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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedDecember 31, 2020
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 001-31446
CIMAREX ENERGY CO.
(Exact name of registrant as specified in its charter)
Delaware 45-0466694
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification No.)
1700 Lincoln Street, Suite 3700DenverColorado 80203
(Address of principal executive offices) (Zip Code)
(303) 295-3995
(Registrant’s telephone number)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading 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 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 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 No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerAccelerated filer Non-accelerated filerSmaller reporting company 
Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.                                                     
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 No
Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2020 was approximately $2.75 billion.
Number of shares of Cimarex Energy Co. common stock outstanding as of January 31, 2021 was 102,807,656.
Documents Incorporated by Reference: Portions of the Registrant’s Proxy Statement for its 2021 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
 
  
  
  
  


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GLOSSARY
Bbls—Barrels (of oil or natural gas liquids)
Bcf—Billion cubic feet (of natural gas)
BOE—Barrels of oil equivalent
GAAP—Generally accepted accounting principles in the U.S.
Gross Acres or Gross Wells—The total acres or wells in which a working interest is owned.
MBbls—Thousand barrels
MBOE—Thousand barrels of oil equivalent
Mcf—Thousand cubic feet
MMBbls—Million barrels
MMBtu—Million British thermal units
MMBOE—Million barrels of oil equivalent
MMcf—Million cubic feet
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


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 2021 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 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, 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;

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 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;

Cybersecurity threats, technology system failures, and data security issues;

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

Hedging activities and the viability of our 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;

Continuing compliance with the financial covenant contained in our amended and restated credit agreement;

The loss of certain federal income tax deductions;

Litigation;

Environmental liabilities;

New federal regulations regarding species or 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;

Risks associated with concentration of operations in one major geographic area;

Availability and cost of capital;

Title to properties;

Ability to complete property sales or other transactions; and

Other factors discussed in the company’s reports filed with the Securities and 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 gas reserves and in projecting future rates of production, production 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.

Reservoir engineering is a subjective process of estimating underground accumulations of oil and 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 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 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 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, 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 increase shareholder value through the profitable growth of our proved reserves and production 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 for reinvestment in exploration and development 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-strategic assets. Key elements to our approach include:
 
Maintaining a strong financial position;

Investing in a diversified portfolio of drilling opportunities;

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

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

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

Maximizing profitability.

Conservative use of leverage has long been the key to our financial strategy. We believe that low leverage coupled with strong full-cycle returns enables us to better withstand volatility in commodity prices and provide competitive returns and growth to shareholders. See Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Stock Performance Graph and Item 6 Selected Financial Data for additional financial and operating information for fiscal years 2016 - 2020.


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Proved Oil and Gas Reserves

Our December 31, 2020 total proved reserves decreased 14% from prior year-end. Proved undeveloped reserves as a percentage of total proved reserves increased to 16% from 14% a year ago. During 2020, we added 56.6 MMBOE of new reserves through extensions and discoveries and had net negative revisions that totaled 52.4 MMBOE. These revisions consisted primarily of 70.3 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 30.7 MMBOE in positive revisions related to decreases in operating expenses. The change in our proved reserves is as follows:

Proved Reserves
(MBOE)
Reserves at December 31, 2019619,595 
Revisions of previous estimates(52,430)
Extensions and discoveries56,575 
Production(92,412)
Sales of reserves(307)
Reserves at December 31, 2020531,021 
 
A breakdown by commodity of our proved oil and gas reserves follows:

 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 %
 
The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 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 %
 
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 2020 production volumes totaled 252.5 MBOE per day, a 9% decrease from 2019, and were comprised of 42% gas, 30% oil, and 28% NGLs. The following table 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 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 

Acquisitions and Divestitures

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

On 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. 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 total consideration transferred of $820.3 million. In addition, we assumed $870.0 million of Resolute’s long-term debt, which we immediately repaid. See Note 13 to the Consolidated Financial Statements for further information on this acquisition.


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Exploration and Development Overview

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

xec-20201231_g1.jpg

A summary of our 2020 exploration and development activity and 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 

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 2020, our development activity primarily focused on the Wolfcamp shale formation in Culberson and Reeves Counties in Texas and Lea and Eddy Counties in New Mexico. The Wolfcamp is being developed with horizontal wells primarily using two-mile laterals.

The Permian Basin produced 184.0 MBOE per day in 2020, which was 73% of our total company production. Total production from the region decreased 3% in 2020 from 2019. In 2020, we invested $503.3 million, or 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 2020 in the Mid-Continent was focused in the Woodford shale and the Meramec horizon, both in Oklahoma.

During 2020, production from the Mid-Continent averaged 68.1 MBOE per day, or 27% of total company production. Total production from the region decreased 22% in 2020 as compared to 2019. In 2020, we invested $40.8 million, or 8% of our total E&D investment, in the Mid-Continent.

Drilling Activity

In 2020, we completed or participated in the completion of 149 gross (51.0 net) productive wells, of which we operated 61 gross (47.6 net) wells. At year-end, we were in the process of drilling or participating in 10 gross (4.3 net) wells and there were 77 gross (39.6 net) wells waiting on completion.

We completed the following number of development 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 
Dry1.5 1.9 — — 
Total151 52.5 291 92.1 349 122.1 

At December 31, 2020, we owned an interest in 10,061 gross (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, 2020:

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


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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, 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 1,007,607 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 

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 — — — — 

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

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Title to Oil and Gas Properties

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

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 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 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 senior 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.

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, performed an independent evaluation of our estimated net reserves representing greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of December 31, 2020. The individual primarily responsible for overseeing

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the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over 10 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 26 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 16 years.

Marketing

Our oil and gas production 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 tied to either monthly or daily index pricing and we sell the majority of our NGLs at prices tied to 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 end-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 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 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. 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

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permitting process or permit compliance status of any of our facilities or operations. Expenditures are required to comply with environmental regulations. These costs are a normal, recurring expense of operations and not an extraordinary cost of compliance with current government regulations.

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

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

Under the Natural Gas Policy Act (“NGPA”), 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 they will cause 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, 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. There are unknown risks and uncertainties, or risks we currently deem 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 numerous uncertainties regarding the COVID-19 pandemic, such as the ultimate geographic spread, duration, and severity of the 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 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 return 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 completion of almost all of our wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation’s pores to the well bore. Typically, the fluid used in this process is primarily water. In 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 NGL 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 NGLs, the level of domestic and global oil, gas, and NGL 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 with new discoveries or acquisitions. Accordingly, for the foreseeable future, we expect to make 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 ability to raise additional debt or equity capital to fund acquisitions.

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

Accounting rules require that we periodically review the carrying value of our oil and gas properties for possible impairment. We recognized ceiling test impairments totaling $1.64 billion during the year ended December 31, 2020 and $618.7 million 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. If commodity pricing conditions stay at current levels or decline further, we may incur further ceiling test impairments in future quarters. Because the ceiling calculation uses trailing twelve-month average commodity prices, the effect of declining prices is a lower ceiling value each quarter. This results in ongoing impairments each quarter until prices 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.

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; 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 proved reserves from others. This requires significant capital expenditures and can impose reinvestment risk for us, as we may not be able to continue to replace our reserves economically. While we occasionally may seek to acquire proved reserves, our main business strategy is to grow through exploration and drilling. Without successful exploration and development, our reserves, production, and revenues could decline rapidly, which would negatively impact the results of our operations.

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


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Our drilling operations may be curtailed, delayed, or canceled for many reasons. Factors, in addition to those enumerated above, include unforeseen poor drilling conditions, title problems, unexpected pressure irregularities, equipment failures, accidents, adverse weather conditions, and the cost of, or shortages or delays in the availability of, drilling and completion services could negatively impact our drilling operations.

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

Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future net cash flow depend on a number of variables and assumptions. Refer to CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS 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 engineering consulting firm, performed an independent evaluation of our estimated net reserves representing greater than 80% of the total future net revenue discounted at 10%, as of December 31, 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, and fractionation facilities, most of which are owned by third parties. Oil, 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 our 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, and NGLs to meet minimum volume commitments. These availability and capacity issues are more likely to occur in remote areas with less established infrastructure, such as our Delaware Basin area where we have significant oil and gas production. Any of these availability or capacity issues, whether resulting from the COVID-19 pandemic, construction delays, government restrictions, such as occurred with the revocation of the permit for the Keystone XL Pipeline on the first day of the Biden administration, weather, fire, or other reasons, could negatively affect our operations and revenues.

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.


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

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

Because our activity is 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. In remote areas vendors also can charge higher rates due to the inability to attract employees to those areas and 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.

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.

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

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

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

The Oil Pollution Act of 1990 (“OPA”), 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 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 freshwater mussel species in areas including New Mexico and Texas where we operate in the Permian Basin, as an endangered species. In March 2018, we entered into a CCA concerning voluntary conservation actions with respect to the Texas Hornshell.

Participating in CCAs could result in increased costs to us from species protection measures, time delays or limitations on drilling activities, which costs, delays, or limitations may be significant. Listing 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 listing of the Mexican Long Nosed bat, whose habitat includes the Permian Basin where we operate, and 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 limit our ability to explore for or produce oil and gas in certain areas and increase our costs.


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

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

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 been partially depleted or drained by earlier offset drilling. We 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 wellbore causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores), which could cause a depletion of our proved reserves and may inhibit 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 other nearby wells could cause us, in order to protect our existing wells, to shut in production for indefinite periods of time. Shutting in our wells and damage to our wells from offset completions could result in increased costs and could adversely affect the reserves and re-commenced production from such shut in wells.

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, 2020, other companies operated approximately 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 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

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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.

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

We could lose leases under certain circumstances if we do not maintain production in paying quantities or meet other lease requirements, and the amounts we spent for those leases could 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 3.1% of our total net undeveloped acreage at December 31, 2020. At that date, we had leases representing 132,051 net acres expiring in 2021, 35,516 net acres expiring in 2022, and 7,154 net acres expiring in 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-strategic assets in order to increase capital resources available for other strategic assets and to create organizational and operational efficiencies. We also occasionally sell interests in strategic assets for the purpose of accelerating the development of and increasing efficiencies in such strategic assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties, and the availability of purchasers willing to acquire the assets with terms we deem acceptable.

Sellers 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 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 us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations. In addition, with respect to offshore assets, if purchasers declare bankruptcy, the United States Department of Interior may pursue former owners for decommissioning expenses, which can be substantial. See Note 8 to the Consolidated Financial Statements for further discussion regarding our asset retirement obligations.

Competition for experienced technical personnel may negatively impact our operations.

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


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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.

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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 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.

The closing price of Cimarex stock as reported on the NYSE on January 29, 2021, was $42.18. At January 31, 2021, Cimarex’s 102,807,656 shares of outstanding common stock were held by approximately 1,174 stockholders of record.

Issuer Purchases of Equity Securities

The following table sets forth information regarding repurchases of our common stock during the year ended December 31, 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 — — 


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Stock Performance Graph

The following graph shows the cumulative five-year total return 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, 2015 to December 31, 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 on 12/31/15 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 


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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 

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

Our principal business objective is to increase shareholder value through the profitable growth of our proved reserves and production 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 for reinvestment in exploration and development 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-strategic assets.


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

In the first quarter of 2020, 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 multi-disciplinary task force to address the potential impacts of COVID-19 on our employees and operations. The task force developed health and safety protocols to 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. 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.

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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)


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Pipeline expansion projects in the Permian Basin and reduced drilling activity and production have 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, differentials could potentially worsen. Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and gas production and can be adversely affected by realized price decreases.

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

Total daily production volumes decreased 9% to 252.5 MBOE per day.

Oil volumes decreased 11% to 76.7 MBbls per day.

Gas volumes decreased 8% to 635.6 MMcf per day.

NGL volumes decreased 10% to 69.8 MBbls per day.

Total production revenue decreased 35% to $1.51 billion.

Year-end proved reserves decreased 14% to 531.0 MMBOE, as compared to 619.6 MMBOE at year-end 2019.

Exploration and development capital investments were $544.9 million, as compared to $1.24 billion in 2019.

Cash flow provided by operating activities decreased 33% to $904.2 million.

Net loss of $1.97 billion ($19.73 per diluted share) as compared to a net loss of $124.6 million ($1.33 per diluted share) in 2019.

All of the above results were impacted by the demand destruction and lower prices in 2020 that occurred primarily due to the COVID-19 pandemic. Further discussion of these results is provided below.
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