xec-20200930

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


(Mark One)
☒	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period ended		September 30, 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 No. 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 3700

Denver

Colorado

80203

(Address of principal executive offices)

(Zip Code)

(303) 295-3995

(Registrant’s telephone number, including area code)

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)

XEC

New York Stock Exchange

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 filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No ☒

The number of shares of Cimarex Energy Co. common stock outstanding as of October 31, 2020 was 101,963,311.

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CIMAREX ENERGY CO.

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		Page
PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2020 and December 31, 2019	7

	Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (Unaudited) for the three months and nine months ended September 30, 2020 and 2019	8

	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended September 30, 2020 and 2019	9

	Condensed Consolidated Statements of Stockholders’ Equity (Unaudited) for the three months and nine months ended September 30, 2020 and 2019	10

	Notes to Condensed Consolidated Financial Statements (Unaudited)	13

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	57

Item 4.	Controls and Procedures	58

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	59

Item 1A.	Risk Factors	59

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	67

Item 6.	Exhibits	68

Signatures		69

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GLOSSARY

Bbls—Barrels

Bcf—Billion cubic feet

BOE—Barrels of oil equivalent

Gross Wells—The total wells in which a working interest is owned.

MBbls—Thousand barrels

MBOE—Thousand barrels of oil equivalent

Mcf—Thousand cubic feet

MMBtu—Million British thermal units

MMcf—Million cubic feet

Net Wells—The sum of the fractional working interest owned in gross wells expressed in whole numbers and fractions of whole numbers.

NGL or NGLs—Natural gas liquids

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

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

Throughout this Form 10-Q, 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 2020 capital expenditures. All statements, other than statements of historical facts, that address activities, events, outcomes, and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-Q and our Form 10-K for the year ended December 31, 2019. All the risks disclosed in this Form 10-Q and our 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;

•Cash flow and anticipated liquidity;

•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;

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•Availability of financing and access to capital markets;

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

•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;

•Impairments of goodwill;

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

•Establishing valuation allowances against our net deferred tax assets;

•Hedging activities and the viability of our hedging counterparties, many of whom have been negatively impacted by the COVID-19 pandemic;

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

•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;

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

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

•Ability to successfully integrate the business acquired from Resolute Energy Corporation (“Resolute”);

•Unknown liabilities related to Resolute;

•Amount, nature, and timing of capital expenditures;

•Administrative, legislative, and regulatory changes;

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

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

•Drilling of wells;

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

•Proving up undeveloped acreage;

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

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

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•Environmental liabilities;

•The ability to receive drilling and other permits and rights-of-way in a timely manner, which may be negatively impacted by the impact of COVID-19 restrictions on regulatory employees who process and approve permits and rights-of-way or a change in federal and state administrations and legislatures;

•Development drilling and testing results;

•Production decline rates are greater than expected;

•Performance of acquired properties and newly drilled wells;

•Regulatory approvals, including regulatory restrictions on state and federal lands, which may be negatively impacted by the impact of COVID-19 restrictions on regulatory employees responsible for regulatory approvals and by a change in presidential administration and legislatures;

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

•Unexpected future capital expenditures;

•Economic and competitive conditions;

•Availability and cost of capital;

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

•Changes in estimates of proved reserves;

•Derivative and hedging activities;

•Success of the company’s risk management activities;

•Title to properties;

•Litigation;

•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.

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

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q or in our Annual Report on Form 10-K for the year ended December 31, 2019 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-Q 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-Q with the SEC, except as required by law.

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PART I

ITEM 1. Financial Statements

CIMAREX ENERGY CO.

Condensed Consolidated Balance Sheets

(in thousands, except share and per share information)

(Unaudited)


	September 30,		December 31,
	2020		2019
Assets
Current assets:
Cash and cash equivalents	$	272,957	$	94,722
Accounts receivable, net of allowance:
Trade	67,358		57,879
Oil and gas sales	196,008		384,707
Gas gathering, processing, and marketing	6,074		5,998
Oil and gas well equipment and supplies	45,959		47,893
Derivative instruments	39,402		17,944
Prepaid expenses	6,053		10,759
Other current assets	218		1,584
Total current assets	634,029		621,486
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	21,076,796		20,678,334
Unproved properties and properties under development, not being amortized	1,208,733		1,255,908
	22,285,529		21,934,242
Less—accumulated depreciation, depletion, amortization, and impairment	(18,862,339)		(16,723,544)
Net oil and gas properties	3,423,190		5,210,698
Fixed assets, net of accumulated depreciation of $439,968 and $389,458, respectively	457,010		519,291
Goodwill	—		716,865
Derivative instruments	952		580
Deferred income taxes	21,971		—
Other assets	68,818		71,109
	$	4,605,970	$	7,140,029
Liabilities, Redeemable Preferred Stock, and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	20,053	$	36,280
Gas gathering, processing, and marketing	14,582		12,740
Accrued liabilities:
Exploration and development	32,049		112,228
Taxes other than income	43,450		54,446
Other	205,362		252,304
Derivative instruments	96,763		16,681
Revenue payable	123,705		207,939
Operating leases	59,989		66,003
Total current liabilities	595,953		758,621
Long-term debt principal	2,000,000		2,000,000
Less—unamortized debt issuance costs and discounts	(13,215)		(14,754)
Long-term debt, net	1,986,785		1,985,246

Deferred income taxes	—		338,424
Asset retirement obligation	160,250		154,045
Derivative instruments	26,048		1,018
Operating leases	144,755		184,172
Other liabilities	66,757		60,742
Total liabilities	2,980,548		3,482,268
Commitments and contingencies (Note 10)
Redeemable preferred stock - 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, $0.01 par value, 62,500 shares authorized and issued (Note 5)	81,620		81,620
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 101,970,811 and 102,144,577 shares issued, respectively	1,020		1,021
Additional paid-in capital	3,226,828		3,243,325
(Accumulated deficit) retained earnings	(1,684,046)		331,795

Total stockholders’ equity	1,543,802		3,576,141
	$	4,605,970	$	7,140,029

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(in thousands, except per share information)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues:
Oil sales	$	249,826	$	435,094	$	749,623	$	1,196,166
Gas and NGL sales	140,761		135,483		339,503		479,442
Gas gathering and other	11,555		11,200		36,727		31,231
Gas marketing	(483)		528		(1,981)		(1,114)
	401,659		582,305		1,123,872		1,705,725
Costs and expenses:
Impairment of oil and gas properties	351,029		—		1,625,878		—
Depreciation, depletion, and amortization	155,467		227,978		565,507		631,722
Asset retirement obligation	4,159		2,194		10,544		6,400
Impairment of goodwill	—		—		714,447		—
Production	62,025		89,820		213,598		257,219
Transportation, processing, and other operating	53,130		59,797		161,334		173,479
Gas gathering and other	4,649		5,273		16,473		17,015
Taxes other than income	22,822		30,873		70,269		105,600
General and administrative	28,598		15,499		80,333		69,494
Stock compensation	9,738		6,797		22,879		20,004
Loss (gain) on derivative instruments, net	65,607		(38,735)		(37,448)		35,949
Other operating expense, net	167		10,141		548		19,057
	757,391		409,637		3,444,362		1,335,939
Operating (loss) income	(355,732)		172,668		(2,320,490)		369,786
Other (income) and expense:
Interest expense	23,361		24,586		69,589		69,665
Capitalized interest	(12,286)		(16,264)		(38,407)		(41,811)
Loss on early extinguishment of debt	—		—		—		4,250
Other, net	(1,572)		(140)		1,053		(4,548)
(Loss) income before income tax	(365,235)		164,486		(2,352,725)		342,230
Income tax (benefit) expense	(72,495)		40,639		(360,556)		82,758
Net (loss) income	$	(292,740)	$	123,847	$	(1,992,169)	$	259,472

Earnings (loss) per share to common stockholders:
Basic	$	(2.94)	$	1.21	$	(19.99)	$	2.56
Diluted	$	(2.94)	$	1.21	$	(19.99)	$	2.56



Comprehensive (loss) income:
Net (loss) income	$	(292,740)	$	123,847	$	(1,992,169)	$	259,472
Other comprehensive income:
Change in fair value of investments, net of tax of $0, ($648), $0 and ($220), respectively	—		(2,198)		—		(745)
Total comprehensive (loss) income	$	(292,740)	$	121,649	$	(1,992,169)	$	258,727

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)


	Nine Months Ended September 30,
	2020		2019
Cash flows from operating activities:
Net (loss) income	$	(1,992,169)	$	259,472
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Impairment of oil and gas properties	1,625,878		—
Depreciation, depletion, and amortization	565,507		631,722
Asset retirement obligation	10,544		6,400
Impairment of goodwill	714,447		—
Deferred income taxes	(360,395)		82,758
Stock compensation	22,879		20,004
(Gain) loss on derivative instruments, net	(37,448)		35,949
Settlements on derivative instruments	120,729		(1,118)
Loss on early extinguishment of debt	—		4,250
Amortization of debt issuance costs and discounts	2,488		2,285
Changes in non-current assets and liabilities	6,070		(2,630)
Other, net	9,083		9,061
Changes in operating assets and liabilities:
Accounts receivable	179,953		80,183
Other current assets	6,688		2,140
Accounts payable and other current liabilities	(161,564)		(146,319)
Net cash provided by operating activities	712,690		984,157
Cash flows from investing activities:
Acquisition of oil and gas properties	(7,250)		(285,596)
Oil and gas capital expenditures	(482,141)		(999,225)
Other capital expenditures	(39,965)		(59,035)
Sales of oil and gas assets	69,836		28,547
Sales of other assets	1,892		859
Net cash used by investing activities	(457,628)		(1,314,450)
Cash flows from financing activities:
Borrowings of long-term debt	172,000		2,239,310
Repayments of long-term debt	(172,000)		(2,610,000)
Financing, underwriting, and debt redemption fees	(1,566)		(11,798)
Finance lease payments	(3,863)		(2,731)
Dividends paid	(68,893)		(60,130)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards	(2,505)		(2,406)
Proceeds from exercise of stock options	—		1,267
Net cash used by financing activities	(76,827)		(446,488)
Net change in cash and cash equivalents	178,235		(776,781)
Cash and cash equivalents at beginning of period	94,722		800,666
Cash and cash equivalents at end of period	$	272,957	$	23,885

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands)

(Unaudited)


				Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Total Stockholders’ Equity
	Common Stock
	Shares	Amount
Balance, December 31, 2019	102,145	$	1,021	$	3,243,325	$	331,795	$	3,576,141
Dividends paid on stock awards subsequently forfeited	—	—		6		23		29
Dividends declared on common stock ($0.22 per share)	—	—		—		(22,548)		(22,548)
Dividends declared on redeemable preferred stock ($20.3125 per share)	—	—		—		(1,269)		(1,269)
Net loss	—	—		—		(774,282)		(774,282)

Common stock reacquired and retired	(12)	—		(165)		—		(165)
Restricted stock forfeited and retired	(31)	—		—		—		—

Stock-based compensation	—	—		11,594		—		11,594

Balance, March 31, 2020	102,102	$	1,021	$	3,254,760	$	(466,281)	$	2,789,500
Dividends paid on stock awards subsequently forfeited	—	—		1		7		8
Dividends declared on common stock ($0.22 per share)	—	—		(22,561)		2		(22,559)
Dividends declared on redeemable preferred stock ($20.3125 per share)	—	—		(1,269)		—		(1,269)
Net loss	—	—		—		(925,147)		(925,147)

Issuance of restricted stock awards	66	1		(1)		—		—
Common stock reacquired and retired	(2)	—		(24)		—		(24)
Restricted stock forfeited and retired	(15)	—		—		—		—

Stock-based compensation	—	—		10,338		—		10,338

Balance, June 30, 2020	102,151	$	1,022	$	3,241,244	$	(1,391,419)	$	1,850,847
Dividends paid on stock awards subsequently forfeited	—	—		17		80		97
Dividends declared on common stock ($0.22 per share)	—	—		(22,472)		33		(22,439)
Dividends declared on redeemable preferred stock ($20.3125 per share)	—	—		(1,270)		—		(1,270)
Net loss	—	—		—		(292,740)		(292,740)

Issuance of restricted stock awards	7	—		—		—		—
Common stock reacquired and retired	(94)	(1)		(2,315)		—		(2,316)
Restricted stock forfeited and retired	(93)	(1)		1		—		—

Stock-based compensation	—	—		11,623		—		11,623

Balance, September 30, 2020	101,971	$	1,020	$	3,226,828	$	(1,684,046)	$	1,543,802

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands)

(Unaudited)


				Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Stockholders’ Equity
	Common Stock
	Shares	Amount
Balance, December 31, 2018	95,756	$	958	$	2,785,188	$	542,885	$	755	$	3,329,786
Dividends paid on stock awards subsequently forfeited	—	—		—		2		—		2
Dividends declared on common stock ($0.20 per share)	—	—		—		(20,308)		—		(20,308)
Dividends declared on redeemable preferred stock ($20.3125 per share)	—	—		—		(1,269)		—		(1,269)
Net income	—	—		—		26,316		—		26,316
Issuance of stock for Resolute Energy acquisition (Note 13)	5,652	56		412,959		—		—		413,015
Unrealized change in fair value of investments, net of tax	—	—		—		—		1,149		1,149
Issuance of restricted stock awards	11	—		—		—		—		—
Common stock reacquired and retired	(10)	—		(654)		—		—		(654)
Restricted stock forfeited and retired	(4)	—		—		—		—		—
Exercise of stock options	3	—		80		—		—		80
Stock-based compensation	—	—		13,245		—		—		13,245
Balance, March 31, 2019	101,408	$	1,014	$	3,210,818	$	547,626	$	1,904	$	3,761,362
Dividends paid on stock awards subsequently forfeited	—	—		1		4		—		5
Dividends declared on common stock ($0.20 per share)	—	—		—		(20,330)		—		(20,330)
Dividends declared on redeemable preferred stock ($20.3125 per share)	—	—		—		(1,270)		—		(1,270)
Net income	—	—		—		109,309		—		109,309
Unrealized change in fair value of investments, net of tax	—	—		—		—		304		304
Issuance of restricted stock awards	54	1		(1)		—		—		—
Restricted stock forfeited and retired	(4)	—		—		—		—		—
Exercise of stock options	15	—		594		—		—		594
Stock-based compensation	—	—		11,919		—		—		11,919
Balance, June 30, 2019	101,473	$	1,015	$	3,223,331	$	635,339	$	2,208	$	3,861,893

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands)

(Unaudited)


				Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Stockholders’ Equity
	Common Stock
	Shares	Amount
Balance, June 30, 2019	101,473	$	1,015	$	3,223,331	$	635,339	$	2,208	$	3,861,893
Dividends paid on stock awards subsequently forfeited	—	—		—		6		—		6
Dividends declared on common stock ($0.20 per share)	—	—		—		(20,390)		—		(20,390)
Dividends declared on redeemable preferred stock ($20.3125 per share)	—	—		—		(1,270)		—		(1,270)
Net income	—	—		—		123,847		—		123,847
Unrealized change in fair value of investments, net of tax	—	—		—		—		(2,198)		(2,198)
Issuance of restricted stock awards	375	3		(3)		—		—		—
Common stock reacquired and retired	(35)	—		(1,752)		—		—		(1,752)
Restricted stock forfeited and retired	(4)	—		—		—		—		—
Exercise of stock options	11	—		593		—		—		593
Stock-based compensation	—	—		12,149		—		—		12,149
Balance, September 30, 2019	101,820	$	1,018	$	3,234,318	$	737,532	$	10	$	3,972,878

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

1.BASIS OF PRESENTATION

Cimarex Energy Co. (“Cimarex,” “company,” “we,” or “us”), a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, and New Mexico. The accompanying unaudited financial statements have been prepared pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2019.

In the opinion of management, the accompanying financial statements reflect all adjustments necessary to fairly present our financial position, results of operations, and cash flows for the periods and as of the dates shown. The accounts of Cimarex and its subsidiaries are presented in the accompanying financial statements, with intercompany balances and transactions eliminated in consolidation.

On March 1, 2019, we acquired Resolute Energy Corporation (“Resolute”) in a cash and stock transaction. The results of Resolute’s operations have been included in our consolidated financial statements since the March 1, 2019 acquisition date. See Note 13 for more information on this transaction.

Use of Estimates

Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, lease liabilities, and contingencies.

Prior Year Reclassifications

Certain amounts in the prior year financial statements have been reclassified to conform to the 2020 financial statement presentation. These reclassifications include reclassifying certain “Gas gathering and other” expenses to “Transportation, processing, and other operating” expense and “Production” expense. These reclassifications were made to reflect an allocation of the costs incurred to operate our gas gathering facilities as a cost to transport our equity share of gas produced and operate our wells. The following table shows the reclassifications made:


	Three Months Ended September 30, 2019						Nine Months Ended September 30, 2019
(in thousands)	Prior Year Presentation		Current Year Reclassifications		Current Year Presentation		Prior Year Presentation		Current Year Reclassifications		Current Year Presentation
Production	$	88,300	$	1,520	$	89,820	$	253,259	$	3,960	$	257,219
Transportation, processing, and other operating	$	52,697	7,100		$	59,797	$	154,636	18,843		$	173,479
Gas gathering and other	$	13,893	(8,620)		$	5,273	$	39,818	(22,803)		$	17,015
			$	—					$	—

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

Oil and Gas Well Equipment and Supplies

Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of disposal and transportation. Declines in the price of oil and gas well equipment and supplies in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.

Oil and Gas Properties

We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Under the full cost method of accounting, we are required to perform a quarterly ceiling test calculation to test our oil and gas properties for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.

The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, overall exploration and development costs, and deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur a full cost ceiling test impairment. The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date.

For the nine months ended September 30, 2020, we incurred ceiling test impairments totaling $1.626 billion ($351.0 million for the three months ended September 30, 2020, $941.2 million for the three months ended June 30, 2020, and $333.7 million for the three months ended March 31, 2020). These impairments resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves. We expect these conditions to continue at least through December 31, 2020 and possibly beyond and, therefore, expect to incur another ceiling test impairment at December 31, 2020.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. In performing the goodwill test, we compare the fair value of our reporting unit with its carrying amount. If the carrying amount of the reporting unit were to exceed its fair value, an impairment charge would be recognized in the amount of this excess, limited to the total amount of goodwill allocated to that reporting unit. We evaluate our goodwill for impairment in the fourth quarter of each year and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our assessment as of October 31, 2019, goodwill was not impaired. However, during the three months ended March 31, 2020 the company’s market capitalization declined significantly, caused by macroeconomic and geopolitical conditions including the collapse of oil prices driven by surplus supply and decreased demand caused by the COVID-19 pandemic. In addition, the uncertainty related to oil demand significantly impacted our investment and operating decisions. As a result, we concluded that a triggering event had occurred, which required us to perform an interim quantitative impairment test for goodwill as of March 31, 2020. As a result of that quantitative

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

impairment test, which utilized quoted market prices for our common stock as a basis for determining fair value, we concluded that goodwill was fully impaired at March 31, 2020.

The following table reflects components of the change in the carrying amount of goodwill for the nine months ended September 30, 2020:


(in thousands)	Nine Months Ended September 30, 2020
Goodwill balance at January 1, 2020	$	716,865
Resolute acquisition purchase price adjustments (Note 13)	(2,418)
Impairment	(714,447)
Goodwill balance at September 30, 2020	$	—

Revenue Recognition

Oil, Gas, and NGL Sales

Revenue is recognized from the sales of oil, gas, and NGLs when the customer obtains control of the product, when we have no further obligations to perform related to the sale, and when collectability is probable. All of our sales of oil, gas, and NGLs are made under contracts with customers, which typically include variable consideration based on monthly pricing tied to local indices and monthly volumes delivered. The nature of our contracts with customers does not require us to constrain that variable consideration or to estimate the amount of transaction price attributable to future performance obligations for accounting purposes. As of September 30, 2020, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas, and/or NGLs. Our contracts with customers typically require payment within one month of delivery.

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

Gas Gathering

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

Gas Marketing

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

Gas Imbalances

Revenue from the sale of gas is recorded on the basis of gas actually sold by or for us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

2.LONG-TERM DEBT

Long-term debt at September 30, 2020 and December 31, 2019 consisted of the following:


	September 30, 2020						December 31, 2019
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)		Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discounts (1)		Long-term Debt, net
4.375% Notes due 2024	$	750,000	$	(2,884)	$	747,116	$	750,000	$	(3,535)	$	746,465
3.90% Notes due 2027	750,000		(5,731)		744,269		750,000		(6,289)		743,711
4.375% Notes due 2029	500,000		(4,600)		495,400		500,000		(4,930)		495,070
	$	2,000,000	$	(13,215)	$	1,986,785	$	2,000,000	$	(14,754)	$	1,985,246

________________________________________

(1)The 4.375% Notes due 2024 were issued at par, therefore, the amounts shown in the table are for unamortized debt issuance costs only. At September 30, 2020, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.4 million and $1.3 million, respectively. At September 30, 2020, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.0 million and $0.6 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.8 million and $1.5 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.3 million and $0.6 million, respectively.

Bank Debt

On June 3, 2020, we entered into the First Amendment to Amended and Restated Credit Agreement (the “First Amendment”) dated as of February 5, 2019 for our senior unsecured revolving credit facility (“Credit Facility”). The Credit Facility has aggregate commitments of $1.25 billion with an option for us to increase the aggregate commitments to $1.5 billion, and matures on February 5, 2024. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. The First Amendment, among other things: (i) allows up to $3.5 billion of non-cash impairment charge add-backs to Shareholders’ Equity for covenant calculation purposes, (ii) institutes traditional anti-cash hoarding provisions at a consolidated cash threshold of $175.0 million, (iii) reduces the priority lien debt basket from 15% of Consolidated Net Tangible Assets (as defined in the credit agreement) to a $50.0 million cap, and (iv) adds an acknowledgement and consent to European Union bail-in legislation. As of September 30, 2020, we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $1.248 billion. During the three and nine months ended September 30, 2020, we borrowed and repaid an aggregate of $11.0 million and $172.0 million, respectively, on the Credit Facility to meet cash requirements as needed.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR (or an alternate rate determined by the administrative agent for the Credit Facility in accordance with the Credit Facility when LIBOR is no longer available) plus 1.125 – 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 – 1.0%, based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of 0.125 – 0.35%, based on the credit rating for our senior unsecured long-term debt.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capitalization ratio of no greater than 65%. As of September 30, 2020, we were in compliance with all of the financial covenants.

At September 30, 2020 and December 31, 2019, we had $4.7 million and $4.0 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in “Other assets” on our Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2020, we incurred $1.5 million in fees paid to the creditor and third-party costs for the First Amendment. These costs are being amortized to interest expense ratably over the life of the Credit Facility.

Senior Notes

On March 8, 2019, we issued $500 million aggregate principal amount of 4.375% senior unsecured notes due March 15, 2029 at 99.862% of par to yield 4.392% per annum. We received $494.7 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs. The notes bear an annual interest rate of 4.375% and interest is payable semiannually on March 15 and September 15, with the first payment made on September 15, 2019. We used the net proceeds to repay borrowings outstanding under our Credit Facility that were used to help fund the Resolute acquisition on March 1, 2019. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.50%.

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

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

Our senior unsecured notes are governed by indentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of September 30, 2020.

3. DERIVATIVE INSTRUMENTS

We periodically use derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future cash flow from favorable price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels.

As of September 30, 2020, we have entered into oil and gas collars, oil basis swaps, and oil “roll differential” swaps. We also occasionally enter into fixed price swaps. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price plus or minus a fixed differential, as applicable, and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI NYMEX (Cushing, Oklahoma) price and the WTI Midland price. For our Permian and Mid-Continent gas production, the contract prices in our collars are

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

consistent with the index prices used to sell our production. Our oil roll differential swaps are settled based on the difference between the monthly roll differential and a fixed price per Bbl. The monthly roll differential is calculated as the sum of 2/3 of the difference in the WTI NYMEX closing settlement price for the first nearby month futures contract minus the second nearby futures contract and 1/3 of the difference in the WTI NYMEX closing settlement price for the first nearby month futures contract minus the third nearby month futures contract. By using a roll differential swap, we have fixed the differential in pricing between the WTI NYMEX calendar month average and the physical crude oil delivery month. Under our fixed price swaps, we receive the difference between the fixed price and the published index price if the published index price is below the fixed price and we pay the difference between the fixed price and the published index price if the published index price is above the fixed price. The following tables summarize our outstanding derivative contracts as of September 30, 2020:


Oil Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
WTI (1)
Volume (Bbls)	—		—		—		3,772,000		3,772,000
Weighted Avg Price - Floor	$	—	$	—	$	—	$	40.91	$	40.91
Weighted Avg Price - Ceiling	$	—	$	—	$	—	$	49.84	$	49.84
2021:
WTI (1)
Volume (Bbls)	3,600,000		3,094,000		2,300,000		2,300,000		11,294,000
Weighted Avg Price - Floor	$	38.06	$	34.62	$	32.44	$	32.44	$	34.83
Weighted Avg Price - Ceiling	$	46.45	$	43.28	$	41.49	$	41.49	$	43.56
2022:
WTI (1)
Volume (Bbls)	990,000		364,000		—		—		1,354,000
Weighted Avg Price - Floor	$	35.91	$	37.50	$	—	$	—	$	36.34
Weighted Avg Price - Ceiling	$	47.37	$	51.04	$	—	$	—	$	48.36

________________________________________

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

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)


Gas Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
PEPL (1)
Volume (MMBtu)	—		—		—		9,200,000		9,200,000
Weighted Avg Price - Floor	$	—	$	—	$	—	$	1.78	$	1.78
Weighted Avg Price - Ceiling	$	—	$	—	$	—	$	2.21	$	2.21
Perm EP (2)
Volume (MMBtu)	—		—		—		6,440,000		6,440,000
Weighted Avg Price - Floor	$	—	$	—	$	—	$	1.36	$	1.36
Weighted Avg Price - Ceiling	$	—	$	—	$	—	$	1.64	$	1.64
Waha (3)
Volume (MMBtu)	—		—		—		6,440,000		6,440,000
Weighted Avg Price - Floor	$	—	$	—	$	—	$	1.43	$	1.43
Weighted Avg Price - Ceiling	$	—	$	—	$	—	$	1.73	$	1.73
2021:
PEPL (1)
Volume (MMBtu)	9,000,000		8,190,000		6,440,000		6,440,000		30,070,000
Weighted Avg Price - Floor	$	1.83	$	1.83	$	1.88	$	1.88	$	1.85
Weighted Avg Price - Ceiling	$	2.23	$	2.22	$	2.29	$	2.29	$	2.25
Perm EP (2)
Volume (MMBtu)	6,300,000		6,370,000		4,600,000		4,600,000		21,870,000
Weighted Avg Price - Floor	$	1.50	$	1.50	$	1.64	$	1.64	$	1.56
Weighted Avg Price - Ceiling	$	1.79	$	1.79	$	1.95	$	1.95	$	1.86
Waha (3)
Volume (MMBtu)	8,100,000		8,190,000		6,440,000		6,440,000		29,170,000
Weighted Avg Price - Floor	$	1.52	$	1.52	$	1.65	$	1.65	$	1.58
Weighted Avg Price - Ceiling	$	1.83	$	1.83	$	1.98	$	1.98	$	1.90
2022:
PEPL (1)
Volume (MMBtu)	3,600,000		—		—		—		3,600,000
Weighted Avg Price - Floor	$	2.00	$	—	$	—	$	—	$	2.00
Weighted Avg Price - Ceiling	$	2.40	$	—	$	—	$	—	$	2.40
Perm EP (2)
Volume (MMBtu)	1,800,000		—		—		—		1,800,000
Weighted Avg Price - Floor	$	1.85	$	—	$	—	$	—	$	1.85
Weighted Avg Price - Ceiling	$	2.18	$	—	$	—	$	—	$	2.18
Waha (3)
Volume (MMBtu)	3,600,000		—		—		—		3,600,000
Weighted Avg Price - Floor	$	1.77	$	—	$	—	$	—	$	1.77
Weighted Avg Price - Ceiling	$	2.15	$	—	$	—	$	—	$	2.15

________________________________________

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

(1)The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.

(2)The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.

(3)The index price for these collars is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.


Oil Basis Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
WTI Midland (1)
Volume (Bbls)	—		—		—		2,944,000		2,944,000
Weighted Avg Differential (2)	$	—	$	—	$	—	$	0.18	$	0.18
2021:
WTI Midland (1)
Volume (Bbls)	2,790,000		2,639,000		2,208,000		2,208,000		9,845,000
Weighted Avg Differential (2)	$	0.03	$	(0.04)	$	(0.26)	$	(0.26)	$	(0.12)
2022:
WTI Midland (1)
Volume (Bbls)	990,000		364,000		—		—		1,354,000
Weighted Avg Differential (2)	$	0.20	$	0.35	$	—	$	—	$	0.24

________________________________________

(1)The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.

(2)The index price we receive under these basis swaps is WTI as quoted on the NYMEX plus or minus, as applicable, the weighted average differential shown in the table.


Oil Roll Differential Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2021:
WTI (1)
Volume (Bbls)	630,000		637,000		644,000		644,000		2,555,000
Weighted Avg Price	$	(0.24)	$	(0.24)	$	(0.24)	$	(0.24)	$	(0.24)
2022:
WTI (1)
Volume (Bbls)	630,000		—		—		—		630,000
Weighted Avg Price	$	(0.24)	$	—	$	—	$	—	$	(0.24)

________________________________________

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

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

The following tables summarize our derivative contracts entered into subsequent to September 30, 2020 through October 31, 2020:


Gas Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total













2021:
PEPL (1)
Volume (MMBtu)	—		910,000		1,840,000		1,840,000		4,590,000
Weighted Avg Price - Floor	$	—	$	2.40	$	2.40	$	2.40	$	2.40
Weighted Avg Price - Ceiling	$	—	$	2.81	$	2.86	$	2.86	$	2.85
Perm EP (2)
Volume (MMBtu)	—		910,000		1,840,000		1,840,000		4,590,000
Weighted Avg Price - Floor	$	—	$	2.40	$	2.40	$	2.40	$	2.40
Weighted Avg Price - Ceiling	$	—	$	2.85	$	2.88	$	2.88	$	2.87
Waha (3)
Volume (MMBtu)	—		910,000		1,840,000		1,840,000		4,590,000
Weighted Avg Price - Floor	$	—	$	2.40	$	2.40	$	2.40	$	2.40
Weighted Avg Price - Ceiling	$	—	$	2.82	$	2.86	$	2.86	$	2.85
2022:
PEPL (1)
Volume (MMBtu)	1,800,000		1,820,000		—		—		3,620,000
Weighted Avg Price - Floor	$	2.40	$	2.40	$	—	$	—	$	2.40
Weighted Avg Price - Ceiling	$	2.86	$	2.86	$	—	$	—	$	2.86
Perm EP (2)
Volume (MMBtu)	1,800,000		1,820,000		—		—		3,620,000
Weighted Avg Price - Floor	$	2.40	$	2.40	$	—	$	—	$	2.40
Weighted Avg Price - Ceiling	$	2.88	$	2.88	$	—	$	—	$	2.88
Waha (3)
Volume (MMBtu)	1,800,000		1,820,000		—		—		3,620,000
Weighted Avg Price - Floor	$	2.40	$	2.40	$	—	$	—	$	2.40
Weighted Avg Price - Ceiling	$	2.86	$	2.86	$	—	$	—	$	2.86

________________________________________

(1)The index price for these collars is PEPL as quoted in Platt’s Inside FERC.

(2)The index price for these collars is Perm EP as quoted in Platt’s Inside FERC.

(3)The index price for these collars is Waha as quoted in Platt’s Inside FERC.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)


Oil Basis Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total




2021:
WTI Midland (1)
Volume (Bbls)	—		364,000		368,000		368,000		1,100,000
Weighted Avg Differential (2)	$	—	$	0.16	$	0.16	$	0.16	$	0.16
2022:
WTI Midland (1)
Volume (Bbls)	360,000		364,000		—		—		724,000
Weighted Avg Differential (2)	$	0.16	$	0.16	$	—	$	—	$	0.16

________________________________________

(1)The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.

(2)The index price we receive under these basis swaps is WTI as quoted on the NYMEX plus or minus, as applicable, the weighted average differential shown in the table.


Oil Roll Differential Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2021:
WTI (1)
Volume (Bbls)	—		364,000		368,000		368,000		1,100,000
Weighted Avg Price	$	—	$	(0.20)	$	(0.20)	$	(0.20)	$	(0.20)
2022:
WTI (1)
Volume (Bbls)	360,000		364,000		—		—		724,000
Weighted Avg Price	$	(0.20)	$	(0.20)	$	—	$	—	$	(0.20)

________________________________________

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

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

Derivative Gains and Losses

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the components of “Loss (gain) on derivative instruments, net” for the periods indicated.


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2020		2019		2020		2019
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts	$	43,975	$	5,818	$	76,294	$	(10,398)
Oil contracts	35,306		(42,857)		6,987		45,229
	79,281		(37,039)		83,281		34,831
Cash (receipts) payments on derivative instruments, net:
Gas contracts	(2,837)		(17,554)		(20,426)		(34,966)
Oil contracts	(10,837)		15,858		(100,303)		36,084
	(13,674)		(1,696)		(120,729)		1,118
Loss (gain) on derivative instruments, net	$	65,607	$	(38,735)	$	(37,448)	$	35,949

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

Derivative Fair Value

Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty. Our accounting policy is to not offset asset and liability positions in our balance sheets.

The following tables present the amounts and classifications of our derivative assets and liabilities as of September 30, 2020 and December 31, 2019, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.


		September 30, 2020
(in thousands)	Balance Sheet Location	Asset		Liability
Oil contracts	Current assets — Derivative instruments	$	39,402	$	—

Oil contracts	Non-current assets — Derivative instruments	952		—

Oil contracts	Current liabilities — Derivative instruments	—		47,778
Gas contracts	Current liabilities — Derivative instruments	—		48,985
Oil contracts	Non-current liabilities — Derivative instruments	—		14,865
Gas contracts	Non-current liabilities — Derivative instruments	—		11,183
Total gross amounts presented in the balance sheet		40,354		122,811
Less: gross amounts not offset in the balance sheet		(36,537)		(36,537)
Net amount		$	3,817	$	86,274

		December 31, 2019
(in thousands)	Balance Sheet Location	Asset		Liability
Oil contracts	Current assets — Derivative instruments	$	1,624	$	—
Gas contracts	Current assets — Derivative instruments	16,320		—
Oil contracts	Non-current assets — Derivative instruments	580		—
Oil contracts	Current liabilities — Derivative instruments	—		16,681

Oil contracts	Non-current liabilities — Derivative instruments	—		824
Gas contracts	Non-current liabilities — Derivative instruments	—		194
Total gross amounts presented in the balance sheet		18,524		17,699
Less: gross amounts not offset in the balance sheet		(9,865)		(9,865)
Net amount		$	8,659	$	7,834

We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. We mitigate our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our derivative liability positions, nor do we require our counterparties to post collateral for our benefit. In the future we may enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

4.FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Authoritative accounting guidance has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable.

The following table provides fair value measurement information for certain assets and liabilities as of September 30, 2020 and December 31, 2019:


	September 30, 2020				December 31, 2019
(in thousands)	Book Value		Fair Value		Book Value		Fair Value
Financial Assets (Liabilities):
4.375% Notes due 2024	$	(750,000)	$	(804,975)	$	(750,000)	$	(792,225)
3.90% Notes due 2027	$	(750,000)	$	(755,850)	$	(750,000)	$	(778,050)
4.375% Notes due 2029	$	(500,000)	$	(517,350)	$	(500,000)	$	(530,400)
Derivative instruments — assets	$	40,354	$	40,354	$	18,524	$	18,524
Derivative instruments — liabilities	$	(122,811)	$	(122,811)	$	(17,699)	$	(17,699)

Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The fair value (Level 1) of our fixed rate notes was based on quoted market prices. The fair value of our derivative instruments (Level 2) was estimated using discounted cash flow and option pricing models. These models use certain observable variables including forward prices, volatility curves, interest rates, and credit ratings and spreads. The fair value estimates are adjusted relative to non-performance risk as appropriate. See Note 3 for further information on the fair value of our derivative instruments.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Included in “Accrued liabilities — Other” at September 30, 2020 are: (i) accrued operating expenses (e.g., production, transportation, and gathering expenses) of approximately $66.3 million and (ii) accrued general and administrative expenses of $36.8 million, which consisted primarily of $17.9 million in regular payroll-related costs and $15.9 million in voluntary early retirement incentive program and involuntary reduction in workforce accruals. Included in “Accrued liabilities — Other” at December 31, 2019 are: (i) accrued operating expenses (e.g., production, transportation, and gathering expenses) of approximately $74.7 million and (ii) accrued general and administrative costs, primarily payroll-related, of approximately $43.3 million.

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary. For properties we operate, we have the right to realize amounts due to us from non-operators by netting the non-operators’ share of production revenues from those properties.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

We routinely assess the recoverability of all material accounts receivable and accrue a reserve to the allowance for doubtful accounts based on our estimation of expected losses over the life of the receivables. At September 30, 2020 and December 31, 2019, the allowance for doubtful accounts was $3.4 million and $3.6 million, respectively.

5.CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At September 30, 2020, there were 102.0 million shares of common stock outstanding and 62.5 thousand shares of 8.125% Series A Cumulative Perpetual Convertible Preferred Stock outstanding (the “Convertible Preferred Stock”). Holders of the Convertible Preferred Stock are entitled to receive, when, as, and if declared by the Board, cumulative cash dividends at an annual rate of 8.125% of each share’s liquidation preference of $1,000. In the event of any liquidation, winding up, or dissolution of Cimarex, each holder will be entitled to receive in respect of its shares, up to each share’s liquidation preference, with the total liquidation preference being $62.5 million in the aggregate, after satisfaction of liabilities and any senior stock (of which there is currently none) and before any payment or distribution to holders of junior stock (including common stock). Each holder has the right at any time, at its option, to convert any or all of such holder’s shares of Convertible Preferred Stock into a certain number of shares of Cimarex common stock based on a conversion rate that adjusts upon the occurrence of certain events, including the payment of cash dividends to common shareholders, plus $471.40 in cash per share of Convertible Preferred Stock. The September 30, 2020 conversion rate was 8.32093 shares of common stock for each share of Convertible Preferred Stock. As a result of the cash component included in the redemption feature of the Convertible Preferred Stock conversion option, with such conversion not solely within our control, the instruments are classified as Redeemable preferred stock in temporary equity on the Condensed Consolidated Balance Sheets.

Dividends

Common Stock

In August 2020, our Board of Directors declared a cash dividend of $0.22 per share of common stock. The dividend is payable on or before December 1, 2020 to stockholders of record on November 13, 2020. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. The $22.5 million dividend declared during the third quarter 2020 was recorded as a reduction of additional paid-in capital and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet at September 30, 2020. Nonforfeitable dividends paid on stock awards that subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to stock compensation expense in the period in which the forfeitures occur. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Preferred Stock

In August 2020, our Board of Directors declared a cash dividend of $20.3125 per share of Convertible Preferred Stock. The dividend was paid in October to stockholders of record on October 1, 2020. This $1.3 million dividend was recorded as a reduction of additional paid-in capital and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet at September 30, 2020.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

6.STOCK-BASED COMPENSATION

We have recognized stock-based compensation cost as shown below for the periods indicated.


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2020		2019		2020		2019
Restricted stock awards:
Performance stock awards	$	5,931	$	5,604	$	14,050	$	16,533
Service-based stock awards	6,214		6,140		20,176		19,364
	12,145		11,744		34,226		35,897
Stock option awards	207		411		1,121		1,429
Total stock compensation cost	12,352		12,155		35,347		37,326
Less amounts capitalized to oil and gas properties	(2,614)		(5,358)		(12,468)		(17,322)
Stock compensation expense	$	9,738	$	6,797	$	22,879	$	20,004

Periodic stock compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards as well as due to the capitalization rates applied to the gross expense. Our accounting policy is to account for forfeitures in compensation cost when they occur. In response to low oil prices and demand destruction in 2020, we have reduced our acquisition, exploration, and development activities, and, therefore, the percentage of gross stock compensation capitalized has decreased from prior periods.

7.ASSET RETIREMENT OBLIGATIONS

We recognize the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the plugging and abandonment of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is accreted each period. If there is a change in the estimated cost or timing of retirement, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost. Capitalized costs are included as a component of the depreciation and depletion calculations.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the nine months ended September 30, 2020:


(in thousands)	Nine Months Ended September 30, 2020
Asset retirement obligation at January 1, 2020	$	181,869
Liabilities incurred	2,224
Liability settlements and disposals	(21,289)
Accretion expense	5,639
Revisions of estimated liabilities	3,844
Asset retirement obligation at September 30, 2020	172,287
Less current obligation	(12,037)
Long-term asset retirement obligation	$	160,250

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

8.EARNINGS (LOSS) PER SHARE

The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below for the periods indicated:


	Three Months Ended September 30,
	2020					2019
(in thousands, except per share information)	Income (Numerator)		Shares (Denominator)	Per-Share Amount		Income (Numerator)		Shares (Denominator)	Per-Share Amount
Net (loss) income	$	(292,740)				$	123,847
Less: dividends and net income attributable to participating securities (1)	(298)					(1,898)
Less: preferred stock dividends	(1,270)					(1,270)
Basic (loss) earnings per share
(Loss) income available to common stockholders	(294,308)		100,013	$	(2.94)	120,679		99,735	$	1.21
Effects of dilutive securities
Options (2)	—		—			—		—
Diluted (loss) earnings per share
(Loss) income available to common stockholders and assumed conversions	$	(294,308)	100,013	$	(2.94)	$	120,679	99,735	$	1.21


	Nine Months Ended September 30,
	2020					2019
(in thousands, except per share information)	Income (Numerator)		Shares (Denominator)	Per-Share Amount		Income (Numerator)		Shares (Denominator)	Per-Share Amount
Net (loss) income	$	(1,992,169)				$	259,472
Less: dividends and net income attributable to participating securities (1)	(1,417)					(3,951)
Less: preferred stock dividends	(3,808)					(3,809)
Basic (loss) earnings per share
(Loss) income available to common stockholders	(1,997,394)		99,912	$	(19.99)	251,712		98,452	$	2.56
Effects of dilutive securities
Options (2)	$	—	—			$	—	6
Diluted (loss) earnings per share
(Loss) income available to common stockholders and assumed conversions	$	(1,997,394)	99,912	$	(19.99)	$	251,712	98,458	$	2.56

________________________________________

(1)Participating securities do not have a contractual obligation to share in the losses of the entity, therefore, net losses are not attributable to participating securities.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

(2)Inclusion of certain potential common shares would have an anti-dilutive effect, therefore, these shares were excluded from the calculations of diluted earnings (loss) per share. Excluded from the calculation for the three months ended September 30, 2020 were 405.3 thousand potential common shares from the assumed exercise of employee stock options, 520.1 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock, and 8.8 thousand potential common shares from the assumed vesting of incremental shares of unvested restricted stock awards. Excluded from the calculation for the three months ended September 30, 2019 were 507.6 thousand potential common shares from the assumed exercise of employee stock options and 506.4 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock. Excluded from the calculation for the nine months ended September 30, 2020 were 405.3 thousand potential common shares from the assumed exercise of employee stock options, 520.1 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock, and 8.8 thousand potential common shares from the assumed vesting of incremental shares of unvested restricted stock awards. Excluded from the calculation for the nine months ended September 30, 2019 were 524.0 thousand potential common shares from the assumed exercise of employee stock options and 506.4 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock.

9.INCOME TAXES

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


	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2020			2019			2020			2019
Current tax benefit	$	—		$	—		$	(161)		$	—
Deferred tax (benefit) expense	(72,495)			40,639			(360,395)			82,758
	$	(72,495)		$	40,639		$	(360,556)		$	82,758

Combined federal and state effective income tax rate	19.8		%	24.7		%	15.3		%	24.2		%

Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 21% primarily due to state income taxes and non-deductible expenses. The combined federal and state effective income tax rate for the nine months ended September 30, 2020 is also impacted by the non-deductible impairment of goodwill recorded during the first quarter 2020. We believe our combined federal and state effective income tax rates in subsequent periods will be higher than the effective rate for the nine months ended September 30, 2020.

On March 1, 2019, we completed the acquisition of Resolute. For federal income tax purposes, the acquisition was a tax-free merger whereby Cimarex acquired carryover tax basis in Resolute’s tax assets and liabilities. As of December 31, 2019, we had a net deferred tax liability of $31.1 million reflecting the difference between the fair value of Resolute’s assets and liabilities recorded in the acquisition and the income tax basis of the assets and liabilities assumed. See Note 13 for more information regarding the purchase price allocation. The net deferred tax liability includes certain deferred tax assets net of valuation allowances. The acquired tax attributes include federal net operating loss, capital loss, and enhanced oil recovery tax credit carryforwards. The carryforwards are subject to an annual limitation under Internal Revenue Code Section 382.

At December 31, 2019, we had a U.S. net tax operating loss carryforward of approximately $1.93 billion; $1.79 billion of which will expire in tax years 2032 through 2037 and $140.0 million of which will not expire. We also had enhanced oil recovery and marginal well credits of $3.9 million at December 31, 2019.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

During the three months ended September 30, 2020, we recorded additional valuation allowances of $6.7 million against both federal and state net operating loss carryovers. When assessing the need for a valuation allowance against a deferred tax asset, both positive and negative evidence is considered when determining the ability to utilize our deferred tax assets. Based on our estimate of the timing of future reversals of existing taxable temporary differences, our estimate of future taxable income exclusive of reversing temporary differences and carryforwards, the length of time before the deferred tax assets associated with the net operating loss carryovers begin to expire, and tax planning strategies that could be implemented to accelerate taxable amounts to utilize expiring carryovers, we believe it is more likely than not that the benefit from the deferred tax asset recorded in the financial statements will be realized. We will continue to assess all available positive and negative evidence to estimate whether sufficient future taxable income will be generated in order to utilize the deferred tax assets. Additional valuation allowances may be required in future periods if additional losses are incurred or other circumstances change.

At September 30, 2020, we had no unrecognized tax benefits that would impact our effective tax rate and have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2017 through 2019 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities, which remain open to examination for tax years 2015 through 2019.

10.COMMITMENTS AND CONTINGENCIES

At September 30, 2020, we had estimated commitments of approximately: (i) $223.5 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $3.4 million to finish gathering system and water facilities construction in progress.

At September 30, 2020, we have various firm transportation agreements for gas pipeline capacity with end dates ranging from 2021 - 2025 under which we will have to pay an estimated $18.7 million over the remaining terms of the agreements.

We have minimum volume water delivery commitments associated with a water services agreement entered into in connection with the sale of certain water infrastructure assets in Eddy County, New Mexico (see Note 13). If we do not deliver the water volumes, the estimated maximum amount that would be payable under this commitment, calculated as of September 30, 2020, would be approximately $65.7 million.

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

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

Litigation

We have various litigation matters related to the ordinary course of our business. We assess the probability of estimable amounts related to these matters in accordance with authoritative accounting guidance and adjust our accruals accordingly. Though some of the related claims may be significant, we believe the resolution of them, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals.

11. SUPPLEMENTAL CASH FLOW INFORMATION


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2020		2019		2020		2019
Cash paid during the period for:
Interest (net of capitalized amounts of $6,191, $9,574, $31,664 and $29,695, respectively) (1)	$	6,097	$	4,399	$	25,706	$	37,383
Income taxes	$	300	$	—	$	300	$	1,206
Cash received for income tax refunds	$	1,634	$	—	$	2,118	$	336

________________________________________

(1)The nine months ended September 30, 2019 includes $17.6 million in interest paid upon the redemption of Resolute’s senior notes and credit facility on March 1, 2019.

12.RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to Cimarex. Cimarex incurred drilling costs of approximately $6.9 thousand and $23.4 million related to these services during the three and nine months ended September 30, 2020 and $13.6 million and $60.2 million during the three and nine months ended September 30, 2019. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.

13.ACQUISITIONS AND DIVESTITURES

On September 30, 2020, we closed on the sale of certain water infrastructure assets in Eddy County, New Mexico, for net cash proceeds of $69.0 million. We will be entitled to additional future cash payments from the buyer upon the delivery of certain rights of way and if water volumes delivered by Cimarex or third parties meet certain thresholds during the 10 years following the date of sale. See Note 10 for more information on this sale.

On March 1, 2019, we completed the acquisition of Resolute Energy Corporation, an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the Permian Basin of west Texas. The principal factors considered by management in making this acquisition included: (i) our expectation that Resolute’s assets’ returns are competitive with those in our existing portfolio, (ii) the opportunity to apply our experience and learnings from already operating in this area to generating productivity gains from Resolute’s properties, (iii) the ability to increase our acreage position in the Delaware Basin, and (iv) the expectation that the acquisition will be financially accretive.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

We acquired 100% of the outstanding common shares and voting interests of Resolute in a cash and stock transaction. The acquisition date fair value of the consideration transferred totaled $820.3 million, which consisted of cash, common stock, and a newly created series of preferred stock (see Note 5 for more information on the preferred stock) as follows:


(in thousands)	Fair Value of Consideration Transferred
Cash	$	325,677
Common stock (5,652 shares issued)	413,015
Preferred stock (63 shares issued)	81,620
	$	820,312

The fair value of the common stock issued as part of the consideration was determined on the basis of the closing market price of Cimarex common stock on the acquisition date. The fair value of the preferred stock issued as part of the consideration was determined using a multiple probability simulation model.

Purchase Price Allocation

The Resolute acquisition has been accounted for as a business combination, using the acquisition method. The following table presents the allocation of the Resolute purchase price to the identifiable assets acquired and liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded to goodwill. The table also presents the adjustments made to the purchase price allocation during the 12-month period following the acquisition date. The purchase price allocation was finalized during the three months ended March 31, 2020. The most significant adjustment was made to reduce the fair value of the unproved oil and gas properties acquired by $30.3 million based on the finalization of the quantity of acres acquired. The tax effect of this adjustment reduced the related deferred income taxes by $6.9 million. The completion of the final Resolute tax returns provided the underlying tax basis of Resolute’s assets and liabilities and net operating losses and resulted in a reduction of the deferred tax liability of $24.4 million. The remaining adjustments were related to finalization of working capital balances. The offset to all of the adjustments was goodwill.

The following table sets forth the purchase price allocation:


(in thousands)	March 1, 2019		Adjustments		March 1, 2020
Cash	$	41,236	$	—	$	41,236
Accounts receivable	50,739		11,521		62,260
Other current assets	13,280		(1,176)		12,104
Proved oil and gas properties	692,600		—		692,600
Unproved oil and gas properties	1,054,200		(30,314)		1,023,886
Fixed assets	5,355		(32)		5,323
Goodwill	107,341		(13,126)		94,215
Other assets	142		—		142
Current liabilities	(202,735)		1,790		(200,945)
Long-term debt	(870,000)		—		(870,000)
Deferred income taxes	(62,409)		31,337		(31,072)
Asset retirement obligation	(9,437)		—		(9,437)
Total identifiable net assets	$	820,312	$	—	$	820,312

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2020

(Unaudited)

In connection with the acquisition, we assumed, and immediately repaid, $870.0 million principal amount of long-term debt consisting of $600.0 million of senior notes and $270.0 million of credit facility borrowings. On March 1, 2019, we repaid Resolute’s credit facility borrowings, delivered a notice of optional redemption of Resolute’s senior notes for an April 1, 2019 redemption date, and irrevocably deposited with a trustee the full amount of funds to repay the aggregate outstanding senior notes principal balance plus accrued and unpaid interest, incurring a $4.3 million loss on early extinguishment of debt. The cash consideration transferred and the repayment of Resolute’s long-term debt were funded using cash on hand and borrowings on our Credit Facility. We subsequently repaid the borrowings on our Credit Facility using the net proceeds from the March 8, 2019 issuance of $500 million aggregate principal amount of 4.375% senior unsecured notes.

Goodwill of $94.2 million was recognized in the purchase price allocation principally as a result of recording net deferred tax liabilities arising from the difference between the tax basis and the purchase price allocated to Resolute’s assets and liabilities, and anticipated opportunities for cost savings through administrative and operational synergies. We concluded that goodwill was impaired at March 31, 2020 (see Note 1 for more information regarding the goodwill impairment).

Acquisition-related costs incurred in the nine months ended September 30, 2019 were $8.4 million, with the majority incurred in the first quarter 2019. These costs, which were comprised primarily of advisory and legal fees, are included in the “Other operating expense, net” line item in the Condensed Consolidated Statement of Operations and Comprehensive Income.

Pro Forma Financial Information

The results of Resolute’s operations have been included in our consolidated financial statements since the March 1, 2019 acquisition date. The following supplemental pro forma information for the three and nine months ended September 30, 2019 has been prepared to give effect to the Resolute acquisition as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of the combined company’s proved oil and gas properties, (ii) the capitalization of interest expense, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by Cimarex of $8.4 million and transaction-related costs incurred by Resolute of $60.0 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by Cimarex to integrate the Resolute assets. The pro forma financial data has not been adjusted to reflect any other acquisitions or dispositions made during the period presented as their results were not deemed material.

The pro forma information is not necessarily indicative of the results that might have occurred had the transaction actually taken place on January 1, 2018 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities, and other factors.


(in thousands, except per share information)	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Revenue	$	582,305	$	1,758,861
Net income	$	123,857	$	245,753
Net income per common share:
Basic	$	1.21	$	2.39
Diluted	$	1.21	$	2.39

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Cimarex is an independent oil and gas exploration and production company. Our operations are entirely located in the United States, 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 long-term growth of our proved reserves and production while seeking to minimize our impact on the communities in which we operate for the long-term. Our strategy centers on maximizing cash flow from producing properties so that we can reinvest in exploration and development opportunities and provide cash returns to shareholders through dividends. We consider merger and acquisition opportunities that enhance our competitive position and we occasionally divest non-strategic assets.

On March 1, 2019, we completed the acquisition of Resolute Energy Corporation (“Resolute”), an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the Permian Basin of west Texas. See Note 13 to the Condensed Consolidated Financial Statements for more information on the acquisition.

We believe that detailed technical analysis, operational focus, and a disciplined capital investment process mitigates risk and positions 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 Russia 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 oil prices have risen to $39.63 per barrel in September 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.

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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 capital investments from $255.9 million in the first quarter of 2020 to $83.8 million in the second quarter of 2020 and $80.5 million in the third quarter of 2020. However, with the subsequent improvement in oil prices we are currently running four drilling rigs and expect to exit 2020 with four rigs. We are also currently completing wells with two completion crews. As a result, total capital expenditures for 2020 are expected to be approximately $600 million. This level of capital expenditures is expected to be less than our cash flow from operating activities, which will allow us to build cash and not incur any additional borrowings this year.

The table below shows average NYMEX prices and our company-wide average realized prices and price differentials for the periods indicated. Our average realized prices have declined for all products in the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019. Our average realized gas and NGL prices increased during the three months ended September 30, 2020 as compared to the three months ended September 30, 2019, while our average realized oil price declined. The average NYMEX prices have declined for all products in the 2020 periods as compared to the 2019 periods. However, our price differentials have improved for all products in the 2020 periods as compared to the 2019 periods.


	Three Months Ended September 30,				Variance Between 2020 / 2019	Nine Months Ended September 30,				Variance Between 2020 / 2019
	2020		2019			2020		2019
Average NYMEX price
Oil — per barrel	$	40.93	$	56.45	(27)%	$	38.32	$	57.06	(33)%
Gas — per Mcf	$	1.98	$	2.23	(11)%	$	1.88	$	2.67	(30)%

Average realized price
Oil — per barrel	$	37.94	$	52.71	(28)%	$	34.31	$	52.02	(34)%
Gas — per Mcf	$	1.14	$	0.88	30%	$	0.85	$	1.08	(21)%
NGL — per barrel	$	10.89	$	10.80	1%	$	9.50	$	13.36	(29)%

Average price differential
Oil — per barrel	$	(2.99)	$	(3.74)	20%	$	(4.01)	$	(5.04)	20%
Gas — per Mcf	$	(0.84)	$	(1.35)	38%	$	(1.03)	$	(1.59)	35%

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
	2020				2019
	Year-to-date		Third Quarter		Second Quarter		First Quarter		Year		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
Oil
Permian Basin	$	(3.86)	$	(2.71)	$	(8.12)	$	(2.00)	$	(4.48)	$	(2.18)	$	(3.76)	$	(5.80)	$	(6.90)
Mid-Continent	$	(5.23)	$	(5.06)	$	(9.53)	$	(2.02)	$	(3.14)	$	(2.05)	$	(3.72)	$	(4.39)	$	(2.17)
Total Company	$	(4.01)	$	(2.99)	$	(8.28)	$	(1.99)	$	(4.26)	$	(2.16)	$	(3.74)	$	(5.58)	$	(6.03)

Gas
Permian Basin	$	(1.38)	$	(1.15)	$	(1.09)	$	(1.85)	$	(2.14)	$	(1.67)	$	(1.83)	$	(3.10)	$	(1.91)
Mid-Continent	$	(0.40)	$	(0.31)	$	(0.31)	$	(0.57)	$	(0.68)	$	(0.74)	$	(0.66)	$	(0.86)	$	(0.46)
Total Company	$	(1.03)	$	(0.84)	$	(0.80)	$	(1.40)	$	(1.52)	$	(1.31)	$	(1.35)	$	(2.14)	$	(1.24)

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Pipeline expansion projects in the Permian Basin are expected to ease capacity constraints as they come online in 2021, which is reflected in the current futures markets that show narrowing differentials. However, if pipeline projects are delayed, production increases faster than capacity increases, or the basin experiences pipeline disruptions or other constraints, higher differentials will persist or potentially worsen. Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and gas production and can be adversely affected by realized price decreases. See RESULTS OF OPERATIONS Revenues below for further information regarding our realized commodity prices.

See RISK FACTORS in Item 1A of this Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of risk factors that affect our business, financial condition, and results of operations. Also, see CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in this report for important information about these types of statements.

Summary of Operating and Financial Results for the Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019:

•Total production volumes decreased 5% to 71.3 MMBOE.

•Oil volumes decreased 5% to 79.7 MBbls per day.

•Gas volumes decreased 3% to 651.0 MMcf per day.

•NGL volumes decreased 6% to 72.0 MBbls per day.

•Total production revenue decreased 35%, or $586.5 million, to $1.089 billion.

•Cash flow provided by operating activities decreased 28%, or $271.5 million, to $712.7 million.

•Exploration and development expenditures decreased 58%, or $576.5 million, to $413.0 million.

•Net loss was $1.992 billion, or $19.99 per diluted share, for the first nine months of 2020, as compared to net income of $259.5 million, or $2.56 per diluted share, for the first nine months of 2019.

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RESULTS OF OPERATIONS

Three and Nine Months Ended September 30, 2020 Compared to Three and Nine Months Ended September 30, 2019

Revenues

Our revenues are derived from sales of our oil, gas, and NGL production. Increases or decreases in our revenues, profitability, and future production growth are highly dependent on the commodity prices we receive. Prices are market driven and we expect that future prices will continue to fluctuate due to supply and demand factors, availability of transportation, seasonality, and geopolitical and economic factors. See QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for more information regarding the sensitivity of our revenues to price fluctuations.

Production volumes were lower for all products during the three months ended September 30, 2020 as compared to the three months ended September 30, 2019. This was due to a reduction in drilling and completion activity subsequent to the first quarter 2020 and curtailment or shut in of production in certain areas during the three months ended September 30, 2020 as a result of the unprecedented demand destruction and resulting severe price decreases for oil stemming from the COVID-19 pandemic. Realized prices were lower for oil, while realized prices for gas and NGLs were higher during the three months ended September 30, 2020 as compared to the three months ended September 30, 2019. Gas price differentials improved during the 2020 period as compared to the 2019 period. For the nine months ended September 30, 2020, average production volumes and realized prices were lower for all products as compared to the nine months ended September 30, 2019. Our production revenue decreased 32%, or $180.0 million, during the three months ended September 30, 2020 as compared to the three months ended September 30, 2019. Our production revenue decreased 35%, or $586.5 million, during the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019. The following tables show our production revenue for the periods indicated as well as the change in revenue due to changes in volumes and prices.


	Three Months Ended September 30,				Variance Between 2020 / 2019			Price/Volume Variance
Production Revenue (in thousands)	2020		2019					Price		Volume		Total
Oil sales	$	249,826	$	435,094	$	(185,268)	(43)%	$	(97,253)	$	(88,015)	$	(185,268)
Gas sales	63,323		58,277		5,046		9%	14,433		(9,387)		5,046
NGL sales	77,438		77,206		232		—%	640		(408)		232
	$	390,587	$	570,577	$	(179,990)	(32)%	$	(82,180)	$	(97,810)	$	(179,990)


	Nine Months Ended September 30,				Variance Between 2020 / 2019			Price/Volume Variance
Production Revenue (in thousands)	2020		2019					Price		Volume		Total
Oil sales	$	749,623	$	1,196,166	$	(446,543)	(37)%	$	(386,954)	$	(59,589)	$	(446,543)
Gas sales	152,307		198,615		(46,308)		(23)%	(41,029)		(5,279)		(46,308)
NGL sales	187,196		280,827		(93,631)		(33)%	(76,099)		(17,532)		(93,631)
	$	1,089,126	$	1,675,608	$	(586,482)	(35)%	$	(504,082)	$	(82,400)	$	(586,482)

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The table below presents our production volumes by region.


	Three Months Ended September 30,		Nine Months Ended September 30,
Production Volumes	2020	2019	2020	2019
Oil (Bbls per day)
Permian Basin	62,930	74,819	70,415	70,188
Mid-Continent	8,523	14,788	9,173	13,880
Other	118	124	155	162
	71,571	89,731	79,743	84,230
Gas (MMcf per day)
Permian Basin	380.2	422.9	415.6	381.2
Mid-Continent	222.3	293.7	234.5	292.1
Other	0.9	1.4	0.9	1.3
	603.4	718.0	651.0	674.6
NGL (Bbls per day)
Permian Basin	53,971	53,311	50,079	51,492
Mid-Continent	23,249	24,338	21,814	25,480
Other	74	44	58	49
	77,294	77,693	71,951	77,021
Total (BOE per day)
Permian Basin	180,273	198,617	189,755	185,222
Mid-Continent	68,816	88,076	70,071	88,044
Other	338	401	376	418
	249,427	287,094	260,202	273,684

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The table below presents our production volumes by commodity, our average realized commodity prices, and certain major U.S. index prices. The sale of our Permian Basin oil production is typically tied to the WTI Midland benchmark price and the sale of our Mid-Continent oil production is typically tied to the WTI Cushing benchmark price. During the nine months ended September 30, 2020, approximately 88% of our oil production was in the Permian Basin, up from approximately 83% during the nine months ended September 30, 2019. Our realized prices do not include settlements of commodity derivative contracts.


	Three Months Ended September 30,						Variance Between 2020 / 2019	Nine Months Ended September 30,						Variance Between 2020 / 2019
	2020			2019				2020			2019
Oil
Total volume — MBbls	6,585			8,255			(20)%	21,849			22,995			(5)%
Total volume — MBbls per day	71.6			89.7			(20)%	79.7			84.2			(5)%
Percentage of total production	29		%	31		%		30		%	31		%
Average realized price — per barrel	$	37.94		$	52.71		(28)%	$	34.31		$	52.02		(34)%
Average WTI Midland price — per barrel	$	41.07		$	55.83		(26)%	$	38.72		$	54.84		(29)%
Average WTI Cushing price — per barrel	$	40.93		$	56.45		(27)%	$	38.32		$	57.06		(33)%

Gas
Total volume — MMcf	55,510			66,058			(16)%	178,387			184,166			(3)%
Total volume — MMcf per day	603.4			718.0			(16)%	651.0			674.6			(3)%
Percentage of total production	40		%	42		%		42		%	41		%
Average realized price — per Mcf	$	1.14		$	0.88		30%	$	0.85		$	1.08		(21)%
Average Henry Hub price — per Mcf	$	1.98		$	2.23		(11)%	$	1.88		$	2.67		(30)%

NGL
Total volume — MBbls	7,111			7,148			(1)%	19,715			21,027			(6)%
Total volume — MBbls per day	77.3			77.7			(1)%	72.0			77.0			(6)%
Percentage of total production	31		%	27		%		28		%	28		%
Average realized price — per barrel	$	10.89		$	10.80		1%	$	9.50		$	13.36		(29)%

Total
Total production — MBOE	22,947			26,413			(13)%	71,295			74,716			(5)%
Total production — MBOE per day	249.4			287.1			(13)%	260.2			273.7			(5)%
Average realized price — per BOE	$	17.02		$	21.60		(21)%	$	15.28		$	22.43		(32)%

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Other revenues

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


	Three Months Ended September 30,				Variance Between 2020 / 2019		Nine Months Ended September 30,				Variance Between 2020 / 2019
Gas Gathering and Marketing Revenues (in thousands)	2020		2019				2020		2019
Gas gathering and other	$	11,555	$	11,200	$	355	$	36,727	$	31,231	$	5,496
Gas marketing	$	(483)	$	528	$	(1,011)	$	(1,981)	$	(1,114)	$	(867)

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

Operating Costs and Expenses

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

Total operating costs and expenses for the three months ended September 30, 2020 were higher by 85%, or $347.8 million, compared to the three months ended September 30, 2019. The primary reasons for the increase were: (i) the $351.0 million ceiling test impairment incurred during the three months ended September 30, 2020 and (ii) the $104.3 million increase in net losses on derivative instruments, partially offset by decreases of (iii) $72.5 million in depreciation, depletion, and amortization and (iv) $27.8 million in production expense.


	Three Months Ended September 30,				Variance Between 2020 / 2019		Per BOE
Operating Costs and Expenses (in thousands, except per BOE)	2020		2019				2020		2019
Impairment of oil and gas properties	$	351,029	$	—	$	351,029	N/A		N/A
Depreciation, depletion, and amortization	155,467		227,978		(72,511)		$	6.78	$	8.63
Asset retirement obligation	4,159		2,194		1,965		$	0.18	$	0.08

Production (1)	62,025		89,820		(27,795)		$	2.70	$	3.40
Transportation, processing, and other operating (1)	53,130		59,797		(6,667)		$	2.32	$	2.26
Gas gathering and other (1)	4,649		5,273		(624)		$	0.20	$	0.20
Taxes other than income	22,822		30,873		(8,051)		$	0.99	$	1.17
General and administrative	28,598		15,499		13,099		$	1.25	$	0.59
Stock compensation	9,738		6,797		2,941		$	0.42	$	0.26
Loss (gain) on derivative instruments, net	65,607		(38,735)		104,342		N/A		N/A
Other operating expense, net	167		10,141		(9,974)		N/A		N/A
	$	757,391	$	409,637	$	347,754

________________________________________

(1) In order to conform with the 2020 presentation, the 2019 amount presented reflects the reclassification of certain “Gas gathering and other” expenses to “Transportation, processing, and other operating” expenses and “Production” expense. These reclassifications were made to reflect an allocation of the costs incurred to operate our gas gathering facilities as a cost to transport our equity share of gas produced and operate our wells. See

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Note 1 to the Condensed Consolidated Financial Statements for further information regarding these prior year reclassifications.

Total operating costs and expenses for the nine months ended September 30, 2020 were higher by 158%, or $2.108 billion, compared to the nine months ended September 30, 2019. The primary reasons for the increase were: (i) the $1.626 billion in ceiling test impairments incurred during the nine months ended September 30, 2020 and (ii) the $714.4 million impairment of goodwill incurred during the nine months ended September 30, 2020, partially offset by (iii) the $73.4 million increase in net gains on derivative instruments and decreases of (iv) $66.2 million in depreciation, depletion, and amortization, (v) $43.6 million in production expense, and (vi) $35.3 million in taxes other than income.


	Nine Months Ended September 30,				Variance Between 2020 / 2019		Per BOE
Operating Costs and Expenses (in thousands, except per BOE)	2020		2019				2020		2019
Impairment of oil and gas properties	$	1,625,878	$	—	$	1,625,878	N/A		N/A
Depreciation, depletion, and amortization	565,507		631,722		(66,215)		$	7.93	$	8.45
Asset retirement obligation	10,544		6,400		4,144		$	0.15	$	0.09
Impairment of goodwill	714,447		—		714,447		N/A		N/A
Production (1)	213,598		257,219		(43,621)		$	3.00	$	3.44
Transportation, processing, and other operating (1)	161,334		173,479		(12,145)		$	2.26	$	2.32
Gas gathering and other (1)	16,473		17,015		(542)		$	0.23	$	0.23
Taxes other than income	70,269		105,600		(35,331)		$	0.99	$	1.41
General and administrative	80,333		69,494		10,839		$	1.13	$	0.93
Stock compensation	22,879		20,004		2,875		$	0.32	$	0.27
(Gain) loss on derivative instruments, net	(37,448)		35,949		(73,397)		N/A		N/A
Other operating expense, net	548		19,057		(18,509)		N/A		N/A
	$	3,444,362	$	1,335,939	$	2,108,423

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Impairment of Oil and Gas Properties

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

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The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur a full cost ceiling test impairment. The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date.

Depreciation, Depletion, and Amortization

Depletion of our producing properties is computed using the units-of-production method. The economic life of each producing well depends upon the estimated proved reserves for that well, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved, and impairments of oil and gas properties will also impact depletion expense. Our depletion expense decreased during the three and nine months ended September 30, 2020 as compared to the three and nine months ended September 30, 2019 primarily due to a decrease in our depletable basis mostly resulting from ceiling test impairments recognized at December 31, 2019, March 31, 2020, and June 30, 2020. In addition, our depletion expense decreased during the 2020 periods also as a result of a decrease in our production resulting from a reduction in drilling and completion activity subsequent to the first quarter 2020 and curtailment or shut in of production in certain areas stemming from the demand destruction caused by the COVID-19 pandemic. These causes for decreased depletion expense were partially offset by a decrease in our reserves primarily due to a decrease in the trailing twelve month prices used to calculate reserves.

Fixed assets consist primarily of gas gathering and plant facilities, water infrastructure assets, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated to depreciation expense on the straight-line method based on the expected lives of the individual assets, which range from 3 to 30 years. Also included in our depreciation expense is the depreciation of the right-of-use asset associated with our finance lease gas gathering system. The increase in depreciation expense during the three and nine months ended September 30, 2020 as compared to the three and nine months ended September 30, 2019 is primarily due to increased depreciation on our gas gathering and plant facilities due to ongoing expenditures on this infrastructure. Depreciation, depletion, and amortization (“DD&A”) consisted of the following for the periods indicated:


	Three Months Ended September 30,				Variance Between 2020 / 2019		Per BOE
DD&A Expense (in thousands, except per BOE)	2020		2019				2020		2019
Depletion	$	137,655	$	211,422	$	(73,767)	$	6.00	$	8.00
Depreciation	17,812		16,556		1,256		0.78		0.63
	$	155,467	$	227,978	$	(72,511)	$	6.78	$	8.63

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	Nine Months Ended September 30,				Variance Between 2020 / 2019		Per BOE
DD&A Expense (in thousands, except per BOE)	2020		2019				2020		2019
Depletion	$	512,917	$	583,033	$	(70,116)	$	7.19	$	7.80
Depreciation	52,590		48,689		3,901		0.74		0.65
	$	565,507	$	631,722	$	(66,215)	$	7.93	$	8.45

Impairment of Goodwill

We concluded that goodwill was impaired at March 31, 2020 and expensed the entire balance of $714.4 million at that time. See Note 1 to the Condensed Consolidated Financial Statements for additional information regarding the impairment of goodwill.

Production

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


	Three Months Ended September 30,				Variance Between 2020 / 2019		Per BOE
Production Expense (in thousands, except per BOE)	2020		2019				2020		2019
Lease operating expense	$	51,066	$	67,815	$	(16,749)	$	2.22	$	2.57
Workover expense	10,959		22,005		(11,046)		0.48		0.83
	$	62,025	$	89,820	$	(27,795)	$	2.70	$	3.40


	Nine Months Ended September 30,				Variance Between 2020 / 2019		Per BOE
Production Expense (in thousands, except per BOE)	2020		2019				2020		2019
Lease operating expense	$	183,962	$	204,441	$	(20,479)	$	2.58	$	2.73
Workover expense	29,636		52,778		(23,142)		0.42		0.71
	$	213,598	$	257,219	$	(43,621)	$	3.00	$	3.44

Lease operating expense for the third quarter of 2020 decreased 25%, or $16.7 million, compared to the third quarter of 2019. Lease operating expense for the nine months ended September 30, 2020 decreased 10%, or $20.5 million, compared to the nine months ended September 30, 2019. The decreases in the 2020 periods as compared to the 2019 periods are primarily related to the reduction in activity and our cost saving efforts such as our initiative to reduce outside labor, our voluntary early retirement incentive program, delaying non-essential work, shutting in wells, and decreasing drilling and completion, which has led to fewer wells coming online.

Workover expense for the third quarter of 2020 decreased 50%, or $11.0 million, compared to the third quarter of 2019. Workover expense for the nine months ended September 30, 2020 decreased 44%, or $23.1 million, compared to the nine months ended September 30, 2019. We had fewer workover projects during the 2020 periods as compared to the 2019 periods as a result of a concerted effort to reduce activity and delay non-essential work. We expect workover expense to increase in future periods from the third quarter of 2020 levels.

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Transportation, Processing, and Other Operating

Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, including gathering, fuel, compression, and processing costs. Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, changes in fuel and compression costs, and the structure of sales contracts. If the sales contract transfers control of the product at the wellhead, transportation and processing costs are included as a reduction in the revenue we record and are not included in transportation, processing, and other operating costs. Transportation, processing, and other operating costs for the third quarter of 2020 were 11%, or $6.7 million, lower than the same costs in the third quarter of 2019. Transportation, processing, and other operating costs for the nine months ended September 30, 2020 were 7%, or $12.1 million, lower than the same costs in the nine months ended September 30, 2019. The decrease in this expense in the 2020 periods as compared to the 2019 periods is primarily due to a decrease in volumes.

Gas Gathering and Other

Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs and operating and maintenance expenses. A portion of these costs are reclassified to “Transportation, processing, and other operating” expense and “Production” expense in order to reflect an allocation of the costs incurred to operate our gas gathering facilities as a cost of transporting our equity share of gas produced and operating our wells. Gas gathering and other in the three months ended September 30, 2020 was 12%, or $0.6 million, lower than gas gathering and other in the three months ended September 30, 2019 resulting primarily from a decrease in compression costs. Gas gathering and other in the nine months ended September 30, 2020 was 3%, or $0.5 million, lower than gas gathering and other in the nine months ended September 30, 2019.

Taxes Other than Income

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


	Three Months Ended September 30,						Variance Between 2020 / 2019		Nine Months Ended September 30,						Variance Between 2020 / 2019
Taxes Other than Income (in thousands)	2020			2019					2020			2019
Production	$	15,838		$	23,485		$	(7,647)	$	44,293		$	80,223		$	(35,930)
Ad valorem	6,627			7,152			(525)		25,078			24,686			392
Other	357			236			121		898			691			207
	$	22,822		$	30,873		$	(8,051)	$	70,269		$	105,600		$	(35,331)

Taxes other than income as a percentage of production revenue	5.8		%	5.4		%			6.5		%	6.3		%

Taxes other than income decreased $8.1 million, or 26%, in the third quarter of 2020 as compared to the third quarter of 2019 and decreased $35.3 million, or 33%, in the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019. Production taxes typically make up the majority of our taxes other than income and they decreased significantly primarily due to decreased revenues as a result of decreased prices and volumes. Ad valorem tax accruals are based on the most recent actual taxes paid with adjustments made based on expected valuations and as better information, including actual valuations, is received. Other taxes are comprised of franchise and consumer use and sales taxes.

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General and Administrative

General and administrative (“G&A”) expense consists primarily of salaries and related benefits, office rent, legal and consulting fees, systems costs, and other administrative costs incurred. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting. The amount of expense capitalized varies and depends on whether the cost incurred can be directly identified with acquisition, exploration, and development activities. The percentage of gross G&A capitalized ranged from 31% to 48% during the periods presented in the table below, which shows our G&A costs.


	Three Months Ended September 30,				Variance Between 2020 / 2019		Nine Months Ended September 30,				Variance Between 2020 /2019
General and Administrative Expense (in thousands)	2020		2019				2020		2019
Gross G&A	$	41,377	$	29,828	$	11,549	$	124,644	$	125,994	$	(1,350)
Less amounts capitalized to oil and gas properties	(12,779)		(14,329)		1,550		(44,311)		(56,500)		12,189
G&A expense	$	28,598	$	15,499	$	13,099	$	80,333	$	69,494	$	10,839

G&A expense for the third quarter of 2020 was 85%, or $13.1 million, higher than G&A expense for the third quarter of 2019. G&A expense for the nine months ended September 30, 2020 was 16%, or $10.8 million, higher than G&A expense for the nine months ended September 30, 2019. G&A expense increased in the 2020 periods as compared to the 2019 periods primarily due to severance costs associated with the voluntary early retirement incentive program (“ERIP”) that we offered to employees who met certain eligibility criteria in the first quarter of 2020 and the involuntary reduction in workforce (“RIF”) that we carried out in the third quarter of 2020. We recognized $31.0 million in severance expense in 2020, including $14.6 million in the third quarter of 2020. At September 30, 2020 and December 31, 2019, we had 747 and 987 employees, respectively. Partially offsetting increases to G&A expense due to the severance associated with the ERIP and RIF programs were decreases in salaries and wages resulting primarily from the ERIP. We expect G&A expense related to salaries and wages to be lower in future periods as a result of the ERIP and RIF. In response to low oil prices and demand destruction, we have reduced our acquisition, exploration, and development activities, and, therefore, the percentage of gross G&A capitalized has decreased from prior periods.

Stock Compensation

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


	Three Months Ended September 30,				Variance Between 2020 / 2019		Nine Months Ended September 30,				Variance Between 2020 / 2019
Stock Compensation Expense (in thousands)	2020		2019				2020		2019
Restricted stock awards:
Performance stock awards	$	5,931	$	5,604	$	327	$	14,050	$	16,533	$	(2,483)
Service-based stock awards	6,214		6,140		74		20,176		19,364		812
	12,145		11,744		401		34,226		35,897		(1,671)
Stock option awards	207		411		(204)		1,121		1,429		(308)
Total stock compensation cost	12,352		12,155		197		35,347		37,326		(1,979)
Less amounts capitalized to oil and gas properties	(2,614)		(5,358)		2,744		(12,468)		(17,322)		4,854
Stock compensation expense	$	9,738	$	6,797	$	2,941	$	22,879	$	20,004	$	2,875

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Periodic stock compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards as well as due to the capitalization rates applied to the gross expense. In response to low oil prices and demand destruction in 2020, we have reduced our acquisition, exploration, and development activities, and, therefore, the percentage of gross stock compensation capitalized has decreased from prior periods.

Loss (Gain) on Derivative Instruments, Net

The following table presents the components of “Loss (gain) on derivative instruments, net” for the periods indicated. See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.


	Three Months Ended September 30,				Variance Between 2020 / 2019		Nine Months Ended September 30,				Variance Between 2020 / 2019
Loss (Gain) on Derivative Instruments, Net (in thousands)	2020		2019				2020		2019
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts	$	43,975	$	5,818	$	38,157	$	76,294	$	(10,398)	$	86,692
Oil contracts	35,306		(42,857)		78,163		6,987		45,229		(38,242)
	79,281		(37,039)		116,320		83,281		34,831		48,450
Cash (receipts) payments on derivative instruments, net:
Gas contracts	(2,837)		(17,554)		14,717		(20,426)		(34,966)		14,540
Oil contracts	(10,837)		15,858		(26,695)		(100,303)		36,084		(136,387)
	(13,674)		(1,696)		(11,978)		(120,729)		1,118		(121,847)
Loss (gain) on derivative instruments, net	$	65,607	$	(38,735)	$	104,342	$	(37,448)	$	35,949	$	(73,397)

Other Operating Expense, Net

Other operating expense, net during the nine months ended September 30, 2019 included $8.4 million in acquisition-related costs incurred to effect the Resolute acquisition. These costs consisted primarily of advisory and legal fees. Other operating expense, net for the three and nine months ended September 30, 2019 included $10.0 million of litigation settlements.

Other Income and Expense


	Three Months Ended September 30,				Variance Between 2020 / 2019		Nine Months Ended September 30,				Variance Between 2020 / 2019
Other Income and Expense (in thousands)	2020		2019				2020		2019
Interest expense	$	23,361	$	24,586	$	(1,225)	$	69,589	$	69,665	$	(76)
Capitalized interest	(12,286)		(16,264)		3,978		(38,407)		(41,811)		3,404
Loss on early extinguishment of debt	—		—		—		—		4,250		(4,250)
Other, net	(1,572)		(140)		(1,432)		1,053		(4,548)		5,601
	$	9,503	$	8,182	$	1,321	$	32,235	$	27,556	$	4,679

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The majority of our interest expense relates to interest on our senior unsecured notes. Also included in interest expense is interest expense on our Credit Facility borrowings, the amortization of debt issuance costs and discounts, and miscellaneous interest expense. See LIQUIDITY AND CAPITAL RESOURCES Long-term Debt below for further information regarding our debt. The $4.3 million loss on early extinguishment of debt incurred during the nine months ended September 30, 2019 was associated with the $600 million of 8.5% senior notes we acquired with Resolute and elected to immediately repay. The maturity date of the Resolute notes was May 1, 2020.

We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing gathering and water facility assets. Capitalized interest will fluctuate based primarily on the amount of costs subject to interest capitalization and based on the rates applicable to borrowings outstanding during the period. The amount of interest capitalized was lower for the three and nine months ended September 30, 2020 than it was for the three and nine months ended September 30, 2019 due to a decrease in costs subject to interest capitalization primarily as a result of a decrease in the balance of non-producing leasehold acquired in the Resolute acquisition. Since the March 1, 2019 acquisition, the balance of these assets has declined due to purchase price adjustments and transfers to proved properties. Also contributing to the decrease in costs subject to interest capitalization in the 2020 periods as compared to the 2019 periods is a decrease in the in-progress costs of drilling and completing wells and constructing gathering facility assets due to decreased activity in 2020.

Components of “Other, net” consist of miscellaneous income and expense items that vary from period to period, including interest income, gain or loss related to the sale or value of oil and gas well equipment and supplies, gain or loss on miscellaneous asset sales, and income and expense associated with other non-operating activities.

Income Tax (Benefit) Expense

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


	Three Months Ended September 30,						Variance Between 2020 / 2019		Nine Months Ended September 30,						Variance Between 2020 / 2019
Income Tax (Benefit) Expense (in thousands)	2020			2019					2020			2019
Current tax benefit	$	—		$	—		$	—	$	(161)		$	—		$	(161)
Deferred tax (benefit) expense	(72,495)			40,639			(113,134)		(360,395)			82,758			(443,153)
	$	(72,495)		$	40,639		$	(113,134)	$	(360,556)		$	82,758		$	(443,314)

Combined federal and state effective income tax rate	19.8		%	24.7		%			15.3		%	24.2		%

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LIQUIDITY AND CAPITAL RESOURCES

Overview

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

We strive to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include our cash flow from operations, cash on hand, available borrowing capacity under our revolving credit facility, proceeds from sales of non-strategic assets.

Our liquidity is highly dependent on prices we receive for the oil, gas, and NGLs we produce. Prices we receive are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital, and future rate of growth. See RESULTS OF OPERATIONS Revenues above for further information regarding the impact realized prices have had on our earnings. Low oil prices will lead to lower production revenues and could lead to payment being required where we fail to deliver oil, gas, and NGLs to meet minimum volume commitments.

We address volatility in commodity prices primarily by maintaining flexibility in our capital investment program. We have a balanced and abundant drilling inventory and limited long-term commitments, which enable us to respond quickly to industry volatility. 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 capital investments from $255.9 million in the first quarter of 2020 to $83.8 million in the second quarter of 2020 and $80.5 million in the third quarter of 2020. However, with the subsequent improvement in oil prices we are currently running four drilling rigs and expect to exit 2020 with four rigs. We also currently are completing wells with two completion crews. As a result, total capital expenditures for 2020 are expected to be approximately $600 million. This level of capital expenditures is expected to be less than our cash flow from operating activities, which will allow us to build cash and not incur any additional borrowings this year. See Capital Expenditures below for information regarding our E&D activities for the three and nine months ended September 30, 2020 and 2019 and our plans to fund 2020 capital expenditures.

We periodically use derivative instruments to mitigate volatility in commodity prices. At September 30, 2020, we had derivative contracts covering a portion of our 2020 - 2022 production. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. See Note 3 to the Condensed Consolidated Financial Statements for information regarding our derivative instruments.

Cash and cash equivalents at September 30, 2020 were $273.0 million. At September 30, 2020, our long-term debt consisted of $2.0 billion of senior unsecured notes, with $750 million 4.375% notes due in 2024, $750 million 3.90% notes due in 2027, and $500 million 4.375% notes due in 2029. At September 30, 2020, we had no borrowings and $2.5 million in letters of credit outstanding under our credit facility, leaving an unused borrowing availability of $1.248 billion. We expect the investment approach discussed above will allow us to accumulate cash for the future repayment of debt. See Long-term Debt below for more information regarding our debt.

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

We expect our operating cash flow and other capital resources to be adequate to meet our needs for planned capital expenditures, working capital, debt service, and dividends declared for the next twelve months.

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Analysis of Cash Flow Changes

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


	Nine Months Ended September 30,
(in thousands)	2020		2019
Net cash provided by operating activities	$	712,690	$	984,157
Net cash used by investing activities	$	(457,628)	$	(1,314,450)
Net cash used by financing activities	$	(76,827)	$	(446,488)

Net cash provided by operating activities for the nine months ended September 30, 2020 was $712.7 million, down $271.5 million, or 28%, from $984.2 million for the nine months ended September 30, 2019. The $271.5 million decrease resulted primarily from a decrease in revenues in the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 due to the price collapses and demand destruction seen in 2020 as a result of the COVID-19 pandemic and actions of OPEC and other countries in 2020. This decrease was partially offset by increased cash inflows for settlements of derivative instruments, decreased operating expenses, and a decreased investment in working capital during the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019. See RESULTS OF OPERATIONS above for more information regarding the changes in revenues and expenses.

Net cash used by investing activities for the nine months ended September 30, 2020 and 2019 was $457.6 million and $1.314 billion, respectively. The majority of our cash flows used by investing activities are for oil and gas capital expenditures, which totaled $482.1 million and $999.2 million for the nine months ended September 30, 2020 and 2019, respectively. Our 2020 oil and gas capital expenditures have decreased as compared to 2019 due to deliberate actions taken by us to reduce our capital investment in response to the decline in oil prices and demand. Net cash used by investing activities in the nine months ended September 30, 2019 included the $325.7 million cash portion of the consideration paid for the Resolute acquisition, net of the $41.2 million in cash acquired with Resolute. The remaining investing cash outflows are primarily for midstream asset expenditures. Included in net cash used by investing activities are the proceeds of miscellaneous asset sales, including non-strategic oil and gas properties. The nine months ended September 30, 2020 includes net cash proceeds of $69.0 million received for the September 30, 2020 sale of certain water infrastructure assets in Eddy County, New Mexico.

Net cash used by financing activities was $76.8 million and $446.5 million during the nine months ended September 30, 2020 and 2019, respectively. During the nine months ended September 30, 2020, we borrowed and repaid an aggregate of $172.0 million on our credit facility to meet cash requirements as needed. During the nine months ended September 30, 2020, we amended our credit facility, paying $1.5 million in financing costs. During the nine months ended September 30, 2019, we issued $500 million aggregate principal amount of 4.375% senior unsecured notes due March 15, 2029 at 99.862% of par for proceeds of $499.3 million, paying $4.6 million in underwriting fees and financing costs. Additionally, we borrowed and repaid an aggregate of $1.740 billion on our credit facility during the nine months ended September 30, 2019 in part to assist in funding the Resolute acquisition. In connection with the acquisition of Resolute, we assumed $870.0 million in principal amount of long-term debt that we immediately repaid, incurring a redemption fee of $4.3 million. During the nine months ended September 30, 2019, we amended our credit facility, paying $3.0 million in financing costs. Net cash used by financing activities during both periods included: (i) the payment of dividends, (ii) the payment of income tax withholdings made on behalf of our employees upon the net settlement of employee stock awards, and (iii) finance lease payments. During the nine months ended September 30, 2020, we paid one $0.20 per share dividend and two $0.22 per share dividends on our common stock and three $20.3125 per share dividends on our preferred stock, totaling $68.9 million. During the nine months ended September 30, 2019, we paid one $0.18 per share dividend and two $0.20 per share dividends on our common stock and two $20.3125 per share dividends on our preferred stock,

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totaling $60.1 million. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Capital Expenditures

The following table presents capitalized expenditures for oil and gas acquisition, exploration, and development activities. The table also presents the amounts, net of applicable purchase price adjustments, removed from our oil and gas properties balance due to property sales.


	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2020		2019			2020		2019
Acquisitions:
Proved	$	—	$	2,373		$	7,250	$	696,173
Unproved	—		(30,314)		(1)	—		1,021,468
	—		(27,941)			7,250		1,717,641
Exploration and development:
Land and seismic	11,586		18,377			37,626		42,456
Exploration and development	68,963		278,083			375,357		947,002
	80,549		296,460			412,983		989,458
Property sales:
Proved	(67,514)		(9,286)			(67,514)		(27,314)
Unproved	—		(81)			(830)		(9,835)
	(67,514)		(9,367)			(68,344)		(37,149)
	$	13,035	$	259,152		$	351,889	$	2,669,950

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(1) Amount represents an adjustment made to the Resolute preliminary purchase price allocation upon finalization of the quantity of acres acquired.

Amounts in the table above are presented on an accrual basis. The Condensed Consolidated Statements of Cash Flows reflect activities on a cash basis, when payments are made and proceeds received.

On March 1, 2019, we completed the acquisition of Resolute. The fair value of the proved and unproved properties recorded in the preliminary purchase price allocation for this acquisition as of September 30, 2019 was $692.6 million and $1.02 billion, respectively, as included in the table above.

Our 2020 total capital expenditures were originally projected to range from $1.25-$1.35 billion, with the majority expected to be invested in the Permian Basin. In response to the decline in oil prices in the second quarter 2020, we took immediate steps to reduce our capital investment, including releasing all but one drilling rig by mid-May and deferring well completion activity. This resulted in a reduction in capital investments from $255.9 million in the first quarter of 2020 to $83.8 million in the second quarter of 2020 and $80.5 million in the third quarter of 2020. However, with the subsequent improvement in oil prices we currently are running four drilling rigs and expect to exit 2020 with four rigs. We also currently are completing wells with two completion crews. As a result, total capital expenditures for 2020 are expected to be approximately $600 million. This level of capital expenditures is expected to be less than our cash flow from operating activities, which will allow us to build cash and not incur any additional borrowings this year. We regularly review our capital expenditures throughout the year and will adjust our investments based on increases or decreases in our cash flow. We have the flexibility to adjust our capital expenditures based upon market conditions.

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We intend to continue to fund our 2020 capital investment program with cash flow from our operating activities and potential sales of non-strategic assets. The timing of capital expenditures and the receipt of cash flows do not necessarily match, which may cause us to borrow and repay funds under our credit facility from time to time. See Long-term Debt—Bank Debt below for further information regarding our credit facility.

The following table reflects wells completed by region during the periods indicated.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Gross wells
Permian Basin	7	44	59	100
Mid-Continent	4	52	43	144
	11	96	102	244
Net wells
Permian Basin	1.4	16.1	32.3	53.0
Mid-Continent	nil	5.4	1.7	16.1
	1.4	21.5	34.0	69.1

As of September 30, 2020, we had 11 gross (5.5 net) wells in the process of being drilled: 7 gross (5.5 net) in the Permian Basin and 4 gross (nil net) in the Mid-Continent region. As of September 30, 2020, we had 74 gross (39.0 net) wells waiting on completion: 51 gross (38.7 net) in the Permian Basin and 23 gross (0.3 net) in the Mid-Continent region. By mid-May 2020, we had released all but one rig and placed completion activities on hold due to economic conditions. Since that time with the stabilization of commodity prices, we have added three drilling rigs and plan to exit 2020 with four rigs. We also began completing wells starting in September with two completion crews. We maintain flexibility to adjust our activity as conditions change.

We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations. While we expect current pending legislation or regulations to increase the cost of business, we do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact, based on current laws and regulations. However, compliance with new legislation or regulations or the election of a new administration could increase our costs or adversely affect demand for oil or gas and result in a material adverse effect on our financial position or operations. See our Form 10-K for the year ended December 31, 2019, Item 1A Risk Factors, and Part II, Item 1A, Risk Factors, of this Form 10-Q for a description of risks related to current and potential future environmental and safety regulations and requirements that could adversely affect our operations and financial condition.

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Long-term Debt

Long-term debt at September 30, 2020 and December 31, 2019 consisted of the following:


	September 30, 2020						December 31, 2019
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)		Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discounts (1)		Long-term Debt, net
4.375% Notes due 2024	$	750,000	$	(2,884)	$	747,116	$	750,000	$	(3,535)	$	746,465
3.90% Notes due 2027	750,000		(5,731)		744,269		750,000		(6,289)		743,711
4.375% Notes due 2029	500,000		(4,600)		495,400		500,000		(4,930)		495,070
	$	2,000,000	$	(13,215)	$	1,986,785	$	2,000,000	$	(14,754)	$	1,985,246

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Bank Debt

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At September 30, 2020 and December 31, 2019, we had $4.7 million and $4.0 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in “Other assets” on our Condensed Consolidated Balance Sheets. We incurred $1.5 million in fees paid to the creditor and third-party costs for the First Amendment. These costs are being amortized to interest expense ratably over the life of the Credit Facility.

Senior Notes

Our senior unsecured notes are governed by indentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of September 30, 2020.

Working Capital Analysis

At September 30, 2020, we had a working capital surplus of $38.1 million, an increase of $175.2 million or 128% from a working capital deficit of $137.1 million at December 31, 2019. Our working capital deficit decreased primarily as a result of the following:

Working Capital Increases

•Our cash balance increased by $178.2 million due to improvement in cash flow with the stabilization of commodity prices and the September 30, 2020 sale of certain water infrastructure assets in Eddy County, New Mexico;

•Operations-related accounts payable and accrued liabilities decreased by $151.0 million, primarily due to decreases in revenue payable due to declines in prices and trade accounts payable and other operations-related payables and accruals due to decreased activity; and

•A decrease in our exploration and development and midstream capital accruals of $84.9 million as a result of our decision to reduce our capital investment in response to the decline in oil prices.

Working Capital Decreases

•Accounts receivable decreased by $179.1 million, primarily due to declines in prices lowering our oil and gas sales receivable; and

•A decrease of $58.6 million from a net current derivative asset to a net current derivative liability.

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Accounts receivable are a major component of our working capital and include amounts due from a diverse group of companies comprised of major energy companies, pipeline companies, local distribution companies, and other end-users. We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary. For properties we operate, we have the right to realize amounts due to us from non-operators by netting the non-operators’ share of production revenues from those properties. We routinely assess the recoverability of all material accounts receivable and accrue a reserve to the allowance for doubtful accounts based on our estimation of expected losses over the life of the receivables. Historically, losses associated with uncollectible receivables have not been significant. However, most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry, such as those currently impacting the industry as a result of the COVID-19 pandemic and low commodity prices.

Dividends

A quarterly cash dividend has been paid on our common stock every quarter since the first quarter of 2006. In August 2020, our Board of Directors declared a cash dividend of $0.22 per common share, totaling $22.5 million, which is payable on or before December 1, 2020 to stockholders of record on November 13, 2020. Also in August 2020, our Board of Directors declared a cash dividend of $20.3125 per preferred share, totaling $1.3 million. The dividend was paid in October to preferred stockholders of record on October 1, 2020. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2020, our material off-balance sheet arrangements consisted of operating lease agreements with lease terms at commencement of 12 months or less. As an accounting policy, we have elected not to apply the recognition requirements of Topic 842 to these leases. As such, we have not recorded any lease liabilities associated with these leases.

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Contractual Obligations and Material Commitments

At September 30, 2020, we had the following contractual obligations and material commitments:


	Payments Due by Period
Contractual obligations (in thousands)	Total		10/01/20 - 09/30/21		10/01/21 - 09/30/23			10/01/23 - 09/30/25			10/01/25 and Thereafter
Long-term debt—principal (1)	$	2,000,000	$	—	$	—		$	750,000		$	1,250,000
Long-term debt—interest (1)	521,999		81,868		167,875			135,063			137,193
Operating leases (2)	78,082		22,548		24,675			20,160			10,699
Unconditional purchase obligations (3)	23,197		11,351		6,193			5,653			—
Derivative liabilities	122,811		96,763		26,048			—			—
Asset retirement obligation (4)	172,287		12,037		—		(4)	—		(4)	—		(4)
Other long-term liabilities (5)	46,204		2,648		10,684			3,609			29,263
	$	2,964,580	$	227,215	$	235,475		$	914,485		$	1,427,155

________________________________________

(1)The interest payments presented above include the accrued interest payable on our long-term debt as of September 30, 2020 as well as future payments calculated using the long-term debt’s fixed rates, stated maturity dates, and principal amounts outstanding as of September 30, 2020. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.

(2)Operating leases include the estimated remaining contractual payments under lease agreements as of September 30, 2020. These lease agreements are primarily comprised of leases for commercial real estate, which consists primarily of office space, and compressor equipment.

(3)Of the total unconditional purchase obligations, $18.7 million represents obligations for firm transportation agreements for gas pipeline capacity.

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

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

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

At September 30, 2020, we had firm sales contracts to deliver approximately 498.2 Bcf of gas over the next 10.8 years. If we do not deliver this gas, our estimated financial commitment, calculated using October 2020 index prices, would be approximately $780.0 million. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels and our ability to make market purchases to fulfill these volumetric obligations.

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In connection with gas gathering and processing agreements, we have volume commitments over the next 8.3 years. If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2020, would be approximately $658.9 million. With the current commodity price environment we curtailed some production and reduced drilling activity subsequent to the first quarter 2020 and may again curtail production and further reduce drilling activity in the future; however, at this time we do not believe any financial commitment resulting from potential future volume commitment shortfalls will be material.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas or oil, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2020, would be approximately $102.6 million. Of this total, we have accrued a liability of $4.3 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points. This accrual is reflected in the table above in Other long-term liabilities. With the current commodity price environment we curtailed some production and reduced drilling activity subsequent to the first quarter 2020 and may again curtail production and further reduce drilling activity in the future; however, at this time we do not believe any financial commitment resulting from potential future minimum volume delivery commitment shortfalls will be material.

We have minimum volume water delivery commitments associated with a water services agreement entered into in connection with the sale of certain water infrastructure assets in Eddy County, New Mexico (see Note 13 to the Condensed Consolidated Financial Statements). If we do not deliver the water volumes, the estimated maximum amount that would be payable under this commitment, calculated as of September 30, 2020, would be approximately $65.7 million. At this time we do not believe any financial commitment resulting from potential future minimum volume delivery commitment shortfalls will be material.

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

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We consider accounting policies and estimates related to oil and gas reserves, full cost accounting, and income taxes to be critical accounting policies and estimates. These are summarized in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Price Fluctuations

Our major market risk is pricing applicable to our oil, gas, and NGL production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil, gas, and NGL production has been volatile and unpredictable. For the three months ended September 30, 2020, our total production revenue was comprised of approximately 64% oil sales, 16% gas sales, and 20% NGL sales. For the nine months ended September 30, 2020, our total production revenue was comprised of approximately 69% oil sales, 14% gas sales, and 17% NGL sales. The following table shows how hypothetical changes in the realized prices we receive for our commodity sales may have impacted revenue for the period indicated.

Impact on Revenue

Change in Realized Price

Three Months Ended
September 30, 2020

Nine Months Ended
September 30, 2020

(in thousands)

Oil

± $1.00

per barrel

± $6,585

± $21,849

Gas

± $0.10

per Mcf

± $5,551

± $17,839

NGL

± $1.00

per barrel

± $7,111

± $19,715

± $19,247

± $59,403

We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. At September 30, 2020, we had oil and gas derivatives covering a portion of our 2020 - 2022 production, which were recorded as current and non-current assets and liabilities. At September 30, 2020, our oil and gas derivatives had a gross asset fair value of $40.4 million and a gross liability fair value of $122.8 million. See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.

While these contracts limit the downside risk of adverse price movements, they may also limit future cash flow from favorable price movements. The following table shows how a hypothetical ± 10% change in the underlying forward prices used to calculate the fair value of our derivatives may have impacted the fair value as of September 30, 2020.


		Impact on Fair Value
	Change in Forward Price	September 30, 2020
		(in thousands)
Oil	-10%	$	54,958
Oil	+10%	$	(56,574)
Gas	-10%	$	22,278
Gas	+10%	$	(22,606)

Interest Rate Risk

At September 30, 2020, our long-term debt consisted of $750 million of 4.375% senior unsecured notes that mature on June 1, 2024, $750 million of 3.90% senior unsecured notes that mature on May 15, 2027, and $500 million of 4.375% senior unsecured notes that mature on March 15, 2029. Because all of our outstanding long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Cimarex’s management, under the supervision and with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of Cimarex’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of September 30, 2020. Based on that evaluation, the CEO and CFO concluded that the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods required by the U.S. Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including the CEO and CFO, to allow timely decisions regarding required disclosures.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting that occurred during the fiscal quarter ended September 30, 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

The information set forth under the heading “Litigation” in Note 10 to the Condensed Consolidated Financial Statements is incorporated by reference in response to this item.

ITEM 1A. RISK FACTORS

The following risks and uncertainties, together with other information set forth in this Form 10-Q and our Form 10-K for the year ended December 31, 2019, should be carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties presently unknown to us or currently deemed immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, financial condition, and results of operations, which in turn could negatively impact the value of our securities. Many of these risks relate to the current COVID-19 pandemic; however, there are many other impacts of the pandemic or outbreaks of other communicable diseases that may become material. Given the unpredictable and unprecedented nature of the current situation it is impractical to identify all potential risks and estimate the ultimate adverse impact on our business. All the risks disclosed in this Form 10-Q and our Form 10-K may be amplified by the COVID-19 outbreak and its unpredictable nature. These risk factors speak only as of the filing date of this Form 10-Q and are subject to change without notice as we cannot predict all risk 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 disease, can negatively impact the global economy, reduce demand and pricing for oil, gas, and NGLs, lead to operational disruptions and limit our ability to execute on our business plan, which could materially and adversely affect our business, financial condition, and results of operations. Furthermore, uncertainty regarding the impact of any contagious disease outbreak could lead to increased volatility in oil, gas, and NGL prices. For example, the current pandemic involving COVID-19 and the measures being taken to address and limit the spread of the virus 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. There currently are too many variables and uncertainties regarding the COVID-19 pandemic, such as the ultimate geographic spread, duration, and severity of the outbreak and the extent and duration of governmental restrictions and business closures, to fully assess the impact on our business and operations; however, this impact 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. Methane, a primary component of natural gas, and carbon dioxide, also present in natural gas as a secondary product and sometimes considered an impurity or a by-product of the burning of oil and natural gas, are examples of GHGs. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict emissions of GHGs. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the

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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, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Any such future laws and final regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to develop and implement best management practices aimed at reducing GHG emissions, install and maintain emissions control technologies, as well as monitor and report on GHG emissions associated with our operations, which would increase our operating costs, and 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.

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

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

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

Policy and Legal Risks. Policy risks include actions that attempt to lessen activities that contribute to adverse effects of climate change or policy actions that seek to promote adaptation to climate change. These policy actions could be accelerated by a change in Presidential administrations or a change of majority party in control of Congress. Examples of policy actions include implementing carbon-pricing mechanisms to reduce GHG emissions (which would increase the costs of our doing business), shifting energy use toward lower emission sources (which could lower demand for our oil and gas production, resulting in lower prices and lower revenues), adopting energy-efficiency solutions (which also could lower demand for our oil and gas production, resulting in lower prices and lower revenues), encouraging greater water efficiency measures (which would increase our costs of production), and promoting more sustainable land-use practices (which also would increase our costs of production and could impact our ability to operate in certain areas). Policy actions also may include restrictions or bans on oil and gas activities, such as 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. Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil, NGL, and gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce

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environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. While we are currently not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

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

Market Risk. Markets could be affected by climate change through shifts in supply and demand for certain commodities, especially carbon-intensive commodities such as oil and gas and other products dependent on oil and gas. 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, there have also been efforts in recent years to influence the investment community, including investment advisers, banks and certain sovereign wealth, pension, and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. 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. Such environmental activism, initiatives aimed at limiting climate change and reducing air pollution, and pledges by banks, including 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. This could lower demand for our oil and gas production, resulting in lower prices and lower revenues as consumers avoid carbon-intensive industries. This may also put pressure on investment managers to shift investments to less carbon-intensive industries and alternative energy industries, limiting our access to capital.

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

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 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 closure of factories and businesses, the significant travel restrictions and the stay-at-home orders, causing lower commodity prices. Oil prices also can decrease if OPEC increases supply, as it did in the first quarter

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of 2020 at a time when global demand was also 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 or counterparties to our hedging transactions whose businesses also could be impacted by these same conditions.

Our proved oil and gas reserves and production volumes will decrease unless those reserves are replaced with new discoveries or acquisitions. Accordingly, for the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations, our revolving credit facility, and proceeds from the sale of senior notes or equity. Low 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 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 of $1.626 billion during the nine months ended September 30, 2020 and $618.7 million in 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. We expect to incur another ceiling test impairment at December 31, 2020 and, 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 will result 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. For example, as of December 31, 2019, management concluded that we did not have an effective process and control in place to periodically evaluate the quantitative effect associated with the inclusion or exclusion of certain inputs, such as skim oil and drip liquids, in the Company’s oil and gas reserve database used in the ceiling test impairment calculations, depletion calculations, and the preparation of the related disclosures included in the supplemental information on oil and gas producing activities (unaudited), which represented a material weakness in our internal control over financial reporting and, therefore, that we did not maintain effective internal control over financial reporting as of December 31, 2019, as reported in our Form 10-K for the year ended December 31, 2019. For a description of the material weakness identified by management and the remediation plan for that material weakness, see Part II, Item 9A Controls and Procedures in our Form 10-K for the year ended December 31, 2019. If the new controls implemented to address the material weakness and to strengthen the overall internal control related to the reserve reporting process are not designed or do not operate effectively, or if we are unsuccessful in following these new controls, this may result in untimely or inaccurate reporting of our financial statements.

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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.

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 remain at 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, the Company’s 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, weather, fire, or other reasons, could negatively affect our operations and revenues.

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. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the 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 as we shut in wells in response to lower commodity prices or the lack of pipeline and storage capacity relating to 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, which could result in increased costs and could adversely affect the reserves and re-commenced production from such shut in wells. We have no control over the operations or activities of offsetting operators.

We may be subject to information technology system failures, network disruptions, and breaches in data 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 security threats, including: cybersecurity threats such as attempts to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing facilities, pipelines and refineries; and threats from terrorist acts. Cybersecurity attacks are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data, and “ransomware” attacks where data is locked unless a payment is made, any of which could have an adverse effect on our reputation, business, financial condition, results of operations, or cash flows. While we have not suffered any material losses relating to such attacks, there can be no assurance that we will not suffer such losses in the future.

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

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

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

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

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

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

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

These events could damage our reputation and lead to 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 from home during the COVID-19 pandemic, there may be heightened vulnerability to cyber attacks.

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

At September 30, 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.

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

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operations, and other factors, many of which are beyond our control. The current COVID-19 pandemic has 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 Cimarex’s and its subsidiaries’ ability to, among other things:

•create certain liens;

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

•enter into sale and leaseback transactions.

In addition, our revolving credit agreement requires us to maintain a total debt-to-capitalization ratio (as defined in the credit agreement) of not more than 65%. While we were in compliance with this covenant at September 30, 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.

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.

Unless production is established within the units covering undeveloped leasehold acres, those leases could terminate, and the amounts we spent for those leases could be lost. In addition, we could lose leases under certain circumstances if we do not maintain production in paying quantities or meet other lease requirements. 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. The combined net acreage expiring

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in the next three years represents approximately 4.0% of our total net undeveloped acreage at December 31, 2019. At that date, we had leases representing 166,227 net acres expiring in 2020, 21,226 net acres expiring in 2021, and 35,457 net acres expiring in 2022. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

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 in light of the discovery of facts not presently known to us or as a result of determinations by judges, juries, or other finders of fact that are not in accord with our evaluation of the possible liability or outcome of such proceedings. Therefore, there can be no assurance that outcomes of future legal proceedings would not have an adverse effect on our liquidity and capital resources.

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

Exploration, production, and the sale of oil and gas are subject to extensive laws and regulations, including those implemented to protect the environment, human health and safety, and wildlife. Federal, state, tribal, and local regulatory agencies frequently require permitting and impose conditions on our activities. During the permitting process, these regulatory agencies often exercise considerable discretion in both the timing and scope of the permits, and the public, including special interest groups, often has an opportunity to influence the timing and outcome of the process. The requirements or conditions imposed by these agencies can be costly and can delay the commencement of our operations. In addition, a number of initiatives were put forth by the Obama administration in the form of Presidential or Secretarial Memoranda, which are still in effect, and have the potential to impact the cost of doing business or could result in substantial delays in permitting, drilling, and other oil and gas activities. A change in administration could lead to additional impacts on the cost of doing business and additional delays in, or the prohibition of, permitting, drilling and other oil and gas activities on federal as well as tribal, state, and private lands. Permits and other regulatory approvals also may be negatively impacted by the impact of COVID-19 restrictions on regulatory employees responsible for regulatory approvals.

Failing to comply with any of the applicable laws and regulations, or Presidential initiatives, could result in the suspension or termination of our operations and subject us to administrative, civil, and criminal liabilities and penalties. Such costs could have a material adverse effect on both our financial condition and operations.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

The following table sets forth information regarding repurchases of our common stock during the three months ended September 30, 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.


Period	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs






July 1-31, 2020	94,245	$	24.57	—	—
August 1-31, 2020	—	—		—	—
September 1-30, 2020	—	—		—	—



Total	94,245	$	24.57	—	—

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ITEM 6. EXHIBITS

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith.


Exhibit Number						Description
10.1						Form of Severance Compensation Agreement (filed as Exhibit 10.1 to the Current Report on Form 8-K filed March 13, 2020 (Commission File No. 001-31446) and incorporated herein by reference).
10.2						Form of Notice of Grant of Performance Stock Units and Award Agreement (Performance Award) (filed as Exhibit 10.2 to the Current Report on Form 8-K filed March 13, 2020 (Commission File No. 001-31446) and incorporated herein by reference).
10.3						Form of Amendment to Severance Compensation Agreement (filed as Exhibit 10.2 to the Current Report on Form 8-K/A filed May 12, 2020 (Commission File No. 001-31446) and incorporated herein by reference).
10.4						First Amendment to Amended and Restated Credit Agreement, dated June 3, 2020, among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, Wells Fargo Bank, N.A., as syndication agent, the co-documentation agents party thereto, J.P. Morgan Chase Bank, N.A. and Wells Fargo Securities, LLC, as lead arrangers and bookrunners, and the lenders party thereto. (filed as Exhibit 10.1 to the Current Report on Form 8-K/A filed June 4, 2020 (Commission File No. 001-31446) and incorporated herein by reference).
10.5						Amended and Restated Credit Agreement, dated February 5, 2019, among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, Wells Fargo Bank, N.A., as syndication agent, the co-documentation agents party thereto, J.P. Morgan Chase Bank, N.A. and Wells Fargo Securities, LLC, as lead arrangers and bookrunners, and the lenders party thereto. (filed as Exhibit 10.1 to the Current Report on Form 8-K filed February 7, 2019 (Commission File No. 001-31446) and incorporated herein by reference).
10.6						Succession Agreement dated July 1, 2020 between Cimarex Energy Co. and Joseph R. Albi (filed as Exhibit 10.1 to the Current Report on Form 8-K/A filed July 2, 2020 (Commission File No. 001-31446) and incorporated herein by reference).
31.1						Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *
31.2						Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *
32.1						Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350. *
32.2						Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350. *
101.INS						XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH						Inline XBRL Taxonomy Extension Schema Document
101.CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB						Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE						Inline XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


November 4, 2020


			CIMAREX ENERGY CO.


			/s/ G. Mark Burford
			G. Mark Burford
			Senior Vice President and Chief Financial Officer
			(Principal Financial Officer)


			/s/ Timothy A. Ficker
			Timothy A. Ficker
			Vice President, Controller, and Chief Accounting Officer
			(Principal Accounting Officer)