets and liabilities for contracts currently accounted for as operating leases.  We do not intend to adopt the standard early.
In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842. This ASU provides an optional transition 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 company is reasonably certain to exercise);

•a practical expedient that permits combining lease and nonlease components in a contract and accounting for the combination as a lease (elected by asset class); and

•a practical expedient to not evaluate under Topic 842 (discussed above) existing or expiredreassess certain land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. Under the full cost method of accounting, we capitalizeexistence prior to oil and gas properties all property acquisition, exploration, and development costs, which include the costs of land easements. We plan to elect this practical expedient and continue to apply our current accounting policy to account for land easements that existed before our adoption of Topic 842 and will evaluate new or modified land easements under Topic 842 upon our adoption of Topic 842. We are in the process of evaluating the potential impact of adopting this guidance, and do not intend to adopt the standard early.January 1, 2019.


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2. CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At December 31, 2017,2020, there were 95.4102.9 million shares of common stock and no28.2 thousand shares of preferred stock outstanding. See

Redeemable Preferred Stocks

In February 2019, our Consolidated StatementsBoard of Stockholders’ EquityDirectors created a new series of preferred stock, par value $0.01 per share, designated as 8.125% Series A Cumulative Perpetual Convertible Preferred Stock (the “Preferred Stock”) and authorized 62.5 thousand shares. In March 2019, in conjunction with the Resolute acquisition (see Note 13), we issued all of these shares of Preferred Stock. Prior to this issuance, we had not issued any preferred stock.

Holders of the Preferred Stock are entitled to receive, when, as, and if declared by the Board out of funds of Cimarex legally available for detailed capital stock activity.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


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from the most recent date as to which dividends have been paid. In May 2015, we completed an underwritten public offeringthe event of 6.9 millionany 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, which included 0.9 million sharesstock), the liquidation preference 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 $109.00$1,000 per share, with the total liquidation preference at December 31, 2020 being $28.2 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 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 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 8.38732 as of December 31, 2020. Additionally, at any time on or after 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 Preferred Stock to be automatically converted into that number of shares of Cimarex common stock for each share of 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 Preferred Stock and $471.40 in cash per share of Preferred Stock. We also have the right at any time to repurchase shares of Preferred Stock through privately negotiated transactions. As a parresult of the cash redemption features included in the 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 Sheets.

In December 2020, we repurchased 34.3 thousand shares of Preferred Stock, leaving 28.2 thousand shares of 8.125% Series A Cumulative Perpetual Convertible Preferred Stock authorized and issued at December 31, 2020. The book value of $0.01, and we received net proceeds of $729.5 millionthe repurchased shares exceeded the aggregate amount Cimarex paid to repurchase the shares by $1.8 million. That amount has been treated as a return from the sale, after deducting underwriting fees.holders of the Preferred Stock and recorded as an increase to additional paid-in capital (similar to the treatment of dividends declared, which are recorded as a reduction of additional paid-in capital).

Dividends

Common Stock

A quarterly cash dividend has been paid to stockholders inon our common stock every quarter since the first quarter of 2006. In each quarter of 2020, a $0.22 per common share dividend was declared. In each quarter of 2019 a $0.20 per common share dividend was declared. A quarterly dividend of $0.08$0.18 per common share was declared in each quarterboth the third and fourth quarters of 20172018 and 2016 and a quarterly dividend of $0.16 per common share was declared in eachboth the first and second quarters of 2018. Dividends are paid in the quarter following the quarter of 2015. We typically declaredeclaration. At December 31, 2020, we had dividends payable to common stockholders of $22.9 million that was included in one quarter and pay them in the next quarter.“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. 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 stock award forfeitures occur. Dividends accrued and unpaid on performance stock awards that are canceled upon completion of the vesting period due to the market condition not being met, are reversed out of retained earnings or additional paid-in capital, as applicable, in the period in which the stock award cancellations occur. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.



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Preferred Stock

In each quarter of 2020 and 2019 our Board of Directors declared a cash dividend of $20.3125 per share of Preferred Stock. Dividends are paid in the quarter following the quarter of declaration. At December 31, 2020, we had dividends payable to preferred stockholders of $0.6 million that was included in “Accrued liabilities — Other”.

3. LONG-TERM DEBT

Long-term debt at December 31, 20172020 and 20162019 consisted of the following:

  December 31, 2017 December 31, 2016
(in thousands) Principal 
Unamortized Debt
Issuance Costs and Discount (1)
 
Long-term
Debt, net
 Principal 
Unamortized Debt
Issuance Costs
 
Long-term
Debt, net
5.875% Senior Notes $—
 $—
 $—
 $750,000
 $(5,691) $744,309
4.375% Senior Notes 750,000
 (5,383) 744,617
 750,000
 (6,370) 743,630
3.90% Senior Notes 750,000
 (7,697) 742,303
 —
 —
 —
Total long-term debt $1,500,000
 $(13,080) $1,486,920
 $1,500,000
 $(12,061) $1,487,939
 December 31, 2020December 31, 2019
(in thousands)PrincipalUnamortized
Debt
Issuance Costs and Discounts (1)		Long-term
Debt, net		PrincipalUnamortized
Debt
Issuance Costs and Discounts (1)		Long-term
Debt, net
4.375% notes due 2024$750,000 $(2,672)$747,328 $750,000 $(3,535)$746,465 
3.90% notes due 2027750,000 (5,541)744,459 750,000 (6,289)743,711 
4.375% notes due 2029500,000 (4,488)495,512 500,000 (4,930)495,070 
Total long-term debt$2,000,000 $(12,701)$1,987,299 $2,000,000 $(14,754)$1,985,246 

(1)At December 31, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.9 million and $1.8 million, respectively.  The 4.375% notes were issued at par.
(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, 2020, the unamortized debt issuance costs and discount related to the 3.90% notes due 2027 were $4.3 million and $1.3 million, respectively. At December 31, 2020, the unamortized debt issuance costs and discount related to the 4.375% notes due 2029 were $3.9 million and $0.6 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% notes due 2027 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.

Bank Debt

In October 2015,On June 3, 2020, we entered into a newthe First Amendment to Amended and Restated Credit Agreement (the “First Amendment”) dated as of February 5, 2019 for our senior unsecured revolving credit facility (“Credit Facility”) which matures October 16, 2020.. The Credit Facility has aggregate commitments of $1.0$1.25 billion with an option for us to increase the aggregate commitments to $1.25$1.5 billion, at any time.and matures on 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. The First Amendment, among other things: (i) allows up to $3.5 billion of non-cash impairment charge add-backs to Shareholders’ Equity for covenant calculation purposes, (ii) institutes traditional anti-cash hoarding provisions (if borrowings are outstanding under the Credit Facility) at a consolidated cash threshold of $175.0 million, (iii) reduces the priority lien debt basket from 15% of Consolidated Net Tangible Assets (as defined in the credit agreement) to a $50.0 million cap, and (iv) adds an acknowledgement and consent to European Union bail-in legislation. As of December 31, 2017,2020, we had no0 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, 2020, we borrowed and repaid an aggregate of $172.0 million on the Credit Facility to meet cash requirements as needed.



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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.

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-capitaldebt-to-capitalization ratio of no greater than 65%. As of December 31, 2017,2020, we were in compliance with all of the financial covenants.

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At December 31, 20172020 and 2016,2019, we had $3.4$4.3 million and $4.5$4.0 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.Consolidated Balance Sheets. During the year ended December 31, 2020, we incurred $1.5 million in fees paid to the lenders and third-party costs for the First Amendment. The debt issuance costs are being amortized to interest expense ratably over the life of the Credit Facility.

Senior Notes

On April 10, 2017,March 8, 2019, we completed a cash tender offer to purchase any of our 5.875% notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5issued $500.0 million aggregate principal amount of the4.375% senior unsecured notes validly tendered.  We settledat 99.862% of par to yield 4.392% per annum. The notes are due March 15, 2029 and interest is payable semiannually on March 15 and September 15. The effective interest rate on these tendered notes, for $268.1 million, including accrued interest.  On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including the redemption date, settling the notes for $512.0 million, including accrued interest.  We recognized a loss on early extinguishmentamortization of debt related to these transactions of $28.2 million, composed primarily of tenderissuance costs and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.  The original maturity date of the 5.875% notes was May 1, 2022.discount, is 4.50%.
On
In April 10, 2017, we issued $750$750.0 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.  TheThese notes bear an annual interest rate of 3.90%are due May 15, 2027 and interest is payable semiannually on May 15 and November 15, with15.  The effective interest rate on these notes, including the first payment occurring November 15, 2017.  Along with cash on hand, we used the proceeds to fund the settlementamortization of the tendereddebt issuance costs and redeemed 5.875% notes. discount, is 4.01%.

In June 2014, we issued $750$750.0 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 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
Our senior unsecured notes isare governed by an indentureindentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of December 31, 2017. The effective interest rate on the 4.375% notes and the 3.90% notes, including the amortization2020.



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4. DERIVATIVE INSTRUMENTS

We periodically use derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future 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 derivative positions from current levels.

As of December 31, 2017,2020, we have entered into oil and gas collars, oil basis swaps, and oil basis“roll differential” swaps. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the ceiling price and the index price if the index price is above the 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 or minus a fixed differential, as applicable, 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. Our roll differential swaps are settled based on the difference between the monthly roll differential and a fixed price per Bbl. The monthly roll differential is calculated as the sum of 2/3 of the difference in the WTI NYMEX closing settlement price for the first nearby month futures contract minus the second nearby month futures contract and 1/3 of the difference in the WTI NYMEX calendar month average price and the physical crude oil delivery month price. The following tables summarize our outstanding derivative contracts as of December 31, 2017:2020:


Oil CollarsFirst
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter		Total
2021:     
WTI (1)
     
Volume (Bbls)3,600,000 3,094,000 3,680,000 3,680,000 14,054,000 
Weighted Avg Price - Floor$38.06 $34.62 $34.65 $34.65 $35.52 
Weighted Avg Price - Ceiling$46.45 $43.28 $44.37 $44.37 $44.66 
2022:     
WTI (1)
     
Volume (Bbls)2,340,000 1,729,000 920,000 0 4,989,000 
Weighted Avg Price - Floor$37.31 $38.16 $40.00 $0 $38.10 
Weighted Avg Price - Ceiling$48.41 $49.56 $49.19 $0 $48.95 

(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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Gas CollarsFirst
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter		Total
2021:     
PEPL (1)
     
Volume (MMBtu)9,000,000 9,100,000 8,280,000 8,280,000 34,660,000 
Weighted Avg Price - Floor$1.83 $1.89 $2.00 $2.00 $1.93 
Weighted Avg Price - Ceiling$2.23 $2.28 $2.42 $2.42 $2.33 
Perm EP (2)
     
Volume (MMBtu)6,300,000 7,280,000 6,440,000 6,440,000 26,460,000 
Weighted Avg Price - Floor$1.50 $1.62 $1.86 $1.86 $1.71 
Weighted Avg Price - Ceiling$1.79 $1.92 $2.22 $2.22 $2.03 
Waha (3)
Volume (MMBtu)8,100,000 9,100,000 8,280,000 8,280,000 33,760,000 
Weighted Avg Price - Floor$1.52 $1.61 $1.82 $1.82 $1.69 
Weighted Avg Price - Ceiling$1.83 $1.93 $2.17 $2.17 $2.03 
2022:     
PEPL (1)
Volume (MMBtu)5,400,000 1,820,000 0 0 7,220,000 
Weighted Avg Price - Floor$2.13 $2.40 0 0 $2.20 
Weighted Avg Price - Ceiling$2.55 $2.86 0 0 $2.63 
Perm EP (2)
Volume (MMBtu)3,600,000 1,820,000 0 0 5,420,000 
Weighted Avg Price - Floor$2.13 $2.40 0 0 $2.22 
Weighted Avg Price - Ceiling$2.53 $2.88 0 0 $2.65 
Waha (3)
     
Volume (MMBtu)5,400,000 1,820,000 0 0 7,220,000 
Weighted Avg Price - Floor$1.98 $2.40 0 0 $2.09 
Weighted Avg Price - Ceiling$2.39 $2.86 0 0 $2.50 

(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 Collars: 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2018:  
  
  
  
  
WTI (1)
  
  
  
  
  
Volume (Bbls) 2,610,000
 2,093,000
 1,748,000
 1,196,000
 7,647,000
Weighted Avg Price - Floor $47.28
 $47.26
 $46.68
 $48.00
 $47.25
Weighted Avg Price - Ceiling $56.33
 $55.61
 $54.90
 $55.10
 $55.62
           
2019:  
  
  
  
  
WTI (1)
  
  
  
  
  
Volume (Bbls) 630,000
 637,000
 —
 —
 1,267,000
Weighted Avg Price - Floor $48.00
 $48.00
 $—
 $—
 $48.00
Weighted Avg Price - Ceiling $56.09
 $56.09
 $—
 $—
 $56.09

(1)The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”).

Gas Collars: 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2018:  
  
  
  
  
PEPL (1)
  
  
  
  
  
Volume (MMBtu) 11,700,000
 9,100,000
 6,440,000
 3,680,000
 30,920,000
Weighted Avg Price - Floor $2.57
 $2.47
 $2.43
 $2.43
 $2.49
Weighted Avg Price - Ceiling $2.93
 $2.81
 $2.67
 $2.66
 $2.81
Perm EP (2)
  
  
  
  
  
Volume (MMBtu) 8,100,000
 6,370,000
 4,600,000
 2,760,000
 21,830,000
Weighted Avg Price - Floor $2.52
 $2.39
 $2.34
 $2.33
 $2.42
Weighted Avg Price - Ceiling $2.84
 $2.67
 $2.53
 $2.52
 $2.68
2019:  
  
  
  
  
PEPL (1)
  
  
  
  
  
Volume (MMBtu) 2,700,000
 2,730,000
 —
 —
 5,430,000
Weighted Avg Price - Floor $2.40
 $2.40
 $—
 $—
 $2.40
Weighted Avg Price - Ceiling $2.67
 $2.67
 $—
 $—
 $2.67
Perm EP (2)
  
  
  
  
  
Volume (MMBtu) 1,800,000
 1,820,000
 —
 —
 3,620,000
Weighted Avg Price - Floor $2.30
 $2.30
 $—
 $—
 $2.30
Weighted Avg Price - Ceiling $2.49
 $2.49
 $—
 $—
 $2.49
81

(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.

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Oil Basis SwapsFirst
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter		Total
2021:     
WTI Midland (1)
     
Volume (Bbls)2,790,000 3,003,000 3,220,000 3,220,000 12,233,000 
Weighted Avg Differential (2)$0.03 $(0.02)$(0.08)$(0.08)$(0.04)
2022:     
WTI Midland (1)
     
Volume (Bbls)1,980,000 1,365,000 644,000 0 3,989,000 
Weighted Avg Differential (2)$0.25 $0.31 $0.38 $0 $0.29 

(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 or minus, as applicable, the weighted average differential shown in the table.

Oil Roll Differential SwapsFirst
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter		Total
2021:     
WTI (1)
     
Volume (Bbls)630,000 1,001,000 1,656,000 1,656,000 4,943,000 
Weighted Avg Price$(0.24)$(0.22)$(0.10)$(0.10)$(0.14)
2022:     
WTI (1)
     
Volume (Bbls)1,620,000 1,001,000 644,000 0 3,265,000 
Weighted Avg Price$(0.10)$(0.01)$0.10 $0 $(0.03)

(1)The index price used to determine the settlement “roll” is WTI as quoted on the NYMEX.

Oil Basis Swaps: 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2018:          
WTI Midland (1)
          
Volume (Bbls) 1,170,000
 1,183,000
 1,196,000
 736,000
 4,285,000
Weighted Avg Differential (2) $(0.72) $(0.72) $(0.72) $(0.58) $(0.69)
2019:          
WTI Midland (1)
          
Volume (Bbls) 450,000
 455,000
 —
 —
 905,000
Weighted Avg Differential (2) $(0.47) $(0.47) $—
 $—
 $(0.47)

(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.

The following tables summarize our derivative contracts entered into subsequent to December 31, 2017 through February 22, 2018:82
Oil Collars: 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2018:          
WTI (1)          
Volume (Bbls) —
 546,000
 552,000
 552,000
 1,650,000
Weighted Avg Price - Floor $—
 $50.00
 $50.00
 $50.00
 $50.00
Weighted Avg Price - Ceiling $—
 $66.82
 $66.82
 $66.82
 $66.82
2019:          
WTI (1)          
Volume (Bbls) 540,000
 546,000
 552,000
 —
 1,638,000
Weighted Avg Price - Floor $50.00
 $50.00
 $50.00
 $—
 $50.00
Weighted Avg Price - Ceiling $66.82
 $66.82
 $66.82
 $—
 $66.82

(1)The index price for these collars is WTI as quoted on the NYMEX.

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Gas Collars: 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2018:          
PEPL (1)
          
Volume (MMBtu) —
 1,820,000
 1,840,000
 1,840,000
 5,500,000
Weighted Avg Price - Floor $—
 $1.98
 $1.98
 $1.98
 $1.98
Weighted Avg Price - Ceiling $—
 $2.16
 $2.16
 $2.16
 $2.16
Perm EP (2)
          
Volume (MMBtu) —
 1,820,000
 1,840,000
 1,840,000
 5,500,000
Weighted Avg Price - Floor $—
 $1.65
 $1.65
 $1.65
 $1.65
Weighted Avg Price - Ceiling $—
 $1.80
 $1.80
 $1.80
 $1.80
2019:          
PEPL (1)
          
Volume (MMBtu) 1,800,000
 1,820,000
 1,840,000
 —
 5,460,000
Weighted Avg Price - Floor $1.98
 $1.98
 $1.98
 $—
 $1.98
Weighted Avg Price - Ceiling $2.16
 $2.16
 $2.16
 $—
 $2.16
Perm EP (2)
          
Volume (MMBtu) 1,800,000
 1,820,000
 1,840,000
 —
 5,460,000
Weighted Avg Price - Floor $1.65
 $1.65
 $1.65
 $—
 $1.65
Weighted Avg Price - Ceiling $1.80
 $1.80
 $1.80
 $—
 $1.80

(1)The index price for these collars is PEPL as quoted in Platt’s Inside FERC.  
(2)The index price for these collars is Perm EP as quoted in Platt’s Inside FERC.
Oil Basis Swaps: 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2018:          
WTI Midland (1)
          
Volume (Bbls) —
 91,000
 92,000
 92,000
 275,000
Weighted Avg Differential (2) $—
 $(0.70) $(0.70) $(0.70) $(0.70)
2019:          
WTI Midland (1)
          
Volume (Bbls) 90,000
 91,000
 92,000
 —
 273,000
Weighted Avg Differential (2) $(0.70) $(0.70) $(0.70) $—
 $(0.70)

(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 designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments.  Consequently, changes in the fair value of 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 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 components of (Gain) loss“Loss (gain) on derivative instruments, netnet” for the periods indicated.


 Years Ended December 31,
(in thousands)202020192018
Decrease (increase) in fair value of derivative instruments, net:   
Gas contracts$56,475 $(13,114)$15,742 
Oil contracts98,306 76,833 (126,130)
154,781 63,719 (110,388)
Cash (receipts) payments on derivative instruments, net:   
Gas contracts(15,476)(40,114)(13,794)
Oil contracts(103,771)53,245 38,223 
(119,247)13,131 24,429 
Loss (gain) on derivative instruments, net$35,534 $76,850 $(85,959)

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  Years Ended December 31,
(in thousands) 2017 2016 2015
Change in fair value of derivative instruments, net:  
  
  
Gas contracts $(40,226) $27,462
 $(4,472)
Oil contracts 17,383
 35,724
 (6,774)

 (22,843) 63,186
 (11,246)
Cash (receipts) payments on derivative instruments, net:  
  
  
Gas contracts (4,557) (6,467) —
Oil contracts 6,190
 (970) —

 1,633
 (7,437) —
(Gain) loss on derivative instruments, net $(21,210) $55,749
 $(11,246)
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 balance sheets.

The following tables present the amounts and classifications of our derivative assets and liabilities as of December 31, 20172020 and 2016,2019, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.

   December 31, 2017 December 31, 2020
(in thousands) Balance Sheet Location Asset Liability(in thousands)Balance Sheet LocationAssetLiability
Oil contractsOil contractsCurrent assets — Derivative instruments$5,425 $— 
Gas contracts Current assets — Derivative instruments $15,151
 $—
Gas contractsCurrent assets — Derivative instruments1,423 — 
Gas contracts Non-current assets — Derivative instruments 2,086
 —
Gas contractsNon-current assets — Derivative instruments2,342 — 
Oil contracts Current liabilities — Derivative instruments —
 42,066
Oil contractsCurrent liabilities — Derivative instruments— 106,507 
Gas contractsGas contractsCurrent liabilities — Derivative instruments— 38,891 
Oil contracts Non-current liabilities — Derivative instruments —
 4,268
Oil contractsNon-current liabilities — Derivative instruments— 12,526 
Gas contractsGas contractsNon-current liabilities — Derivative instruments— 5,223 
Total gross amounts presented in the balance sheetTotal gross amounts presented in the balance sheet 17,237
 46,334
Total gross amounts presented in the balance sheet9,190 163,147 
Less: gross amounts not offset in the balance sheetLess: gross amounts not offset in the balance sheet (17,237) (17,237)Less: gross amounts not offset in the balance sheet(8,863)(8,863)
Net amountNet amount $—
 $29,097
Net amount$327 $154,284 

 December 31, 2019
(in thousands)Balance Sheet LocationAssetLiability
Oil contractsCurrent assets — Derivative instruments$1,624 $— 
Gas contractsCurrent assets — Derivative instruments16,320 — 
Oil contractsNon-current assets — Derivative instruments580 — 
Oil contractsCurrent liabilities — Derivative instruments— 16,681 
Oil contractsNon-current liabilities — Derivative instruments— 824 
Gas contractsNon-current liabilities — Derivative instruments— 194 
Total gross amounts presented in the balance sheet18,524 17,699 
Less: gross amounts not offset in the balance sheet(9,865)(9,865)
Net amount$8,659 $7,834 
    December 31, 2016
(in thousands) Balance Sheet Location Asset Liability
Oil contracts Current liabilities — Derivative instruments $—
 $27,892
Gas contracts Current liabilities — Derivative instruments —
 21,478
Oil contracts Non-current liabilities — Derivative instruments —
 1,059
Gas contracts Non-current liabilities — Derivative instruments —
 1,511
Total gross amounts presented in the balance sheet —
 51,940
Less: gross amounts not offset in the balance sheet —
 —
Net amount $—
 $51,940

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 havehas 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 derivative liability positions.  Because some of the member banks have discontinued derivative activities, inpositions, nor do we require our counterparties to post collateral for our benefit.  In the future we may enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.


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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). The FASBdate. Authoritative accounting guidance 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 inputs are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability.unobservable.

The following table provides fair value measurement information for certain assets and liabilities as of December 31, 20172020 and 2016.2019.


 December 31, 2020December 31, 2019
(in thousands)Book ValueFair ValueBook ValueFair Value
Financial Assets (Liabilities):    
4.375% Notes due 2024$(750,000)$(818,025)$(750,000)$(792,225)
3.90% Notes due 2027$(750,000)$(826,575)$(750,000)$(778,050)
4.375% Notes due 2029$(500,000)$(567,250)$(500,000)$(530,400)
Derivative instruments — assets$9,190 $9,190 $18,524 $18,524 
Derivative instruments — liabilities$(163,147)$(163,147)$(17,699)$(17,699)
  December 31, 2017 December 31, 2016
(in thousands) Book Value Fair Value Book Value Fair Value
Financial Assets (Liabilities):  
  
  
  
5.875% Notes due 2022 $—
 $—
 $(750,000) $(782,835)
4.375% Notes due 2024 $(750,000) $(797,010) $(750,000) $(779,453)
3.90% Notes due 2027 $(750,000) $(767,813) $—
 $—
Derivative instruments — assets $17,237
 $17,237
 $—
 $—
Derivative instruments — liabilities $(46,334) $(46,334) $(51,940) $(51,940)

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 fair value (Level 1) of our fixed rate notes was based on their last traded value before period end.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 andprices, 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, 20172020 are: (i) accrued operating expenses (e.g. production, transportation, and midstream expenses) of approximately $61.3$67.4 million and (ii) accrued general and administrative primarily payroll-related, costs of approximately $54.6 million.$46.8 million, which consisted primarily of $34.1 million in regular payroll-related costs and $11.3 million in voluntary early retirement incentive program and involuntary reduction in workforce severance accruals. Included in “Accrued liabilities — other”Other” at December 31, 20162019 are: (i) accrued operating expenses (e.g. production, transportation, and midstream expenses) of approximately $53.9$74.7 million and (ii) accrued general and administrative costs, primarily payroll-related, costs of approximately $43.5$43.3 million.

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry.  Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in 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. For properties we operate, we have the right to realize amounts due to us from non-operators by netting the non-operators’ share of production revenues from those properties.
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 the amount of the reserve may be reasonably estimated. At December 31, 2017 and 2016, the allowance for doubtful accounts totaled $2.2 million and $1.6 million, respectively.


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We routinely assess the recoverability of all material accounts receivable and accrue a reserve to the allowance for credit losses based on our estimation of expected losses over the life of the receivables. At December 31, 2020 and 2019, the allowance for credit losses totaled $2.6 million and $3.6 million, respectively.

Major Customers


In 2017,each of the years ended December 31, 2020, 2019, and 2018, we made sales to 2 customers that each amounted to 10% or more of our majorconsolidated revenues for the respective year. Sales to those two customers were Energy Transfer Partners, L.P. (“Energy Transfer Partners”) and Plains All American Pipeline, L.P. (“Plains All American”), which accounted for 21%26% and 13%23%, respectively, of our consolidated revenues that year. In 2017, the revenue totals for Energy Transfer Partners include revenue from Sunoco Logistics Partners L.P. (“Sunoco”) since the two entities merged in 2017. Sunoco was our major customer in 2016, accounting for 20% of our consolidated revenues that year. In 2015, our major customers were Sunoco2020, 29% and Enterprise Products Partners L.P., which accounted for 21% and 17%25%, respectively, of our consolidated revenues that year.in 2019, and 21% and 23%, respectively, of our consolidated revenues in 2018.

If any one of our major customers waswere to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production with some delay.production. If multiple significant customers were to discontinue purchasing our production, we believe there wouldcould be some initial challenges, initially, but we have ample alternative markets to handle theany sales disruption.

6. STOCK-BASED AND OTHER COMPENSATION

Equity Incentive Plan

Our 20142019 Equity Incentive Plan (the “2014“2019 Plan”) was approved by stockholders in May 2014 and our previous plan was terminated at that time.2019. Outstanding awards under previous plans were not impacted, but no additional awards will be made under the previous plan were not impacted.plans. A total of 6.66.3 million shares of common stock may be issued under the 20142019 Plan, including shares available from the previous plan.plans. The 20142019 Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performancestock units, dividend equivalents,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)202020192018
Restricted stock awards:   
Performance stock awards$17,338 $21,590 $23,083 
Service-based stock awards26,014 25,611 20,385 
 43,352 47,201 43,468 
Stock option awards1,460 1,903 2,456 
Total stock-based compensation cost44,812 49,104 45,924 
Less amounts capitalized to oil and gas properties(14,917)(22,706)(23,029)
Stock-based compensation expense$29,895 $26,398 $22,895 
  Years Ended December 31,
(in thousands) 2017 2016 2015
Restricted stock awards:  
  
  
Performance stock awards $26,020
 $24,183
 $18,991
Service-based stock awards 19,746
 18,391
 14,547
  45,766
 42,574
 33,538
Stock option awards 2,599
 2,565
 2,803
Total stock compensation cost 48,365
 45,139
 36,341
Less amounts capitalized to oil and gas properties (22,109) (20,616) (16,782)
Stock compensation expense $26,256
 $24,523
 $19,559

Periodic stockstock-based 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 total stock compensation cost in 2017 as compared to 2016Our accounting policy is primarily due to awards granted either during or subsequent to 2016. These increases were partially offset by awards vesting prior to or during 2017.
We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017.  ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, accounting for forfeitures, and classification on the statement of cash flows.  Pursuant to ASU 2016-09, we made an accounting policy election to account for forfeitures in compensation cost when they occur, rather than including an estimateoccur. 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. The amount capitalized to oil and gas properties decreased as a percentage of total stock-based compensation cost in 2020 as compared to 2019 and 2018 due to reduced acquisition, exploration, and development activities in 2020 as a result of the number of awards that are expected to vest in our compensation cost.  The amendments within ASU 2016-09 related to the timing of when excess tax benefitslow oil prices and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a 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 increased beginning additional paid-in capital by $4.4 million.  The

demand
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destruction experienced in 2020 stemming from the COVID-19 pandemic and OPEC and other countries’ actions. The decreased capitalization caused the overall stock-based compensation expense to increase.
amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to the payment of employee tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method.  In accordance with this method, we adjusted the statement of cash flows for the year ended December 31, 2016 by increasing both net cash provided by operating activities and net cash used by financing activities by $26.6 million for the payment of employee tax withholdings on the net settlement of equity-classified awards. There were no cash flows related to excess tax benefits during the year ended December 31, 2016. For the year ended December 31, 2015, we adjusted the statement of cash flows for the payment of employee tax withholdings on the net settlement of equity-classified awards as well as for the classification of excess tax benefits by increasing net cash provided by operating activities and decreasing net cash provided by financing activities by $34.2 million.
Restricted Stock

The following table provides information about restricted stock awards granted during the last three years.

 Years Ended December 31,
 202020192018
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 awards311,974 $29.84 264,393 $47.66 123,533 $90.26 
Service-based stock awards846,918 $35.54 681,988 $45.88 469,438 $81.29 
Total restricted stock awards1,158,892 $34.01 946,381 $46.38 592,971 $83.16 
 Years Ended December 31,
 2017 2016 2015
 
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 awards300,525
 $89.46
 269,915
 $117.63
 263,939
 $87.12
Service-based stock awards251,312
 $94.04
 208,724
 $114.61
 207,180
 $114.80
Total restricted stock awards551,837
 $91.55
 478,639
 $116.31
 471,119
 $99.29

Performance stock awards wereare 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’sgroups’ stock price performance. AfterThe performance stock awards granted in 2018 and 2019 are equity-classified awards and after three years of continued service, an executive will be entitled to vest in 50%0% to 200% of the award depending on our stock price performance, with the vested amount paid in shares. For the performance stock awards granted in 2020, after three years of continued service, an executive will be entitled to vest in 0% to 200% of the award depending on our stock price performance, with the vested amount up to 100% paid in shares and any vested amount above 100% paid in cash. The share-settled portion of these awards are equity-classified awards and the cash-settled portion of these awards are liability-classified awards.

We recognize compensation cost related to the equity-classified portion of performance stock awards ratably over the applicable vesting period based on the estimated grant date fair value of the award.awards, which is calculated using a multiple probability simulation model incorporating the effect of the market condition. We recognize compensation cost related to the liability-classified portion of performance stock awards over the applicable vesting period based on an estimated fair value that is remeasured each reporting period using a multiple probability simulation model incorporating the effect of the market condition. 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 ranging from one to five years. The majority of our service-based stock awards cliff vest five years from the grant date.
Compensation We recognize compensation cost for the performanceservice-based stock awards is based onupon the grant date fair value of the award, utilizing a Monte Carlo simulation model. Compensation cost forwhich is the service-basedclosing market price of our common stock awards is based uponon the grant date market value of the award.date. Such costs are recognized ratably over the applicable vesting period.



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The following table provides information on restricted stock activity during the year.

 Service-basedPerformance
(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, 20201,639,069 $74.51 664,977 $72.99 
Vested(237,616)$94.23 (205,746)$82.83 
Granted846,918 $35.54 311,974 $29.84 
Canceled (1)0 $0 (119,521)$89.46 
Forfeited(155,450)$78.43 0 $0 
Outstanding as of December 31, 20202,092,921 $56.21 651,684 $46.20 

(1)    These performance shares were canceled since the market condition was not satisfied as of the end of the performance period.
 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, 2017934,723
 $96.57
 809,270
 $96.41
Vested(234,468) $63.49
 (275,416) $84.50
Granted251,312
 $94.04
 300,525
 $89.46
Forfeited(41,316) $105.83
 —
 $—
Outstanding as of December 31, 2017910,251
 $103.98
 834,379
 $97.83

The total fairvest date market value of restricted stock that vested during the years ended December 31, 2020, 2019, and 2018 was $54.4$12.0 million, in 2017, $67.9$15.1 million, in 2016, and $52.2$34.1 million, in 2015.respectively.

Unrecognized compensation cost related to equity-classified unvested restricted stock at December 31, 20172020 was $105.6approximately $84.2 million. We expect to recognize thatthis cost over a weighted average period of 2.82.6 years. As of December 31, 2020, the fair value of the unvested liability-classified performance stock awards was $3.5 million and the associated vested liability was $70 thousand. The vested liability is included in “Other liabilities”.

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Restricted Units


As of December 31, 20172020 and 2016,2019, 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 outstanding as of December 31, 20172020 expire seven to ten years from the grant date and have service-based vesting whereby the awards vest in increments of one-third, generally on each of the first three anniversary dates of the grant. The exercise price for an option under the 20142019 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”) 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.

CompensationWe recognize compensation cost related to stock options is based on the estimated grant date fair value of the award and it is recognized ratably over the applicable vesting period. We estimate the grant date fair value using the Black-Scholes option-pricingoption pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the expected years until exercise. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.



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The following summarizestable provides information regarding options granted during the last three years, including the assumptions used to determine the fair value of those options.


 Years Ended December 31,
 202020192018
Options granted194,900 132,900 92,050 
Weighted average grant date fair value$12.61 $12.14 $26.71 
Weighted average exercise price$34.06 $42.78 $83.28 
Total fair value (in thousands)$2,458 $1,613 $2,458 
Expected years until exercise4.94.95.0
Expected stock volatility53.9 %37.1 %34.7 %
Dividend yield2.6 %1.9 %0.9 %
Risk-free interest rate0.4 %1.4 %2.7 %
 Years Ended December 31,
 2017 2016 2015
Options granted96,100
 89,850
 69,000
Weighted average grant date fair value$28.37
 $33.38
 $37.56
Weighted average exercise price$92.37
 $114.07
 $115.28
Total fair value (in thousands)$2,727
 $2,999
 $2,592
Expected years until exercise4.5
 4.0
 5.0
Expected stock volatility35.0% 36.7% 36.6%
Dividend yield0.3% 0.3% 0.6%
Risk-free interest rate1.7% 1.0% 1.6%

Information aboutThe following table provides information regarding outstanding stock options is summarized below.as of December 31, 2020 and changes during the year.

Number of OptionsWeighted
Average
Exercise
Price		Weighted
Average
Remaining
Term		Aggregate
Intrinsic
Value
(in thousands)
Outstanding as of January 1, 2020495,538 $87.17   
Exercised0 $0   
Granted194,900 $34.06   
Canceled(107,025)$94.29   
Forfeited(36,036)$55.69   
Outstanding as of December 31, 2020547,377 $68.94 4.6 years$711 
Exercisable as of December 31, 2020271,827 $99.38 3.0 years$0 
 Number of Options 
Weighted
Average
Exercise
Price
 
Weighted
Average
Remaining
Term
 
Aggregate
Intrinsic
Value
(in thousands)
Outstanding as of January 1, 2017307,810
 $101.72
    
Exercised(5,768) $68.33
    
Granted96,100
 $92.37
    
Canceled(1,665) $139.02
    
Forfeited(13,789) $88.92
    
Outstanding as of December 31, 2017382,688
 $100.17
 4.4 years $9,553
Exercisable as of December 31, 2017209,782
 $98.55
 3.2 years $6,020

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The following table provides information regarding options exercised and the grant date fair value of options vested.

 Years Ended December 31,
(in thousands)202020192018
Cash received from option exercises$0 $1,267 $2,241 
Intrinsic value of options exercised$0 $425 $1,030 
Grant date fair value of options vested$1,855 $2,262 $2,547 



89
  Years Ended December 31,
(in thousands) 2017 2016 2015
Cash received from option exercises $394
 $4,804
 $8,451
Tax benefit from option exercises included in paid-in-capital $—
 $—
 $4,442
Intrinsic value of options exercised $257
 $2,994
 $7,467
Grant date fair value of options vested $2,227
 $2,486
 $2,734
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The following summary reflects the status oftable provides information regarding non-vested stock options as of December 31, 20172020 and changes during the year.

Number of OptionsWeighted
Average
Grant Date
Fair Value		Weighted
Average
Exercise
Price
Number of Options 
Weighted
Average
Grant Date
Fair Value
 
Weighted
Average
Exercise
Price
Non-vested as of January 1, 2017148,361
 $35.58
 $117.55
Non-vested as of January 1, 2020Non-vested as of January 1, 2020208,255 $17.60 $58.47 
Vested(57,766) $38.55
 $128.59
Vested(91,569)$20.26 $66.47 
Granted96,100
 $28.37
 $92.37
Granted194,900 $12.61 $34.06 
Forfeited(13,789) $29.41
 $88.92
Forfeited(36,036)$16.74 $55.69 
Non-vested as of December 31, 2017172,906
 $31.08
 $102.15
Non-vested as of December 31, 2020Non-vested as of December 31, 2020275,550 00

As of December 31, 2017,2020, there was $4.1$3.2 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost over a weighted average period of 1.92.2 years.

Other Compensation

We maintain and sponsor a contributory 401(k) plan for our employees. Employer contributions related to the plan were $10.4$8.2 million, $6.7$8.7 million, and $6.4$13.1 million for 2017, 2016,2020, 2019, and 2015,2018, respectively. IncludedEmployer discretionary contributions were included in the 2017 amount are accrued employer discretionary contributions.2018 amount. No such employer discretionary contributions occurred in 2016 and 2015.were accrued for 2020 or 2019.


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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. Earnings (loss) per share are based on actual figures rather than the rounded figures presented.


 Year Ended December 31, 2020
(in thousands, except per share information)Income (Numerator)Shares (Denominator)Per-Share Amount
Net loss$(1,967,458) 
Plus: return from repurchase of redeemable preferred stock1,810 
Less: dividends attributable to participating securities (1)(1,808)
Less: redeemable preferred stock dividends(4,861)
Basic loss per share
Loss available to common stockholders(1,972,317)99,952 $(19.73)
Effects of dilutive securities
Dilutive securities (2)0 0 
Diluted loss per share
Loss available to common stockholders and assumed conversions$(1,972,317)99,952 $(19.73)
 Year Ended December 31, 2019
(in thousands, except per share information)Income (Numerator)Shares (Denominator)Per-Share Amount
Net loss$(124,619) 
Less: dividends attributable to participating securities (1)(1,519)
Less: redeemable preferred stock dividends(5,078)
Basic loss per share
Loss available to common stockholders(131,216)98,789 $(1.33)
Effects of dilutive securities
Dilutive securities (2)0 0 
Diluted loss per share
Loss available to common stockholders and assumed conversions$(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 stockholders780,764 93,793 $8.32 
Effects of dilutive securities
Dilutive securities (2)3 27 
Diluted earnings per share
Income available to common stockholders and assumed conversions$780,767 93,820 $8.32 


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  Years Ended December 31,
(in thousands, except per share data) 2017 2016 2015
Basic:  
  
  
Net income (loss) $494,329
 $(408,803) $(2,579,604)
Participating securities’ share in earnings (1) (8,551) —
 —
Net income (loss) available to common stockholders $485,778
 $(408,803) $(2,579,604)
Diluted:  
  
  
Net income (loss) $494,329
 $(408,803) $(2,579,604)
Participating securities’ share in earnings (1) (8,548) —
 —
Net income (loss) available to common stockholders $485,781
 $(408,803) $(2,579,604)
Shares:  
  
  
Basic shares outstanding 93,466
 93,379
 92,992
Dilutive effect of stock options (2) 43
 —
 —
Fully diluted common stock 93,509
 93,379
 92,992
Earnings (loss) per share to common stockholders (3):  
  
  
Basic $5.19
 $(4.38) $(27.75)
Diluted $5.19
 $(4.38) $(27.75)
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(1)Participating securities are not included in undistributed earnings when a loss exists.
(2)Inclusion of certain shares would have an anti-dilutive effect; therefore, 302.9 thousand, 2.1 million, and 2.1 million shares were excluded from the calculations for the years ended December 31, 2017, 2016, and 2015, respectively.
(3)Earnings (loss) per share are based on actual figures rather than the rounded figures presented.
(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 (loss) per share. Excluded from the calculation for the year ended December 31, 2020 were 547.4 thousand potential common shares from the assumed exercise of employee stock options, 512.4 thousand potential common shares from the assumed conversion of the Preferred Stock, and 8.8 thousand potential common shares from the assumed vesting of incremental shares of unvested restricted stock units. Excluded from the calculation for the year ended December 31, 2019 were 491.1 thousand potential common shares from the assumed exercise of employee stock options, 426.4 thousand potential common shares from the assumed conversion of the Preferred Stock, and 37.4 thousand potential common shares from the assumed vesting of incremental shares of unvested restricted stock awards. Excluded from the calculation for the year ended December 31, 2018 were 392.8 thousand potential common shares from assumed exercise of employee stock options. See Note 2 for further information regarding our 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, 20172020 and 2016.2019.


(in thousands)20202019
Asset retirement obligation at January 1,$181,869 $166,904 
Liabilities incurred4,491 21,511 
Liability settlements and disposals(21,922)(19,595)
Accretion expense7,485 7,499 
Revisions of estimated liabilities5,944 5,550 
Asset retirement obligation at December 31,177,867 181,869 
Less current obligation12,272 27,824 
Long-term asset retirement obligation$165,595 $154,045 
(in thousands) 2017 2016
Asset retirement obligation at January 1, $154,523
 $164,105
Liabilities incurred 17,996
 3,914
Liability settlements and disposals (12,947) (24,108)
Accretion expense 7,534
 7,595
Revisions of estimated liabilities 2,363
 3,017
Asset retirement obligation at December 31, 169,469
 154,523
Less current obligation 11,048
 13,753
Long-term asset retirement obligation $158,421
 $140,770

Liabilities incurred in 2017 includes $10.5during the year ended December 31, 2019 included $9.4 million for the estimated liability to decommission two offshore properties in the Gulf of Mexico in which we were a prior lessee. In January 2018, the Bureau of Safety and Environmental Enforcement (“BSEE”) notified us and other prior lessees that the current lessee of the properties had filed a petition for relief under the bankruptcy code and, as a result, had defaulted on its obligation to decommission the properties. Consequently, BSEE ordered us and other prior lessees to decommission all wells, pipelines, platforms, and other facilities related to these properties. Our estimate of our liability may change as we refine our understanding of the extent of our obligations under the orders from BSEE and obtain additional information on decommissioning costs.Resolute acquisition.


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During 2017 and 2016, the liability settlements and disposals included $0.5 million and $14.9 million, respectively, related to properties that were sold.
9. INCOME TAXES

The components of theour provision for income taxes arewere as follows:


 Years Ended December 31,
(in thousands)202020192018
Current taxes:   
Federal benefit$(198)$0 $(3,007)
State expense167 532 383 
 (31)532 (2,624)
Deferred taxes:   
Federal (benefit) expense(323,597)(24,055)211,717 
State (benefit) expense(35,299)(2,847)21,563 
 (358,896)(26,902)233,280 
 $(358,927)$(26,370)$230,656 
  Years Ended December 31,
(in thousands) 2017 2016 2015
Current taxes:  
  
  
Federal (benefit) expense $(2,810) $—
 $14,417
State (benefit) expense (2) (1,115) 293
  (2,812) (1,115) 14,710
Deferred taxes:  
  
  
Federal expense (benefit) 173,859
 (201,529) (1,386,086)
State expense (benefit) 16,620
 (11,757) (100,353)
  190,479
 (213,286) (1,486,439)
  $187,667
 $(214,401) $(1,471,729)


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, revisions, and changes in tax laws and tax rates enacted in the period.period, and changes in valuation allowances. Reconciliations of the income tax (benefit) expense (benefit) calculated at the federal statutory rate of 35%21% to the total income tax (benefit) expense (benefit) are as follows:

 Years Ended December 31,
(in thousands)202020192018
Provision at statutory rate$(488,541)$(31,708)$214,726 
Effect of state taxes(29,467)(1,717)18,795 
Acquisition-related costs0 1,318 0 
Tax credits and other permanent differences1,365 2,548 1,583 
Change in valuation allowance, net(4,221)0 (1,376)
Stock-based compensation11,903 3,189 (3,072)
Goodwill impairment150,034 0 0 
Income tax (benefit) expense$(358,927)$(26,370)$230,656 


  Years Ended December 31,
(in thousands) 2017 2016 2015
Provision at statutory rate $238,699
 $(218,122) $(1,417,967)
Effect of state taxes 10,074
 (10,237) (64,794)
Revision of previous balances —
 7,181
 5,997
Tax credits and other permanent differences 5,442
 5,296
 5,035
Change in valuation allowance, net 486
 1,481
 —
Stock-based compensation (5,888) —
 —
Impact of reduction in federal statutory rate (61,146) —
 —
Income tax expense (benefit) $187,667
 $(214,401) $(1,471,729)

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The company recorded a $33.1 million increase to the net operating loss deferred tax asset and corresponding increase to retained earnings in the first quarter of 2017 upon adoption of ASU 2016-09 for deductions taken for employee stock awards on the company’s tax returns in excess of amounts expensed through the company’s statement of operations. Pursuant to ASU 2016-09, excess tax benefits for employee share-based payments of $5.9 million were recognized in income tax expense in 2017.
As a result of the enactment of H.R.1 on December 22, 2017, the company remeasured the 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. We believe the accounting for the effects of H.R.1 recognized in the December 31, 2017 financial statements is materially complete. However, evolving analyses and interpretations of the law may cause a change to the amounts presented. Any such changes that may arise will be recognized in the period determined, but no later than December 31, 2018. As a result of H.R.1, we expect our effective tax rate in future periods will be lower than in periods prior to enactment. In addition, the limitations on utilization of net operating losses and deductibility of interest and executive compensation may result in the payment of cash taxes earlier than expected.

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The components of net deferred taxes are as follows:


 December 31,
(in thousands)20202019
Assets:  
Stock-based compensation and other accrued amounts$59,659 $31,521 
Net operating loss and other carryforwards, net of valuation allowance456,613 454,743 
Credit carryforward, net of valuation allowance4,223 3,936 
 520,495 490,200 
Liabilities:  
Property, plant and equipment(500,023)(828,624)
Net deferred tax assets (liabilities)$20,472 $(338,424)
  December 31,
(in thousands) 2017 2016
Assets:  
  
Stock compensation and other accrued amounts $31,044
 $58,306
Net operating loss carryforward, net of valuation allowance 313,738
 399,912
Credit carryforward 3,995
 6,016
  348,777
 464,234
Liabilities:  
  
Property, plant and equipment (450,395) (408,399)
Net deferred tax (liabilities) assets $(101,618) $55,835

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. See Note 13 for more information regarding the purchase price allocation. The net deferred tax liability recorded in connection with the acquisition includes certain deferred tax assets net of valuation allowances. The acquired tax attributes include federal net operating loss, capital loss, and enhanced oil recovery tax credit carryforwards.

Since 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 utilize the Resolute net operating losses (“NOLs”) and other tax attributes acquired is limited to an annual amount calculated at acquisition plus any net unrealized built-in gains recognized within five years of the ownership change. The annual limitation amount is $19.6 million. The estimated net unrealized built-in gain at December 31, 2019 of $253.9 million was increased to $291.0 million at December 31, 2020, pursuant to filed returns and changes in estimates. As of December 31, 2019, the acquired Resolute federal NOLs were reduced by a $57.6 million valuation allowance. As a result of the increase in the estimated net unrealized built-in gain and the utilization of $13.5 million of Resolute’s Section 382 limited tax attributes in Cimarex’s 2019 federal income tax return, the valuation allowance was reduced to $34.0 million at December 31, 2020. A full valuation allowance remains on the Resolute acquired capital loss carryforward of $67.2 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 2033.

At December 31, 2017,2020, we had a U.S. net tax operating loss carryforward (including Resolute) of approximately $1,377.7 million,$1.997 billion, $1.773 billion of which would expireis subject to expiration in years 20312032 through 2037.2037 and $224.4 million of which is not subject to expiration. We believe that the carryforward, net of valuation allowance, will be utilized before it expires. WeAt December 31, 2020, we recorded a $3.5$1.7 million increase to the net operating loss carryforward at December 31, 2017, for certain state losses and a corresponding increase in thevaluation allowance related to state net operating loss valuation allowance of $4.0 million. The net decrease in the state net operating losses after reduction for the valuation allowance was $0.5 million.losses. The total valuation allowance on state net operating losses at December 31, 20172020 was $103.7$120.7 million becausesince it is not more likely than not that these additional state net operating losses will be utilized before they expire. There are no other valuation allowances. We also had an alternative minimum tax credit carryforward of approximately $3.0 million and enhanced oil recovery and marginal well credits of $0.9 million.$4.2 million at December 31, 2020.

When assessing the need for a valuation allowance against a deferred tax asset, both positive and negative evidence is considered when determining the ability to utilize our deferred tax assets. Based on our estimate of the timing of future reversals of existing taxable temporary differences, our estimate of future taxable income exclusive of reversing temporary differences and carryforwards, the length of time before the deferred tax assets associated with the net operating loss carryovers begin to expire, and tax planning strategies that could be implemented to accelerate taxable amounts to utilize expiring carryovers, we believe it is more likely than not that the benefit from


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the deferred tax asset recorded in the financial statements will be realized. We will continue to assess all available positive and negative evidence to estimate whether sufficient future taxable income will be generated in order to utilize the deferred tax assets. Additional valuation allowances may be required in future periods if additional losses are incurred or other circumstances change.

At December 31, 20172020 and 2016,2019, 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 20142017 through 20162019 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 20132016 through 2016.2019. We do not anticipate the need for any significant income tax payments in the near term.


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 commitmentsoperating leases for office space underin 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 lease arrangements. Duringexpenses and taxes incurred by the years ended December 31, 2017, 2016, and 2015, rent expense for these operating leases approximated $13.1 million, $12.9 million, and $13.2 million, respectively.
Shown below are future minimum cash payments required underlandlord. At our option, the terms of these leases ascan be renewed for varying periods, and in some cases may be terminated early at our option. As of December 31, 2017.
(in thousands)  
2018 $9,742
2019 10,702
2020 10,836
2021 11,053
2022 11,222
Later years 32,645
Total future minimum lease payments $86,200
2020, these leases had remaining lease terms ranging from 3.4 to 5.7 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 various commitmentsno 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 compressor equipment under operatingour 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 arrangements totaling $8.5 million withcomponents 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 terms expiring in the next 2 - 24 months.components would be insignificant.


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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, 2020, these leases had remaining lease terms ranging from one month to 10.4 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.

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.

•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 production-related class of assets.

We have 1 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, 2020, this lease had a remaining term of 4.7 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, 2020, 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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Balance Sheet Presentation

The following tables present the amounts and classifications of our estimated right-of-use assets, net and lease liabilities as of December 31, 2020 and 2019:

December 31,
(in thousands)Balance Sheet Location20202019
Operating lease right-of-use assetsNon-current assets — Fixed assets, net$185,118 $240,263 
Finance lease right-of-use assetNon-current assets — Other assets25,052 24,849 
Total right-of-use assets$210,170 $265,112 

December 31,
(in thousands)Balance Sheet Location20202019
Operating lease liabilities — currentCurrent liabilities — Operating leases$59,051 $66,003 
Operating lease liabilities — non-currentNon-current liabilities — Operating leases134,705 184,172 
Finance lease liability — currentCurrent liabilities — Accrued liabilities — Other7,099 7,328 
Finance lease liability — non-currentNon-current liabilities — Other liabilities19,731 18,749 
Total lease liabilities$220,586 $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 periods:

Years Ended December 31,
(in thousands)20202019
Finance lease cost:
Amortization of right-of-use asset$5,286 $4,385 
Interest on lease liability1,663 1,719 
Operating lease cost:
Production expense (1)19,914 20,965 
Transportation, processing, and other operating (1)21,386 17,264 
Gas gathering and other expense (1)991 5,607 
General and administrative expense (2)12,701 12,421 
Short-term lease cost (3)235,840 539,110 
Total lease cost$297,781 $601,471 

(1)Operating lease cost in the table above is composed of costs incurred under production-related leases. These costs are included in the indicated captions on the Consolidated Statements of Operations and Comprehensive Income (Loss).
(2)Operating lease cost in the table above is composed of costs incurred under real estate leases. A majority of these costs are included in the indicated caption on the Consolidated Statements of Operations and Comprehensive Income (Loss). A portion of these costs are capitalized as part of proved properties on the


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Consolidated Balance Sheets. These costs include variable lease costs of $3.2 million and $3.1 million for the years ended December 31, 2020 and 2019, respectively.
(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 costs. These costs are capitalized as part of proved properties on the Consolidated Balance Sheets.

The following table summarizes estimated cash paid for our leases for the indicated periods:

Years Ended December 31,
(in thousands)20202019
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash outflows from finance lease$4,842 $3,869 
Operating cash outflows from operating leases$53,066 $54,044 
Cash paid for short-term leases and variable lease payments:
Operating cash outflows from operating leases$3,169 $3,103 
Investing cash outflows from operating leases$235,024 $551,325 

During the years ended December 31, 2020 and 2019, we recognized $42.7 million and $91.7 million, respectively, in right-of-use assets in connection with new operating leases entered into during the period.

The following table presents the weighted-average remaining lease terms and discount rates of our leases as of the indicated dates:

December 31,
20202019
Weighted-average remaining lease term (in years):
Finance lease4.75.9
Operating leases3.94.1
Weighted-average discount rate:
Finance lease6.3 %5.7 %
Operating leases5.0 %3.9 %



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Lease Liability Maturity Analysis

The following table reflects the undiscounted future cash flows utilized in the calculation of the lease liabilities recorded at December 31, 2020:

December 31, 2020
(in thousands)Operating LeasesFinance Lease
January 1, 2021 — December 31, 2021$67,330 $7,618 
January 1, 2022 — December 31, 202261,595 6,666 
January 1, 2023 — December 31, 202341,567 6,340 
January 1, 2024 — December 31, 202421,259 6,015 
January 1, 2025 — December 31, 20258,438 3,829 
Remaining periods14,695 0 
Total undiscounted future cash flows214,884 30,468 
Less effects of discounting(21,128)(3,638)
Lease liabilities recognized$193,756 $26,830 

Other Commitments


At December 31, 2017,2020, we had estimated commitments of approximately: (i) $252.6$224.2 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $33.3$4.3 million to finish gathering systemmidstream construction in progress.

At December 31, 2017,2020, we had firm sales contracts to deliver approximately 217.6470.3 Bcf of gas over the next 7.110.5 years.  If we do not deliver this gas, our estimated financial commitment, calculated using the January 20182021 index price,prices, would be approximately $476.7$908.1 million.  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 8.38.0 years.  If we do not deliver the committed gas or NGLs, as the case may be,applicable, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2017,2020, would be approximately $298.3$640.7 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 associated with agreements to reimburse connection costs to various pipelines.  If we do not deliver this gas or oil, as applicable, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2017,2020, would be approximately $11.4$104.7 million.  However,Of this total, we believe no financial commitmenthave accrued a liability of $4.3 million representing the estimated amount we will behave to pay due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.to insufficient forecasted volumes at particular connection points.

At December 31, 2017,2020, we have various firm transportation agreements for gas pipeline capacity with end dates ranging from 20182021 - 2025 under which we will have to pay an estimated $36.5$16.6 million over the remaining terms of the agreements. These agreements were

We have minimum volume water delivery commitments associated with a water services agreement, which ends in 2030, that was entered into to support our residue marketing efforts, andin connection with the sale of certain water infrastructure assets in Eddy County, New Mexico (see Note 13). If we believe we have sufficient reservesdo not deliver the water volumes, the estimated maximum amount that will utilizewould be payable under this firm transportation.commitment, calculated as of December 31, 2020, would be approximately $64.1 million.

All of the noted commitments were routine and made in the normalordinary course of our business.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Litigation

In the normalordinary course of business, we are involved with various litigation matters. When 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 amount of loss can be reasonably estimated, all in accordance with authoritative accounting guidance, established by the FASB, and adjust our accruals accordingly. Though some of the related claims may be significant, we believe 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 31, 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.

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11. RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to Cimarex. Cimarex incurred drilling costs of approximately $52.6$24.9 million, $18.3$72.8 million, and $7.9$80.1 million related to these services during the years ended December 31, 2017, 2016,2020, 2019, and 2015,2018, respectively. The amounts incurred in the years ended December 31, 2020 and 2019 are included in the short-term lease costs disclosed in Note 10. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.


12. SUPPLEMENTAL CASH FLOW INFORMATION

 Years Ended December 31,
(in thousands)202020192018
Cash paid during the period for:   
Interest expense (net of capitalized amounts of $48,306, $49,944, and $19,969, respectively) (1)$41,407 $50,601 $45,357 
Income taxes$300 $1,364 $0 
Cash received for income tax refunds$2,118 $2,033 $760 
 ________________________________________
(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.




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  Years Ended December 31,
(in thousands) 2017 2016 2015
Cash paid during the period for:  
  
  
Interest expense (net of capitalized amounts of $23,113, $20,308, and $28,819, respectively) $52,245
 $59,282
 $51,966
Income taxes $3
 $13
 $558
Cash received for income tax refunds $111
 $1,450
 $1,503


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13. ACQUISITIONS AND DIVESTITURES

On August 31, 2018, we closed on the divestiture of oil and gas properties principally located in Ward County, Texas for which we received $534.6 million 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 September 30, 2020, we closed on the sale of certain water infrastructure assets in Eddy County, New Mexico, for which we received net cash proceeds of $68.7 million during 2020, as adjusted for customary closing adjustments and transaction costs. We will be entitled to additional future cash payments from the buyer upon the delivery of certain rights-of-way and if water volumes delivered by Cimarex or third parties meet certain thresholds during the 10 years following the date of sale. See Note 10 for more information on this sale.

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 Permian Basin of west Texas. The principal factors considered by management in making this acquisition included: (i) our expectation that Resolute’s assets’ returns would be 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 would 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 2 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.



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Purchase Price Allocation

The Resolute acquisition has been accounted for as a business combination, using the acquisition method. The following table presents the 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 made to the purchase price allocation during the 12-month period following the acquisition date. The purchase price allocation was finalized during the three months ended March 31, 2020. 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 income taxes 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 finalization of working capital balances. The offset to all of the adjustments was goodwill.

The following table sets forth the purchase price allocation:

(in thousands)March 1, 2019AdjustmentsMarch 1, 2020
Cash$41,236 $0 $41,236 
Accounts receivable50,739 11,521 62,260 
Other current assets13,280 (1,176)12,104 
Proved oil and gas properties692,600 0 692,600 
Unproved oil and gas properties1,054,200 (30,314)1,023,886 
Fixed assets5,355 (32)5,323 
Goodwill107,341 (13,126)94,215 
Other assets142 0 142 
Current liabilities(202,735)1,790 (200,945)
Long-term debt(870,000)0 (870,000)
Deferred income taxes(62,409)31,337 (31,072)
Asset retirement obligation(9,437)0 (9,437)
Total identifiable net assets$820,312 $0 $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 were 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.

Goodwill of $94.2 million was recognized in the purchase price allocation 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. We concluded that goodwill was impaired at March 31, 2020 (see Note 1 for more information regarding the goodwill impairment).



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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).

Pro Forma Financial Information (Unaudited)

The results of Resolute’s operations have been included in our consolidated financial statements since the March 1, 2019 acquisition date. 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 and Resolute. 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)20192018
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 





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Oil and Gas Reserve Information—Proved reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (“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 2326 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 1316 years.


DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewedperformed an independent evaluation of our estimated net reserves associated withrepresenting greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of December 31, 2017.2020.  The individual primarily responsible for overseeing the reviewevaluation is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over 3310 years of experience in oil and gas reservoir studies and reserves evaluations.


Proved reserves are those quantities of oil, gas, and 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 involved in this estimation process.


The following table summarizes the trailing twelve-month index prices used in the reserves estimates for 2017, 2016,2020, 2019, and 2015.2018.  These prices are prior to adjustments for fixed and determinable amounts under provisions in existing contracts, location, grade, and quality.

December 31, December 31,
2017 2016 2015 202020192018
Gas price per Mcf$2.98
 $2.48
 $2.59
Gas price per Mcf$1.99 $2.58 $3.10 
Oil price per Bbl$51.34
 $42.75
 $50.28
Oil price per Bbl$39.54 $55.67 $65.56 
NGL price per Bbl$19.09
 $14.37
 $14.41



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The following table sets forth our estimates of our proved, proved developed, and proved undeveloped oil, gas, and NGL reserves as of December 31, 2017, 2016, 2015,2020, 2019, 2018, and 20142017 and changes in our proved reserves for the years ended December 31, 2017, 2016,2020, 2019, and 2015.2018. All of our proved reserves are located entirely within the U.S.United States of America.

Gas
(MMcf)		Oil
(MBbls)		NGL
(MBbls)		Total
(MBOE)
Total proved reserves:    
December 31, 20171,607,635 137,238 153,860 559,037 
Revisions of previous estimates(132,577)(4,348)3,777 (22,667)
Extensions and discoveries342,810 53,763 47,614 158,512 
Purchases of reserves3 — — 1 
Production(205,837)(24,710)(21,994)(81,010)
Sales of reserves(20,713)(15,405)(3,821)(22,678)
December 31, 20181,591,321 146,538 179,436 591,195 
Revisions of previous estimates(180,632)(8,516)(12,038)(50,661)
Extensions and discoveries247,406 41,193 36,834 119,261 
Purchases of reserves129,435 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, 20191,532,145 169,770 194,468 619,595 
Revisions of previous estimates(43,504)(19,692)(25,488)(52,430)
Extensions and discoveries107,322 22,269 16,419 56,575 
Purchases of reserves— — — — 
Production(232,625)(28,087)(25,554)(92,412)
Sales of reserves(496)(197)(27)(307)
December 31, 20201,362,842 144,063 159,818 531,021 
Proved developed reserves:    
December 31, 20171,334,510 114,116 126,227 462,761 
December 31, 20181,398,729 116,339 151,566 501,027 
December 31, 20191,358,329 138,783 166,552 531,722 
December 31, 20201,190,907 112,785 135,901 447,170 
Proved undeveloped reserves:    
December 31, 2017273,125 23,122 27,633 96,276 
December 31, 2018192,592 30,199 27,870 90,168 
December 31, 2019173,816 30,987 27,916 87,873 
December 31, 2020171,935 31,278 23,917 83,851 
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MMcfe)
Total proved reserves: 
  
  
  
December 31, 20141,666,733
 118,992
 125,273
 3,132,323
Revisions of previous estimates(154,390) (14,633) (5,668) (276,192)
Extensions and discoveries183,084
 22,859
 18,079
 428,714
Purchases of reserves15
 1
 1
 25
Production(168,987) (18,663) (13,063) (359,343)
Sales of reserves(9,503) (758) (345) (16,120)
December 31, 20151,516,952
 107,798
 124,277
 2,909,407
Revisions of previous estimates5,888
 (4,357) 6,670
 19,761
Extensions and discoveries123,175
 19,419
 14,050
 323,987
Purchases of reserves959
 1
 —
 965
Production(168,227) (16,528) (14,200) (352,591)
Sales of reserves(7,327) (455) (164) (11,042)
December 31, 20161,471,420
 105,878
 130,633
 2,890,487
Revisions of previous estimates(39,749) (1,225) (2,099) (59,706)
Extensions and discoveries363,774
 53,464
 42,692
 940,714
Purchases of reserves642
 42
 78
 1,363
Production(187,468) (20,861) (17,374) (416,875)
Sales of reserves(984) (60) (70) (1,761)
December 31, 20171,607,635
 137,238
 153,860
 3,354,222
Proved developed reserves: 
  
  
  
December 31, 20141,263,957
 100,050
 89,630
 2,402,033
December 31, 20151,129,490
 89,189
 87,549
 2,189,920
December 31, 20161,144,720
 92,032
 99,176
 2,291,966
December 31, 20171,334,510
 114,116
 126,227
 2,776,565
Proved undeveloped reserves: 
  
  
  
December 31, 2014402,776
 18,942
 35,643
 730,290
December 31, 2015387,462
 18,609
 36,728
 719,487
December 31, 2016326,700
 13,846
 31,457
 598,521
December 31, 2017273,125
 23,122
 27,633
 577,657

Year-end 20172020 proved reserves increaseddecreased approximately 16%14% from year-end 20162019 proved reserves, to 3.35 Tcfe.531.0 MMBOE.  Proved natural gas reserves were 1.611.36 Tcf, proved oil reserves were 0.82 Tcfe,144.1 MMBbls, and proved NGL reserves were 0.92 Tcfe.159.8 MMBbls.  Our reserves in the Mid-ContinentPermian Basin accounted for 52%68% of total proved reserves, with nearly all of the remainder in the Permian Basin.Mid-Continent.

During 2017,2020, we added 940.7 Bcfe56.6 MMBOE of proved reserves through extensions and discoveries, primarily in the Mid-Continent and Permian Basin where we added 282.9 Bcfe47.8 MMBOE, with the remaining 8.8 MMBOE in additions being in the Mid-Continent. We had net negative revisions of 52.4 MMBOE, which consisted of 70.3 MMBOE in downward price


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revisions, 10.0 MMBOE associated with the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure, and 657.8 Bcfe,2.8 MMBOE in net negative technical revisions primarily related to offset completion impacts. These negative revisions were partially offset by 30.7 MMBOE in positive revisions related to decreases in operating expenses.

During 2019, we added 119.3 MMBOE of proved reserves through extensions and discoveries, primarily in the Permian Basin and Mid-Continent where we added 99.9 MMBOE and 19.4 MMBOE, respectively. 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 revisions of 50.7 MMBOE, which consisted of 47.2 MMBOE in downward price revisions and 7.0 MMBOE related to increases in operating expenses. In addition, 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 were partially offset by net positive technical revisions of 17.1 MMBOE primarily related to better than expected performance from wells with initial production in late 2018 and positive adjustments to PUD reserves converted to proved developed reserves during 2019.

During 2018, we added 158.5 MMBOE of proved reserves through extensions and discoveries, primarily in the Permian Basin and Mid-Continent where we added 120.3 MMBOE and 38.0 MMBOE, respectively. In addition, we had net negative revisions of 59.7 Bcfe.22.7 MMBOE. The revisions included decreases of 248.8 Bcfe38.6 MMBOE for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure and 43.9 Bcfe7.7 MMBOE related to increases in operating expenses. These decreases were partially offset by increases of 187.2 Bcfe2.7 MMBOE in price-related revisions and 45.8 Bcfe20.9 MMBOE of net technical revisions. The majority of the technical revisions were related primarily to better than expected performance from wells with initial production in late 2016.

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During 2016, we added 324.0 Bcfe of proved reserves through extensions2017 and discoveries, primarily in the Mid-Continent and Permian Basin where we added 121.6 Bcfe and 198.7 Bcfe, respectively.  In addition, we had net positive 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, partially offset by negative revisions of 244.9 Bcfe due 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.

During 2015, we added 428.7 Bcfe of proved reserves through extensions and discoveries, primarily in the Mid-Continent and Permian Basin, where we added 176.8 Bcfe and 251.1 Bcfe, respectively.  During 2015, we had net negative reserve revisions of 276.2 Bcfe.  The significant decrease in commodity prices seen in 2015 resulted in negative revisions of 398.8 Bcfe due to prices.  In addition, 19.1 Bcfe of negative revisions were due to increases in operating expenses, which shortened the economic lives of properties.  These decreases were partially offset by net positive performance revisions of 141.7 Bcfe, which included 47.4 Bcfe for better than expected performance of PUD reserves converted to proved developed reserves during the year and positive adjustments of 95.3 Bcfe to previously booked PUD reserves.2018.

At December 31, 2017,2020, we had PUD reserves of 577.7 Bcfe,83.9 MMBOE, down 20.8 Bcfe,4.0 MMBOE, or 3%5%, from 598.5 Bcfe87.9 MMBOE of PUD reserves at December 31, 2016.2019.  Changes in our PUD reserves during 2020 are summarized in the table below (in Bcfe).below.

PUD Reserves
(MMBOE)
PUD reserves at December 31, 20162019598.587.9 
Converted to developed(61.1(30.5))
Additions307.340.5 
Net revisions(267.0(14.0))
PUD reserves at December 31, 20172020577.783.9 


During 2017,2020, we invested $69.5$154.9 million to develop and convert 10%35% of our 20162019 PUD reserves to proved developed reserves. During 2016,2019, we invested $108.8$399.5 million to develop PUD reserves, converting 14%and convert 66% of our 20152018 PUD reserves to proved developed reserves. During 2015,2018, we invested $246.5$264.5 million to develop PUD reserves, converting 24%and convert 30% of our 20142017 PUD reserves to proved developed reserves.


During 2017, 234.4 Bcfe, or 76%, of2020, our 307.3 Bcfe40.5 MMBOE of PUD reserve additions occurredconsisted of 33.8 MMBOE added in the Permian Basin while the remainder of the additions wereand 6.7 MMBOE added in our western Oklahoma Cana area.Mid-Continent. At December 31, 2017, 41%2020, 90% of our PUD reserves were in the Permian Basin, while the remainder were in our western Oklahoma Cana area. During 2020, we had net negative PUD reserve revisions of 14.0 MMBOE.  Of this total, 10.0 MMBOE was for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure and the majority of the remainder was due to downward price revisions. We have no PUD reserves that have remained undeveloped for five years or more after initial disclosure and we have no PUD reserves whose scheduled delay to initiation of development is beyond five years of initial disclosure.


During 2017, we had net negative PUD reserve revisions of 267.0 Bcfe.  Of this total, 248.8 Bcfe was for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure. The remaining 18.2 Bcfe of net negative adjustments was comprised of negative technical revisions of 20.1 Bcfe to remaining previously booked PUD reserves and 4.5 Bcfe of negative revisions from higher projected operating expenses that were partially offset by 6.4 Bcfe of positive price-related revisions.

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Costs Incurred—The following table sets forth the capitalizedour costs incurred in our oil and gas production,for property acquisition, exploration, and development activities.

 Years Ended December 31,
(in thousands)202020192018
Acquisition of properties   
Proved$11,878 $695,450 $62 
Unproved46,946 1,083,230 102,666 
Exploration1,522 2,321 6,341 
Development496,388 1,181,605 1,487,453 
$556,734 $2,962,606 $1,596,522 
  Years Ended December 31,
(in thousands) 2017 2016 2015
Costs incurred during the year:  
  
  
Acquisition of properties  
  
  
Proved $938
 $2,678
 $30
Unproved 135,565
 67,961
 41,233
Exploration 11,804
 5,814
 6,902
Development 1,140,548
 672,842
 823,830
Oil and gas expenditures 1,288,855
 749,295
 871,995
Property sales (11,680) (24,687) (41,276)
  1,277,175
 724,608
 830,719
Asset retirement obligation, net 9,416
 (7,950) (4,818)
  $1,286,591
 $716,658
 $825,901


Aggregate Capitalized Costs—The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at December 31, 2017.2020.


(in thousands)December 31, 2020
Proved properties$21,281,840 
Unproved properties and properties under development, not being amortized1,142,183 
22,424,023 
Less—accumulated depreciation, depletion, amortization, and impairment(18,987,354)
Net oil and gas properties$3,436,669 
(in thousands)  
Proved properties $17,513,460
Unproved properties and properties under development, not being amortized 476,903
  17,990,363
Less-accumulated depreciation, depletion, amortization, and impairments (14,748,833)
Net oil and gas properties $3,241,530


Costs Not Being Amortized—The following table summarizes oil and gas property costs not being amortized at December 31, 2017,2020, by year that the costs were incurred.


(in thousands)December 31, 2020
2020$197,861 
2019827,418 
201865,770 
2017 and prior51,134 
 $1,142,183 
(in thousands)  
2017 $266,124
2016 53,076
2015 32,592
2014 and prior 125,111
  $476,903


Of the costs not being amortized, $140.0$151.4 million (29%(13%) relates to unevaluated wells in progress and $47.7$98.3 million (10%(9%) is capitalized interest.  The remaining $289.2$892.5 million (61%(78%) is for land and seismic expenditures, most of which were for costs invested in our Mid-Continent regionPermian Basin ($104.6852.6 million) and ourMid-Continent ($39.3 million). The majority of the Permian Basin region ($169.1 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—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, with the 20172020 effective tax rate adjusted to remove the impact ofgoodwill impairment not deductible for tax purposes and the reductionchange in the federal statutory rate.valuation allowance.


 Years Ended December 31,
(in thousands, except per BOE)202020192018
Oil, gas, and NGL revenues from production$1,512,688 $2,321,921 $2,297,645 
Less operating costs and income taxes:   
Impairment of oil and gas properties1,638,329 618,693 — 
Depletion625,481 817,099 538,919 
Asset retirement obligation14,653 8,586 7,142 
Production285,324 339,941 296,189 
Transportation, processing, and other operating213,366 238,259 211,463 
Taxes other than income79,699 148,953 125,169 
Income tax (benefit) expense(295,716)26,318 252,840 
 2,561,136 2,197,849 1,431,722 
Results of operations from oil and gas producing activities$(1,048,448)$124,072 $865,923 
Depletion rate per BOE$6.77 $8.04 $6.65 
  Years Ended December 31,
(in thousands, except per Mcfe) 2017 2016 2015
Oil, gas, and NGL revenues from production $1,874,003
 $1,221,218
 $1,417,538
Less operating costs and income taxes:  
  
  
Impairment of oil and gas properties —
 757,670
 4,033,295
Depletion 399,328
 346,003
 689,120
Asset retirement obligation 15,624
 7,828
 9,121
Production 262,180
 232,002
 299,374
Transportation, processing, and other operating 254,730
 210,144
 183,134
Taxes other than income 89,864
 61,946
 84,764
Income tax expense (benefit) 310,937
 (135,665) (1,410,065)
  1,332,663
 1,479,928
 3,888,743
Results of operations from oil and gas producing activities $541,340
 $(258,710) $(2,471,205)
Depletion rate per Mcfe $0.96
 $0.98
 $1.92


Standardized Measure of Future Net Cash Flows—The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas 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)202020192018
Future cash inflows$7,167,623 $11,726,488 $14,050,367 
Future production costs(3,193,242)(4,619,438)(4,889,601)
Future development costs(525,714)(814,397)(1,017,318)
Future income tax expenses(66,555)(578,675)(1,303,762)
Future net cash flows3,382,112 5,713,978 6,839,686 
10% annual discount for estimated timing of cash flows(1,129,593)(2,084,952)(2,824,499)
Standardized measure of discounted future net cash flows$2,252,519 $3,629,026 $4,015,187 

  December 31,
(in thousands) 2017 2016 2015
Future cash inflows $11,967,325
 $7,576,211
 $8,839,485
Future production costs (4,360,599) (2,970,891) (3,521,881)
Future development costs (948,735) (794,298) (1,058,020)
Future income tax expenses (882,519) (507,145) (728,029)
Future net cash flows 5,775,472
 3,303,877
 3,531,555
10% annual discount for estimated timing of cash flows (2,490,471) (1,411,259) (1,597,424)
Standardized measure of discounted future net cash flows $3,285,001
 $1,892,618
 $1,934,131

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SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)



The estimates of cash flows shown above are based upon the unweighted trailing twelve-month average first-day-of-the-month benchmark prices.  See table above under Oil 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, economic, and economicother factors.

The following are the principal sources of change in the Standardized Measure.

 Years Ended December 31,
(in thousands)202020192018
Standardized measure, beginning of period$3,629,026 $4,015,187 $3,285,001 
Sales, net of production costs(934,299)(1,594,768)(1,660,649)
Net change in sales prices and in production costs related to future production(1,465,206)(1,267,223)377,178 
Extensions and discoveries, net of future production and development costs261,090 758,685 1,738,993 
Changes in estimated future development costs130,440 35,940 194,523 
Previously estimated development costs incurred during the period306,225 640,292 335,954 
Revisions of quantity estimates(273,738)(304,217)96,783 
Accretion of discount394,835 473,919 372,482 
Change in income taxes283,764 404,681 (284,186)
Purchases of reserves in place— 568,897 — 
Sales of reserves in place(3,838)(18,330)(300,592)
Change in production rates and other(75,780)(84,037)(140,300)
Standardized measure, end of period$2,252,519 $3,629,026 $4,015,187 



109
  Years Ended December 31,
(in thousands) 2017 2016 2015
Standardized Measure, beginning of period $1,892,618
 $1,934,131
 $4,352,845
Sales, net of production costs (1,267,229) (717,126) (850,267)
Net change in sales prices, net of production costs 855,024
 (429,956) (4,262,261)
Extensions and discoveries, net of future production and development costs 1,443,577
 517,702
 573,373
Changes in future development costs 298,819
 167,387
 280,163
Previously estimated development costs incurred during the period 78,398
 110,945
 214,749
Revision of quantity estimates (65,376) 15,701
 (240,063)
Accretion of discount 212,192
 227,904
 638,948
Change in income taxes (210,519) 115,609
 1,691,721
Purchases of reserves in place 2,255
 429
 20
Sales of reserves (1,666) (9,440) (26,225)
Change in production rates and other 46,908
 (40,668) (438,872)
Standardized Measure, end of period $3,285,001
 $1,892,618
 $1,934,131


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CIMAREX ENERGY CO.


SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)



  Quarter
2017 First Second Third Fourth
(in thousands, except per share data)        
Revenues $447,176
 $456,452
 $463,681
 $550,940
Expenses, net 316,204
 359,190
 372,282
 376,244
Net income $130,972
 $97,262
 $91,399
 $174,696
Earnings per share to common stockholders:  
  
  
  
Basic $1.38
 $1.02
 $0.96
 $1.83
Diluted $1.38
 $1.02
 $0.96
 $1.83
  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 (loss) income $(231,459) $(214,454) $(10,673) $47,783
Earnings (loss) per share to common stockholders:  
  
  
  
Basic $(2.49) $(2.31) $(0.12) $0.50
Diluted $(2.49) $(2.31) $(0.12) $0.50

(1)
The 2016 quarterly expenses, net include non-cash impairments to our oil 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.
The tables below summarize our quarterly financial data for 2020 and 2019. The sum of the individual quarterly earnings (loss) per common share amounts may not agree with year-to-date 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.


 Quarter
2020FirstSecondThirdFourth
(in thousands, except per share data)    
Revenues$472,830 $249,383 $401,659 $434,723 
Expenses, net1,247,112 1,174,530 694,399 410,012 
Net (loss) income$(774,282)$(925,147)$(292,740)$24,711 
Earnings (loss) per share to common stockholders:    
Basic$(7.77)$(9.28)$(2.94)$0.25 
Diluted$(7.77)$(9.28)$(2.94)$0.25 


 Quarter
2019FirstSecondThirdFourth
(in thousands, except per share data)    
Revenues$576,957 $546,463 $582,305 $657,244 
Expenses, net550,641 437,154 458,458 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)

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Cimarex’s management, under the supervision and with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), havehas 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)(“Exchange Act”)) as of December 31, 2017.2020.  Based on that evaluation, the CEO and CFO concluded that the disclosure controls and procedures are effective in providing 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.

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’sCompany’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.  OurThe 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.

As of December 31, 2017,2020, 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). Based on that assessment, management concluded that the internal control over financial reporting was effective as of December 31, 2017.2020.

OurThe Company’s independent registered public accounting firm, KPMG LLP, hasthat audited the effectivenessconsolidated financial statements included in Item 8 of ourthis Form 10-K has also audited the Company’s internal control over financial reporting and has issued a report as of December 31, 2017, which follows2020 and has issued an attestation report. KPMG LLP’s attestation report on the Company’s internal control over financial reporting is included later in this report.Item 9A of this Form 10-K.



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CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter ended December 31, 20172020 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
To the Stockholders and Board of Directors
Cimarex Energy Co.:

Opinion on Internal Control Over Financial Reporting

We have audited Cimarex Energy Co. and subsidiaries’ (the “Company”)Company) internal control over financial reporting as of December 31, 2017,2020, based on criteria established inInternal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2020, 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”)(PCAOB), the consolidated balance sheets of the Company as of December 31, 20172020 and 2016,2019, 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, 2017,2020, and the related notes (collectively, the consolidated financial statements), and our report dated February 23, 20182021 expressed an unqualified opinion 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 the Company’s internal control over financial reporting based on our audit. 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 audit in accordance with the standards of the 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.


/s/ KPMG LLP


Denver, Colorado
February 23, 2018


2021
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ITEM 9B. OTHER INFORMATION

None.



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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information concerning the directors of Cimarex and the late filing of a Form 5 required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 10, 201812, 2021 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, 2017.2020. The executive officers of Cimarex as of February 23, 20182021 were:

NameAgeOffice
Thomas E. Jorden6063Chairman of the Board, Chief Executive Officer, and President
Joseph R. Albi59Executive Vice President — Operations, Chief Operating Officer
Stephen P. Bell6366Executive Vice President — Business Development
G. Mark Burford5053Senior Vice President and Chief Financial Officer
Francis B. Barron5558Senior Vice President — General Counsel
John A. Lambuth5558Executive Vice President — Exploration
Christopher H. Clason54Senior Vice President and Chief Human Resources Officer
Thomas F. McCoy58Senior Vice President — ExplorationProduction
Blake A. Sirgo38Vice President — Operations
Gary R. Abbott4548Vice President — Corporate Engineering
Krista L. Johnson47Vice President — Human Resources, Governmental Relations, and External Affairs
Timothy A. Ficker5053Vice 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 shethe officer 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 BURFORD  was 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 appointed2015 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.


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JOHN A. LAMBUTH was named Executive Vice President of Exploration in February 2020. He served as Senior Vice President of Exploration infrom December 2015. Prior to his promotion, he2015 until February 2020. He previously served as the Company’s Vice President of Exploration sincebeginning 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 was named Senior Vice President and Chief Human Resources Officer in February 2020. Mr. 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.

THOMAS F. McCOY was named Senior Vice President of Production in February 2020. He previously served as Vice President of Production beginning in August 2013. He joined Cimarex as Gulf Coast Engineering Manager in 2003, and later served as Chief Reservoir Engineer and as Mid-Continent Exploration Manager. Prior to joining Cimarex, Mr. McCoy was with Vintage Petroleum Company and began his career in 1987 with Phillips Petroleum Company. Mr. McCoy holds a B.S. and M.S. in Petroleum Engineering from the University of Tulsa.

BLAKE A. SIRGO was named Vice President of Operations in February 2020. He previously served as Vice President Operations Resources from November 2018 to February 2020, Permian Division Production Manager from 2016 to November 2018, and in various engineering and production manager positions since joining Cimarex in 2008. Mr. Sirgo began his career in 2005 with Occidental Petroleum as a facilities engineer. Mr. Sirgo holds a Bachelor’s in Mechanical Engineering from the University of Texas.

GARY R. ABBOTT was electednamed 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 reservoirsenior 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 aswas 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 10, 201812, 2021 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, 2017.2020.


ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

InformationThe following table sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the company at December 31, 2020:

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 holders547,377 $68.94 1,674,858 
Equity compensation plans not approved by security holders— — — 
Total547,377 $68.94 1,674,858 

The remaining information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 10, 201812, 2021 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, 2017.2020.


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 10, 201812, 2021 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, 2017.2020.


ITEM 14. PRINCIPAL ACCOUNTINGACCOUNTANT FEES AND SERVICES

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 10, 201812, 2021 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, 2017.

2020.
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PART IV
 
ITEM 15. EXHIBITS,EXHIBIT AND FINANCIAL STATEMENT SCHEDULES


Page
(a) (1)
The following financial statements are included in Item 8 to this 10-K:

5967

Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended December 31, 2017, 2016, 2020, 2019, and 20152018
6068

Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016,2020, 2019, and 20152018
6169

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2017, 2016, 2020, 2019, and 20152018
6270

6371
(2(2))
(3(3))

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 (+).

ExhibitTitle
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).
ExhibitTitle
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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ExhibitTitle
4.4
Form of 5.875% Senior Notes due 2022 included in Exhibit 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.

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ExhibitTitle
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).
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 *
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.


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ExhibitTitle
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
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
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
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
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).

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ExhibitTitle
10.1110.4
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
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). +
10.1310.5
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). +
10.1410.6
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). +
10.1510.7
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). +
10.1610.8
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). +
10.1710.9
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). +
10.1810.10
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. +
10.1910.11
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). +
10.2010.12
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). +
10.2110.13
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, 2014 filed on August 6, 2014 (Commission File No. 001-31446) and incorporated herein by reference). +


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ExhibitTitle
10.2210.14
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). +
10.2310.15
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). +
10.2410.16
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). +

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ExhibitTitle
10.2510.17
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). +
10.2610.18
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). +
10.2710.19
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). +
10.2810.20
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). +
10.2910.21
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).
10.3110.22
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). +
10.3210.23
Succession Agreement dated August 17, 2015 (filed as Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 filed on November 4, 2015 (Commission File No. 001-31446) and incorporated herein by reference).
10.33
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 filed on August 9, 2017 (Commission File No. 001-31446) and incorporated herein by reference). +
10.24
Purchase and 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 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).


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ExhibitTitle
14.110.25
CodeForm of Ethics for Chief Executive OfficerNotice of Grant of Restricted Stock and Senior Financial OfficersAward Agreement (Performance Award) (filed as Exhibit 14.110.35 to the Annual Report on Form 10-K for the year ended December 31, 20032018 filed on March 11, 2004February 20, 2019 (Commission File No. 001-31446) and incorporated herein by reference). +
14.210.26
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).
10.27
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).
10.28
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).
10.29
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).
10.30
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).
10.31
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).
10.32
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).
10.33
Amended and Restated Credit Agreement, dated February 5, 2019, among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, Wells Fargo Bank, N.A., as syndication agent, the co-documentation agents party thereto, J.P. Morgan Chase Bank, N.A. and Wells Fargo Securities, LLC, as lead arrangers and bookrunners, and the lenders party thereto. (filed as Exhibit 10.1 to the Current Report on Form 8-K filed February 7, 2019 (Commission File No. 001-31446) and incorporated herein by reference).
10.34
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). +
10.35
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). +
10.36
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). +


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ExhibitTitle
10.37
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). +
10.38
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). +
10.39
Form of Severance Compensation Agreement (filed as Exhibit 10.1 to the Current Report on Form 8-K filed March 13, 2020 (Commission File No. 001-31446) and incorporated herein by reference). +
10.40
Form of Notice of Grant of Performance Stock Units and Award Agreement (Performance Award) (filed as Exhibit 10.2 to the Current Report on Form 8-K filed March 13, 2020 (Commission File No. 001-31446) and incorporated herein by reference). +
10.41
Form of Amendment to Severance Compensation Agreement (filed as Exhibit 10.2 to the Current Report on Form 8-K/A filed May 12, 2020 (Commission File No. 001-31446) and incorporated herein by reference). +
10.42
First Amendment to Amended and Restated Credit Agreement, dated June 3, 2020, among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, Wells Fargo Bank, N.A., as syndication agent, the co-documentation agents party thereto, J.P. Morgan Chase Bank, N.A. and Wells Fargo Securities, LLC, as lead arrangers and bookrunners, and the lenders party thereto. (filed as Exhibit 10.1 to the Current Report on Form 8-K/A filed June 4, 2020 (Commission File No. 001-31446) and incorporated herein by reference).
10.43
Succession Agreement dated July 1, 2020 between Cimarex Energy Co. and Joseph R. Albi (filed as Exhibit 10.1 to the Current Report on Form 8-K/A filed July 2, 2020 (Commission File No. 001-31446) and incorporated herein by reference). +
10.44
Form of Notice of Grant of Performance Stock Units and Award Agreement (Performance Award). + *
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
23.1
23.2
24.1
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.*

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Exhibit
ExhibitTitle
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
Letter dated January 16, 201820, 2021 from DeGolyer and MacNaughton, independent petroleum engineering consulting firm, reporting the results of its audit of Cimarex reserves as of December 31, 20172020 of certain selected properties.*
101.INSXBRL 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.SCHInline XBRL Taxonomy Extension Schema Document. *
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document. *
101.LABInline XBRL Taxonomy Extension Label Linkbase Document. *
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document. *
101.DEFInline 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.



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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: February 23, 2018
2021
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.

SignatureTitleDate
/s/ Thomas E. JordenChairman of the Board, Director, Chief Executive Officer,
Thomas E. JordenChief Executive Officer, and President (Principal Executive Officer)February 23, 20182021
*Director, Executive Vice President —
Attorney-in-FactOperations, Chief Operating OfficerFebruary 23, 2018
Joseph R. Albi
/s/ G. Mark BurfordSenior Vice President and Chief Financial Officer
G. Mark BurfordFinancial Officer (Principal(Principal Financial Officer)February 23, 20182021
/s/ Timothy A. FickerVice President, Controller, Chief Accounting Officer
Timothy A. FickerAccounting Officer (Principal(Principal Accounting Officer)February 23, 20182021
*
Attorney-in-FactDirectorFebruary 23, 20182021
Hans HelmerichJoseph R. Albi
*
Attorney-in-FactDirectorFebruary 23, 20182021
David A. HentschelPaul N. Eckley
*
Attorney-in-FactDirectorFebruary 23, 20182021
Hans Helmerich
*
Attorney-in-FactDirectorFebruary 23, 2021
Kathleen A. Hogenson
*
Attorney-in-FactDirectorFebruary 23, 2021
Harold R. Logan, Jr.
*
Attorney-in-FactDirectorFebruary 23, 20182021
Floyd R. Price
*
Attorney-in-FactDirectorFebruary 23, 20182021
Monroe W. Robertson
*
Attorney-in-FactDirectorFebruary 23, 20182021
Lisa A. Stewart
*
Attorney-in-FactDirectorFebruary 23, 20182021
Michael J. Sullivan
*
Attorney-in-FactDirectorFebruary 23, 2018
Frances M. Vallejo
*By:/s/ G. Mark BurfordSenior Vice President and Chief Financial Officer
G. Mark Burford Attorney-in-Fact
Financial Officer (Principal(Principal Financial Officer)February 23, 20182021




101


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