Cimarex Energy (CIMXP) 10-Q 2019 Q3 Quarterly report

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, 2019
or
☐	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _______________ to _______________

 Commission File 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, 2019 was 101,810,140.

CIMAREX ENERGY CO.

Table of Contents

		Page
PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2019 and December 31, 2018	4
	Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited) for the three months and nine months ended September 30, 2019 and 2018	5
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended September 30, 2019 and 2018	6
	Condensed Consolidated Statement of Stockholders’ Equity (Unaudited) for the three months and nine months ended September 30, 2019 and 2018	7
	Notes to Condensed Consolidated Financial Statements (Unaudited)	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	53
Item 4.	Controls and Procedures	54
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 6.	Exhibits	56
Signatures		57

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, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended.  These forward-looking statements include, among others, statements concerning our outlook with regard to timing and amount of future production of oil and gas, price realizations, amounts, nature and timing of capital expenditures for exploration and development, plans for funding operations and capital expenditures, drilling of wells, operating costs and other expenses, marketing of oil, gas, and NGLs and other statements of expectations, beliefs, future plans and strategies, anticipated events or trends, and similar expressions concerning matters that are not historical facts.  The forward-looking statements in this report are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by the statements.

These risks and uncertainties include, but are not limited to, fluctuations in the price we receive for our oil and gas production, full cost ceiling test impairments to the carrying values of our oil and gas properties, reductions in the quantity of, and price received for, oil and gas sold due to decreased industry-wide demand and/or curtailments in production from specific properties or areas due to mechanical, transportation, marketing, weather or other problems, 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, increased financing costs due to a significant increase in interest rates, availability of financing, our ability to successfully integrate the business acquired from Resolute Energy Corporation (“Resolute”), unknown liabilities related to Resolute, and the effectiveness of our internal control over financial reporting and our ability to remediate a material weakness in our internal control over financial reporting.  In addition, exploration and development opportunities that we pursue may not result in economic, productive oil and gas properties.  There are also numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures.  These and other risks and uncertainties affecting us are discussed in greater detail in this report and in our other filings with the Securities and Exchange Commission.

3

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,
	2019			2018
Assets
Current assets:
Cash and cash equivalents	$	23,885		$	800,666
Accounts receivable, net of allowance:
Trade	75,853			122,065
Oil and gas sales	342,513			315,063
Gas gathering, processing, and marketing	6,963			17,072
Oil and gas well equipment and supplies	49,113			55,553
Derivative instruments	49,385			101,939
Prepaid expenses	6,220			7,554
Other current assets	2,647			4,227
Total current assets	556,579			1,424,139
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	20,134,383			18,566,757
Unproved properties and properties under development, not being amortized	1,539,008			436,325
	21,673,391			19,003,082
Less—accumulated depreciation, depletion, amortization, and impairment	(15,979,664		)	(15,287,752		)
Net oil and gas properties	5,693,727			3,715,330
Fixed assets, net of accumulated depreciation of $373,351 and $324,631, respectively	538,179			257,686
Goodwill	751,836			620,232
Derivative instruments	5,715			9,246
Other assets	73,169			35,451
	$	7,619,205		$	6,062,084
Liabilities, Redeemable Preferred Stock, and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	53,643		$	76,927
Gas gathering, processing, and marketing	12,282			29,887
Accrued liabilities:
Exploration and development	111,728			124,674
Taxes other than income	48,494			33,622
Other	270,610			221,159
Derivative instruments	24,983			27,627
Revenue payable	207,751			194,811
Operating leases	67,208			—
Total current liabilities	796,699			708,707
Long-term debt principal	2,000,000			1,500,000
Less—unamortized debt issuance costs and discounts	(15,266		)	(11,446		)
Long-term debt, net	1,984,734			1,488,554
Deferred income taxes	446,961			334,473
Asset retirement obligation	157,431			152,758
Derivative instruments	403			2,267
Operating leases	199,645			—
Other liabilities	62,154			45,539
Total liabilities	3,648,027			2,732,298
Commitments and contingencies (Note 10)
Redeemable preferred stock - 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, $0.01 par value, 62,500 shares authorized and issued and no shares authorized and issued, respectively (Note 5)	81,620			—
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 101,820,140 and 95,755,797 shares issued, respectively	1,018			958
Additional paid-in capital	3,234,318			2,785,188
Retained earnings	654,212			542,885
Accumulated other comprehensive income	10			755
Total stockholders’ equity	3,889,558			3,329,786
	$	7,619,205		$	6,062,084

See accompanying Notes to Condensed Consolidated Financial Statements.

4

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Operations and Comprehensive Income

(in thousands, except per share information)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues:
Oil sales	$	435,094		$	342,495		$	1,196,166		$	1,036,402
Gas and NGL sales	135,483			240,087			479,442			646,007
Gas gathering and other	11,200			9,244			31,231			32,506
Gas marketing	528			(338		)	(1,114		)	(19		)
	582,305			591,488			1,705,725			1,714,896
Costs and expenses:
Impairment of oil and gas properties	108,879			—			108,879			—
Depreciation, depletion, and amortization	227,978			136,302			631,722			412,549
Asset retirement obligation	2,194			1,893			6,400			5,006
Production	88,300			76,272			253,259			226,758
Transportation, processing, and other operating	52,697			49,720			154,636			146,818
Gas gathering and other	13,893			10,569			39,818			29,859
Taxes other than income	30,873			28,431			105,600			86,549
General and administrative	15,499			21,148			69,494			64,208
Stock compensation	6,797			6,437			20,004			16,262
(Gain) loss on derivative instruments, net	(38,735		)	54,006			35,949			71,546
Other operating expense, net	10,141			10,015			19,057			15,470
	518,516			394,793			1,444,818			1,075,025
Operating income	63,789			196,695			260,907			639,871
Other (income) and expense:
Interest expense	24,586			17,159			69,665			50,837
Capitalized interest	(16,264		)	(5,457		)	(41,811		)	(15,117		)
Loss on early extinguishment of debt	—			—			4,250			—
Other, net	(139		)	(7,544		)	(4,547		)	(14,716		)
Income before income tax	55,606			192,537			233,350			618,867
Income tax expense	15,079			44,183			57,198			143,198
Net income	$	40,527		$	148,354		$	176,152		$	475,669
Earnings per share to common stockholders:
Basic	$	0.39		$	1.56		$	1.72		$	5.00
Diluted	$	0.39		$	1.56		$	1.72		$	5.00
Comprehensive income:
Net income	$	40,527		$	148,354		$	176,152		$	475,669
Other comprehensive income:
Change in fair value of investments, net of tax of ($648), $159, ($220) and $160, respectively	(2,198		)	539			(745		)	541
Total comprehensive income	$	38,329		$	148,893		$	175,407		$	476,210

 

See accompanying Notes to Condensed Consolidated Financial Statements.

5

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)

	Nine Months Ended September 30,
	2019			2018
Cash flows from operating activities:
Net income	$	176,152		$	475,669
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of oil and gas properties	108,879			—
Depreciation, depletion, and amortization	631,722			412,549
Asset retirement obligation	6,400			5,006
Deferred income taxes	57,198			142,815
Stock compensation	20,004			16,262
Loss on derivative instruments, net	35,949			71,546
Settlements on derivative instruments	(1,118		)	(20,418		)
Loss on early extinguishment of debt	4,250			—
Amortization of debt issuance costs and discounts	2,285			2,183
Changes in non-current assets and liabilities	(2,630		)	(1,244		)
Other, net	9,062			1,059
Changes in operating assets and liabilities:
Accounts receivable	80,183			(11,772		)
Other current assets	2,140			4,421
Accounts payable and other current liabilities	(146,319		)	59,737
Net cash provided by operating activities	984,157			1,157,813
Cash flows from investing activities:
Acquisition of Resolute Energy, net of cash acquired (Note 13)	(284,441		)	—
Oil and gas capital expenditures	(1,000,380		)	(1,151,484		)
Other capital expenditures	(59,035		)	(75,037		)
Sales of oil and gas assets	28,547			573,367
Sales of other assets	859			990
Net cash used by investing activities	(1,314,450		)	(652,164		)
Cash flows from financing activities:
Borrowings of long-term debt	2,239,310			—
Repayments of long-term debt	(2,610,000		)	—
Financing, underwriting, and debt redemption fees	(11,798		)	—
Finance lease payments	(2,731		)	—
Dividends paid	(60,130		)	(38,038		)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards	(2,406		)	(6,410		)
Proceeds from exercise of stock options	1,267			2,211
Net cash used by financing activities	(446,488		)	(42,237		)
Net change in cash and cash equivalents	(776,781		)	463,412
Cash and cash equivalents at beginning of period	800,666			400,534
Cash and cash equivalents at end of period	$	23,885		$	863,946

  

See accompanying Notes to Condensed Consolidated Financial Statements.

6

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 ($20.31 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 ($20.31 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.

7

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 ($20.31 per share)	—		—		—			(1,270		)	—			(1,270		)
Net income	—		—		—			40,527			—			40,527
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
September 30, 2019	101,820		$	1,018	$	3,234,318		$	654,212		$	10		$	3,889,558

See accompanying Notes to Condensed Consolidated Financial Statements.

8

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands)

(Unaudited)

					Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income			Total Stockholders’ Equity
	Common Stock
	Shares		Amount
Balance, December 31, 2017	95,437		$	954	$	2,764,384		$	(199,259	)	$	2,199		$	2,568,278
Dividends paid on stock awards subsequently forfeited	—		—		3			4			—			7
Dividends declared on common stock ($0.16 per share)	—		—		(15,271		)	—			—			(15,271		)
Net income	—		—		—			186,318			—			186,318
Unrealized change in fair value of investments, net of tax	—		—		—			—			(190		)	(190		)
Issuance of restricted stock awards	2		—		—			—			—			—
Common stock reacquired and retired	(3	)	—		(305		)	—			—			(305		)
Restricted stock forfeited and retired	(7	)	—		—			—			—			—
Exercise of stock options	4		—		345			—			—			345
Stock-based compensation	—		—		12,411			—			—			12,411
Balance, March 31, 2018	95,433		954		2,761,567			(12,937		)	2,009			2,751,593
Dividends paid on stock awards subsequently forfeited	—		—		26			13			—			39
Dividends declared on common stock ($0.16 per share)	—		—		21			(15,262		)	—			(15,241		)
Net income	—		—		—			140,997			—			140,997
Unrealized change in fair value of investments, net of tax	—		—		—			—			192			192
Issuance of restricted stock awards	27		—		—			—			—			—
Common stock reacquired and retired	(5	)	—		(641		)	—			—			(641		)
Restricted stock forfeited and retired	(75	)	—		—			—			—			—
Exercise of stock options	13		—		904			—			—			904
Stock-based compensation	—		—		8,655			—			—			8,655
Balance, June 30, 2018	95,393		$	954	$	2,770,532		$	112,811		$	2,201		$	2,886,498

See accompanying Notes to Condensed Consolidated Financial Statements.

9

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, 2018	95,393		$	954		$	2,770,532		$	112,811		$	2,201	$	2,886,498
Dividends paid on stock awards subsequently forfeited	—		—			4			3			—		7
Dividends declared on common stock ($0.18 per share)	—		—			—			(17,245		)	—		(17,245		)
Net income	—		—			—			148,354			—		148,354
Unrealized change in fair value of investments, net of tax	—		—			—			—			539		539
Issuance of restricted stock awards	260		3			(3		)	—			—		—
Common stock reacquired and retired	(56	)	—			(5,464		)	—			—		(5,464		)
Restricted stock forfeited and retired	(10	)	(1		)	1			—			—		—
Exercise of stock options	16		—			962			—			—		962
Stock-based compensation	—		—			12,171			—			—		12,171
Balance, September 30, 2018	95,603		$	956		$	2,778,203		$	243,923		$	2,740	$	3,025,822

See accompanying Notes to Condensed Consolidated Financial Statements.

10

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

1. BASIS OF PRESENTATION

Cimarex Energy Co. (“Cimarex,” “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, 2018.

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. Certain amounts in the prior year financial statements have been reclassified to conform to the 2019 financial statement presentation.

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, and contingencies.

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 calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results.

11

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

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. 

At September 30, 2019, we incurred a ceiling test impairment of $108.9 million.   The impairment resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves. We expect these conditions to continue at least through year-end and possibly beyond and, therefore, expect to incur another ceiling test impairment at December 31, 2019.

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, 2019, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a 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 and NGLs are sold under a limited number of contract structure types common in our industry. Under these contracts the gas and its components, including NGLs, may be sold to a single purchaser or the residue gas and NGLs may be sold to separate purchasers. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product. However, depending on the contract structure type, certain transportation, processing, and other charges may be deducted against the prices received for the product. Our oil typically is 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 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 us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

12

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

Lease Accounting

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (“Topic 842”).  The FASB subsequently issued various ASUs that provided additional implementation guidance. Topic 842 requires lessees to recognize lease liabilities and right-of-use assets on the balance sheet for contracts that provide lessees with the right to control the use of identified assets for a period of time. The scope of Topic 842 excludes leases to explore for or use minerals, oil, natural gas, and similar nonregenerative resources. We adopted Topic 842 effective January 1, 2019, using the modified retrospective method applied to all leases that existed on that date, which resulted in the recognition of lease liabilities of $276.9 million and right-of-use assets of $265.0 million. In connection with adoption we made use of the following practical expedients, which are provided in Topic 842:

• a package of practical expedients to not reassess: 1) whether expired or existing contracts are or contain a lease, 2) lease classification for expired or existing leases, and 3) initial direct costs for existing leases;

• an election not to apply the recognition requirements in Topic 842 to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that the Company is reasonably certain to exercise);

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

• a practical expedient to not reassess certain land easements in existence prior to January 1, 2019.

2. LONG-TERM DEBT

Long-term debt at September 30, 2019 and December 31, 2018 consisted of the following:

	September 30, 2019							December 31, 2018
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)			Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discount (1)			Long-term Debt, net
4.375% Notes due 2024	$	750,000	$	(3,758	)	$	746,242	$	750,000	$	(4,439	)	$	745,561
3.90% Notes due 2027	750,000		(6,471		)	743,529		750,000		(7,007		)	742,993
4.375% Notes due 2029	500,000		(5,037		)	494,963		—		—			—
	$	2,000,000	$	(15,266	)	$	1,984,734	$	1,500,000	$	(11,446	)	$	1,488,554

________________________________________

(1) At September 30, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.0 million and $1.5 million, respectively. At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.4 million and $1.6 million, respectively. At September 30, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.4 million and $0.7 million, respectively. The 4.375% Notes due 2024 were issued at par.

13

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

Bank Debt

On February 5, 2019, we entered into an Amended and Restated Credit Agreement for our senior unsecured revolving credit facility (“Credit Facility”). Among other things, the amended and restated credit facility increased the aggregate commitments to $1.25 billion with an option for us to increase the aggregate commitments to $1.5 billion, and extended the maturity date to February 5, 2024. As of September 30, 2019, we had 0 bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $1.248 billion. During the three and nine months ended September 30, 2019, we borrowed and repaid an aggregate of $529.0 million and $1.74 billion, 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.

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of September 30, 2019, we were in compliance with all of the financial covenants.

At September 30, 2019 and December 31, 2018, we had $4.3 million and $2.2 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in Other assets on our Condensed Consolidated Balance Sheets. These costs are being amortized to interest expense ratably over the life of the Credit Facility. We incurred $3.0 million in additional debt issuance costs in amending our Credit Facility.

Senior Notes

On 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 that were 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, 2019.

14

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

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, 2019, we have entered into oil and gas collars, oil basis swaps, oil and gas fixed price swaps, and sold oil calls. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the ceiling price and the index price if the index price is above the ceiling price.  No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price plus or minus a fixed differential, as applicable, and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI NYMEX (Cushing Oklahoma) price and the WTI Midland price. For our Permian and Mid-Continent gas production, the contract prices in our collars are consistent with the index prices used to sell our production. 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. Under our sold oil calls, 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, 2019:

Oil Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		—		—		3,312,000		3,312,000
Weighted Avg Price - Floor	$	—	$	—	$	—	$	54.28	$	54.28
Weighted Avg Price - Ceiling	$	—	$	—	$	—	$	66.90	$	66.90
2020:
WTI (1)
Volume (Bbls)	2,548,000		1,820,000		1,104,000		1,104,000		6,576,000
Weighted Avg Price - Floor	$	53.50	$	50.90	$	50.00	$	50.00	$	51.61
Weighted Avg Price - Ceiling	$	66.57	$	62.87	$	61.91	$	61.91	$	63.98
2021:
WTI (1)
Volume (Bbls)	360,000		—		—		—		360,000
Weighted Avg Price - Floor	$	50.00	$	—	$	—	$	—	$	50.00
Weighted Avg Price - Ceiling	$	60.11	$	—	$	—	$	—	$	60.11

________________________________________

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

15

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

Gas Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
PEPL (1)
Volume (MMBtu)	—		—		—		11,040,000		11,040,000
Weighted Avg Price - Floor	$	—	$	—	$	—	$	1.92	$	1.92
Weighted Avg Price - Ceiling	$	—	$	—	$	—	$	2.35	$	2.35
Perm EP (2)
Volume (MMBtu)	—		—		—		5,520,000		5,520,000
Weighted Avg Price - Floor	$	—	$	—	$	—	$	1.38	$	1.38
Weighted Avg Price - Ceiling	$	—	$	—	$	—	$	1.71	$	1.71
Waha (3)
Volume (MMBtu)	—		—		—		5,520,000		5,520,000
Weighted Avg Price - Floor	$	—	$	—	$	—	$	1.48	$	1.48
Weighted Avg Price - Ceiling	$	—	$	—	$	—	$	1.82	$	1.82
2020:
PEPL (1)
Volume (MMBtu)	8,190,000		5,460,000		2,760,000		2,760,000		19,170,000
Weighted Avg Price - Floor	$	1.92	$	1.90	$	1.85	$	1.85	$	1.90
Weighted Avg Price - Ceiling	$	2.36	$	2.28	$	2.31	$	2.31	$	2.32
Perm EP (2)
Volume (MMBtu)	3,640,000		2,730,000		1,840,000		1,840,000		10,050,000
Weighted Avg Price - Floor	$	1.40	$	1.40	$	1.35	$	1.35	$	1.38
Weighted Avg Price - Ceiling	$	1.79	$	1.82	$	1.66	$	1.66	$	1.75
Waha (3)
Volume (MMBtu)	4,550,000		2,730,000		—		—		7,280,000
Weighted Avg Price - Floor	$	1.50	$	1.57	$	—	$	—	$	1.53
Weighted Avg Price - Ceiling	$	1.87	$	1.97	$	—	$	—	$	1.91
2021:
PEPL (1)
Volume (MMBtu)	910,000		—		—		—		910,000
Weighted Avg Price - Floor	$	1.85	$	—	$	—	$	—	$	1.85
Weighted Avg Price - Ceiling	$	2.31	$	—	$	—	$	—	$	2.31

________________________________________

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

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

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

16

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

Oil Basis Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Total
2019:
WTI Midland (1)
Volume (Bbls)	—		—		—		3,634,000			3,634,000
Weighted Avg Differential (2)	$	—	$	—	$	—	$	(5.62	)	$	(5.62	)
2020:
WTI Midland (1)
Volume (Bbls)	2,457,000		1,729,000		1,104,000		1,104,000			6,394,000
Weighted Avg Differential (2)	$	0.22	$	0.26	$	0.65	$	0.65		$	0.38
2021:
WTI Midland (1)
Volume (Bbls)	360,000		—		—		—			360,000
Weighted Avg Differential (2)	$	0.54	$	—	$	—	$	—		$	0.54

________________________________________

(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 Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		—		—		460,000		460,000
Weighted Avg Price	$	—	$	—	$	—	$	64.54	$	64.54

________________________________________

(1) The fixed price on these swaps is NYMEX WTI.

Gas Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
Henry Hub (1)
Volume (MMBtu)	—		—		—		3,220,000		3,220,000
Weighted Avg Price	$	—	$	—	$	—	$	3.00	$	3.00

________________________________________

(1) The fixed price on these swaps is NYMEX Henry Hub.

Sold Oil Calls	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		—		—		337,640		337,640
Weighted Avg Call Price	$	—	$	—	$	—	$	64.36	$	64.36

________________________________________

(1) The index on these sold calls is NYMEX WTI.

17

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

The following tables summarize our derivative contracts entered into subsequent to September 30, 2019 through November 1, 2019:

Oil Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		—		—		122,000		122,000
Wtd Avg Price - Floor	$	—	$	—	$	—	$	47.73	$	47.73
Wtd Avg Price - Ceiling	$	—	$	—	$	—	$	55.00	$	55.00
2020:
WTI (1)
Volume (Bbls)	182,000		182,000		184,000		184,000		732,000
Wtd Avg Price - Floor	$	47.73	$	47.73	$	47.73	$	47.73	$	47.73
Wtd Avg Price - Ceiling	$	55.00	$	55.00	$	55.00	$	55.00	$	55.00
2021:
WTI (1)
Volume (Bbls)	180,000		—		—		—		180,000
Wtd Avg Price - Floor	$	47.73	$	—	$	—	$	—	$	47.73
Wtd Avg Price - Ceiling	$	55.00	$	—	$	—	$	—	$	55.00

________________________________________

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

Oil Basis Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI Midland (1)
Volume (Bbls)	—		—		—		122,000		122,000
Weighted Avg Differential (2)	$	—	$	—	$	—	$	0.62	$	0.62
2020:
WTI Midland (1)
Volume (Bbls)	182,000		182,000		184,000		184,000		732,000
Weighted Avg Differential (2)	$	0.62	$	0.62	$	0.62	$	0.62	$	0.62
2021:
WTI Midland (1)
Volume (Bbls)	180,000		—		—		—		180,000
Weighted Avg Differential (2)	$	0.62	$	—	$	—	$	—	$	0.62

________________________________________

(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.

18

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(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 (Gain) loss on derivative instruments, net for the periods indicated.

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2019			2018			2019			2018
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts	$	5,818		$	6,378		$	(10,398	)	$	9,155
Oil contracts	(42,857		)	47,129			45,229			41,973
	(37,039		)	53,507			34,831			51,128
Cash (receipts) payments on derivative instruments, net:
Gas contracts	(17,554		)	(3,462		)	(34,966		)	(18,499		)
Oil contracts	15,858			3,961			36,084			38,917
	(1,696		)	499			1,118			20,418
(Gain) loss on derivative instruments, net	$	(38,735	)	$	54,006		$	35,949		$	71,546

19

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(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, 2019 and December 31, 2018, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.

		September 30, 2019
(in thousands)	Balance Sheet Location	Asset			Liability
Oil contracts	Current assets — Derivative instruments	$	35,671		$	—
Gas contracts	Current assets — Derivative instruments	13,714			—
Oil contracts	Non-current assets — Derivative instruments	5,650			—
Gas contracts	Non-current assets — Derivative instruments	65			—
Oil contracts	Current liabilities — Derivative instruments	—			24,901
Gas contracts	Current liabilities — Derivative instruments	—			82
Oil contracts	Non-current liabilities — Derivative instruments	—			117
Gas contracts	Non-current liabilities — Derivative instruments	—			286
Total gross amounts presented in the balance sheet		55,100			25,386
Less: gross amounts not offset in the balance sheet		(18,346		)	(18,346		)
Net amount		$	36,754		$	7,040
		December 31, 2018
(in thousands)	Balance Sheet Location	Asset			Liability
Oil contracts	Current assets — Derivative instruments	$	94,240		$	—
Gas contracts	Current assets — Derivative instruments	7,699			—
Oil contracts	Non-current assets — Derivative instruments	9,246			—
Oil contracts	Current liabilities — Derivative instruments	—			23,378
Gas contracts	Current liabilities — Derivative instruments	—			4,249
Oil contracts	Non-current liabilities — Derivative instruments	—			311
Gas contracts	Non-current liabilities — Derivative instruments	—			1,956
Total gross amounts presented in the balance sheet		111,185			29,894
Less: gross amounts not offset in the balance sheet		(29,894		)	(29,894		)
Net amount		$	81,291		$	—

We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. We mitigate our exposure to any single counterparty by contracting with a number of financial institutions, each of which 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.

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 (exit price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels.

20

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

The following table provides fair value measurement information for certain assets and liabilities as of September 30, 2019 and December 31, 2018:

	September 30, 2019						December 31, 2018
(in thousands)	Book Value			Fair Value			Book Value			Fair Value
Financial Assets (Liabilities):
4.375% Notes due 2024	$	(750,000	)	$	(788,993	)	$	(750,000	)	$	(744,578	)
3.90% Notes due 2027	$	(750,000	)	$	(765,015	)	$	(750,000	)	$	(701,273	)
4.375% Notes due 2029	$	(500,000	)	$	(526,140	)	$	—		$	—
Derivative instruments — assets	$	55,100		$	55,100		$	111,185		$	111,185
Derivative instruments — liabilities	$	(25,386	)	$	(25,386	)	$	(29,894	)	$	(29,894	)

Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The 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, 2019 were accrued operating expenses (e.g. production, transportation, and gathering expenses) of approximately $82.1 million. Included in “Accrued liabilities — Other” at December 31, 2018 were: (i) accrued operating expenses of approximately $69.1 million, (ii) accrued general and administrative, primarily payroll-related, costs of approximately $47.4 million, and (iii) an accrual of approximately $35.8 million representing the amount by which checks issued, but not yet presented to our banks, exceeded balances in applicable bank accounts.

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.

We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At September 30, 2019 and December 31, 2018, the allowance for doubtful accounts was $3.4 million and $2.7 million, respectively.

21

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

5. CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At September 30, 2019, there were 101.8 million shares of common stock outstanding.

From the 15 million shares of preferred stock authorized, our Board of Directors created a series of preferred stock designated as 8.125% Series A Cumulative Perpetual Convertible Preferred Stock and authorized 62.5 thousand shares. In March 2019, in conjunction with the Resolute acquisition (see Note 13), we issued 62.5 thousand shares of 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share (the “Convertible Preferred Stock”). Holders of the Convertible Preferred Stock are entitled to receive, when, as, and if declared by the Board out of funds of Cimarex legally available for payment, cumulative cash dividends at the annual rate of 8.125% of each share’s liquidation preference of $1,000. Dividends on the preferred stock are payable quarterly in arrears and accumulate from the most recent date as to which dividends have been paid. In the event of any liquidation, winding up, or dissolution of Cimarex, whether voluntary or involuntary, each holder will be entitled to receive in respect of its shares and to be paid out of the assets of Cimarex legally available for distribution to its stockholders, after satisfaction of liabilities to Cimarex’s creditors and any senior stock (of which there is currently none) and before any payment or distribution is made to holders of junior stock (including common stock), the liquidation preference of $1,000 per share, with the total liquidation preference being $62.5 million in the aggregate. Each holder has the right at any time, at its option, to convert any or all of such holder’s shares of Convertible Preferred Stock at an initial conversion rate of 8.0421 shares of fully paid and nonassessable shares of our common stock and $471.40 in cash per share of Convertible Preferred Stock. Additionally, at any time on or after October 15, 2021, we shall have the right, at our option, if the closing sale price of our common stock meets certain criteria, to elect to cause all, and not part, of the outstanding shares of Convertible Preferred Stock to be automatically converted into that number of shares of Cimarex common stock for each share of Convertible Preferred Stock equal to the conversion rate in effect on the mandatory conversion date as such terms are defined in the Certificate of Designations for the Convertible Preferred Stock and $471.40 in cash per share of Convertible Preferred Stock. As a result of the cash redemption features included in the Convertible Preferred Stock conversion option, with such conversion not solely within our control, the instruments are classified as Redeemable preferred stock in temporary equity on the Condensed Consolidated Balance Sheet.

Dividends

Common Stock

In August 2019, our Board of Directors declared a cash dividend of $0.20 per share of common stock. The dividend is payable on or before November 29, 2019 to stockholders of record on November 15, 2019. 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 $20.4 million dividend declared during the third quarter 2019 was recorded as a reduction of retained earnings and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet. 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 2019, our Board of Directors declared a cash dividend of $20.31 per share of Convertible Preferred Stock. The dividend was paid in October to stockholders of record on October 1, 2019. This $1.3 million dividend was recorded as a reduction of retained earnings and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet at September 30, 2019.

22

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(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)	2019			2018			2019			2018
Restricted stock awards:
Performance stock awards	$	5,604		$	6,364		$	16,533		$	16,902
Service-based stock awards	6,140			5,244			19,364			14,563
	11,744			11,608			35,897			31,465
Stock option awards	411			571			1,429			1,825
Total stock compensation cost	12,155			12,179			37,326			33,290
Less amounts capitalized to oil and gas properties	(5,358		)	(5,742		)	(17,322		)	(17,028		)
Stock compensation expense	$	6,797		$	6,437		$	20,004		$	16,262

Periodic stock compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards.  The increase in total stock compensation cost in the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 is primarily due to awards granted either during or subsequent to the nine months ended September 30, 2018, partially offset by awards vesting either prior to or during the nine months ended September 30, 2019. Our accounting policy is to account for forfeitures in compensation cost when they occur.

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 asset retirement capitalized 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, 2019:

(in thousands)	Nine Months Ended September 30, 2019
Asset retirement obligation at January 1, 2019	$	166,904
Liabilities incurred	14,655
Liability settlements and disposals	(15,675		)
Accretion expense	5,622
Revisions of estimated liabilities	4,266
Asset retirement obligation at September 30, 2019	175,772
Less current obligation	(18,341		)
Long-term asset retirement obligation	$	157,431

For the nine months ended September 30, 2019, liabilities incurred included $9.4 million for the Resolute

23

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

acquisition.

8. EARNINGS PER SHARE

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

	Three Months Ended September 30,
	2019						2018
(in thousands, except per share information)	Income (Numerator)			Shares (Denominator)	Per-Share Amount		Income (Numerator)			Shares (Denominator)	Per-Share Amount
Net income	$	40,527					$	148,354
Less: net income attributable to participating securities	(688		)				(2,069		)
Less: preferred stock dividends	(1,270		)				—
Basic earnings per share
Income available to common stockholders	38,569			99,735	$	0.39	146,285			93,845	$	1.56
Effects of dilutive securities (1)
Options	—			—			—			22
Diluted earnings per share
Income available to common stockholders and assumed conversions	$	38,569		99,735	$	0.39	$	146,285		93,867	$	1.56

________________________________________

(1) Inclusion of certain potential common shares would have an anti-dilutive effect, therefore, these shares were excluded from the calculations of diluted earnings per share. Excluded from the three months ended September 30, 2019 calculation were 507.6 thousand potential common shares from the assumed exercise of employee stock options and 502.6 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock. Excluded from the three months ended September 30, 2018 calculation were 378.1 thousand potential common shares from the assumed exercise of employee stock options.

24

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

	Nine Months Ended September 30,
	2019						2018
(in thousands, except per share information)	Income (Numerator)			Shares (Denominator)	Per-Share Amount		Income (Numerator)			Shares (Denominator)	Per-Share Amount
Net income	$	176,152					$	475,669
Less: net income attributable to participating securities	(2,763		)				(6,610		)
Less: preferred stock dividends	(3,809		)				—
Basic earnings per share
Income available to common stockholders	169,580			98,452	$	1.72	469,059			93,758	$	5.00
Effects of dilutive securities (1)
Options	—			6			2			30
Diluted earnings per share
Income available to common stockholders and assumed conversions	$	169,580		98,458	$	1.72	$	469,061		93,788	$	5.00

________________________________________

(1) Inclusion of certain potential common shares would have an anti-dilutive effect, therefore, these shares were excluded from the calculations of diluted earnings per share. Excluded from the nine months ended September 30, 2019 calculation were 524.0 thousand potential common shares from the assumed exercise of employee stock options and 502.6 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock. Excluded from the nine months ended September 30, 2018 calculation were 387.7 thousand potential common shares from the assumed exercise of employee stock options.

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)	2019			2018			2019			2018
Current tax expense	$	—		$	1,100		$	—		$	383
Deferred tax expense	15,079			43,083			57,198			142,815
	$	15,079		$	44,183		$	57,198		$	143,198
Combined federal and state effective income tax rate	27.1		%	22.9		%	24.5		%	23.1		%

At December 31, 2018, we had a U.S. net tax operating loss carryforward of approximately $1.16 billion, which will expire in tax years 2032 through 2037. We believe that the carryforward will be utilized before it expires. We also had enhanced oil recovery and marginal well credits of $3.5 million at December 31, 2018.

On March 1, 2019, the Company completed its acquisition of Resolute. For federal income tax purposes, the acquisition was a tax-free merger whereby the Company acquired carryover tax basis in Resolute’s assets and liabilities. As of March 1, 2019, the Company recorded a net deferred tax liability of $62.4 million associated with the acquired assets. Due to revisions in the value of certain assets acquired, we reduced the deferred tax liability associated with the acquisition by $6.9 million. See Note 13 for more information regarding the preliminary purchase price allocation and subsequent adjustments made to it. The net deferred tax liability includes certain deferred tax assets net of valuation

25

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

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 September 30, 2019, we had 0 unrecognized tax benefits that would impact our effective tax rate and have made 0 provisions for interest or penalties related to uncertain tax positions. The tax years 2016 through 2018 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities, which remain open to examination for tax years 2014 through 2018.

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.

10. COMMITMENTS AND CONTINGENCIES

Lease Commitments

Effective January 1, 2019, we began accounting for leases in accordance with Topic 842, which requires lessees to recognize lease liabilities and right-of-use assets on the balance sheet for contracts that provide lessees with the right to control the use of identified assets for periods of greater than 12 months. Prior to January 1, 2019, we accounted for leases in accordance with ASC Topic 840, Leases, under which operating leases were not recorded on the balance sheet.

Real Estate Leases

We have operating leases for office space in various locations that provide us the right to control the use of the specified office space over the term of the contract. These leases require us to make monthly “base rent” payments, as well as “additional payments” for our share of operating expenses and taxes incurred by the landlord. At our option, the terms of these leases can be renewed for varying periods, and in some cases may be terminated early at our option. As of September 30, 2019, these leases had remaining lease terms ranging from 4.7 to 6.9 years. These leases do not contain residual value guarantees, options to purchase the underlying office space, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of office space.

Lease liabilities associated with our real estate leases were recorded at the present value of the future lease payments, after considering the following:

• “Base rent” payments are considered fixed lease payments, while “additional payments” are considered variable lease payments.

• At commencement of each real estate lease we were not reasonably certain to exercise the option to renew or terminate such lease.

• The discount rate used to calculate each lease liability was based on our incremental borrowing rate, which was estimated utilizing trading metrics for our senior unsecured notes as adjusted using relevant market factors to develop a synthetic secured yield curve.

• As an accounting policy we have elected not to separate nonlease components from lease components for our real estate class of assets.

• Where applicable, we determined that the effect of accounting for the right to use land separately from other lease components would be insignificant.

Production-Related Leases

We have operating leases for equipment used in connection with our oil and gas production operations, including well-head compressors, pipeline compressors, and artificial lift mechanisms. These leases provide us the right to control the use of explicitly or implicitly identified equipment during the term of the contract. These leases

26

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

often include an “evergreen” provision that allows the contract term to continue on a month-to-month basis following expiration of the initial term stated in the contract. As of September 30, 2019, these leases had remaining lease terms ranging from one month to 10.8 years. These leases require us to make monthly payments of fixed amounts, which cover the cost of renting the equipment and, in some cases, the cost of maintaining the leased equipment. These leases do not typically require us to make variable lease payments. These leases do not contain residual value guarantees, options to purchase the underlying equipment, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of production-related equipment.

Lease liabilities associated with our production-related operating leases were recorded at the present value of the future lease payments, after considering the following:

• For leases with an evergreen provision, the term of the lease was determined to be the noncancellable period in the contract plus the period beyond the noncancellable period that we believe it is reasonably certain we will need the equipment for operational purposes, limited to the point in time at which both we and the lessor each have the right to terminate the lease without permission from the other party with no more than an insignificant penalty.

• The discount rate used to calculate each lease liability was based on our incremental borrowing rate, which was estimated utilizing trading metrics for our senior unsecured notes as adjusted using relevant market factors to develop a synthetic secured yield curve.

• As an accounting policy, we have elected not to separate nonlease components from lease components for our production-related class of assets.

We have one finance lease, which results from a gathering agreement (the “Gathering Agreement”) on a gathering system. Under terms of the Gathering Agreement, we have the option to acquire a portion of the underlying gathering system upon termination of the Gathering Agreement. We make monthly payments under the Gathering Agreement based on the volume of oil gathered and a gathering rate per barrel, which is adjusted periodically. As of September 30, 2019, this lease had a remaining term of 5.9 years.

Exploration and Development-Related Leases

We have operating leases for equipment used in connection with our exploration and development activities, including drilling rigs, pressure pumping equipment, directional drilling tools, well-control devices, and various pieces of support equipment. These leases provide us the right to control the use of explicitly or implicitly identified equipment during the term of the contract. As of September 30, 2019, these leases had remaining lease terms of 12 months or less. These leases typically require us to make payments in amounts based on the usage of the underlying equipment. These leases do not contain residual value guarantees, options to purchase the underlying equipment, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of exploration and development-related equipment.

As an accounting policy, we have elected not to apply the recognition requirements of Topic 842 to our exploration and development-related class of assets with lease terms at commencement of 12 months or less. As such, we have not recorded any lease liabilities associated with our exploration and development-related leases. In addition, as an accounting policy we have elected not to separate nonlease components from lease components for our exploration and development-related class of assets.

27

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

Balance Sheet Presentation

The following tables present the amounts and classifications of our right-of-use assets and estimated lease liabilities as of September 30, 2019:

(in thousands)	Balance Sheet Location	September 30, 2019
Operating lease right-of-use assets	Non-current assets — Fixed assets, net	$	256,657
Finance lease right-of-use asset	Non-current assets — Other assets	25,946
Total right-of-use assets		$	282,603

(in thousands)	Balance Sheet Location	September 30, 2019
Operating lease liabilities — current	Current liabilities — Operating leases	$	67,208
Operating lease liabilities — non-current	Non-current liabilities — Operating leases	199,645
Finance lease liability — current	Current liabilities — Accrued liabilities-Other	7,129
Finance lease liability — non-current	Non-current liabilities — Other liabilities	20,148
Total lease liabilities		$	294,130

Lease Cost and Cash Flows

The following table summarizes estimated total lease cost, which includes amounts recognized in income and amounts capitalized for the indicated period:

(in thousands)	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Finance lease cost:
Amortization of right-of-use asset	$	1,096	$	3,289
Interest on lease liability	400		1,343
Operating lease cost: (1)
Production expense	4,047		11,824
Gas gathering and other expense	7,324		20,010
General and administrative expense	2,320		6,954
Short-term lease cost (2)	112,833		429,877
Total lease cost	$	128,020	$	473,297

________________________________________

(1) Operating lease cost in the table above is composed of costs incurred under real estate and production-related leases. These costs are included in the indicated captions on the Condensed Consolidated Statements of Operations.

(2) Short-term lease cost in the table above is composed of costs incurred under leases with terms of 12 months or less for right-of-use assets used in exploration and development activities. Payments under such leases are typically based on usage of the underlying right-of-use asset and, therefore, are also variable lease payments. These costs are capitalized as part of proved properties on the Condensed Consolidated Balance Sheet.

28

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

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

(in thousands)	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash outflows from finance lease	$	2,731
Operating cash outflows from operating leases	$	39,404
Cash paid for short-term leases and variable lease payments:
Investing cash outflows from operating leases	$	444,504

During the nine months ended September 30, 2019, we recognized $81.7 million in right-of-use assets in connection with new operating leases entered into during the period.

Lease Liability Maturity Analysis

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

	September 30, 2019
Weighted-average remaining lease term (in years):
Finance lease	5.9
Operating leases	4.3
Weighted-average discount rate:
Finance lease	5.9	%
Operating leases	3.9	%

The following table reflects the undiscounted future cash flows utilized in the calculation of the lease liabilities recorded at September 30, 2019:

	September 30, 2019
(in thousands)	Operating Leases			Finance Lease
October 1, 2019 — September 30, 2020	$	76,860		$	6,445
October 1, 2020 — September 30, 2021	68,661			5,679
October 1, 2021 — September 30, 2022	62,529			5,420
October 1, 2022 — September 30, 2023	44,495			5,161
October 1, 2023 —September 30, 2024	22,277			4,903
Remaining periods	15,572			4,267
Total undiscounted future cash flows	290,394			31,875
Less effects of discounting	(23,541		)	(4,598		)
Lease liabilities recognized	$	266,853		$	27,277

29

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

As of December 31, 2018, the following future minimum cash payments were required under leases for office space:

(in thousands)	December 31, 2018
2019	$	9,849
2020	10,790
2021	11,000
2022	11,130
2023	11,433
Remaining periods	20,831
Total future minimum lease payments	$	75,033

In addition, as of December 31, 2018, we had various contractual commitments for compressor equipment under operating lease arrangements totaling $34.8 million with lease terms expiring over 1 - 35 months.

Other Commitments

At September 30, 2019, we had estimated commitments of approximately: (i) $311.4 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $9.1 million to finish gathering system construction in progress.

At September 30, 2019, we had firm sales contracts to deliver approximately 723.7 Bcf of gas over the next 11.8 years. If we do not deliver this gas, our estimated financial commitment, calculated using October 2019 index prices, would be approximately $1.23 billion. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next 9.3 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, 2019, would be approximately $641.6 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2019, would be approximately $151.9 million. Of this total, we have accrued a liability of $4.5 million, representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.

At September 30, 2019, we have various firm transportation agreements for gas and oil pipeline capacity with end dates ranging from 2020 - 2028 under which we will have to pay an estimated $68.2 million over the remaining terms of the agreements. These agreements were entered into to support our residue gas and oil marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation.

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

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 guidance established by the FASB and adjust our

30

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

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)	2019		2018		2019		2018
Cash paid during the period for:
Interest (net of capitalized amounts of $9,574, $407, $29,695 and $9,796, respectively) (1)	$	4,399	$	—	$	37,383	$	23,343
Income taxes	$	—	$	—	$	1,206	$	—
Cash received for income tax refunds	$	—	$	—	$	336	$	718

________________________________________

(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 $13.6 million and $60.2 million related to these services during the three and nine months ended September 30, 2019 and $17.0 million and $57.0 million during the three and nine months ended September 30, 2018. The amount incurred in 2019 is included in the short-term lease costs disclosed in Note 10. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.

13. ACQUISITIONS

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’ attractive returns are competitive with those in our existing portfolio, (ii) the opportunity to apply our experience and learnings from already operating in this area to generating productivity gains from Resolute’s properties, (iii) the ability to increase our acreage position in the Delaware Basin, and (iv) the expectation that the acquisition will be financially accretive.

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

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

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

31

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

Preliminary Purchase Price Allocation

The Resolute acquisition has been accounted for as a business combination, using the acquisition method. The following table presents the preliminary allocation of the Resolute purchase price to the identifiable assets acquired and liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded to goodwill. The table also presents the adjustments to the preliminary purchase price allocation recorded through September 30, 2019. The most significant adjustment was made to the fair value of the unproved oil and gas properties acquired based on the finalization of the quantity of acres acquired. The tax effect of this adjustment reduced the related deferred income taxes. The remaining adjustments were working capital adjustments. The offset to all of the adjustments is goodwill. In conjunction with the adjustment to the unproved oil and gas properties balance, capitalized interest was reduced by $0.4 million in the current period to adjust capitalized interest recognized in previous periods. The purchase price allocation remains preliminary as certain data necessary to complete it is not yet available, and includes, but is not limited to, finalization of the fair value of certain assets and liabilities, including pre-acquisition working capital balances and completion of the final Resolute tax returns that will provide the underlying tax basis of Resolute’s assets and liabilities and net operating losses. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.

The following table sets forth the preliminary purchase price allocation:

(in thousands)	March 1, 2019			Adjustments			September 30, 2019
Cash	$	41,236		$	—		$	41,236
Accounts receivable	50,739			1,838			52,577
Other current assets	13,280			(792		)	12,488
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			24,263			131,604
Other assets	142			—			142
Current liabilities	(202,735		)	(1,862		)	(204,597		)
Long-term debt	(870,000		)	—			(870,000		)
Deferred income taxes	(62,409		)	6,899			(55,510		)
Asset retirement obligation	(9,437		)	—			(9,437		)
Total identifiable net assets	$	820,312		$	—		$	820,312

In connection with the acquisition, we assumed, and immediately repaid, $870.0 million principal amount of long-term debt consisting of $600.0 million of senior notes and $270.0 million of credit facility borrowings. On March 1, 2019, we repaid Resolute’s credit facility borrowings, delivered a notice of optional redemption of Resolute’s senior notes for an April 1, 2019 redemption date, and irrevocably deposited with a trustee the full amount of funds to repay the aggregate outstanding senior notes principal balance plus accrued and unpaid interest, incurring a $4.3 million loss on early extinguishment of debt. The cash consideration transferred and the repayment of Resolute’s long-term debt was funded using cash on hand and borrowings on our Credit Facility. We subsequently repaid the borrowings on our Credit Facility using the net proceeds from the March 8, 2019 issuance of $500 million aggregate principal amount of 4.375% senior unsecured notes (see Note 2 for more information on our debt issuance).

Goodwill of $131.6 million has been recognized principally as a result of recording net deferred tax liabilities arising from the difference between the tax basis and the purchase price allocated to Resolute’s assets and liabilities,

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2019

(Unaudited)

and anticipated opportunities for cost savings through administrative and operational synergies. Goodwill is not expected to be deductible for tax purposes.

Acquisition-related costs incurred in 2019 were $8.4 million. These costs, which are comprised primarily of advisory, legal, and other professional and consulting fees, are included in the Other operating expense, net line item on our Condensed Consolidated Statements of Operations and Comprehensive Income.

The results of Resolute’s operations have been included in our consolidated financial statements since the March 1, 2019 acquisition date. The amount of revenue and direct operating expenses resulting from the acquisition included in our Condensed Consolidated Statements of Operations and Comprehensive Income from March 1, 2019 through September 30, 2019 is $154.1 million and $36.5 million, respectively.

Pro Forma Financial Information

The following supplemental pro forma information for the three and nine months ended September 30, 2019 and 2018 has been prepared to give effect to the Resolute acquisition as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of the combined company’s proved oil and gas properties, (ii) the capitalization of interest expense, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by Cimarex of $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 periods presented as their results were not deemed material.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2019		2018		2019		2018
Revenue	$	582,305	$	691,140	$	1,758,861	$	1,954,550
Net income	$	40,536	$	148,620	$	162,493	$	484,173
Net income per common share:
Basic	$	0.39	$	1.47	$	1.57	$	4.81
Diluted	$	0.39	$	1.47	$	1.57	$	4.80

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

We believe that detailed technical analysis, operational focus, and a disciplined capital investment process mitigate risk and position us to continue to achieve profitable increases in proved reserves and production. Our drilling inventory and limited long-term commitments provide the flexibility to respond quickly to industry volatility. Our investments are generally funded with cash flow provided by operating activities together with cash on hand, bank borrowings, sales of non-core assets, and, from time to time, public financing based on our monitoring of capital markets and our balance sheet.

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.

As demonstrated in the table below, our company-wide average realized prices for the three and nine months ended September 30, 2019 as compared to the same periods in 2018 have declined for all products. In the case of oil sales, these decreases result from a combination of declining NYMEX prices in the 2019 periods, partially offset by improving differentials. In the case of gas sales, these decreases are driven by declining NYMEX prices and widening differentials.

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	Three Months Ended September 30,						Variance Between 2019 / 2018	Nine Months Ended September 30,						Variance Between 2019 / 2018
	2019			2018				2019			2018
Average NYMEX price
Oil — per barrel	$	56.45		$	69.50		(19)%	$	57.06		$	66.75		(15)%
Gas — per Mcf	$	2.23		$	2.91		(23)%	$	2.67		$	2.90		(8)%
Average realized price
Oil — per barrel	$	52.71		$	58.25		(10)%	$	52.02		$	59.70		(13)%
Gas — per Mcf	$	0.88		$	1.84		(52)%	$	1.08		$	1.92		(44)%
NGL — per barrel	$	10.80		$	25.72		(58)%	$	13.36		$	22.90		(42)%
Average price differential
Oil — per barrel	$	(3.74	)	$	(11.25	)	67%	$	(5.04	)	$	(7.05	)	29%
Gas — per Mcf	$	(1.35	)	$	(1.07	)	(26)%	$	(1.59	)	$	(0.98	)	(62)%

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
	2019									2018
	Third Quarter			Second Quarter			First Quarter			Fourth Quarter			Third Quarter			Second Quarter			First Quarter
Oil
Permian Basin	$	(3.76	)	$	(5.80	)	$	(6.90	)	$	(11.64	)	$	(14.34	)	$	(8.05	)	$	(3.12	)
Mid-Continent	$	(3.72	)	$	(4.39	)	$	(2.17	)	$	(2.33	)	$	(1.08	)	$	(2.18	)	$	(2.34	)
Gas
Permian Basin	$	(1.83	)	$	(3.10	)	$	(1.91	)	$	(2.21	)	$	(1.25	)	$	(1.31	)	$	(0.78	)
Mid-Continent	$	(0.66	)	$	(0.86	)	$	(0.46	)	$	(0.83	)	$	(0.94	)	$	(1.03	)	$	(0.70	)

Pipeline expansion projects in the Permian Basin are expected to ease capacity constraints as they come online over the next few years, which is reflected in the current futures markets that show narrowing differentials. However, if pipeline constraints remain because expansion projects are delayed or canceled, production increases faster than capacity increases, pipeline disruptions or other reasons, higher differentials will persist or potentially worsen. Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and 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, 2018, 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.

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Summary of Operating and Financial Results for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018:

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

• Total production volumes increased 29% to 273.7 MBOE per day.

• Oil volumes increased 32% to 84.2 MBbls per day.

• Gas volumes increased 24% to 674.6 MMcf per day.

• NGL volumes increased 33% to 77.0 MBbls per day.

• Total production revenue remained flat at $1.68 billion.

• Cash flow provided by operating activities decreased 15% to $984.2 million.

• Exploration and development expenditures decreased 17% to $989.5 million.

• Net income was $176.2 million, or $1.72 per diluted share, for the first nine months of 2019, as compared to net income of $475.7 million, or $5.00 per diluted share, for the first nine months of 2018.

RESULTS OF OPERATIONS

Three and Nine Months Ended September 30, 2019 vs. Three and Nine Months Ended September 30, 2018

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 higher for all products during the three and nine months ended September 30, 2019 as compared to the three and nine months ended September 30, 2018, while realized prices were lower. Our acquisition of Resolute and ongoing completion of new wells have increased our volumes. However, lower market prices and large basis differentials, both of which are out of our control, have lowered our realized prices and, therefore, our revenue. In addition, transportation and processing charges for sales contracts that transfer control of the product at the wellhead versus the tailgate of processing plants are reflected as reductions to revenue under Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”) and, therefore, negatively impact our realized prices. The largest sales contract we acquired with Resolute is this type of contract and sales volumes under legacy Cimarex contracts structured this way have increased. See below “Transportation, Processing, and Other Operating” for additional information. Our revenue decreased 2%, or $12.0 million, during the three months ended September 30, 2019 as compared to the three months ended September 30, 2018, and decreased less than 1%, or $6.8 million, during the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. 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.

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	Three Months Ended September 30,				Variance Between 2019 / 2018				Price/Volume Variance
Production Revenue (in thousands)	2019		2018						Price			Volume		Total
Oil sales	$	435,094	$	342,495	$	92,599		27%	$	(45,734	)	$	138,333	$	92,599
Gas sales	58,277		94,433		(36,156		)	(38)%	(63,415		)	27,259		(36,156		)
NGL sales	77,206		145,654		(68,448		)	(47)%	(106,645		)	38,197		(68,448		)
	$	570,577	$	582,582	$	(12,005	)	(2)%	$	(215,794	)	$	203,789	$	(12,005	)

	Nine Months Ended September 30,				Variance Between 2019 / 2018				Price/Volume Variance
Production Revenue (in thousands)	2019		2018						Price			Volume		Total
Oil sales	$	1,196,166	$	1,036,402	$	159,764		15%	$	(176,599	)	$	336,363	$	159,764
Gas sales	198,615		284,941		(86,326		)	(30)%	(154,699		)	68,373		(86,326		)
NGL sales	280,827		361,066		(80,239		)	(22)%	(200,596		)	120,357		(80,239		)
	$	1,675,608	$	1,682,409	$	(6,801	)	—%	$	(531,894	)	$	525,093	$	(6,801	)

The table below presents our production volumes by region.

	Three Months Ended September 30,		Nine Months Ended September 30,
Production Volumes	2019	2018	2019	2018
Oil (Bbls per day)
Permian Basin	74,819	49,001	70,188	49,211
Mid-Continent	14,788	14,755	13,880	14,149
Other	124	153	162	226
	89,731	63,909	84,230	63,586
Gas (MMcf per day)
Permian Basin	422.9	239.4	381.2	239.3
Mid-Continent	293.7	317.9	292.1	303.6
Other	1.4	1.5	1.3	1.5
	718.0	558.8	674.6	544.4
NGL (Bbls per day)
Permian Basin	53,311	31,919	51,492	29,863
Mid-Continent	24,338	29,603	25,480	27,829
Other	44	38	49	56
	77,693	61,560	77,021	57,748
Total (BOE per day)
Permian Basin	198,617	120,822	185,222	118,952
Mid-Continent	88,076	97,346	88,044	92,569
Other	401	427	418	548
	287,094	218,595	273,684	212,069

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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 three and nine months ended September 30, 2019, approximately 83% of our oil production was in the Permian Basin, up from approximately 77% during the three and nine months ended September 30, 2018. Our realized prices do not include settlements of commodity derivative contracts.

	Three Months Ended September 30,						Variance Between 2019 / 2018	Nine Months Ended September 30,						Variance Between 2019 / 2018
	2019			2018				2019			2018
Oil
Total volume — MBbls	8,255			5,880			40%	22,995			17,359			32%
Total volume — MBbls per day	89.7			63.9			40%	84.2			63.6			32%
Percentage of total production	31		%	29		%		31		%	30		%
Average realized price — per barrel	$	52.71		$	58.25		(10)%	$	52.02		$	59.70		(13)%
Average WTI Midland price — per barrel	$	55.83		$	56.89		(2)%	$	54.84		$	60.97		(10)%
Average WTI Cushing price — per barrel	$	56.45		$	69.50		(19)%	$	57.06		$	66.75		(15)%
Gas
Total volume — MMcf	66,058			51,406			29%	184,166			148,625			24%
Total volume — MMcf per day	718.0			558.8			29%	674.6			544.4			24%
Percentage of total production	42		%	43		%		41		%	43		%
Average realized price — per Mcf (1)	$	0.88		$	1.84		(52)%	$	1.08		$	1.92		(44)%
Average Henry Hub price — per Mcf	$	2.23		$	2.91		(23)%	$	2.67		$	2.90		(8)%
NGL
Total volume — MBbls	7,148			5,663			26%	21,027			15,765			33%
Total volume — MBbls per day	77.7			61.6			26%	77.0			57.7			33%
Percentage of total production	27		%	28		%		28		%	27		%
Average realized price — per barrel (2)	$	10.80		$	25.72		(58)%	$	13.36		$	22.90		(42)%
Total
Total production — MBOE	26,413			20,111			31%	74,716			57,895			29%
Total production — MBOE per day	287.1			218.6			31%	273.7			212.1			29%
Average realized price — per BOE (3)	$	21.60		$	28.97		(25)%	$	22.43		$	29.06		(23)%

________________________________________

The average realized gas, NGL, and total prices shown in the table above reflect the deduction of certain transportation, processing, and other costs as reductions of revenue under ASC 606, which reduced the average realized prices as follows:

(1) The average realized gas prices were reduced by $0.26 per Mcf, $0.07 per Mcf, $0.23 per Mcf, and $0.07 per Mcf for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively.

(2) The average realized NGL prices were reduced by $1.38 per barrel, $1.06 per barrel, $1.32 per barrel, and $1.36 per barrel for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively.

(3) The average realized total prices were reduced by $1.02 per BOE, $0.49 per BOE, $0.93 per BOE, and $0.55 per BOE for the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018, respectively.

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Other revenues

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

	Three Months Ended September 30,					Variance Between 2019 / 2018		Nine Months Ended September 30,						Variance Between 2019 / 2018
Gas Gathering and Marketing Revenues (in thousands)	2019		2018					2019			2018
Gas gathering and other	$	11,200	$	9,244		$	1,956	$	31,231		$	32,506		$	(1,275	)
Gas marketing	$	528	$	(338	)	$	866	$	(1,114	)	$	(19	)	$	(1,095	)

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, 2019 were higher by 31%, or $123.7 million, compared to the three months ended September 30, 2018.  The primary reasons for the increase were: (i) the $108.9 million ceiling test impairment we incurred during the three months ended September 30, 2019, (ii) the $91.7 million increase in depreciation, depletion, and amortization, and (iii) the $12.0 million increase in production expense, partially offset by the $92.7 million increase in net gains on derivative instruments.

	Three Months Ended September 30,					Variance Between 2019 / 2018			Per BOE
Operating Costs and Expenses (in thousands, except per BOE)	2019			2018					2019		2018
Impairment of oil and gas properties	$	108,879		$	—	$	108,879		N/A		N/A
Depreciation, depletion, and amortization	227,978			136,302		91,676			$	8.63	$	6.78
Asset retirement obligation	2,194			1,893		301			$	0.08	$	0.09
Production	88,300			76,272		12,028			$	3.34	$	3.79
Transportation, processing, and other operating	52,697			49,720		2,977			$	2.00	$	2.47
Gas gathering and other	13,893			10,569		3,324			$	0.53	$	0.53
Taxes other than income	30,873			28,431		2,442			$	1.17	$	1.41
General and administrative	15,499			21,148		(5,649		)	$	0.59	$	1.05
Stock compensation	6,797			6,437		360			$	0.26	$	0.32
(Gain) loss on derivative instruments, net	(38,735		)	54,006		(92,741		)	N/A		N/A
Other operating expense, net	10,141			10,015		126			N/A		N/A
	$	518,516		$	394,793	$	123,723

Total operating costs and expenses for the nine months ended September 30, 2019 were higher by 34%, or $369.8 million, compared to the nine months ended September 30, 2018.  The primary reasons for the increase were due to the following: (i) the $108.9 million ceiling test impairment we incurred during the nine months ended September 30, 2019, (ii) the $219.2 million increase in depreciation, depletion, and amortization, (iii) the $26.5 million increase in production expense, and (iv) the $19.1 million increase in taxes other than income, partially offset by the $35.6 million decrease in net losses on derivative instruments.

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	Nine Months Ended September 30,				Variance Between 2019 / 2018			Per BOE
Operating Costs and Expenses (in thousands, except per BOE)	2019		2018					2019		2018
Impairment of oil and gas properties	$	108,879	$	—	$	108,879		N/A		N/A
Depreciation, depletion, and amortization	631,722		412,549		219,173			$	8.45	$	7.13
Asset retirement obligation	6,400		5,006		1,394			$	0.09	$	0.09
Production	253,259		226,758		26,501			$	3.39	$	3.92
Transportation, processing, and other operating	154,636		146,818		7,818			$	2.07	$	2.54
Gas gathering and other	39,818		29,859		9,959			$	0.53	$	0.52
Taxes other than income	105,600		86,549		19,051			$	1.41	$	1.49
General and administrative	69,494		64,208		5,286			$	0.93	$	1.11
Stock compensation	20,004		16,262		3,742			$	0.27	$	0.28
Loss on derivative instruments, net	35,949		71,546		(35,597		)	N/A		N/A
Other operating expense, net	19,057		15,470		3,587			N/A		N/A
	$	1,444,818	$	1,075,025	$	369,793

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.

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. 

At September 30, 2019, we incurred a ceiling test impairment of $108.9 million.  The impairment resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves. We expect these conditions to continue at least through year-end and possibly beyond and, therefore, expect to incur another ceiling test impairment at December 31, 2019.

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 net proved properties, production,

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and reserves have increased during 2019 as compared to 2018 due to our ongoing exploration and development activities as well as due to our acquisition of Resolute. The increase in net properties and production resulted in an overall increase in depletion expense, while the increase in reserves partially offset the increased expense.

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

	Three Months Ended September 30,				Variance Between 2019 / 2018		Per BOE
DD&A Expense (in thousands, except per BOE)	2019		2018				2019		2018
Depletion	$	211,422	$	123,668	$	87,754	$	8.00	$	6.15
Depreciation	16,556		12,634		3,922		0.63		0.63
	$	227,978	$	136,302	$	91,676	$	8.63	$	6.78

	Nine Months Ended September 30,				Variance Between 2019 / 2018		Per BOE
DD&A Expense (in thousands, except per BOE)	2019		2018				2019		2018
Depletion	$	583,033	$	375,278	$	207,755	$	7.80	$	6.48
Depreciation	48,689		37,271		11,418		0.65		0.65
	$	631,722	$	412,549	$	219,173	$	8.45	$	7.13

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 2019 / 2018		Per BOE
Production Expense (in thousands, except per BOE)	2019		2018				2019		2018
Lease operating expense	$	66,294	$	61,568	$	4,726	$	2.51	$	3.06
Workover expense	22,006		14,704		7,302		0.83		0.73
	$	88,300	$	76,272	$	12,028	$	3.34	$	3.79

	Nine Months Ended September 30,				Variance Between 2019 / 2018		Per BOE
Production Expense (in thousands, except per BOE)	2019		2018				2019		2018
Lease operating expense	$	200,481	$	184,400	$	16,081	$	2.68	$	3.19
Workover expense	52,778		42,358		10,420		0.71		0.73
	$	253,259	$	226,758	$	26,501	$	3.39	$	3.92

On an absolute dollar basis, lease operating expense in the third quarter 2019 increased 8%, or $4.7 million, compared to the third quarter of 2018, and for the nine months ended September 30, 2019 increased 9%, or $16.1 million, as compared to the nine months ended September 30, 2018. The increases have primarily stemmed from the Resolute acquisition and the addition of new wells as a result of our ongoing exploration and development activities.

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These increases were partially offset by expense reductions related to the sale of non-core properties principally located in Ward County, Texas in August 2018. The following types of expenses have been the primary drivers of increased expense in the 2019 periods as compared to the 2018 periods: (i) saltwater disposal, (ii) electricity/fuel, (iii) labor, and (iv) compressor and equipment rentals. On a per BOE basis, lease operating expense decreased 18.0% and 16.0% for the three and nine months ended September 30, 2019, respectively, as compared to the three and nine months ended September 30, 2018, as a result of our production growing at a faster rate than increases in our lease operating expense.

Workover expense in the third quarter 2019 increased 50%, or $7.3 million, compared to the third quarter of 2018. Workover expense for the nine months ended September 30, 2019 increased 25%, or $10.4 million, as compared to the nine months ended September 30, 2018. We had an increased number of workover projects contributing to our workover expense during the 2019 periods as compared to the 2018 periods. The following types of expenses have been the primary drivers of increased expense in the 2019 periods as compared to the 2018 periods: (i) major well work, which can include replacing tubing, casing repair, cleanouts, and fishing, (ii) lift, which includes changing lift types or repairing/replacing lift equipment, and (iii) surface equipment maintenance and repair. During the nine months ended September 30, 2018, our workover expense was reduced due to receiving approximately $4.0 million in insurance proceeds related to the remediation and repairs incurred as a result of a 2015 flooding event.

Transportation, Processing, and Other Operating

Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, 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 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. The largest sales contract that we acquired with Resolute is structured this way and sales volumes under legacy Cimarex contracts structured this way have increased, therefore, our transportation and processing costs have not increased commensurate with production volume increases. Transportation, processing, and other operating costs in the third quarter 2019 were 6%, or $3.0 million, higher than the same costs in the third quarter 2018. For the nine months ended September 30, 2019, transportation, processing, and other operating costs were 5%, or $7.8 million, higher than for the nine months ended September 30, 2018. Transportation and processing costs included as a reduction in revenue pursuant to ASC 606 were $26.9 million and $69.5 million for the three and nine months ended September 30, 2019 and $9.9 million and $32.1 million for the three and nine months ended September 30, 2018.

Gas Gathering and Other

Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs and operating and maintenance expenses. Gas gathering and other in the three months ended September 30, 2019 was 31%, or $3.3 million, higher than gas gathering and other in the three months ended September 30, 2018. Gas gathering and other in the nine months ended September 30, 2019 was 33%, or $10.0 million, higher than gas gathering and other in the nine months ended September 30, 2018. The increases are primarily due to overall increases in operating costs partially offset by lower product costs associated with processing third-party production due primarily to lower volumes and prices. The increase in operating costs was due primarily to an increase in compression costs.

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.  

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	Three Months Ended September 30,						Variance Between 2019 / 2018			Nine Months Ended September 30,						Variance Between 2019 / 2018
Taxes Other than Income (in thousands)	2019			2018						2019			2018
Production	$	23,485		$	20,565		$	2,920		$	80,223		$	71,235		$	8,988
Ad valorem	7,152			7,599			(447		)	24,686			14,748			9,938
Other	236			267			(31		)	691			566			125
	$	30,873		$	28,431		$	2,442		$	105,600		$	86,549		$	19,051
Production taxes as a percentage of revenue	5.4		%	4.9		%				6.3		%	5.1		%

Taxes other than income increased $2.4 million, or 9%, in the third quarter of 2019 as compared to the third quarter of 2018 and increased $19.1 million, or 22%, in the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. Production taxes make up the majority of our taxes other than income and they increased primarily due to increased production volumes, but also due to decreased refunds, which are generally for high-cost gas wells in Texas, but also include marketing cost deduction refunds. Ad valorem taxes increased during the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 due to new properties, including those acquired in the Resolute acquisition, and expected increased assessed values. Estimates of ad valorem taxes are adjusted as better information, including actual valuations, is received. Other taxes other than income are comprised of franchise and consumer use and sales taxes.

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 45% to 49% during the periods presented in the table below, which shows our G&A costs.

	Three Months Ended September 30,						Variance Between 2019 / 2018			Nine Months Ended September 30,						Variance Between 2019 / 2018
General and Administrative Expense (in thousands)	2019			2018						2019			2018
Gross G&A	$	29,828		$	41,584		$	(11,756	)	$	125,994		$	121,708		$	4,286
Less amounts capitalized to oil and gas properties	(14,329		)	(20,436		)	6,107			(56,500		)	(57,500		)	1,000
G&A expense	$	15,499		$	21,148		$	(5,649	)	$	69,494		$	64,208		$	5,286

G&A expense for the third quarter of 2019 was 27%, or $5.6 million, lower than G&A expense for the third quarter of 2018. Third quarter of 2019 G&A expense was reduced by gains on our supplemental savings deferred compensation plan, whereas third quarter of 2018 G&A expense was increased by losses in the plan, causing a decrease in G&A expense of $3.5 million between the quarters. Additionally, third quarter of 2019 included a reduction in G&A expense of $2.4 million as compared to third quarter of 2018 due to the reversal of the year-to-date employee profit sharing accrual in third quarter of 2019 as a result of the expected ceiling test impairment at December 31, 2019, which will create a net loss for the year. Lastly, third quarter of 2019 G&A expense was reduced by $3.2 million for our semi-annual billing of working interest partners for major construction overhead on all operated wells, which began occurring in the fourth quarter of 2018. These decreases in G&A expense were partially offset by increases resulting from increased salaries and wages and other employee benefit costs due primarily to increased headcount.

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G&A expense for the nine months ended September 30, 2019 was 8%, or $5.3 million, higher than G&A expense for the nine months ended September 30, 2018. This was primarily due to increased employee-related costs such as salaries and wages, other compensation, and benefits. Included in the nine months ended September 30, 2019 was $2.9 million of severance expense related to former Resolute employees who performed transition work at Cimarex and then were subsequently terminated. 

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 2019 / 2018			Nine Months Ended September 30,						Variance Between 2019 / 2018
Stock Compensation Expense (in thousands)	2019			2018						2019			2018
Restricted stock awards:
Performance stock awards	$	5,604		$	6,364		$	(760	)	$	16,533		$	16,902		$	(369	)
Service-based stock awards	6,140			5,244			896			19,364			14,563			4,801
	11,744			11,608			136			35,897			31,465			4,432
Stock option awards	411			571			(160		)	1,429			1,825			(396		)
Total stock compensation cost	12,155			12,179			(24		)	37,326			33,290			4,036
Less amounts capitalized to oil and gas properties	(5,358		)	(5,742		)	384			(17,322		)	(17,028		)	(294		)
Stock compensation expense	$	6,797		$	6,437		$	360		$	20,004		$	16,262		$	3,742

Periodic stock compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards.  The increase in total stock compensation cost in the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 is primarily due to awards granted either during or subsequent to the nine months ended September 30, 2018, partially offset by awards vesting either prior to or during the nine months ended September 30, 2019.

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(Gain) Loss on Derivative Instruments, Net

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

	Three Months Ended September 30,						Variance Between 2019 / 2018			Nine Months Ended September 30,						Variance Between 2019 / 2018
(Gain) Loss on Derivative Instruments, Net (in thousands)	2019			2018						2019			2018
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts	$	5,818		$	6,378		$	(560	)	$	(10,398	)	$	9,155		$	(19,553	)
Oil contracts	(42,857		)	47,129			(89,986		)	45,229			41,973			3,256
	(37,039		)	53,507			(90,546		)	34,831			51,128			(16,297		)
Cash (receipts) payments on derivative instruments, net:
Gas contracts	(17,554		)	(3,462		)	(14,092		)	(34,966		)	(18,499		)	(16,467		)
Oil contracts	15,858			3,961			11,897			36,084			38,917			(2,833		)
	(1,696		)	499			(2,195		)	1,118			20,418			(19,300		)
(Gain) loss on derivative instruments, net	$	(38,735	)	$	54,006		$	(92,741	)	$	35,949		$	71,546		$	(35,597	)

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, legal, and other professional and consulting fees. Other operating expense, net for each of the quarters ended September 30, 2019 and 2018 included $10.0 million of litigation settlements. Other operating expense, net for the nine months ended September 30, 2019 and 2018 included litigation settlements of $10.0 million and $14.9 million, respectively.

Other Income and Expense

	Three Months Ended September 30,						Variance Between 2019 / 2018			Nine Months Ended September 30,						Variance Between 2019 / 2018
Other Income and Expense (in thousands)	2019			2018						2019			2018
Interest expense	$	24,586		$	17,159		$	7,427		$	69,665		$	50,837		$	18,828
Capitalized interest	(16,264		)	(5,457		)	(10,807		)	(41,811		)	(15,117		)	(26,694		)
Loss on early extinguishment of debt	—			—			—			4,250			—			4,250
Other, net	(139		)	(7,544		)	7,405			(4,547		)	(14,716		)	10,169
	$	8,183		$	4,158		$	4,025		$	27,557		$	21,004		$	6,553

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 increase in interest expense in the 2019 periods as compared to the 2018 periods is primarily due to (i) the March 8, 2019 issuance of $500 million aggregate principal amount of 4.375% senior unsecured notes due March 15, 2029 at 99.862% of par to yield 4.392% per annum, (ii) borrowings on our Credit Facility in 2019 to help fund the Resolute acquisition and thereafter to meet cash requirements as needed (we did not borrow on our Credit Facility in 2018), and (iii) interest expense on our finance lease. 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

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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 midstream assets. Capitalized interest will fluctuate based on the rates applicable to borrowings outstanding during the period and the amount of costs subject to interest capitalization. The amount of costs subject to interest capitalization was higher in the three and nine months ended September 30, 2019 as compared to the three and nine months ended September 30, 2018, primarily due to the Resolute acquisition. Included in the preliminary purchase price allocation of the Resolute acquisition was non-producing leasehold costs of $1.02 billion.

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 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 2019 / 2018			Nine Months Ended September 30,						Variance Between 2019 / 2018
Income Tax Expense (in thousands)	2019			2018						2019			2018
Current tax expense	$	—		$	1,100		$	(1,100	)	$	—		$	383		$	(383	)
Deferred tax expense	15,079			43,083			(28,004		)	57,198			142,815			(85,617		)
	$	15,079		$	44,183		$	(29,104	)	$	57,198		$	143,198		$	(86,000	)
Combined federal and state effective income tax rate	27.1		%	22.9		%				24.5		%	23.1		%

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. See Note 9 to the Condensed Consolidated Financial Statements for additional information regarding our income taxes.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Our liquidity is highly dependent on prices we receive for the oil, 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.

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 enables us to respond quickly to industry volatility. Based on current economic conditions, our 2019 exploration and development (“E&D”) expenditures are projected to range from $1.30 billion to $1.40 billion. Investments in gathering, processing, and other infrastructure are projected to be approximately $70 million for 2019. See Capital Expenditures below for information regarding our E&D activities for the three and nine months ended September 30, 2019 and 2018.

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We periodically use derivative instruments to mitigate volatility in commodity prices. At September 30, 2019, we had derivative contracts covering a portion of our 2019 - 2021 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, 2019 were $23.9 million. At September 30, 2019, 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, 2019, 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. See Long-term Debt below for more information regarding our debt.

Our debt to total capitalization ratio at September 30, 2019 was 35%, up from 31% at December 31, 2018. This ratio is calculated by dividing the sum of (i) the principal amount of long-term debt and (ii) redeemable preferred stock by the sum of (i) the principal amount of long-term debt, (ii) redeemable preferred stock, and (iii) total stockholders’ equity, with all numbers coming directly from the Condensed Consolidated Balance Sheet. Management uses this ratio as one indicator of our financial condition and believes professional research analysts and rating agencies use this ratio for this purpose and to compare our financial condition to other companies’ financial conditions.

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.

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)	2019			2018
Net cash provided by operating activities	$	984,157		$	1,157,813
Net cash used by investing activities	$	(1,314,450	)	$	(652,164	)
Net cash used by financing activities	$	(446,488	)	$	(42,237	)

Net cash provided by operating activities for the nine months ended September 30, 2019 was $984.2 million, down $173.7 million, or 15%, from $1.16 billion for the nine months ended September 30, 2018. The $173.7 million decrease resulted primarily from an increased investment in working capital, primarily related to the repayment of liabilities assumed from Resolute, and increased operating expenses in 2019 as compared to 2018. Partially offsetting this decrease in operating cash flows was a decrease in cash outflows for settlements of derivative instruments. Despite increased production volumes, revenue remained flat between the two periods due to decreased pricing and, therefore, did not offset the increased cash outflows for operating expenses. See RESULTS OF OPERATIONS above for more information regarding the changes in revenue and operating expenses.

Net cash used by investing activities for the nine months ended September 30, 2019 and 2018 was $1.31 billion and $652.2 million, respectively. The majority of our cash flows used by investing activities are for E&D expenditures, which totaled $1.00 billion and $1.15 billion for the nine months ended September 30, 2019 and 2018, respectively. 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. Net cash used by investment activities in the nine months ended September 30, 2018 included $534.6 million in proceeds

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from the sale of oil and gas properties principally located in Ward County, Texas in August 2018. 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-core oil and gas properties.

Net cash used by financing activities was $446.5 million and $42.2 million during the nine months ended September 30, 2019 and 2018, respectively. 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 $1.74 billion on our credit facility during the nine months ended September 30, 2019 to assist in funding the Resolute acquisition and thereafter to meet cash requirements as needed. In connection with the acquisition of Resolute, we assumed $870.0 million 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. We had no long-term debt-related financing cash flows during the nine months ended September 30, 2018. 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) the receipt of proceeds from exercises of stock options. During the nine months ended September 30, 2019, we paid one $0.18 per common share dividend, two $0.20 per common share dividends, and two $20.31 per preferred share dividends, totaling $60.1 million. During the nine months ended September 30, 2018, we paid one $0.08 per common share dividend and two $0.16 per common share dividends, totaling $38.0 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 and property sales, net of applicable purchase price adjustments.

	Three Months Ended September 30,							Nine Months Ended September 30,
(in thousands)	2019				2018			2019			2018
Acquisitions:
Proved	$	2,373			$	—		$	696,173		$	62
Unproved	(30,314		)	(1)	10,015			1,021,468			12,251
	(27,941		)		10,015			1,717,641			12,313
Exploration and development:
Land and seismic	18,377				55,603			42,456			76,027
Exploration and development	278,083				445,429			947,002			1,113,898
	296,460				501,032			989,458			1,189,925
Property sales:
Proved	(9,286		)		(527,650		)	(27,314		)	(557,191		)
Unproved	(81		)		(12,022		)	(9,835		)	(17,323		)
	(9,367		)		(539,672		)	(37,149		)	(574,514		)
	$	259,152			$	(28,625	)	$	2,669,950		$	627,724

________________________________________

(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 Energy Corporation, an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin

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area of the Permian Basin of west Texas. The fair value of the proved and unproved properties recorded in the preliminary purchase price allocation for this acquisition was $692.6 million and $1.02 billion, respectively.

Our 2019 E&D capital investment is projected to range from $1.30 billion to $1.40 billion, with the majority expected to be invested in the Permian Basin. As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on increases or decreases in commodity prices, service costs, and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions.

We intend to continue to fund our 2019 capital investment program with cash flow from our operating activities, cash on hand, and borrowings under our credit facility. Sales of non-core assets and possible capital markets transactions may also be used to supplement funding of capital expenditures and acquisitions. The timing of capital expenditures and the receipt of cash flows do not necessarily match, which may cause us to borrow and repay funds under our credit facility 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,
	2019	2018	2019	2018
Gross wells
Permian Basin	44	33	100	82
Mid-Continent	52	82	144	176
	96	115	244	258
Net wells
Permian Basin	16	24	53	46
Mid-Continent	5	20	16	36
	21	44	69	82

As of September 30, 2019, we had 10 gross (7 net) wells in the process of being drilled, all in the Permian Basin. As of September 30, 2019, we had 79 gross (34 net) wells waiting on completion: 43 gross (32 net) in the Permian Basin and 36 gross (2 net) in the Mid-Continent region. As of September 30, 2019, we had 8 operated rigs running, all in the Permian Basin.

We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations. While we expect current pending legislation or regulations to increase the cost of business, we do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact, based on current laws and regulations. However, compliance with new legislation or regulations could increase our costs or adversely affect demand for oil or gas and result in a material adverse effect on our financial position or operations. See our Form 10-K for the year ended December 31, 2018, Item 1A Risk Factors, for a description of risks related to current and potential future environmental and safety regulations and requirements that could adversely affect our operations and financial condition.

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Long-term Debt

Long-term debt at September 30, 2019 and December 31, 2018 consisted of the following:

	September 30, 2019							December 31, 2018
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)			Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discount (1)			Long-term Debt, net
4.375% Notes due 2024	$	750,000	$	(3,758	)	$	746,242	$	750,000	$	(4,439	)	$	745,561
3.90% Notes due 2027	750,000		(6,471		)	743,529		750,000		(7,007		)	742,993
4.375% Notes due 2029	500,000		(5,037		)	494,963		—		—			—
	$	2,000,000	$	(15,266	)	$	1,984,734	$	1,500,000	$	(11,446	)	$	1,488,554

________________________________________

(1) At September 30, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.0 million and $1.5 million, respectively. At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.4 million and $1.6 million, respectively. At September 30, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.4 million and $0.7 million, respectively. The 4.375% Notes due 2024 were issued at par.

Bank Debt

On February 5, 2019, we entered into an Amended and Restated Credit Agreement for our senior unsecured revolving credit facility (“Credit Facility”). Among other things, the amended and restated credit facility increased the aggregate commitments to $1.25 billion with an option for us to increase the aggregate commitments to $1.5 billion, and extended the maturity date to February 5, 2024. As of September 30, 2019, 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, 2019, we borrowed and repaid an aggregate of $529.0 million and $1.74 billion, 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.

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of September 30, 2019, we were in compliance with all of the financial covenants.

At September 30, 2019 and December 31, 2018, we had $4.3 million and $2.2 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in Other assets on our Condensed Consolidated Balance Sheets. These costs are being amortized to interest expense ratably over the life of the Credit Facility. We incurred $3.0 million in additional debt issuance costs in amending our Credit Facility.

Senior Notes

On 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

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deducting underwriters’ fees, discount, and debt issuance costs.  The notes bear an annual interest rate of 4.375% and interest is payable semiannually on March 15 and September 15, with the first payment made on September 15, 2019.  We used the net proceeds to repay borrowings under our Credit Facility. 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, 2019.

Working Capital Analysis

Our working capital fluctuates primarily as a result of our realized commodity prices, increases or decreases in our production volumes, changes in receivables and payables related to our operating and E&D activities, changes in our oil and gas well equipment and supplies, and changes in the fair value of our derivative instruments.

At September 30, 2019, we had a working capital deficit of $240.1 million, a decrease of $955.6 million or 134% from a working capital surplus of $715.4 million at December 31, 2018. Our working capital decreased primarily due to the decrease in Cash and cash equivalents of $776.8 million, which was a result of our acquisition of Resolute and subsequent repayment of Resolute’s long-term debt. See Note 13 to the Condensed Consolidated Financial Statements for more information regarding the acquisition. In addition to the decrease in cash, other significant changes to working capital consisted primarily of the following: 

• Our net current asset derivative instrument position decreased by $49.9 million.

• The adoption of Topic 842 increased our current liabilities by $74.3 million, representing estimated lease liabilities, primarily for office space, well-head compressors, pipeline compressors, and artificial lift mechanisms. See Note 10 to the Condensed Consolidated Financial Statements for more information regarding our lease liabilities and the adoption of Topic 842.

• Operations-related accounts payable and accrued liabilities increased by $30.3 million.

• Accounts receivable decreased by $28.9 million.

Accounts receivable are a major component of our working capital and include amounts due from a diverse group of companies comprised of major energy companies, pipeline companies, local distribution companies, and other end-users. Historically, losses associated with uncollectible receivables have not been significant. The fair value of derivative instruments fluctuates based on changes in the underlying price indices as compared to the contracted prices.

Dividends

A quarterly cash dividend has been paid on our common stock every quarter since the first quarter of 2006. In August 2019, our Board of Directors declared a cash dividend of $0.20 per common share, totaling $20.4 million, which is payable on or before November 29, 2019 to stockholders of record on November 15, 2019. In March 2019, in conjunction with the Resolute acquisition, we issued 62.5 thousand shares of 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share. In August 2019, our Board of Directors declared a cash dividend of $20.31 per preferred share, totaling $1.3 million. The dividend was paid in October to preferred stockholders of record on October 1, 2019. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors. See Note 5 to the Condensed Consolidated Financial Statements for further information regarding our stock and Note 13 to the Condensed Consolidated Financial Statements for further information regarding the Resolute acquisition.

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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, 2019, 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.

Contractual Obligations and Material Commitments

At September 30, 2019, we had the following contractual obligations and material commitments:

	Payments Due by Period
Contractual obligations (in thousands)	Total		10/1/19 - 9/30/20		10/1/20 - 9/30/22			10/1/22 - 9/30/24			10/1/24 and Thereafter
Long-term debt—principal (1)	$	2,000,000	$	—	$	—		$	750,000		$	1,250,000
Long-term debt—interest (1)	605,936		81,868		167,875			167,875			188,318
Operating leases (2)	96,245		25,779		34,672			23,215			12,579
Unconditional purchase obligations (3)	92,742		23,223		24,693			19,215			25,611
Derivative liabilities	25,386		24,983		403			—			—
Asset retirement obligation (4)	175,772		18,341		—		(4)	—		(4)	—		(4)
Other long-term liabilities (5)	42,506		1,554		5,841			2,896			32,215
	$	3,038,587	$	175,748	$	233,484		$	963,201		$	1,508,723

________________________________________

(1) The interest payments presented above include the accrued interest payable on our long-term debt as of September 30, 2019 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, 2019. 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, 2019. These lease agreements are primarily comprised of leases for commercial real estate, which consists primarily of office space, and compressor equipment.

(3) Of the total unconditional purchase obligations, $24.2 million represents obligations for the purchase of sand for well completions and $68.2 million represents obligations for firm transportation agreements for gas and oil pipeline capacity.

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

(5) Other long-term liabilities include contractual obligations associated with our employee supplemental savings plan, gas balancing liabilities, and other miscellaneous liabilities. All of these liabilities are accrued on our 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, 2019, we had estimated commitments of approximately: (i) $311.4 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $9.1 million to finish gathering system construction in progress.

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At September 30, 2019, we had firm sales contracts to deliver approximately 723.7 Bcf of gas over the next 11.8 years. If we do not deliver this gas, our estimated financial commitment, calculated using October 2019 index prices, would be approximately $1.23 billion. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next 9.3 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, 2019, would be approximately $641.6 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2019, would be approximately $151.9 million. Of this total, we have accrued a liability of $4.5 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.

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, 2018.

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, 2019, our total production revenue was comprised of approximately 76% oil sales, 10% gas sales, and 14% NGL sales. For the nine months ended September 30, 2019, our total production revenue was comprised of approximately 71% oil sales, 12% 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 periods indicated.

			Impact on Revenue
	Change in Realized Price		Three Months Ended September 30, 2019	Nine Months Ended September 30, 2019
			(in thousands)
Oil	± $1.00	per barrel	± $8,255	± $22,995
Gas	± $0.10	per Mcf	± $6,606	± $18,417
NGL	± $1.00	per barrel	± $7,148	± $21,027
			± $22,009	± $62,439

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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, 2019, we had oil and gas derivatives covering a portion of our 2019 - 2021 production, which were recorded as current and non-current assets and liabilities. At September 30, 2019, our oil and gas derivatives had a gross asset fair value of $55.1 million and a gross liability fair value of $25.4 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 hypothetical changes in the forward prices used to calculate the fair value of our derivatives may have impacted the fair value as of September 30, 2019.

		Impact on Fair Value
	Change in Forward Price	September 30, 2019
		(in thousands)
Oil	-$1.00	$	6,660
Oil	+$1.00	$	(6,610	)
Gas	-$0.10	$	4,712
Gas	+$0.10	$	(4,592	)

Interest Rate Risk

At September 30, 2019, 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.

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, 2019.  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, 2019 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  

In addition to the other information set forth in this report, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2018. The risks described in the Annual Report on Form 10-K for the year ended December 31, 2018 are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or future results. Material changes from the risk factors previously disclosed in our Form 10-K for the year ended December 31, 2018 are set forth below.

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

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

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

Under the full cost method of accounting, we are required to perform quarterly ceiling test calculations to test our oil and gas properties for possible impairment. At September 30, 2019, we incurred a ceiling test impairment of our oil and gas properties of $108.9 million. We expect to incur another ceiling test impairment at December 31, 2019 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.

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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
2.1	Agreement and Plan of Merger dated as of November 18, 2018, by and among Cimarex Energy Co., CR Sub 1 Inc., CR Sub 2 LLC, and Resolute Energy Corporation (filed on November 20, 2018 as Exhibit 2.1 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).
4.1	Certificate of Designations of 8⅛% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co., dated February 28, 2019 (filed on March 1, 2019 as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).
4.2	Second Supplemental Indenture dated as of March 8, 2019, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee (filed on March 8, 2019 as Exhibit 4.2 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).
4.3	Form of 4.375% Senior Notes due 2029 (filed on March 8, 2019 as Exhibit 4.3 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).
10.1	Amended and Restated Credit Agreement Dated as of February 5, 2019, by and among Cimarex, as Borrower, the Administrative Agent, the Syndication Agent, the Co-Documentation Agents, the Lenders, and the Lead Arrangers and Bookrunners (filed on February 7, 2019 as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).
10.2	Form of Notice of Grant of Restricted Stock (Director) and Award Agreement (filed on May 29, 2019 as Exhibit 10.2 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).
10.3	2019 Equity Incentive Plan (filed on May 30, 2019 as Exhibit 99.1 to the Registration Statement on Form S-8 (Commission File No. 001-31446) and incorporated herein by reference).
10.4	Form of Notice of Grant of Restricted Stock and Award Agreement (filed on August 5, 2019 as Exhibit 10.4 to the Quarterly Report on Form 10-Q (Commission File No. 001-31446) and incorporated herein by reference).
10.5	Form of Notice of Grant of Nonqualified Stock Option and Award Agreement (filed on August 5, 2019 as Exhibit 10.5 to the Quarterly Report on Form 10-Q (Commission File No. 001-31446) and incorporated herein by reference).
10.6	Director Emeritus Agreement dated September 30, 2019 between Cimarex Energy Co. and Michael J. Sullivan (filed on September 23, 2019 as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).
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 5, 2019
	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)

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