10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)
ý	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period ended March 31, 2019
or
o	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _______________ to _______________

Commission File 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)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý  No o

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 ý  No o

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 ý	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
			Emerging growth company o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 

Yes o  No ý

The number of shares of Cimarex Energy Co. common stock outstanding as of April 30, 2019 was 101,433,207.

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

CIMAREX ENERGY CO.

Table of Contents

		Page
PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2019 and December 31, 2018	4
	Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited) for the three months ended March 31, 2019 and 2018	5
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended March 31, 2019 and 2018	6
	Condensed Consolidated Statement of Stockholders’ Equity (Unaudited) for the three months ended March 31, 2019 and 2018	7
	Notes to Condensed Consolidated Financial Statements (Unaudited)	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 4.	Controls and Procedures	46
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 6.	Exhibits	47
Signatures		48

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, 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)

	March 31,			December 31,
	2019			2018
Assets
Current assets:
Cash and cash equivalents	$	20,930		$	800,666
Accounts receivable, net of allowance:
Trade	123,192			122,065
Oil and gas sales	329,661			315,063
Gas gathering, processing, and marketing	13,049			17,072
Oil and gas well equipment and supplies	62,600			55,553
Derivative instruments	35,830			101,939
Prepaid expenses	8,135			7,554
Other current assets	2,811			4,227
Total current assets	596,208			1,424,139
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	19,410,269			18,566,757
Unproved properties and properties under development, not being amortized	1,707,089			436,325
	21,117,358			19,003,082
Less—accumulated depreciation, depletion, amortization, and impairment	(15,462,464		)	(15,287,752		)
Net oil and gas properties	5,654,894			3,715,330
Fixed assets, net of accumulated depreciation of $340,147 and $324,631, respectively	509,554			257,686
Goodwill	727,573			620,232
Derivative instruments	626			9,246
Other assets	68,337			35,451
	$	7,557,192		$	6,062,084
Liabilities, Redeemable Preferred Stock, and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	65,664		$	76,927
Gas gathering, processing, and marketing	25,190			29,887
Accrued liabilities:
Exploration and development	183,940			124,674
Taxes other than income	32,084			33,622
Other	247,041			221,159
Derivative instruments	77,557			27,627
Revenue payable	215,613			194,811
Operating leases	62,825			—
Total current liabilities	909,914			708,707
Senior notes principal	2,000,000			1,500,000
Less—senior notes unamortized debt issuance costs and discounts	(16,273		)	(11,446		)
Senior notes, net	1,983,727			1,488,554
Deferred income taxes	405,294			334,473
Asset retirement obligation	165,529			152,758
Derivative instruments	756			2,267
Operating leases	186,356			—
Other liabilities	62,634			45,539
Total liabilities	3,714,210			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, 101,407,583 and 95,755,797 shares issued, respectively	1,014			958
Additional paid-in capital	3,210,818			2,785,188
Retained earnings	547,626			542,885
Accumulated other comprehensive income	1,904			755
Total stockholders’ equity	3,761,362			3,329,786
	$	7,557,192		$	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 March 31,
	2019			2018
Revenues:
Oil sales	$	349,306		$	351,723
Gas and NGL sales	217,915			203,718
Gas gathering and other	10,262			11,452
Gas marketing	(526		)	241
	576,957			567,134
Costs and expenses:
Depreciation, depletion, and amortization	190,417			132,859
Asset retirement obligation	2,049			1,060
Production	77,233			71,271
Transportation, processing, and other operating	53,608			45,165
Gas gathering and other	12,320			9,823
Taxes other than income	33,694			30,188
General and administrative	29,084			23,321
Stock compensation	6,713			6,730
Loss (gain) on derivative instruments, net	115,452			(4,159		)
Other operating expense, net	8,326			203
	528,896			316,461
Operating income	48,061			250,673
Other (income) and expense:
Interest expense	20,405			16,783
Capitalized interest	(8,742		)	(4,810		)
Loss on early extinguishment of debt	4,250			—
Other, net	(2,241		)	(4,567		)
Income before income tax	34,389			243,267
Income tax expense	8,073			56,949
Net income	$	26,316		$	186,318
Earnings per share to common stockholders:
Basic	$	0.26		$	1.96
Diluted	$	0.26		$	1.96
Comprehensive income:
Net income	$	26,316		$	186,318
Other comprehensive income:
Change in fair value of investments, net of tax of $339 and ($56), respectively	1,149			(190		)
Total comprehensive income	$	27,465		$	186,128

See accompanying Notes to Condensed Consolidated Financial Statements.

5

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2019			2018
Cash flows from operating activities:
Net income	$	26,316		$	186,318
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	190,417			132,859
Asset retirement obligation	2,049			1,060
Deferred income taxes	8,073			56,949
Stock compensation	6,713			6,730
Loss (gain) on derivative instruments, net	115,452			(4,159		)
Settlements on derivative instruments	(9,051		)	(12,389		)
Loss on early extinguishment of debt	4,250			—
Amortization of debt issuance costs and discounts	719			729
Changes in non-current assets and liabilities	2,148			(900		)
Other, net	3,976			37
Changes in operating assets and liabilities:
Accounts receivable	33,976			44,722
Other current assets	350			1,603
Accounts payable and other current liabilities	(135,297		)	(30,466		)
Net cash provided by operating activities	250,091			383,093
Cash flows from investing activities:
Acquisition of Resolute Energy, net of cash acquired (Note 13)	(284,441		)	—
Oil and gas capital expenditures	(332,742		)	(323,455		)
Other capital expenditures	(17,828		)	(19,056		)
Sales of oil and gas assets	5,000			29,824
Sales of other assets	200			432
Net cash used by investing activities	(629,811		)	(312,255		)
Cash flows from financing activities:
Borrowings of long-term debt	1,182,310			—
Repayments of long-term debt	(1,553,000		)	—
Financing, underwriting, and debt redemption fees	(10,938		)	—
Finance lease payments	(635		)	—
Dividends paid	(17,179		)	(7,602		)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards	(654		)	(305		)
Proceeds from exercise of stock options	80			345
Net cash used by financing activities	(400,016		)	(7,562		)
Net change in cash and cash equivalents	(779,736		)	63,276
Cash and cash equivalents at beginning of period	800,666			400,534
Cash and cash equivalents at end of period	$	20,930		$	463,810

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

					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

See accompanying Notes to Condensed Consolidated Financial Statements.

7

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 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 marketvalue of our proved reserves or future results.

8

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

We did not recognize a ceiling test impairment during the three months ended March 31, 2019 and 2018 because the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation. If pricing conditions deteriorate, including the further widening of local market basis differentials, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. 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.

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 March 31, 2019, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a 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. 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.

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 which 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

9

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

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 March 31, 2019 and December 31, 2018 consisted of the following:

	March 31, 2019							December 31, 2018
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)			Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discount (1)			Long-term Debt, net
4.375% Notes due 2024	$	750,000	$	(4,209	)	$	745,791	$	750,000	$	(4,439	)	$	745,561
3.90% Notes due 2027	750,000		(6,831		)	743,169		750,000		(7,007		)	742,993
4.375% Notes due 2029	500,000		(5,233		)	494,767		—		—			—
	$	2,000,000	$	(16,273	)	$	1,983,727	$	1,500,000	$	(11,446	)	$	1,488,554

________________________________________

(1) At March 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.3 million and $1.6 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 March 31, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.5 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 March 31, 2019, we had no bank borrowings outstanding under the Credit Facility, leaving an unused borrowing availability of $1.25 billion.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR 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.

10

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

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

At March 31, 2019 and December 31, 2018, we had $4.9 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 occurring 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 March 31, 2019.

11

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 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 March 31, 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 March 31, 2019:

Oil Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		3,094,000		2,944,000		2,208,000		8,246,000
Weighted Avg Price - Floor	$	—	$	53.68	$	54.81	$	56.42	$	54.82
Weighted Avg Price - Ceiling	$	—	$	66.57	$	68.60	$	69.40	$	68.05
2020:
WTI (1)
Volume (Bbls)	1,456,000		728,000		—		—		2,184,000
Weighted Avg Price - Floor	$	56.13	$	52.25	$	—	$	—	$	54.83
Weighted Avg Price - Ceiling	$	70.08	$	64.31	$	—	$	—	$	68.15

________________________________________

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

12

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

Gas Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
PEPL (1)
Volume (MMBtu)	—		13,650,000		11,040,000		8,280,000		32,970,000
Weighted Avg Price - Floor	$	—	$	2.03	$	1.94	$	1.94	$	1.98
Weighted Avg Price - Ceiling	$	—	$	2.39	$	2.32	$	2.37	$	2.36
Perm EP (2)
Volume (MMBtu)	—		8,190,000		6,440,000		3,680,000		18,310,000
Weighted Avg Price - Floor	$	—	$	1.67	$	1.49	$	1.40	$	1.55
Weighted Avg Price - Ceiling	$	—	$	1.95	$	1.79	$	1.73	$	1.85
Waha (3)
Volume (MMBtu)	—		3,640,000		5,520,000		5,520,000		14,680,000
Weighted Avg Price - Floor	$	—	$	1.41	$	1.48	$	1.48	$	1.46
Weighted Avg Price - Ceiling	$	—	$	1.73	$	1.82	$	1.82	$	1.80
2020:
PEPL (1)
Volume (MMBtu)	5,460,000		2,730,000		—		—		8,190,000
Weighted Avg Price - Floor	$	1.96	$	1.95	$	—	$	—	$	1.96
Weighted Avg Price - Ceiling	$	2.38	$	2.26	$	—	$	—	$	2.34
Perm EP (2)
Volume (MMBtu)	1,820,000		910,000		—		—		2,730,000
Weighted Avg Price - Floor	$	1.45	$	1.50	$	—	$	—	$	1.47
Weighted Avg Price - Ceiling	$	1.92	$	2.13	$	—	$	—	$	1.99
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

________________________________________

(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.

13

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

Oil Basis Swaps	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2019:
WTI Midland (1)
Volume (Bbls)	—			3,685,500			3,266,000			2,530,000			9,481,500
Weighted Avg Differential (2)	$	—		$	(6.51	)	$	(7.36	)	$	(8.36	)	$	(7.30	)
2020:
WTI Midland (1)
Volume (Bbls)	1,001,000			637,000			—			—			1,638,000
Weighted Avg Differential (2)	$	(0.16	)	$	(0.40	)	$	—		$	—		$	(0.26	)

________________________________________

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

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

Oil Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		455,000		460,000		460,000		1,375,000
Weighted Avg Price	$	—	$	64.54	$	64.54	$	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)	—		3,185,000		3,220,000		3,220,000		9,625,000
Weighted Avg Price	$	—	$	3.00	$	3.00	$	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)	—		333,970		337,640		337,640		1,009,250
Weighted Avg Call Price	$	—	$	64.36	$	64.36	$	64.36	$	64.36

________________________________________

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

14

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

The following table summarizes our derivative contracts entered into subsequent to March 31, 2019 through May 7, 2019:

Oil Basis Swaps	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
WTI Midland (1)
Volume (Bbls)	364,000			—		—		—		364,000
Weighted Avg Differential (2)	$	(0.03	)	$	—	$	—	$	—	$	(0.03	)

________________________________________

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

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

Derivative Gains and Losses

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

	Three Months Ended March 31,
(in thousands)	2019			2018
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts	$	(9,846	)	$	(11,789	)
Oil contracts	116,247			(4,759		)
	106,401			(16,548		)
Cash (receipts) payments on derivative instruments, net:
Gas contracts	3,764			(5,119		)
Oil contracts	5,287			17,508
	9,051			12,389
Loss (gain) on derivative instruments, net	$	115,452		$	(4,159	)

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.

15

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

The following tables present the amounts and classifications of our derivative assets and liabilities as of March 31, 2019 and December 31, 2018, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.

		March 31, 2019
(in thousands)	Balance Sheet Location	Asset			Liability
Oil contracts	Current assets — Derivative instruments	$	19,328		$	—
Gas contracts	Current assets — Derivative instruments	16,502			—
Oil contracts	Non-current assets — Derivative instruments	222			—
Gas contracts	Non-current assets — Derivative instruments	404			—
Oil contracts	Current liabilities — Derivative instruments	—			73,517
Gas contracts	Current liabilities — Derivative instruments	—			4,040
Oil contracts	Non-current liabilities — Derivative instruments	—			749
Gas contracts	Non-current liabilities — Derivative instruments	—			7
Total gross amounts presented in the balance sheet		36,456			78,313
Less: gross amounts not offset in the balance sheet		(26,283		)	(26,283		)
Net amount		$	10,173		$	52,030
		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. 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.

16

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

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

	March 31, 2019						December 31, 2018
(in thousands)	Book Value			Fair Value			Book Value			Fair Value
Financial Assets (Liabilities):
4.375% Notes due 2024	$	(750,000	)	$	(779,340	)	$	(750,000	)	$	(744,578	)
3.90% Notes due 2027	$	(750,000	)	$	(748,620	)	$	(750,000	)	$	(701,273	)
4.375% Notes due 2029	$	(500,000	)	$	(514,380	)	$	—		$	—
Derivative instruments — assets	$	36,456		$	36,456		$	111,185		$	111,185
Derivative instruments — liabilities	$	(78,313	)	$	(78,313	)	$	(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 their last traded value before period end. The fair value of our derivative instruments (Level 2) was estimated using option pricing models. These models use certain variables including forward price and volatility curves and the strike prices for the instruments. 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 March 31, 2019 were accrued operating expenses of approximately $84.0 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 March 31, 2019 and December 31, 2018, the allowance for doubtful accounts was $2.7 million and $2.7 million, respectively.

5. CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At March 31, 2019, there were 101.4 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

17

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

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 will be payable quarterly in arrears and shall 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 February 2019, our Board of Directors declared a cash dividend of $0.20 per share of common stock. The dividend is payable on or before May 31, 2019 to stockholders of record on May 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 $20.3 million dividend declared during the first 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 March 2019, our Board of Directors declared a cash dividend of $20.31 per share of Convertible Preferred Stock. The dividend was paid in April to stockholders of record on April 1, 2019. The $1.3 million dividend declared during the first 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.

18

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

6. STOCK-BASED COMPENSATION

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

	Three Months Ended March 31,
(in thousands)	2019			2018
Restricted stock awards:
Performance stock awards	$	5,394		$	6,729
Service-based stock awards	7,231			5,072
	12,625			11,801
Stock option awards	622			617
Total stock compensation cost	13,247			12,418
Less amounts capitalized to oil and gas properties	(6,534		)	(5,688		)
Stock compensation expense	$	6,713		$	6,730

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. 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 three months ended March 31, 2019:

(in thousands)	Three Months Ended March 31, 2019
Asset retirement obligation at January 1, 2019	$	166,904
Liabilities incurred	10,009
Liability settlements and disposals	(1,361		)
Accretion expense	1,793
Revisions of estimated liabilities	1,912
Asset retirement obligation at March 31, 2019	179,257
Less current obligation	(13,728		)
Long-term asset retirement obligation	$	165,529

For the three months ended March 31, 2019, liabilities incurred included $9.4 million for the Resolute acquisition.

19

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

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 March 31,
	2019						2018
(in thousands, except per share information)	Income (Numerator)			Shares (Denominator)	Per-Share Amount		Income (Numerator)			Shares (Denominator)	Per-Share Amount
Net income	$	26,316					$	186,318
Less: net income attributable to participating securities	(445		)				(2,666		)
Less: preferred stock dividends	(1,269		)				—
Basic earnings per share
Income available to common stockholders	24,602			95,922	$	0.26	183,652			93,699	$	1.96
Effects of dilutive securities (1)
Options	—			10			—			38
Diluted earnings per share
Income available to common stockholders and assumed conversions	$	24,602		95,932	$	0.26	$	183,652		93,737	$	1.96

________________________________________

(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 March 31, 2019 calculation were 388.6 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 March 31, 2018 calculation were 295.6 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 March 31,
(in thousands)	2019			2018
Deferred tax expense	$	8,073		$	56,949
Combined federal and state effective income tax rate	23.5		%	23.4		%

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

20

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

assets. The net deferred tax liability includes certain deferred tax assets net of valuation allowances. The acquired tax attributes include federal net operating loss, capital loss, and enhanced oil recovery tax credit carryforwards. The carryforwards are subject to an annual limitation under Internal Revenue Code Section 382.

At March 31, 2019, we had no unrecognized tax benefits that would impact our effective tax rate and have made no provisions for interest or penalties related to uncertain tax positions. The tax years 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 2015 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 March 31, 2019, these leases had remaining lease terms ranging from 5.2 to 7.4 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

21

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 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 March 31, 2019, these leases had remaining lease terms ranging from one month to 11.3 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.

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 March 31, 2019, this lease had a remaining term of 6.4 years.

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.

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 March 31, 2019, these leases had remaining lease terms of 12 months or less. These leases typically require us to make payments in amounts based on the usage of the underlying equipment. These leases do not contain residual value guarantees, options to purchase the underlying equipment, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of exploration and development-related equipment.

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

22

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

Balance Sheet Presentation

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

(in thousands)	Balance Sheet Location	March 31, 2019
Operating lease right-of-use assets	Non-current assets — Fixed assets, net	$	233,644
Finance lease right-of-use assets	Non-current assets — Other assets	28,138
Total right-of-use assets		$	261,782

(in thousands)	Balance Sheet Location	March 31, 2019
Operating lease liabilities — current	Current liabilities — Operating leases	$	62,825
Operating lease liabilities — non-current	Non-current liabilities — Operating leases	186,356
Finance lease liability — current	Current liabilities — Accrued liabilities-Other	5,936
Finance lease liability — non-current	Non-current liabilities — Other liabilities	23,500
Total lease liabilities		$	278,617

Lease Cost and Cash Flows

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

(in thousands)	Three Months Ended March 31, 2019
Finance lease cost:
Amortization of right-of-use asset	$	1,096
Interest on lease liability	486
Operating lease cost: (1)
Production expense	3,834
Gas gathering and other expense	6,164
General and administrative expense	2,299
Short-term lease cost (2)	154,710
Total lease cost	$	168,589

________________________________________

(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.

23

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

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

(in thousands)	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash outflows from finance lease	$	635
Operating cash outflows from operating leases	$	12,493
Cash paid for short-term leases and variable lease payments:
Investing cash outflows from operating leases	$	139,473

During the three months ended March 31, 2019, we recognized $16.2 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:

	March 31, 2019
Weighted-average remaining lease term (in years):
Finance lease	6.4
Operating leases	4.7
Weighted-average discount rate:
Finance lease	6.7	%
Operating leases	4.1	%

The following table reflects the undiscounted future cash flows utilized in the calculation of the lease liabilities recorded at March 31, 2019:

	March 31, 2019
(in thousands)	Operating Leases			Finance Lease
April 1, 2019 — March 31, 2020	$	71,895		$	6,808
April 1, 2020 — March 31, 2021	59,020			5,950
April 1, 2021 — March 31, 2022	53,649			5,658
April 1, 2022 — March 31, 2023	45,801			5,366
April 1, 2023 — March 31, 2024	21,665			5,075
Remaining periods	21,836			6,690
Total undiscounted future cash flows	273,866			35,547
Less effects of discounting	(24,685		)	(6,111		)
Lease liabilities recognized	$	249,181		$	29,436

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 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 March 31, 2019, we had estimated commitments of approximately: (i) $447.9 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $36.3 million to finish gathering system construction in progress.

At March 31, 2019, we had firm sales contracts to deliver approximately 456.4 Bcf of gas over the next 5.8 years. If we do not deliver this gas, our estimated financial commitment, calculated using the April 2019 index price, would be approximately $461.3 million. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next 9.8 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 March 31, 2019, would be approximately $662.7 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of March 31, 2019, would be approximately $55.5 million. Of this total, we have accrued a liability of $2.7 million, representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.

At March 31, 2019, we have various firm transportation agreements for gas pipeline capacity with end dates ranging from 2019 - 2025 under which we will have to pay an estimated $25.6 million over the remaining terms of the agreements. These agreements were entered into to support our residue gas 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

25

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 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 March 31,
(in thousands)	2019		2018
Cash paid during the period for:
Interest (net of capitalized amounts of $740 and $156, respectively) (1)	$	18,588	$	389
Income taxes	$	6	$	—
Cash received for income tax refunds	$	1	$	2

________________________________________

(1) 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 $24.5 million and $23.6 million related to these services during the three months ended March 31, 2019 and 2018, respectively. 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 the acquired 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 the acquired 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.

26

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

Preliminary Purchase Price Allocation

The Resolute acquisition has been accounted for as a business combination, using the acquisition method. The following table represents 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. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, ultimate settlement of 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
Cash	$	41,236
Accounts receivable	50,739
Other current assets	13,280
Proved oil and gas properties	692,600
Unproved oil and gas properties	1,054,200
Fixed assets	5,355
Goodwill	107,341
Other assets	142
Current liabilities	(202,735		)
Long-term debt	(870,000		)
Deferred income taxes	(62,409		)
Asset retirement obligation	(9,437		)
Total identifiable net assets	$	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 $107.3 million has been recognized principally as a result of recording net deferred tax liabilities arising from the difference between the tax basis and the purchase price allocated to Resolute’s assets and liabilities, and anticipated opportunities for cost savings through administrative and operational synergies. Goodwill is not expected to be deductible for tax purposes.

Acquisition-related costs incurred in 2019 were $8.3 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.

27

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

March 31, 2019

(Unaudited)

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 March 31, 2019 is $24.2 million and $5.3 million, respectively.

Pro Forma Financial Information

The following supplemental pro forma information for the three month periods ended March 31, 2019 and 2018 has been prepared to give effect to the Resolute acquisition as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of the combined company’s proved oil and gas properties, (ii) the capitalization of interest expense, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by Cimarex of $8.3 million and transaction-related costs incurred by Resolute of $60.0 million, for the three months ended March 31, 2019. 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 March 31,
(in thousands)	2019		2018
Revenue	$	630,093	$	638,078
Net income	$	12,617	$	187,079
Net income per share:
Basic	$	0.11	$	1.84
Diluted	$	0.11	$	1.84

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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 increasing 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 the acquired 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 the acquired 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.

Market prices for oil have declined and market prices for gas have increased during the first three months of 2019 as compared to the first three months of 2018. For the 2019 period, average NYMEX oil and gas prices were $54.90 per barrel and $3.15 per Mcf, respectively, representing a decrease of 13% and an increase of 5%, respectively, from the average NYMEX oil and gas prices for the 2018 period. Local market prices for oil and gas can be impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials. Oil and gas production growth and pipeline constraints in the Permian Basin resulted in higher basis differentials and, therefore, lower realized prices. These factors and lower realized prices have continued beyond March 31, 2019. The average prices per barrel of oil and Mcf of gas that we realized were less than the WTI Cushing and Henry Hub indices by the amounts shown in the table below for the periods indicated.

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	Average Price Differentials
	First Quarter 2019		First Quarter 2018
Permian Basin oil	$	6.90	$	3.12
Mid-Continent oil	$	2.17	$	2.34
Permian Basin gas	$	1.91	$	0.78
Mid-Continent gas	$	0.46	$	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, 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. See RESULTS OF OPERATIONS Revenues below for further information regarding our realized commodity prices.

See “Risk Factors” in Item 1A of 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.

Summary of Operating and Financial Results for the Three Months EndedMarch 31, 2019 Compared to the Three Months EndedMarch 31, 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 26% to 258.9 MBOE per day.

• Oil volumes increased 22% to 79.4 MBbls per day.

• Gas volumes increased 20% to 639.1 MMcf per day.

• NGL volumes increased 41% to 73.0 MBbls per day.

• Total production revenue increased 2% to $567.2 million.

• Cash flow provided by operating activities decreased 35% to $250.1 million.

• Exploration and development expenditures increased 17% to $368.0 million.

• Net income was $26.3 million, or $0.26 per diluted share, for the first three months of 2019, as compared to net income of $186.3 million, or $1.96 per diluted share, for the first three months of 2018.

RESULTS OF OPERATIONS

Three Months Ended March 31, 2019 vs. Three Months Ended March 31, 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

30

fluctuations.

Production volumes were higher for all products during the three months ended March 31, 2019 as compared to the three months ended March 31, 2018, while realized prices were lower. Our revenue increased 2%, or $11.8 million, during the three months ended March 31, 2019 as compared to the three months ended March 31, 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.

	Three Months Ended March 31,				Variance Between 2019 / 2018				Price/Volume Variance
Production Revenue (in thousands)	2019		2018						Price			Volume		Total
Oil sales	$	349,306	$	351,723	$	(2,417	)	(1)%	$	(79,050	)	$	76,633	$	(2,417	)
Gas sales	109,976		109,721		255			—%	(21,281		)	21,536		255
NGL sales	107,939		93,997		13,942			15%	(24,623		)	38,565		13,942
	$	567,221	$	555,441	$	11,780		2%	$	(124,954	)	$	136,734	$	11,780

The table below presents our production volumes by region.

	Three Months Ended March 31,
Production Volumes	2019	2018
Oil (Bbls per day)
Permian Basin	64,969	49,845
Mid-Continent	14,224	15,225
Other	222	142
	79,415	65,212
Gas (MMcf per day)
Permian Basin	340.6	237.9
Mid-Continent	297.2	295.5
Other	1.3	1.3
	639.1	534.7
NGL (Bbls per day)
Permian Basin	46,273	24,725
Mid-Continent	26,630	26,959
Other	53	35
	72,956	51,719
Total (BOE per day)
Permian Basin	168,008	114,218
Mid-Continent	90,386	91,433
Other	488	399
	258,882	206,050

Our total production increased 26%, or 52,832 BOE per day, during the three months ended March 31, 2019, as compared to the three months ended March 31, 2018. This increase was the result of our ongoing drilling and completion activity, as well as due to our acquisition of Resolute. See LIQUIDITY AND CAPITAL RESOURCES Capital Expendituresfor information on our capital expenditures.

31

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 months ended March 31, 2019, approximately 82% of our oil production was in the Permian Basin, up from approximately 76% during the three months ended March 31, 2018. Our realized prices do not include settlements of commodity derivative contracts.

	Three Months Ended March 31,						Variance Between 2019 / 2018
	2019			2018
Oil
Total volume — MBbls	7,147			5,869			22%
Total volume — MBbls per day	79.4			65.2			22%
Percentage of total production	31		%	32		%
Average realized price — per barrel	$	48.87		$	59.93		(18)%
Average WTI Midland price — per barrel	$	50.97		$	63.26		(19)%
Average WTI Cushing price — per barrel	$	54.90		$	62.87		(13)%
Gas
Total volume — MMcf	57,516			48,125			20%
Total volume — MMcf per day	639.1			534.7			20%
Percentage of total production	41		%	43		%
Average realized price — per Mcf	$	1.91		$	2.28		(16)%
Average Henry Hub price — per Mcf	$	3.15		$	3.01		5%
NGL
Total volume — MBbls	6,566			4,655			41%
Total volume — MBbls per day	73.0			51.7			41%
Percentage of total production	28		%	25		%
Average realized price — per barrel	$	16.44		$	20.19		(19)%
Total
Total production — MBOE	23,299			18,545			26%
Total production — MBOE per day	258.9			206.1			26%
Average realized price — per BOE	$	24.34		$	29.95		(19)%

32

Other revenues

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

	Three Months Ended March 31,					Variance Between 2019 / 2018
Gas Gathering and MarketingRevenues (in thousands)	2019			2018
Gas gathering and other	$	10,262		$	11,452	$	(1,190	)
Gas marketing	$	(526	)	$	241	$	(767	)

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, others 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 March 31, 2019 were higher by 67%, or $212.4 million, compared to the three months ended March 31, 2018.  The primary reasons for the increase were: (i) the $119.6 million increase in net losses on derivative instruments and (ii) the $57.6 million increase in depreciation, depletion, and amortization. 

	Three Months Ended March 31,					Variance Between 2019 / 2018			Per BOE
Operating Costs and Expenses (in thousands, except per BOE)	2019		2018						2019		2018
Depreciation, depletion, and amortization	$	190,417	$	132,859		$	57,558		$	8.17	$	7.16
Asset retirement obligation	2,049		1,060			989			$	0.09	$	0.06
Production	77,233		71,271			5,962			$	3.31	$	3.84
Transportation, processing, and other operating	53,608		45,165			8,443			$	2.30	$	2.44
Gas gathering and other	12,320		9,823			2,497			$	0.53	$	0.53
Taxes other than income	33,694		30,188			3,506			$	1.45	$	1.63
General and administrative	29,084		23,321			5,763			$	1.25	$	1.26
Stock compensation	6,713		6,730			(17		)	$	0.29	$	0.36
Loss (gain) on derivative instruments, net	115,452		(4,159		)	119,611			N/A		N/A
Other operating expense, net	8,326		203			8,123			N/A		N/A
	$	528,896	$	316,461		$	212,435

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

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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, and reserves have increased for the three months ended March 31, 2019 as compared to the three months ended March 31, 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. Specifically, the depreciation of our finance lease gathering system right-of-use asset is included in our depreciation expense. The increase in depreciation expense during the three months ended March 31, 2019 as compared to the three months ended March 31, 2018 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 March 31,				Variance Between 2019 / 2018		Per BOE
DD&A Expense(in thousands, except per BOE)	2019		2018				2019		2018
Depletion	$	174,712	$	120,390	$	54,322	$	7.50	$	6.49
Depreciation	15,705		12,469		3,236		0.67		0.67
	$	190,417	$	132,859	$	57,558	$	8.17	$	7.16

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 March 31,				Variance Between 2019 / 2018		Per BOE
Production Expense(in thousands, except per BOE)	2019		2018				2019		2018
Lease operating expense	$	62,408	$	60,476	$	1,932	$	2.68	$	3.26
Workover expense	14,825		10,795		4,030		0.63		0.58
	$	77,233	$	71,271	$	5,962	$	3.31	$	3.84

Lease operating expense in the first quarter 2019increased3%, or $1.9 million, compared to the first quarter of 2018. The increases have primarily stemmed from the Resolute acquisition and the addition of new wells as a result of our ongoing exploration and development activities. These increases were partially offset by expense reductions related to the sale of non-core properties principally located in Ward County, Texas in August 2018. Additional wells and increased production have primarily increased the following types of expenses between the two quarters: (i) saltwater disposal, (ii) labor, and (iii) equipment rental.

Workover expense in the first quarter 2019 increased 37%, or $4.0 million, compared to the first quarter of 2018. During the three months ended March 31, 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.

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Transportation, Processing, and Other Operating

Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, including gathering, fuel, compression, and processing costs. Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs. Transportation, processing, and other operating costs in the first quarter 2019 were 19%, or $8.4 million, higher than the same costs in the first quarter 2018. The increase in expense is due to our increased production volumes, offset slightly by lower rates. Our production volumes increased by 26% during the three months ended March 31, 2019 as compared to the three months ended March 31, 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 March 31, 2019 was 25%, or $2.5 million, higher than gas gathering and other in the three months ended March 31, 2018. The increase is 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.  Production taxes make up the majority of this expense for us, with revenue-based production taxes being the largest component of these taxes.  Taxes other than income increased$3.5 million, or 12%, in the first quarter of 2019 as compared to the first quarter of 2018. Production taxes increased by $4.0 million in the first quarter of 2019 as compared to the first quarter of 2018 due to increased production volumes and revenues, however, this increase in expense was nearly offset by an increase of $3.3 million in credits for tax refunds, generally for high-cost gas wells in the State of Texas. Ad valorem taxes increased by $2.9 million in the first quarter of 2019 as compared to the first quarter of 2018 due to the addition of new wells as a result of ongoing drilling activities. Taxes other than income was 5.9% and 5.4% of production revenues for the three months ended March 31, 2019 and 2018, respectively.

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 41% to 43% during the periods presented in the table below, which shows our G&A costs.

	Three Months Ended March 31,						Variance Between 2019 / 2018
General and Administrative Expense(in thousands)	2019			2018
Gross G&A	$	49,236		$	40,848		$	8,388
Less amounts capitalized to oil and gas properties	(20,152		)	(17,527		)	(2,625		)
G&A expense	$	29,084		$	23,321		$	5,763

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G&A expense for the first quarter of 2019 was 25%, or $5.8 million, higher than G&A expense for the first quarter of 2018. This increase was primarily due to increased employee-related costs. Included in the increase is $2.6 million of severance 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 March 31,						Variance Between 2019 / 2018
Stock Compensation Expense(in thousands)	2019			2018
Restricted stock awards:
Performance stock awards	$	5,394		$	6,729		$	(1,335	)
Service-based stock awards	7,231			5,072			2,159
	12,625			11,801			824
Stock option awards	622			617			5
Total stock compensation cost	13,247			12,418			829
Less amounts capitalized to oil and gas properties	(6,534		)	(5,688		)	(846		)
Stock compensation expense	$	6,713		$	6,730		$	(17	)

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.  

Loss (Gain) on Derivative Instruments, Net

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

	Three Months Ended March 31,						Variance Between 2019 / 2018
Loss (Gain) on Derivative Instruments, Net (in thousands)	2019			2018
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts	$	(9,846	)	$	(11,789	)	$	1,943
Oil contracts	116,247			(4,759		)	121,006
	106,401			(16,548		)	122,949
Cash (receipts) payments on derivative instruments, net:
Gas contracts	3,764			(5,119		)	8,883
Oil contracts	5,287			17,508			(12,221		)
	9,051			12,389			(3,338		)
Loss (gain) on derivative instruments, net	$	115,452		$	(4,159	)	$	119,611

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Other Operating Expense, Net

Other operating expense, net during the three months ended March 31, 2019 was comprised primarily of $8.3 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 Income and Expense

	Three Months Ended March 31,						Variance Between 2019 / 2018
Other Income and Expense(in thousands)	2019			2018
Interest expense	$	20,405		$	16,783		$	3,622
Capitalized interest	(8,742		)	(4,810		)	(3,932		)
Loss on early extinguishment of debt	4,250			—			4,250
Other, net	(2,241		)	(4,567		)	2,326
	$	13,672		$	7,406		$	6,266

The majority of our interest expense relates to interest on our senior unsecured notes. Also included in interest expense is the amortization of debt issuance costs and discounts as well as miscellaneous interest expense.  See LIQUIDITY AND CAPITAL RESOURCES Long-term Debt below for further information regarding our debt. The increase in interest expense in 2019 as compared to 2018 is primarily due to (i) the March 8, 2019 issuance of $500 million aggregate principal amount of 4.375% senior unsecured notes due March 15, 2029 at 99.862% of par to yield 4.392% per annum, (ii) Credit Facility borrowings we had outstanding to help fund the Resolute acquisition, and (iii) interest expense on our finance lease. The $4.3 million loss on early extinguishment of debt incurred during the three months ended March 31, 2019 was associated with the $600 million of 8.5% senior notes we acquired with Resolute and elected to immediately repay. The maturity date of the Resolute notes was May 1, 2020.

We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing 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 months ended March 31, 2019 as compared to the three months ended March 31, 2018, primarily due to the Resolute acquisition, which increased our non-producing leasehold costs by $1.05 billion. Additionally, our average interest rate on borrowings outstanding was higher during the 2019 period as compared to the 2018 period due to the debt issuance discussed above.

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 March 31,						Variance Between 2019 / 2018
Income Tax Expense (in thousands)	2019			2018
Deferred tax expense	$	8,073		$	56,949		$	(48,876	)
Combined federal and state effective income tax rate	23.5		%	23.4		%

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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 deal with 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 $1.35 billion to $1.45 billion. Investments in gathering, processing, and other infrastructure are projected to be an additional $60 million to $70 million for 2019. See Capital Expenditures below for information regarding our E&D activities for the three months ended March 31, 2019 and 2018.

We periodically use derivative instruments to mitigate volatility in commodity prices. At March 31, 2019, we had derivative contracts covering a portion of our 2019 - 2020 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 March 31, 2019 were $20.9 million. At March 31, 2019, our long-term debt consisted of $2.0 billion of senior unsecured notes, with $750 million4.375% notes due in 2024, $750 million3.90% notes due in 2027, and $500 million4.375% notes due in 2029. At March 31, 2019, we had no borrowings outstanding under our credit facility, leaving an unused borrowing availability of $1.25 billion. See Long-term Debt below for more information regarding our debt.

Our debt to total capitalization ratio at March 31, 2019 was 36%, up from 31% at December 31, 2018. This ratio is calculated by dividing the sum of (i) the principal amount of senior notes and (ii) redeemable preferred stock by the sum of (i) the principal amount of senior notes, (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.

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Analysis of Cash Flow Changes

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

	Three Months Ended March 31,
(in thousands)	2019			2018
Net cash provided by operating activities	$	250,091		$	383,093
Net cash used by investing activities	$	(629,811	)	$	(312,255	)
Net cash used by financing activities	$	(400,016	)	$	(7,562	)

Net cash provided by operating activities for the three months ended March 31, 2019 was $250.1 million, down $133.0 million, or 35%, from $383.1 million for the three months ended March 31, 2018. The $133.0 million decrease resulted primarily from increased cash outflows related to changes in working capital. Also contributing to the decrease was an increase in operating costs and expenses. Increased revenues and decreased cash outflows for settlements of derivative instruments partially offset the overall decrease in net cash provided by operating activities. See RESULTS OF OPERATIONS above for more information regarding the changes in revenue and operating expenses.

Net cash used by investing activities for the three months ended March 31, 2019 and 2018 was $629.8 million and $312.3 million, respectively. The majority of our cash flows used by investing activities are for E&D expenditures, which totaled $332.7 million and $323.5 million for the three months ended March 31, 2019 and 2018, respectively. Cash used by investing activities in the three months ended March 31, 2019 includes the $325.7 million in cash paid for the Resolute acquisition, net of the $41.2 million in cash acquired with Resolute. The remaining investing cash outflows are primarily for midstream asset expenditures. Included in net cash used by investing activities are the proceeds of miscellaneous asset sales, including non-core oil and gas properties.

Net cash used by financing activities was $400.0 million and $7.6 million during the three months ended March 31, 2019 and 2018, respectively. During the three months ended March 31, 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 $3.7 million in underwriting fees and financing costs. Additionally, we borrowed and repaid $683.0 million on our credit facility during the three months ended March 31, 2019 to assist in funding the Resolute acquisition. During the three months ended March 31, 2019, we amended our credit facility, paying $2.9 million in financing costs. 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. Net cash used by financing activities during both periods included: (i) the payment of dividends on our common stock, (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 three months ended March 31, 2019, we paid an $0.18 per share dividend on our common stock totaling $17.2 million, and during the three months ended March 31, 2018, we paid an $0.08 per share dividend on our common stock totaling $7.6 million. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

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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 March 31,
(in thousands)	2019			2018
Acquisitions:
Proved	$	692,600		$	62
Unproved	1,050,782			2,159
	1,743,382			2,221
Exploration and development:
Land and seismic	9,527			10,097
Exploration and development	358,491			303,372
	368,018			313,469
Property sales:
Proved	4,030			(24,964		)
Unproved	(3,501		)	(4,860		)
	529			(29,824		)
	$	2,111,929		$	285,866

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 area of the Permian Basin of west Texas. The fair value of the proved and unproved properties added through this acquisition was $692.6 million and $1.05 billion, respectively.

Our 2019 E&D capital investment is projected to range from $1.35 billion to $1.45 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.

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

	Three Months Ended March 31,
	2019	2018
Gross wells
Permian Basin	12	17
Mid-Continent	26	37
	38	54
Net wells
Permian Basin	5	9
Mid-Continent	3	6
	8	15

As of March 31, 2019, we had 33 gross (9 net) wells in the process of being drilled: 19 gross (7 net) in the Permian Basin and 14 gross (2 net) in the Mid-Continent region. As of March 31, 2019, there were 131 gross (52 net) wells waiting on completion: 56 gross (40 net) in the Permian Basin and 75 gross (12 net) in the Mid-Continent region. As of March 31, 2019, we had 9 operated rigs running: 8 in the Permian Basin and 1 in the Mid-Continent region.

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.

Long-term Debt

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

	March 31, 2019							December 31, 2018
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)			Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discount (1)			Long-term Debt, net
4.375% Notes due 2024	$	750,000	$	(4,209	)	$	745,791	$	750,000	$	(4,439	)	$	745,561
3.90% Notes due 2027	750,000		(6,831		)	743,169		750,000		(7,007		)	742,993
4.375% Notes due 2029	500,000		(5,233		)	494,767		—		—			—
	$	2,000,000	$	(16,273	)	$	1,983,727	$	1,500,000	$	(11,446	)	$	1,488,554

________________________________________

(1) At March 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.3 million and $1.6 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 March 31, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.5 million and $0.7 million, respectively. The 4.375% Notes due 2024 were issued at par.

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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 March 31, 2019, we had no bank borrowings outstanding under the Credit Facility, leaving an unused borrowing availability of $1.25 billion.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR 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 March 31, 2019, we were in compliance with all of the financial covenants.

At March 31, 2019 and December 31, 2018, we had $4.9 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 occurring 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 March 31, 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 March 31, 2019, we had a working capital deficit of $313.7 million, a decrease of $1.03 billion or 144% from a working capital surplus of $715.4 million at December 31, 2018.

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Our working capital decreased primarily due to the decrease in Cash and cash equivalents of $779.7 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 decreases: 

• Our net current derivative instrument position decreased by $116.0 million from an asset at December 31, 2018 to a liability at March 31, 2019.

• The adoption of Topic 842 increased our current liabilities by $68.8 million, representing 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.

• Accrued liabilities related to our E&D expenditures increased by $59.3 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 February 2019, our Board of Directors declared a $0.20 per common share dividend, totaling $20.3 million, which is payable on or before May 31, 2019 to stockholders of record on May 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 March 2019, our Board of Directors declared a cash dividend of $20.31 per preferred share, totaling $1.3 million. The dividend was paid in April to preferred stockholders of record on April 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.

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 March 31, 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.

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Contractual Obligations and Material Commitments

At March 31, 2019, we had the following contractual obligations and material commitments:

	Payments Due by Period
Contractual obligations (in thousands)	Total		4/1/19 - 3/31/20		4/1/20 - 3/31/22			4/1/22 - 3/31/24			4/1/24 and Thereafter
Long-term debt—principal (1)	$	2,000,000	$	—	$	—		$	—		$	2,000,000
Long-term debt—interest (1)	648,344		82,307		167,875			167,875			230,287
Operating leases (2)	105,058		24,404		40,015			22,716			17,923
Unconditional purchase obligations (3)	58,274		22,874		23,898			6,901			4,601
Derivative liabilities	78,313		77,557		756			—			—
Asset retirement obligation (4)	179,257		13,728		—		(4)	—		(4)	—		(4)
Other long-term liabilities (5)	39,631		2,623		3,237			5,182			28,589
	$	3,108,877	$	223,493	$	235,781		$	202,674		$	2,281,400

________________________________________

(1) The interest payments presented above include the accrued interest payable on our long-term debt as of March 31, 2019 as well as future payments calculated using the long-term debt’s fixed rates, stated maturity dates, and principal amounts outstanding as of March 31, 2019. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.

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

(3) Of the total unconditional purchase obligations, $32.1 million represents obligations for the purchase of sand for well completions and $25.6 million represents obligations for firm transportation agreements for gas pipeline capacity.

(4) We have excluded the presentation of the timing of the cash flows associated with our 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.

At March 31, 2019, we had estimated commitments of approximately: (i) $447.9 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $36.3 million to finish gathering system construction in progress.

At March 31, 2019, we had firm sales contracts to deliver approximately 456.4 Bcf of gas over the next 5.8 years. If we do not deliver this gas, our estimated financial commitment, calculated using the April 2019 index price, would be approximately $461.3 million. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

44

In connection with gas gathering and processing agreements, we have volume commitments over the next 9.8 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 March 31, 2019, would be approximately $662.7 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of March 31, 2019, would be approximately $55.5 million. Of this total, we have accrued a liability of $2.7 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.

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 March 31, 2019, our total production revenue was comprised of 62% oil sales, 19% gas sales, and 19% 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 March 31, 2019
			(in thousands)
Oil	± $1.00	per barrel	± $7,147
Gas	± $0.10	per Mcf	± $5,752
NGL	± $1.00	per barrel	± $6,566
			± $19,465

45

We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. At March 31, 2019, we had oil and gas derivatives covering a portion of our 2019 and 2020 production, which were recorded as current and non-current assets and liabilities. At March 31, 2019, our oil and gas derivatives had a gross asset fair value of $36.5 million and a gross liability fair value of $78.3 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 March 31, 2019.

		Impact on Fair Value
	Change in Forward Price	March 31, 2019
		(in thousands)
Oil	-$1.00	$	6,991
Oil	+$1.00	$	(7,106	)
Gas	-$0.10	$	6,444
Gas	+$0.10	$	(6,797	)

Interest Rate Risk

At March 31, 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 March 31, 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 March 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

46

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. There have been no material changes in our risk factors from those described in the 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.

ITEM 6. EXHIBITS

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).
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
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

47

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.

May 10, 2019
	CIMAREX ENERGY CO.
	/s/ G. Mark Burford
	G. Mark Burford
	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)

48

EX-31.1

Exhibit 31.1

I, Thomas E. Jorden, certify that:

1) I have reviewed this quarterly report on Form 10-Q of Cimarex Energy Co.;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance  with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5) The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: May 10, 2019
	/s/ Thomas E. Jorden
	Name:	Thomas E. Jorden
	Title:	Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

I, G. Mark Burford, certify that:

1) I have reviewed this quarterly report on Form 10-Q of Cimarex Energy Co.;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance  with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5) The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: May 10, 2019
	/s/ G. Mark Burford
	Name:	G. Mark Burford
	Title:	Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification

Pursuant to 18 U.S.C. § 1350, the undersigned officer of Cimarex Energy Co. (the Company), hereby certifies, to such officer’s knowledge, that the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2019 (the Report) fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: May 10, 2019
	/s/ Thomas E. Jorden
	Name:	Thomas E. Jorden
	Title:	Chairman, President and Chief Executive Officer

The foregoing certification is being furnished solely pursuant to 18 U.S.C. § 1350 and is not being filed as a separate disclosure document.

EX-32.2

Exhibit 32.2

Certification

Pursuant to 18 U.S.C. § 1350, the undersigned officer of Cimarex Energy Co. (the Company), hereby certifies, to such officer’s knowledge, that the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2019 (the Report) fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: May 10, 2019
	/s/ G. Mark Burford
	Name:	G. Mark Burford
	Title:	Vice President and Chief Financial Officer

The foregoing certification is being furnished solely pursuant to 18 U.S.C. § 1350 and is not being filed as a separate disclosure document.

XML

DOCUMENT AND ENTITY INFORMATION - shares	3 Months Ended
	Mar. 31, 2019	Apr. 30, 2019
Document And Entity Information [Abstract]
Entity Registrant Name	CIMAREX ENERGY CO
Entity Central Index Key	0001168054
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Emerging Growth Company	false
Small Business	false
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus (i.e. Q1,Q2,Q3,FY)	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		101,433,207

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 20,930	$ 800,666
Accounts receivable, net of allowance:
Trade	123,192	122,065
Oil and gas sales	329,661	315,063
Gas gathering, processing, and marketing	13,049	17,072
Oil and gas well equipment and supplies	62,600	55,553
Derivative instruments	35,830	101,939
Prepaid expenses	8,135	7,554
Other current assets	2,811	4,227
Total current assets	596,208	1,424,139
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	19,410,269	18,566,757
Unproved properties and properties under development, not being amortized	1,707,089	436,325
Gross oil and gas properties	21,117,358	19,003,082
Less—accumulated depreciation, depletion, amortization, and impairment	(15,462,464)	(15,287,752)
Net oil and gas properties	5,654,894	3,715,330
Fixed assets, net of accumulated depreciation of $340,147 and $324,631, respectively	509,554	257,686
Goodwill	727,573	620,232
Derivative instruments	626	9,246
Other assets	68,337	35,451
Total assets	7,557,192	6,062,084
Accounts payable:
Trade	65,664	76,927
Gas gathering, processing, and marketing	25,190	29,887
Accrued liabilities:
Exploration and development	183,940	124,674
Taxes other than income	32,084	33,622
Other	247,041	221,159
Derivative instruments	77,557	27,627
Revenue payable	215,613	194,811
Operating leases	62,825	0
Total current liabilities	909,914	708,707
Senior notes principal	2,000,000	1,500,000
Less—senior notes unamortized debt issuance costs and discounts	(16,273)	(11,446)
Senior notes, net	1,983,727	1,488,554
Deferred income taxes	405,294	334,473
Asset retirement obligation	165,529	152,758
Derivative instruments	756	2,267
Operating leases	186,356	0
Other liabilities	62,634	45,539
Total liabilities	3,714,210	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	0
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 101,407,583 and 95,755,797 shares issued, respectively	1,014	958
Additional paid-in capital	3,210,818	2,785,188
Retained earnings	547,626	542,885
Accumulated other comprehensive income	1,904	755
Total stockholders’ equity	3,761,362	3,329,786
Total liabilities and stockholders' equity	$ 7,557,192	$ 6,062,084

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Accumulated depreciation on fixed assets	$ 340,147	$ 324,631
Redeemable preferred stock dividend rate (as a percent)	8.125%	8.125%
Redeemable preferred stock, par value (USD per share)	$ 0.01	$ 0.01
Redeemable preferred stock authorized (shares)	62,500	0
Redeemable preferred stock issued (shares)	62,500	0
Common stock, par value (USD per share)	$ 0.01	$ 0.01
Common stock authorized (shares)	200,000,000	200,000,000
Common stock issued (shares)	101,407,583	95,755,797

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenues:
Revenues	$ 576,957	$ 567,134
Costs and expenses:
Depreciation, depletion, and amortization	190,417	132,859
Asset retirement obligation	2,049	1,060
Production	77,233	71,271
Transportation, processing, and other operating	53,608	45,165
Gas gathering and other	12,320	9,823
Taxes other than income	33,694	30,188
General and administrative	29,084	23,321
Stock compensation	6,713	6,730
Loss (gain) on derivative instruments, net	115,452	(4,159)
Other operating expense, net	8,326	203
Total costs and expenses	528,896	316,461
Operating income	48,061	250,673
Other (income) and expense:
Interest expense	20,405	16,783
Capitalized interest	(8,742)	(4,810)
Loss on early extinguishment of debt	4,250	0
Other, net	(2,241)	(4,567)
Income before income tax	34,389	243,267
Income tax expense	8,073	56,949
Net income	$ 26,316	$ 186,318
Earnings per share to common stockholders:
Basic (USD per share)	$ 0.26	$ 1.96
Diluted (USD per share)	$ 0.26	$ 1.96
Comprehensive income:
Net income	$ 26,316	$ 186,318
Other comprehensive income:
Change in fair value of investments, net of tax of $339 and ($56), respectively	1,149	(190)
Total comprehensive income	27,465	186,128
Oil sales
Revenues:
Revenues	349,306	351,723
Gas and NGL sales
Revenues:
Revenues	217,915	203,718
Gas gathering and other
Revenues:
Revenues	10,262	11,452
Gas marketing
Revenues:
Revenues	$ (526)	$ 241

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Statement [Abstract]
Change in fair value investments, tax	$ 339	$ (56)

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash flows from operating activities:
Net income	$ 26,316	$ 186,318
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	190,417	132,859
Asset retirement obligation	2,049	1,060
Deferred income taxes	8,073	56,949
Stock compensation	6,713	6,730
Loss (gain) on derivative instruments, net	115,452	(4,159)
Settlements on derivative instruments	(9,051)	(12,389)
Loss on early extinguishment of debt	4,250	0
Amortization of debt issuance costs and discounts	719	729
Changes in non-current assets and liabilities	2,148	(900)
Other, net	3,976	37
Changes in operating assets and liabilities:
Accounts receivable	33,976	44,722
Other current assets	350	1,603
Accounts payable and other current liabilities	(135,297)	(30,466)
Net cash provided by operating activities	250,091	383,093
Cash flows from investing activities:
Acquisition of Resolute Energy, net of cash acquired (Note 13)	(284,441)	0
Oil and gas capital expenditures	(332,742)	(323,455)
Other capital expenditures	(17,828)	(19,056)
Sales of oil and gas assets	5,000	29,824
Sales of other assets	200	432
Net cash used by investing activities	(629,811)	(312,255)
Cash flows from financing activities:
Borrowings of long-term debt	1,182,310	0
Repayments of long-term debt	(1,553,000)	0
Financing, underwriting, and debt redemption fees	(10,938)	0
Finance lease payments	(635)	0
Dividends paid	(17,179)	(7,602)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards	(654)	(305)
Proceeds from exercise of stock options	80	345
Net cash used by financing activities	(400,016)	(7,562)
Net change in cash and cash equivalents	(779,736)	63,276
Cash and cash equivalents at beginning of period	800,666	400,534
Cash and cash equivalents at end of period	$ 20,930	$ 463,810

XML

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income
Balance at beginning of period (shares) at Dec. 31, 2017		95,437
Balance at beginning of period at Dec. 31, 2017	$ 2,568,278	$ 954	$ 2,764,384	$ (199,259)	$ 2,199
Increase (Decrease) in Stockholders' Equity
Dividends paid on stock awards subsequently forfeited	7		3	4
Dividends declared on common stock	(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 (shares)		2
Issuance of restricted stock awards	0
Common stock reacquired and retired (shares)		(3)
Common stock reacquired and retired	(305)		(305)
Restricted stock forfeited and retired (shares)		(7)
Restricted stock forfeited and retired	0
Exercise of stock options (shares)		4
Exercise of stock options	345		345
Stock-based compensation	12,411		12,411
Balance at end of period (shares) at Mar. 31, 2018		95,433
Balance at end of period at Mar. 31, 2018	2,751,593	$ 954	2,761,567	(12,937)	2,009
Balance at beginning of period (shares) at Dec. 31, 2018		95,756
Balance at beginning of period at Dec. 31, 2018	3,329,786	$ 958	2,785,188	542,885	755
Increase (Decrease) in Stockholders' Equity
Dividends paid on stock awards subsequently forfeited	2			2
Dividends declared on common stock	(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) (shares)		5,652
Issuance of stock for Resolute Energy acquisition (Note 13)	413,015	$ 56	412,959
Unrealized change in fair value of investments, net of tax	1,149				1,149
Issuance of restricted stock awards (shares)		11
Issuance of restricted stock awards	0
Common stock reacquired and retired (shares)		(10)
Common stock reacquired and retired	(654)		(654)
Restricted stock forfeited and retired (shares)		(4)
Restricted stock forfeited and retired	0
Exercise of stock options (shares)		3
Exercise of stock options	80		80
Stock-based compensation	13,245		13,245
Balance at end of period (shares) at Mar. 31, 2019		101,408
Balance at end of period at Mar. 31, 2019	$ 3,761,362	$ 1,014	$ 3,210,818	$ 547,626	$ 1,904

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CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Common Stock
Dividends declared per common share (USD per share)	$ 0.20	$ 0.16
Preferred Stock
Dividends declared per preferred share (USD per share)	$ 20.31

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BASIS OF PRESENTATION

3 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

BASIS OF PRESENTATION

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 marketvalue of our proved reserves or future results.

We did not recognize a ceiling test impairment during the three months ended March 31, 2019 and 2018 because the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation. If pricing conditions deteriorate, including the further widening of local market basis differentials, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. 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.

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 March 31, 2019, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a 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. 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.

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 which 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.

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LONG-TERM DEBT

3 Months Ended

Mar. 31, 2019

Long-term Debt, Unclassified [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT

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

	March 31, 2019							December 31, 2018
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)			Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discount (1)			Long-term Debt, net
4.375% Notes due 2024	$	750,000	$	(4,209	)	$	745,791	$	750,000	$	(4,439	)	$	745,561
3.90% Notes due 2027	750,000		(6,831		)	743,169		750,000		(7,007		)	742,993
4.375% Notes due 2029	500,000		(5,233		)	494,767		—		—			—
	$	2,000,000	$	(16,273	)	$	1,983,727	$	1,500,000	$	(11,446	)	$	1,488,554

________________________________________

(1) At March 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.3 million and $1.6 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 March 31, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.5 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 March 31, 2019, we had no bank borrowings outstanding under the Credit Facility, leaving an unused borrowing availability of $1.25 billion.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR 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 March 31, 2019, we were in compliance with all of the financial covenants.

At March 31, 2019 and December 31, 2018, we had $4.9 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 occurring 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 March 31, 2019.

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DERIVATIVE INSTRUMENTS

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedges, Assets [Abstract]

DERIVATIVE INSTRUMENTS

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 March 31, 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 March 31, 2019:

Oil Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		3,094,000		2,944,000		2,208,000		8,246,000
Weighted Avg Price - Floor	$	—	$	53.68	$	54.81	$	56.42	$	54.82
Weighted Avg Price - Ceiling	$	—	$	66.57	$	68.60	$	69.40	$	68.05
2020:
WTI (1)
Volume (Bbls)	1,456,000		728,000		—		—		2,184,000
Weighted Avg Price - Floor	$	56.13	$	52.25	$	—	$	—	$	54.83
Weighted Avg Price - Ceiling	$	70.08	$	64.31	$	—	$	—	$	68.15

________________________________________

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

Gas Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
PEPL (1)
Volume (MMBtu)	—		13,650,000		11,040,000		8,280,000		32,970,000
Weighted Avg Price - Floor	$	—	$	2.03	$	1.94	$	1.94	$	1.98
Weighted Avg Price - Ceiling	$	—	$	2.39	$	2.32	$	2.37	$	2.36
Perm EP (2)
Volume (MMBtu)	—		8,190,000		6,440,000		3,680,000		18,310,000
Weighted Avg Price - Floor	$	—	$	1.67	$	1.49	$	1.40	$	1.55
Weighted Avg Price - Ceiling	$	—	$	1.95	$	1.79	$	1.73	$	1.85
Waha (3)
Volume (MMBtu)	—		3,640,000		5,520,000		5,520,000		14,680,000
Weighted Avg Price - Floor	$	—	$	1.41	$	1.48	$	1.48	$	1.46
Weighted Avg Price - Ceiling	$	—	$	1.73	$	1.82	$	1.82	$	1.80
2020:
PEPL (1)
Volume (MMBtu)	5,460,000		2,730,000		—		—		8,190,000
Weighted Avg Price - Floor	$	1.96	$	1.95	$	—	$	—	$	1.96
Weighted Avg Price - Ceiling	$	2.38	$	2.26	$	—	$	—	$	2.34
Perm EP (2)
Volume (MMBtu)	1,820,000		910,000		—		—		2,730,000
Weighted Avg Price - Floor	$	1.45	$	1.50	$	—	$	—	$	1.47
Weighted Avg Price - Ceiling	$	1.92	$	2.13	$	—	$	—	$	1.99
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

________________________________________

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

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

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

Oil Basis Swaps	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2019:
WTI Midland (1)
Volume (Bbls)	—			3,685,500			3,266,000			2,530,000			9,481,500
Weighted Avg Differential (2)	$	—		$	(6.51	)	$	(7.36	)	$	(8.36	)	$	(7.30	)
2020:
WTI Midland (1)
Volume (Bbls)	1,001,000			637,000			—			—			1,638,000
Weighted Avg Differential (2)	$	(0.16	)	$	(0.40	)	$	—		$	—		$	(0.26	)

________________________________________

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

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

Oil Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		455,000		460,000		460,000		1,375,000
Weighted Avg Price	$	—	$	64.54	$	64.54	$	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)	—		3,185,000		3,220,000		3,220,000		9,625,000
Weighted Avg Price	$	—	$	3.00	$	3.00	$	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)	—		333,970		337,640		337,640		1,009,250
Weighted Avg Call Price	$	—	$	64.36	$	64.36	$	64.36	$	64.36

________________________________________

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

The following table summarizes our derivative contracts entered into subsequent to March 31, 2019 through May 7, 2019:

Oil Basis Swaps	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
WTI Midland (1)
Volume (Bbls)	364,000			—		—		—		364,000
Weighted Avg Differential (2)	$	(0.03	)	$	—	$	—	$	—	$	(0.03	)

________________________________________

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

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

Derivative Gains and Losses

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

	Three Months Ended March 31,
(in thousands)	2019			2018
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts	$	(9,846	)	$	(11,789	)
Oil contracts	116,247			(4,759		)
	106,401			(16,548		)
Cash (receipts) payments on derivative instruments, net:
Gas contracts	3,764			(5,119		)
Oil contracts	5,287			17,508
	9,051			12,389
Loss (gain) on derivative instruments, net	$	115,452		$	(4,159	)

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

		March 31, 2019
(in thousands)	Balance Sheet Location	Asset			Liability
Oil contracts	Current assets — Derivative instruments	$	19,328		$	—
Gas contracts	Current assets — Derivative instruments	16,502			—
Oil contracts	Non-current assets — Derivative instruments	222			—
Gas contracts	Non-current assets — Derivative instruments	404			—
Oil contracts	Current liabilities — Derivative instruments	—			73,517
Gas contracts	Current liabilities — Derivative instruments	—			4,040
Oil contracts	Non-current liabilities — Derivative instruments	—			749
Gas contracts	Non-current liabilities — Derivative instruments	—			7
Total gross amounts presented in the balance sheet		36,456			78,313
Less: gross amounts not offset in the balance sheet		(26,283		)	(26,283		)
Net amount		$	10,173		$	52,030
		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.

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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. 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 March 31, 2019 and December 31, 2018:

	March 31, 2019						December 31, 2018
(in thousands)	Book Value			Fair Value			Book Value			Fair Value
Financial Assets (Liabilities):
4.375% Notes due 2024	$	(750,000	)	$	(779,340	)	$	(750,000	)	$	(744,578	)
3.90% Notes due 2027	$	(750,000	)	$	(748,620	)	$	(750,000	)	$	(701,273	)
4.375% Notes due 2029	$	(500,000	)	$	(514,380	)	$	—		$	—
Derivative instruments — assets	$	36,456		$	36,456		$	111,185		$	111,185
Derivative instruments — liabilities	$	(78,313	)	$	(78,313	)	$	(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 their last traded value before period end. The fair value of our derivative instruments (Level 2) was estimated using option pricing models. These models use certain variables including forward price and volatility curves and the strike prices for the instruments. 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 March 31, 2019 were accrued operating expenses of approximately $84.0 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 March 31, 2019 and December 31, 2018, the allowance for doubtful accounts was $2.7 million and $2.7 million, respectively.

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CAPITAL STOCK

3 Months Ended

Mar. 31, 2019

Stockholders' Equity Note [Abstract]

CAPITAL STOCK

CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At March 31, 2019, there were 101.4 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 will be payable quarterly in arrears and shall 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 February 2019, our Board of Directors declared a cash dividend of $0.20 per share of common stock. The dividend is payable on or before May 31, 2019 to stockholders of record on May 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 $20.3 million dividend declared during the first 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 March 2019, our Board of Directors declared a cash dividend of $20.31 per share of Convertible Preferred Stock. The dividend was paid in April to stockholders of record on April 1, 2019. The $1.3 million dividend declared during the first 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.

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STOCK-BASED COMPENSATION

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

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

	Three Months Ended March 31,
(in thousands)	2019			2018
Restricted stock awards:
Performance stock awards	$	5,394		$	6,729
Service-based stock awards	7,231			5,072
	12,625			11,801
Stock option awards	622			617
Total stock compensation cost	13,247			12,418
Less amounts capitalized to oil and gas properties	(6,534		)	(5,688		)
Stock compensation expense	$	6,713		$	6,730

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. Our accounting policy is to account for forfeitures in compensation cost when they occur.

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ASSET RETIREMENT OBLIGATIONS

3 Months Ended

Mar. 31, 2019

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

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 three months ended March 31, 2019:

(in thousands)	Three Months Ended March 31, 2019
Asset retirement obligation at January 1, 2019	$	166,904
Liabilities incurred	10,009
Liability settlements and disposals	(1,361		)
Accretion expense	1,793
Revisions of estimated liabilities	1,912
Asset retirement obligation at March 31, 2019	179,257
Less current obligation	(13,728		)
Long-term asset retirement obligation	$	165,529

For the three months ended March 31, 2019, liabilities incurred included $9.4 million for the Resolute acquisition.

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EARNINGS PER SHARE

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

EARNINGS PER SHARE

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 March 31,
	2019						2018
(in thousands, except per share information)	Income (Numerator)			Shares (Denominator)	Per-Share Amount		Income (Numerator)			Shares (Denominator)	Per-Share Amount
Net income	$	26,316					$	186,318
Less: net income attributable to participating securities	(445		)				(2,666		)
Less: preferred stock dividends	(1,269		)				—
Basic earnings per share
Income available to common stockholders	24,602			95,922	$	0.26	183,652			93,699	$	1.96
Effects of dilutive securities (1)
Options	—			10			—			38
Diluted earnings per share
Income available to common stockholders and assumed conversions	$	24,602		95,932	$	0.26	$	183,652		93,737	$	1.96

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(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 March 31, 2019 calculation were 388.6 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 March 31, 2018 calculation were 295.6 thousand potential common shares from the assumed exercise of employee stock options.

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INCOME TAXES

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

INCOME TAXES

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 March 31,
(in thousands)	2019			2018
Deferred tax expense	$	8,073		$	56,949
Combined federal and state effective income tax rate	23.5		%	23.4		%

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. The net deferred tax liability includes certain deferred tax assets net of valuation allowances. The acquired tax attributes include federal net operating loss, capital loss, and enhanced oil recovery tax credit carryforwards. The carryforwards are subject to an annual limitation under Internal Revenue Code Section 382.

At March 31, 2019, we had no unrecognized tax benefits that would impact our effective tax rate and have made no provisions for interest or penalties related to uncertain tax positions. The tax years 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 2015 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.

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COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

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 March 31, 2019, these leases had remaining lease terms ranging from 5.2 to 7.4 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 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 March 31, 2019, these leases had remaining lease terms ranging from one month to 11.3 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.

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 March 31, 2019, this lease had a remaining term of 6.4 years.

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.

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 March 31, 2019, these leases had remaining lease terms of 12 months or less. These leases typically require us to make payments in amounts based on the usage of the underlying equipment. These leases do not contain residual value guarantees, options to purchase the underlying equipment, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of exploration and development-related equipment.

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

Balance Sheet Presentation

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

(in thousands)	Balance Sheet Location	March 31, 2019
Operating lease right-of-use assets	Non-current assets — Fixed assets, net	$	233,644
Finance lease right-of-use assets	Non-current assets — Other assets	28,138
Total right-of-use assets		$	261,782

(in thousands)	Balance Sheet Location	March 31, 2019
Operating lease liabilities — current	Current liabilities — Operating leases	$	62,825
Operating lease liabilities — non-current	Non-current liabilities — Operating leases	186,356
Finance lease liability — current	Current liabilities — Accrued liabilities-Other	5,936
Finance lease liability — non-current	Non-current liabilities — Other liabilities	23,500
Total lease liabilities		$	278,617

Lease Cost and Cash Flows

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

(in thousands)	Three Months Ended March 31, 2019
Finance lease cost:
Amortization of right-of-use asset	$	1,096
Interest on lease liability	486
Operating lease cost: (1)
Production expense	3,834
Gas gathering and other expense	6,164
General and administrative expense	2,299
Short-term lease cost (2)	154,710
Total lease cost	$	168,589

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(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.

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

(in thousands)	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash outflows from finance lease	$	635
Operating cash outflows from operating leases	$	12,493
Cash paid for short-term leases and variable lease payments:
Investing cash outflows from operating leases	$	139,473

During the three months ended March 31, 2019, we recognized $16.2 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:

	March 31, 2019
Weighted-average remaining lease term (in years):
Finance lease	6.4
Operating leases	4.7
Weighted-average discount rate:
Finance lease	6.7	%
Operating leases	4.1	%

The following table reflects the undiscounted future cash flows utilized in the calculation of the lease liabilities recorded at March 31, 2019:

	March 31, 2019
(in thousands)	Operating Leases			Finance Lease
April 1, 2019 — March 31, 2020	$	71,895		$	6,808
April 1, 2020 — March 31, 2021	59,020			5,950
April 1, 2021 — March 31, 2022	53,649			5,658
April 1, 2022 — March 31, 2023	45,801			5,366
April 1, 2023 — March 31, 2024	21,665			5,075
Remaining periods	21,836			6,690
Total undiscounted future cash flows	273,866			35,547
Less effects of discounting	(24,685		)	(6,111		)
Lease liabilities recognized	$	249,181		$	29,436

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 March 31, 2019, we had estimated commitments of approximately: (i) $447.9 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $36.3 million to finish gathering system construction in progress.

At March 31, 2019, we had firm sales contracts to deliver approximately 456.4 Bcf of gas over the next 5.8 years. If we do not deliver this gas, our estimated financial commitment, calculated using the April 2019 index price, would be approximately $461.3 million. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next 9.8 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 March 31, 2019, would be approximately $662.7 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of March 31, 2019, would be approximately $55.5 million. Of this total, we have accrued a liability of $2.7 million, representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.

At March 31, 2019, we have various firm transportation agreements for gas pipeline capacity with end dates ranging from 2019 - 2025 under which we will have to pay an estimated $25.6 million over the remaining terms of the agreements. These agreements were entered into to support our residue gas 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 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.

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SUPPLEMENTAL CASH FLOW INFORMATION

3 Months Ended

Mar. 31, 2019

Supplemental Cash Flow Elements [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

	Three Months Ended March 31,
(in thousands)	2019		2018
Cash paid during the period for:
Interest (net of capitalized amounts of $740 and $156, respectively) (1)	$	18,588	$	389
Income taxes	$	6	$	—
Cash received for income tax refunds	$	1	$	2

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(1) Includes $17.6 million in interest paid upon the redemption of Resolute’s senior notes and credit facility on March 1, 2019.

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RELATED PARTY TRANSACTIONS

3 Months Ended

Mar. 31, 2019

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to Cimarex. Cimarex incurred drilling costs of approximately $24.5 million and $23.6 million related to these services during the three months ended March 31, 2019 and 2018, respectively. 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.

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ACQUISITIONS

3 Months Ended

Mar. 31, 2019

Business Combinations [Abstract]

ACQUISITIONS

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 the acquired 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 the acquired properties, (iii) the ability to increase our acreage position in the Delaware Basin, and (iv) the expectation that the acquisition will be financially accretive.

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

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

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

Preliminary Purchase Price Allocation

The Resolute acquisition has been accounted for as a business combination, using the acquisition method. The following table represents 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. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, ultimate settlement of 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
Cash	$	41,236
Accounts receivable	50,739
Other current assets	13,280
Proved oil and gas properties	692,600
Unproved oil and gas properties	1,054,200
Fixed assets	5,355
Goodwill	107,341
Other assets	142
Current liabilities	(202,735		)
Long-term debt	(870,000		)
Deferred income taxes	(62,409		)
Asset retirement obligation	(9,437		)
Total identifiable net assets	$	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 $107.3 million has been recognized principally as a result of recording net deferred tax liabilities arising from the difference between the tax basis and the purchase price allocated to Resolute’s assets and liabilities, and anticipated opportunities for cost savings through administrative and operational synergies. Goodwill is not expected to be deductible for tax purposes.

Acquisition-related costs incurred in 2019 were $8.3 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 March 31, 2019 is $24.2 million and $5.3 million, respectively.

Pro Forma Financial Information

The following supplemental pro forma information for the three month periods ended March 31, 2019 and 2018 has been prepared to give effect to the Resolute acquisition as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of the combined company’s proved oil and gas properties, (ii) the capitalization of interest expense, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by Cimarex of $8.3 million and transaction-related costs incurred by Resolute of $60.0 million, for the three months ended March 31, 2019. 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 March 31,
(in thousands)	2019		2018
Revenue	$	630,093	$	638,078
Net income	$	12,617	$	187,079
Net income per share:
Basic	$	0.11	$	1.84
Diluted	$	0.11	$	1.84

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BASIS OF PRESENTATION (Policies)

3 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

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.

Use of Estimates

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 and Oil and Gas Properties

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 marketvalue of our proved reserves or future results.

We did not recognize a ceiling test impairment during the three months ended March 31, 2019 and 2018 because the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation. If pricing conditions deteriorate, including the further widening of local market basis differentials, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. 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.

Revenue Recognition

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 March 31, 2019, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a 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. 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.

Lease Accounting

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 which 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.

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LONG-TERM DEBT (Tables)

3 Months Ended

Mar. 31, 2019

Long-term Debt, Unclassified [Abstract]

Schedule of Long-Term Debt

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

	March 31, 2019							December 31, 2018
(in thousands)	Principal		Unamortized Debt Issuance Costs and Discounts (1)			Long-term Debt, net		Principal		Unamortized Debt Issuance Costs and Discount (1)			Long-term Debt, net
4.375% Notes due 2024	$	750,000	$	(4,209	)	$	745,791	$	750,000	$	(4,439	)	$	745,561
3.90% Notes due 2027	750,000		(6,831		)	743,169		750,000		(7,007		)	742,993
4.375% Notes due 2029	500,000		(5,233		)	494,767		—		—			—
	$	2,000,000	$	(16,273	)	$	1,983,727	$	1,500,000	$	(11,446	)	$	1,488,554

________________________________________

(1) At March 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.3 million and $1.6 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 March 31, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.5 million and $0.7 million, respectively. The 4.375% Notes due 2024 were issued at par.

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DERIVATIVE INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedges, Assets [Abstract]

Schedule of Outstanding Hedging Contracts Relative to Future Production

The following tables summarize our outstanding derivative contracts as of March 31, 2019:

Oil Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		3,094,000		2,944,000		2,208,000		8,246,000
Weighted Avg Price - Floor	$	—	$	53.68	$	54.81	$	56.42	$	54.82
Weighted Avg Price - Ceiling	$	—	$	66.57	$	68.60	$	69.40	$	68.05
2020:
WTI (1)
Volume (Bbls)	1,456,000		728,000		—		—		2,184,000
Weighted Avg Price - Floor	$	56.13	$	52.25	$	—	$	—	$	54.83
Weighted Avg Price - Ceiling	$	70.08	$	64.31	$	—	$	—	$	68.15

________________________________________

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

Gas Collars	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
PEPL (1)
Volume (MMBtu)	—		13,650,000		11,040,000		8,280,000		32,970,000
Weighted Avg Price - Floor	$	—	$	2.03	$	1.94	$	1.94	$	1.98
Weighted Avg Price - Ceiling	$	—	$	2.39	$	2.32	$	2.37	$	2.36
Perm EP (2)
Volume (MMBtu)	—		8,190,000		6,440,000		3,680,000		18,310,000
Weighted Avg Price - Floor	$	—	$	1.67	$	1.49	$	1.40	$	1.55
Weighted Avg Price - Ceiling	$	—	$	1.95	$	1.79	$	1.73	$	1.85
Waha (3)
Volume (MMBtu)	—		3,640,000		5,520,000		5,520,000		14,680,000
Weighted Avg Price - Floor	$	—	$	1.41	$	1.48	$	1.48	$	1.46
Weighted Avg Price - Ceiling	$	—	$	1.73	$	1.82	$	1.82	$	1.80
2020:
PEPL (1)
Volume (MMBtu)	5,460,000		2,730,000		—		—		8,190,000
Weighted Avg Price - Floor	$	1.96	$	1.95	$	—	$	—	$	1.96
Weighted Avg Price - Ceiling	$	2.38	$	2.26	$	—	$	—	$	2.34
Perm EP (2)
Volume (MMBtu)	1,820,000		910,000		—		—		2,730,000
Weighted Avg Price - Floor	$	1.45	$	1.50	$	—	$	—	$	1.47
Weighted Avg Price - Ceiling	$	1.92	$	2.13	$	—	$	—	$	1.99
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

________________________________________

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

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

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

Oil Basis Swaps	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2019:
WTI Midland (1)
Volume (Bbls)	—			3,685,500			3,266,000			2,530,000			9,481,500
Weighted Avg Differential (2)	$	—		$	(6.51	)	$	(7.36	)	$	(8.36	)	$	(7.30	)
2020:
WTI Midland (1)
Volume (Bbls)	1,001,000			637,000			—			—			1,638,000
Weighted Avg Differential (2)	$	(0.16	)	$	(0.40	)	$	—		$	—		$	(0.26	)

________________________________________

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

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

Oil Swaps	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2019:
WTI (1)
Volume (Bbls)	—		455,000		460,000		460,000		1,375,000
Weighted Avg Price	$	—	$	64.54	$	64.54	$	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)	—		3,185,000		3,220,000		3,220,000		9,625,000
Weighted Avg Price	$	—	$	3.00	$	3.00	$	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)	—		333,970		337,640		337,640		1,009,250
Weighted Avg Call Price	$	—	$	64.36	$	64.36	$	64.36	$	64.36

________________________________________

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

Schedule of Derivative Contracts Entered into Subsequent to Balance Sheet Date

The following table summarizes our derivative contracts entered into subsequent to March 31, 2019 through May 7, 2019:

Oil Basis Swaps	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		Total
2020:
WTI Midland (1)
Volume (Bbls)	364,000			—		—		—		364,000
Weighted Avg Differential (2)	$	(0.03	)	$	—	$	—	$	—	$	(0.03	)

________________________________________

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

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

Schedule of Net (Gains) Losses from Settlements and Changes of Derivative Contracts

The following table presents the components of Loss (gain) on derivative instruments, net for the periods indicated.

	Three Months Ended March 31,
(in thousands)	2019			2018
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts	$	(9,846	)	$	(11,789	)
Oil contracts	116,247			(4,759		)
	106,401			(16,548		)
Cash (receipts) payments on derivative instruments, net:
Gas contracts	3,764			(5,119		)
Oil contracts	5,287			17,508
	9,051			12,389
Loss (gain) on derivative instruments, net	$	115,452		$	(4,159	)

Schedule of Derivative Assets and Liabilities

The following tables present the amounts and classifications of our derivative assets and liabilities as of March 31, 2019 and December 31, 2018, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.

		March 31, 2019
(in thousands)	Balance Sheet Location	Asset			Liability
Oil contracts	Current assets — Derivative instruments	$	19,328		$	—
Gas contracts	Current assets — Derivative instruments	16,502			—
Oil contracts	Non-current assets — Derivative instruments	222			—
Gas contracts	Non-current assets — Derivative instruments	404			—
Oil contracts	Current liabilities — Derivative instruments	—			73,517
Gas contracts	Current liabilities — Derivative instruments	—			4,040
Oil contracts	Non-current liabilities — Derivative instruments	—			749
Gas contracts	Non-current liabilities — Derivative instruments	—			7
Total gross amounts presented in the balance sheet		36,456			78,313
Less: gross amounts not offset in the balance sheet		(26,283		)	(26,283		)
Net amount		$	10,173		$	52,030
		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		$	—

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FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Schedule of Fair Value Measurement Information for Certain Assets and Liabilities

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

	March 31, 2019						December 31, 2018
(in thousands)	Book Value			Fair Value			Book Value			Fair Value
Financial Assets (Liabilities):
4.375% Notes due 2024	$	(750,000	)	$	(779,340	)	$	(750,000	)	$	(744,578	)
3.90% Notes due 2027	$	(750,000	)	$	(748,620	)	$	(750,000	)	$	(701,273	)
4.375% Notes due 2029	$	(500,000	)	$	(514,380	)	$	—		$	—
Derivative instruments — assets	$	36,456		$	36,456		$	111,185		$	111,185
Derivative instruments — liabilities	$	(78,313	)	$	(78,313	)	$	(29,894	)	$	(29,894	)

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STOCK-BASED COMPENSATION (Tables)

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Schedule of Recognition of Non-Cash Stock-Based Compensation Costs

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

	Three Months Ended March 31,
(in thousands)	2019			2018
Restricted stock awards:
Performance stock awards	$	5,394		$	6,729
Service-based stock awards	7,231			5,072
	12,625			11,801
Stock option awards	622			617
Total stock compensation cost	13,247			12,418
Less amounts capitalized to oil and gas properties	(6,534		)	(5,688		)
Stock compensation expense	$	6,713		$	6,730

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ASSET RETIREMENT OBLIGATIONS (Tables)

3 Months Ended

Mar. 31, 2019

Asset Retirement Obligation [Abstract]

Schedule of Asset Retirement Obligations

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the three months ended March 31, 2019:

(in thousands)	Three Months Ended March 31, 2019
Asset retirement obligation at January 1, 2019	$	166,904
Liabilities incurred	10,009
Liability settlements and disposals	(1,361		)
Accretion expense	1,793
Revisions of estimated liabilities	1,912
Asset retirement obligation at March 31, 2019	179,257
Less current obligation	(13,728		)
Long-term asset retirement obligation	$	165,529

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EARNINGS PER SHARE (Tables)

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

Schedule of Calculations of Basic and Diluted Net Earnings (Loss) per Common 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 March 31,
	2019						2018
(in thousands, except per share information)	Income (Numerator)			Shares (Denominator)	Per-Share Amount		Income (Numerator)			Shares (Denominator)	Per-Share Amount
Net income	$	26,316					$	186,318
Less: net income attributable to participating securities	(445		)				(2,666		)
Less: preferred stock dividends	(1,269		)				—
Basic earnings per share
Income available to common stockholders	24,602			95,922	$	0.26	183,652			93,699	$	1.96
Effects of dilutive securities (1)
Options	—			10			—			38
Diluted earnings per share
Income available to common stockholders and assumed conversions	$	24,602		95,932	$	0.26	$	183,652		93,737	$	1.96

________________________________________

(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 March 31, 2019 calculation were 388.6 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 March 31, 2018 calculation were 295.6 thousand potential common shares from the assumed exercise of employee stock options.

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INCOME TAXES (Tables)

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Components of the Provision for 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 March 31,
(in thousands)	2019			2018
Deferred tax expense	$	8,073		$	56,949
Combined federal and state effective income tax rate	23.5		%	23.4		%

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COMMITMENTS AND CONTINGENCIES (Tables)

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of Supplemental Balance Sheet Information of Leases

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

(in thousands)	Balance Sheet Location	March 31, 2019
Operating lease right-of-use assets	Non-current assets — Fixed assets, net	$	233,644
Finance lease right-of-use assets	Non-current assets — Other assets	28,138
Total right-of-use assets		$	261,782

(in thousands)	Balance Sheet Location	March 31, 2019
Operating lease liabilities — current	Current liabilities — Operating leases	$	62,825
Operating lease liabilities — non-current	Non-current liabilities — Operating leases	186,356
Finance lease liability — current	Current liabilities — Accrued liabilities-Other	5,936
Finance lease liability — non-current	Non-current liabilities — Other liabilities	23,500
Total lease liabilities		$	278,617

Schedule of Lease Cost and Cash Paid for Leases

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

(in thousands)	Three Months Ended March 31, 2019
Finance lease cost:
Amortization of right-of-use asset	$	1,096
Interest on lease liability	486
Operating lease cost: (1)
Production expense	3,834
Gas gathering and other expense	6,164
General and administrative expense	2,299
Short-term lease cost (2)	154,710
Total lease cost	$	168,589

________________________________________

(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.

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

(in thousands)	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash outflows from finance lease	$	635
Operating cash outflows from operating leases	$	12,493
Cash paid for short-term leases and variable lease payments:
Investing cash outflows from operating leases	$	139,473

Schedule of Weighted-Average Remaining Lease Term and Discount Rates of Leases

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

	March 31, 2019
Weighted-average remaining lease term (in years):
Finance lease	6.4
Operating leases	4.7
Weighted-average discount rate:
Finance lease	6.7	%
Operating leases	4.1	%

Schedule of Maturity of Finance Leases

The following table reflects the undiscounted future cash flows utilized in the calculation of the lease liabilities recorded at March 31, 2019:

	March 31, 2019
(in thousands)	Operating Leases			Finance Lease
April 1, 2019 — March 31, 2020	$	71,895		$	6,808
April 1, 2020 — March 31, 2021	59,020			5,950
April 1, 2021 — March 31, 2022	53,649			5,658
April 1, 2022 — March 31, 2023	45,801			5,366
April 1, 2023 — March 31, 2024	21,665			5,075
Remaining periods	21,836			6,690
Total undiscounted future cash flows	273,866			35,547
Less effects of discounting	(24,685		)	(6,111		)
Lease liabilities recognized	$	249,181		$	29,436

Schedule of Maturity of Operating Leases

The following table reflects the undiscounted future cash flows utilized in the calculation of the lease liabilities recorded at March 31, 2019:

	March 31, 2019
(in thousands)	Operating Leases			Finance Lease
April 1, 2019 — March 31, 2020	$	71,895		$	6,808
April 1, 2020 — March 31, 2021	59,020			5,950
April 1, 2021 — March 31, 2022	53,649			5,658
April 1, 2022 — March 31, 2023	45,801			5,366
April 1, 2023 — March 31, 2024	21,665			5,075
Remaining periods	21,836			6,690
Total undiscounted future cash flows	273,866			35,547
Less effects of discounting	(24,685		)	(6,111		)
Lease liabilities recognized	$	249,181		$	29,436

Schedule of Future Minimum Lease Payments

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

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

3 Months Ended

Mar. 31, 2019

Supplemental Cash Flow Elements [Abstract]

Schedule of Supplemental Cash Flow Information

	Three Months Ended March 31,
(in thousands)	2019		2018
Cash paid during the period for:
Interest (net of capitalized amounts of $740 and $156, respectively) (1)	$	18,588	$	389
Income taxes	$	6	$	—
Cash received for income tax refunds	$	1	$	2

________________________________________

(1) Includes $17.6 million in interest paid upon the redemption of Resolute’s senior notes and credit facility on March 1, 2019.

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ACQUISITIONS (Tables)

3 Months Ended

Mar. 31, 2019

Business Combinations [Abstract]

Schedule of Consideration Transferred in Acquisition

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

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table sets forth the preliminary purchase price allocation:

(in thousands)	March 1, 2019
Cash	$	41,236
Accounts receivable	50,739
Other current assets	13,280
Proved oil and gas properties	692,600
Unproved oil and gas properties	1,054,200
Fixed assets	5,355
Goodwill	107,341
Other assets	142
Current liabilities	(202,735		)
Long-term debt	(870,000		)
Deferred income taxes	(62,409		)
Asset retirement obligation	(9,437		)
Total identifiable net assets	$	820,312

Schedule of Pro Forma information

	Three Months Ended March 31,
(in thousands)	2019		2018
Revenue	$	630,093	$	638,078
Net income	$	12,617	$	187,079
Net income per share:
Basic	$	0.11	$	1.84
Diluted	$	0.11	$	1.84

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BASIS OF PRESENTATION - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Jan. 01, 2019
Oil and Gas Delivery Commitments and Contracts [Line Items]
Discount rate for calculating present value of estimated future net revenues from proved reserves (as a percent)	10.00%
Lease liabilities recognized	$ 249,181
Operating lease right-of-use assets	$ 233,644
Minimum
Oil and Gas Delivery Commitments and Contracts [Line Items]
Oil and gas delivery commitments and contracts, period	1 month
Accounting Standards Update 2016-02
Oil and Gas Delivery Commitments and Contracts [Line Items]
Lease liabilities recognized		$ 276,900
Operating lease right-of-use assets		$ 265,000

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LONG-TERM DEBT - Long-Term Debt Outstanding (Details) - USD ($)	Mar. 31, 2019	Dec. 31, 2018	Apr. 30, 2017	Jun. 30, 2014
Debt Instrument
Senior notes principal	$ 2,000,000,000	$ 1,500,000,000
Unamortized debt issuance costs and discount	(16,273,000)	(11,446,000)
Long-term Debt, net	1,983,727,000	1,488,554,000
4.375% Notes due 2024
Debt Instrument
Senior notes principal	750,000,000	750,000,000
Unamortized debt issuance costs and discount	(4,209,000)	(4,439,000)
Long-term Debt, net	$ 745,791,000	745,561,000
4.375% Notes due 2024 | Senior Notes
Debt Instrument
Senior notes principal				$ 750,000,000
Stated interest rate (as a percent)	4.375%			4.375%
3.90% Notes due 2027
Debt Instrument
Senior notes principal	$ 750,000,000	750,000,000
Unamortized debt issuance costs and discount	(6,831,000)	(7,007,000)
Long-term Debt, net	$ 743,169,000	742,993,000
3.90% Notes due 2027 | Senior Notes
Debt Instrument
Senior notes principal			$ 750,000,000
Stated interest rate (as a percent)	3.90%		3.90%
Unamortized debt issuance costs	$ 5,300,000	5,400,000
Unamortized discount	1,600,000	1,600,000
4.375% Notes due 2029
Debt Instrument
Senior notes principal	500,000,000	0
Unamortized debt issuance costs and discount	(5,233,000)	0
Long-term Debt, net	$ 494,767,000	$ 0
4.375% Notes due 2029 | Senior Notes
Debt Instrument
Stated interest rate (as a percent)	4.375%
Unamortized debt issuance costs	$ 4,500,000
Unamortized discount	$ 700,000

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LONG-TERM DEBT - Bank Debt Narrative (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Feb. 05, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Unamortized debt issuance costs and discount	$ 16,273,000		$ 11,446,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Aggregate commitments under credit facility		$ 1,250,000,000
Maximum borrowing capacity including accordion feature		1,500,000,000
Borrowings outstanding	0
Unused borrowing availability	$ 1,250,000,000
Debt-to-capital ratio (as a percent)	65.00%
Unamortized debt issuance costs and discount	$ 4,900,000	$ 3,000,000	$ 2,200,000
Minimum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Commitment fee rate (as a percent)	0.125%
Maximum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Commitment fee rate (as a percent)	0.35%
London Interbank Offered Rate (LIBOR) | Minimum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest rate margin (as a percent)	1.125%
London Interbank Offered Rate (LIBOR) | Maximum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest rate margin (as a percent)	2.00%
Base Rate | Minimum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest rate margin (as a percent)	0.125%
Base Rate | Maximum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest rate margin (as a percent)	1.00%

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LONG-TERM DEBT - Senior Notes Narrative (Details) - USD ($)		1 Months Ended	3 Months Ended
	Mar. 08, 2019	Apr. 30, 2017	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Jun. 30, 2014
Debt Instrument
Principal amount			$ 2,000,000,000		$ 1,500,000,000
Proceeds from issuance of long-term debt			1,182,310,000	$ 0
4.375% Notes due 2029
Debt Instrument
Principal amount			500,000,000		0
3.90% Notes due 2027
Debt Instrument
Principal amount			750,000,000		750,000,000
4.375% Notes due 2024
Debt Instrument
Principal amount			$ 750,000,000		$ 750,000,000
Senior Notes | 4.375% Notes due 2029
Debt Instrument
Principal amount	$ 500,000,000
Stated interest rate (as a percent)			4.375%
Issuance price relative to par value (as a percent)	99.862%
Effective rate (as a percent)	4.392%		4.50%
Proceeds from issuance of long-term debt	$ 494,700,000
Senior Notes | 3.90% Notes due 2027
Debt Instrument
Principal amount		$ 750,000,000
Stated interest rate (as a percent)		3.90%	3.90%
Issuance price relative to par value (as a percent)		99.748%
Effective rate (as a percent)		3.93%	4.01%
Senior Notes | 4.375% Notes due 2024
Debt Instrument
Principal amount						$ 750,000,000
Stated interest rate (as a percent)			4.375%			4.375%
Effective rate (as a percent)			4.50%

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DERIVATIVE INSTRUMENTS - Derivative Contracts (Details)	3 Months Ended
	Mar. 31, 2019 MMBTU $ / bbl $ / MMBTU bbl
Oil Collar WTI Index | 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	8,246,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit) | $ / bbl	54.82
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	68.05
Oil Collar WTI Index | Second Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	3,094,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit) | $ / bbl	53.68
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	66.57
Oil Collar WTI Index | Third Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	2,944,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit) | $ / bbl	54.81
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	68.60
Oil Collar WTI Index | Fourth Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	2,208,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit) | $ / bbl	56.42
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	69.40
Oil Collar WTI Index | 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	2,184,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit) | $ / bbl	54.83
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	68.15
Oil Collar WTI Index | First Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	1,456,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit) | $ / bbl	56.13
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	70.08
Oil Collar WTI Index | Second Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	728,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit) | $ / bbl	52.25
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	64.31
Gas Collar PEPL Index | 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	32,970,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.98
Weighted Avg Price - Ceiling (USD per unit)	2.36
Gas Collar PEPL Index | Second Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	13,650,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	2.03
Weighted Avg Price - Ceiling (USD per unit)	2.39
Gas Collar PEPL Index | Third Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	11,040,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.94
Weighted Avg Price - Ceiling (USD per unit)	2.32
Gas Collar PEPL Index | Fourth Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	8,280,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.94
Weighted Avg Price - Ceiling (USD per unit)	2.37
Gas Collar PEPL Index | 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	8,190,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.96
Weighted Avg Price - Ceiling (USD per unit)	2.34
Gas Collar PEPL Index | First Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	5,460,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.96
Weighted Avg Price - Ceiling (USD per unit)	2.38
Gas Collar PEPL Index | Second Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	2,730,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.95
Weighted Avg Price - Ceiling (USD per unit)	2.26
Gas Collar Perm EP | 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	18,310,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.55
Weighted Avg Price - Ceiling (USD per unit)	1.85
Gas Collar Perm EP | Second Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	8,190,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.67
Weighted Avg Price - Ceiling (USD per unit)	1.95
Gas Collar Perm EP | Third Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	6,440,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.49
Weighted Avg Price - Ceiling (USD per unit)	1.79
Gas Collar Perm EP | Fourth Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	3,680,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.40
Weighted Avg Price - Ceiling (USD per unit)	1.73
Gas Collar Perm EP | 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	2,730,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.47
Weighted Avg Price - Ceiling (USD per unit)	1.99
Gas Collar Perm EP | First Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	1,820,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.45
Weighted Avg Price - Ceiling (USD per unit)	1.92
Gas Collar Perm EP | Second Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	910,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.50
Weighted Avg Price - Ceiling (USD per unit)	2.13
Gas Collar Waha | 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	14,680,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.46
Weighted Avg Price - Ceiling (USD per unit)	1.80
Gas Collar Waha | Second Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	3,640,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.41
Weighted Avg Price - Ceiling (USD per unit)	1.73
Gas Collar Waha | Third Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	5,520,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.48
Weighted Avg Price - Ceiling (USD per unit)	1.82
Gas Collar Waha | Fourth Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	5,520,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.48
Weighted Avg Price - Ceiling (USD per unit)	1.82
Gas Collar Waha | 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	7,280,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.53
Weighted Avg Price - Ceiling (USD per unit)	1.91
Gas Collar Waha | First Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	4,550,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.50
Weighted Avg Price - Ceiling (USD per unit)	1.87
Gas Collar Waha | Second Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	2,730,000
Weighted Average Price
Weighted Avg Price - Floor (USD per unit)	1.57
Weighted Avg Price - Ceiling (USD per unit)	1.97
Oil Basis Swaps WTI Midland Index | 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	9,481,500
Weighted Average Price
Weighted Avg Differential (USD per Bbl) | $ / bbl	(7.30)
Oil Basis Swaps WTI Midland Index | Second Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	3,685,500
Weighted Average Price
Weighted Avg Differential (USD per Bbl) | $ / bbl	(6.51)
Oil Basis Swaps WTI Midland Index | Third Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	3,266,000
Weighted Average Price
Weighted Avg Differential (USD per Bbl) | $ / bbl	(7.36)
Oil Basis Swaps WTI Midland Index | Fourth Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	2,530,000
Weighted Average Price
Weighted Avg Differential (USD per Bbl) | $ / bbl	(8.36)
Oil Basis Swaps WTI Midland Index | 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	1,638,000
Weighted Average Price
Weighted Avg Differential (USD per Bbl) | $ / bbl	(0.26)
Oil Basis Swaps WTI Midland Index | 2020 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	364,000
Weighted Average Price
Weighted Avg Differential (USD per Bbl) | $ / bbl	(0.03)
Oil Basis Swaps WTI Midland Index | First Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	1,001,000
Weighted Average Price
Weighted Avg Differential (USD per Bbl) | $ / bbl	(0.16)
Oil Basis Swaps WTI Midland Index | First Quarter - 2020 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	364,000
Weighted Average Price
Weighted Avg Differential (USD per Bbl) | $ / bbl	(0.03)
Oil Basis Swaps WTI Midland Index | Second Quarter - 2020 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	637,000
Weighted Average Price
Weighted Avg Differential (USD per Bbl) | $ / bbl	(0.40)
Oil Swaps WTI Index | 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	1,375,000
Weighted Average Price
Weighted Avg Price (USD per unit) | $ / bbl	64.54
Oil Swaps WTI Index | Second Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	455,000
Weighted Average Price
Weighted Avg Price (USD per unit) | $ / bbl	64.54
Oil Swaps WTI Index | Third Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	460,000
Weighted Average Price
Weighted Avg Price (USD per unit) | $ / bbl	64.54
Oil Swaps WTI Index | Fourth Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	460,000
Weighted Average Price
Weighted Avg Price (USD per unit) | $ / bbl	64.54
Gas Swaps Henry Hub | 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	9,625,000
Weighted Average Price
Weighted Avg Price (USD per unit) | $ / bbl	3.00
Gas Swaps Henry Hub | Second Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	3,185,000
Weighted Average Price
Weighted Avg Price (USD per unit) | $ / bbl	3.00
Gas Swaps Henry Hub | Third Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	3,220,000
Weighted Average Price
Weighted Avg Price (USD per unit) | $ / bbl	3.00
Gas Swaps Henry Hub | Fourth Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (MMBtu) | MMBTU	3,220,000
Weighted Average Price
Weighted Avg Price (USD per unit) | $ / bbl	3.00
Oil Sold Calls WTI Index | 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	1,009,250
Weighted Average Price
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	64.36
Oil Sold Calls WTI Index | Second Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	333,970
Weighted Average Price
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	64.36
Oil Sold Calls WTI Index | Third Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	337,640
Weighted Average Price
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	64.36
Oil Sold Calls WTI Index | Fourth Quarter - 2019 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl	337,640
Weighted Average Price
Weighted Avg Price - Ceiling (USD per unit) | $ / bbl	64.36

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DERIVATIVE INSTRUMENTS - (Gain) Loss on Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative [Line Items]
Decrease (increase) in fair value of derivative instruments, net:	$ 106,401	$ (16,548)
Cash (receipts) payments on derivative instruments, net:	9,051	12,389
Loss (gain) on derivative instruments, net	115,452	(4,159)
Gas contracts
Derivative [Line Items]
Decrease (increase) in fair value of derivative instruments, net:	(9,846)	(11,789)
Cash (receipts) payments on derivative instruments, net:	3,764	(5,119)
Oil contracts
Derivative [Line Items]
Decrease (increase) in fair value of derivative instruments, net:	116,247	(4,759)
Cash (receipts) payments on derivative instruments, net:	$ 5,287	$ 17,508

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DERIVATIVE INSTRUMENTS - Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Asset
Total gross amounts presented in the balance sheet	$ 35,830	$ 101,939
Liability
Total gross amounts presented in the balance sheet	77,557	27,627
Not Designated as Hedging Instrument
Asset
Total gross amounts presented in the balance sheet	36,456	111,185
Less: gross amounts not offset in the balance sheet	(26,283)	(29,894)
Net amount	10,173	81,291
Liability
Total gross amounts presented in the balance sheet	78,313	29,894
Less: gross amounts not offset in the balance sheet	(26,283)	(29,894)
Net amount	52,030	0
Current assets — Derivative instruments | Not Designated as Hedging Instrument | Oil contracts
Asset
Total gross amounts presented in the balance sheet	19,328	94,240
Current assets — Derivative instruments | Not Designated as Hedging Instrument | Gas contracts
Asset
Total gross amounts presented in the balance sheet	16,502	7,699
Non-current assets — Derivative instruments | Not Designated as Hedging Instrument | Oil contracts
Asset
Total gross amounts presented in the balance sheet	222	9,246
Non-current assets — Derivative instruments | Not Designated as Hedging Instrument | Gas contracts
Asset
Total gross amounts presented in the balance sheet	404
Current liabilities — Derivative instruments | Not Designated as Hedging Instrument | Oil contracts
Liability
Total gross amounts presented in the balance sheet	73,517	23,378
Current liabilities — Derivative instruments | Not Designated as Hedging Instrument | Gas contracts
Liability
Total gross amounts presented in the balance sheet	4,040	4,249
Non-current liabilities — Derivative instruments | Not Designated as Hedging Instrument | Oil contracts
Liability
Total gross amounts presented in the balance sheet	749	311
Non-current liabilities — Derivative instruments | Not Designated as Hedging Instrument | Gas contracts
Liability
Total gross amounts presented in the balance sheet	$ 7	$ 1,956

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FAIR VALUE MEASUREMENTS - Summary (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018	Apr. 30, 2017	Jun. 30, 2014
Financial Assets (Liabilities):
Derivative instruments — assets	$ 35,830	$ 101,939
Derivative instruments — liabilities	$ (77,557)	(27,627)
4.375% Notes due 2024 | Senior Notes
Financial Assets (Liabilities):
Stated interest rate (as a percent)	4.375%			4.375%
3.90% Notes due 2027 | Senior Notes
Financial Assets (Liabilities):
Stated interest rate (as a percent)	3.90%		3.90%
4.375% Notes due 2029 | Senior Notes
Financial Assets (Liabilities):
Stated interest rate (as a percent)	4.375%
Book Value
Financial Assets (Liabilities):
Derivative instruments — assets	$ 36,456	111,185
Derivative instruments — liabilities	(78,313)	(29,894)
Book Value | 4.375% Notes due 2024
Financial Assets (Liabilities):
Long-term debt	(750,000)	(750,000)
Book Value | 3.90% Notes due 2027
Financial Assets (Liabilities):
Long-term debt	(750,000)	(750,000)
Book Value | 4.375% Notes due 2029
Financial Assets (Liabilities):
Long-term debt	(500,000)	0
Fair Value
Financial Assets (Liabilities):
Derivative instruments — assets	36,456	111,185
Derivative instruments — liabilities	(78,313)	(29,894)
Fair Value | 4.375% Notes due 2024
Financial Assets (Liabilities):
Long-term debt	(779,340)	(744,578)
Fair Value | 3.90% Notes due 2027
Financial Assets (Liabilities):
Long-term debt	(748,620)	(701,273)
Fair Value | 4.375% Notes due 2029
Financial Assets (Liabilities):
Long-term debt	$ (514,380)	$ 0

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FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Other Financial Instruments
Accrued operating expenses	$ 84.0	$ 69.1
Accrued payroll related general and administrative expenses		47.4
Overdrawn account accrual		35.8
Allowance for Trade Receivables
Other Financial Instruments
Aggregate allowance for doubtful accounts	$ 2.7	$ 2.7

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CAPITAL STOCK - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended		3 Months Ended		12 Months Ended
	Mar. 31, 2019	Feb. 28, 2019	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Class of Stock [Line Items]
Common stock authorized (shares)	200,000,000		200,000,000		200,000,000
Preferred stock authorized (shares)	15,000,000		15,000,000
Common stock outstanding (shares)	101,400,000		101,400,000
Preferred stock dividend rate (as a percent)			8.125%		8.125%
Preferred stock, par value (USD per share)	$ 0.01		$ 0.01
Preferred stock liquidation preference per share (USD per share)	$ 1,000		$ 1,000
Preferred stock, liquidation preference	$ 62,500		$ 62,500
Stock issued upon conversion of preferred stock (shares)	8.0421		8.0421
Price received per share upon conversion (USD per share)	$ 471.40		$ 471.40
Dividends
Dividends declared per common share (USD per share)		$ 0.2
Dividends declared from retained earnings		$ 20,300	$ 20,308	$ 15,271
Preferred stock cash dividends	$ 1,300
Preferred Stock
Class of Stock [Line Items]
Issuance of stock for acquisition (shares)	62,500
Dividends
Dividends declared per preferred share (USD per share)			$ 20.31

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STOCK-BASED COMPENSATION - Summary (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Options, Restricted Stock and Unit Awards
Stock compensation cost	$ 13,247	$ 12,418
Less amounts capitalized to oil and gas properties	(6,534)	(5,688)
Stock compensation expense	6,713	6,730
Restricted stock awards:
Options, Restricted Stock and Unit Awards
Stock compensation cost	12,625	11,801
Performance stock awards
Options, Restricted Stock and Unit Awards
Stock compensation cost	5,394	6,729
Service-based stock awards
Options, Restricted Stock and Unit Awards
Stock compensation cost	7,231	5,072
Stock option awards
Options, Restricted Stock and Unit Awards
Stock compensation cost	$ 622	$ 617

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ASSET RETIREMENT OBLIGATIONS - Summary (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Asset Retirement Obligations
Balance at beginning of year	$ 166,904
Liabilities incurred	10,009
Liability settlements and disposals	(1,361)
Accretion expense	1,793
Revisions of estimated liabilities	1,912
Balance at end of year	179,257
Less current obligation	(13,728)
Long-term asset retirement obligation	$ 165,529	$ 152,758

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ASSET RETIREMENT OBLIGATIONS - Narrative (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Mar. 01, 2019
Resolute Energy Corporation
Business Acquisition [Line Items]
Liabilities incurred	$ 9,400	$ 9,437

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EARNINGS PER SHARE - Summary (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income (Numerator)
Net income	$ 26,316	$ 186,318
Less: net income attributable to participating securities	(445)	(2,666)
Less: preferred stock dividends	(1,269)	0
Basic EPS - Income available to common stockholders	24,602	183,652
Diluted EPS - Income available to common stockholders and assumed conversions	$ 24,602	$ 183,652
Shares (Denominator)
Basic EPS - Income available to common stockholders (shares)	95,922,000	93,699,000
Effects of dilutive securities - options (shares)	10,000	38,000
Diluted EPS - Income available to common stockholders and assumed conversions (shares)	95,932,000	93,737,000
Per-Share Amount
Basic EPS - Income available to common stockholders (USD per share)	$ 0.26	$ 1.96
Diluted EPS - Income available to common stockholders and assumed conversions (USD per share)	$ 0.26	$ 1.96
Employee Stock Option
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Excluded antidilutive securities (shares)	388,600	295,600
Convertible Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Excluded antidilutive securities (shares)	502,600

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INCOME TAXES - Components of the Provision for Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Tax Expense (Benefit)
Deferred tax expense	$ 8,073	$ 56,949
Combined federal and state effective income tax rate (as a percent)	23.50%	23.40%

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INCOME TAXES - Narrative (Details) - USD ($)	Mar. 31, 2019	Mar. 01, 2019	Dec. 31, 2018
Income Tax Contingency [Line Items]
U.S. net tax operating loss carryforward			$ 1,160,000,000
Unrecognized tax benefits that would impact the entity's effective rate	$ 0
Provisions for interest or penalties related to uncertain tax positions	0
Resolute Energy Corporation
Income Tax Contingency [Line Items]
Deferred tax liability	$ 62,400,000	$ 62,409,000
Oil Recovery and Marginal Well Credits
Income Tax Contingency [Line Items]
Tax credit carryforward			$ 3,500,000

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COMMITMENTS AND CONTINGENCIES - Narrative (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2019 USD ($) Bcf	Dec. 31, 2018 USD ($)
Construction, Drilling and Purchase Commitments
Right-of-use asset obtained in exchange for operating leases	$ 16,200
Future minimum payments due on operating leases		$ 75,033
Minimum
Construction, Drilling and Purchase Commitments
Oil and gas delivery commitments and contracts, period	1 month
Drilling Commitments
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 447,900
Gathering System Construction
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 36,300
Natural Gas Sales Contracts
Construction, Drilling and Purchase Commitments
Oil and gas delivery commitments and contracts, remaining contractual volume (bcf) | Bcf	456.4
Oil and gas delivery commitments and contracts, period	5 years 10 months
Maximum financial commitment resulting from inability to meet gas delivery commitments	$ 461,300
Gas Gathering and Processing Agreements
Construction, Drilling and Purchase Commitments
Oil and gas delivery commitments and contracts, period	9 years 9 months
Maximum financial commitment resulting from inability to meet gas delivery commitments	$ 662,700
Minimum Volume Agreement
Construction, Drilling and Purchase Commitments
Maximum financial commitment resulting from inability to meet gas delivery commitments	55,500
Commitment liability	2,700
Other Transportation and Delivery Commitments and Facilities Commitments
Construction, Drilling and Purchase Commitments
Maximum financial commitment resulting from inability to meet gas delivery commitments	$ 25,600
Office Space | Minimum
Construction, Drilling and Purchase Commitments
Remaining lease term	5 years 2 months 13 days
Office Space | Maximum
Construction, Drilling and Purchase Commitments
Remaining lease term	7 years 4 months 25 days
Energy Equipment | Minimum
Construction, Drilling and Purchase Commitments
Remaining lease term	1 month
Energy Equipment | Maximum
Construction, Drilling and Purchase Commitments
Remaining lease term	11 years 3 months 20 days
Gathering System
Construction, Drilling and Purchase Commitments
Remaining lease term	6 years 4 months 25 days
Exploration and Development Equipment | Maximum
Construction, Drilling and Purchase Commitments
Remaining lease term	12 months
Compressor Equipment
Construction, Drilling and Purchase Commitments
Future minimum payments due on operating leases		$ 34,800
Compressor Equipment | Minimum
Construction, Drilling and Purchase Commitments
Remaining lease term		1 month
Compressor Equipment | Maximum
Construction, Drilling and Purchase Commitments
Remaining lease term		35 months

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COMMITMENTS AND CONTINGENCIES - Supplemental Balance Sheet Information (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Assets:
Operating lease right-of-use assets	$ 233,644
Finance lease right-of-use assets	28,138
Total right-of-use assets	261,782
Liabilities:
Operating lease liabilities — current	62,825	$ 0
Operating lease liabilities — non-current	186,356	$ 0
Finance lease liability — current	5,936
Finance lease liability — non-current	23,500
Total lease liabilities	$ 278,617

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COMMITMENTS AND CONTINGENCIES - Lease Cost (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Finance lease cost:
Amortization of right-of-use asset	$ 1,096
Interest on lease liability	486
Operating lease cost:
Short-term lease cost	154,710
Total lease cost	168,589
Production expense
Operating lease cost:
Operating lease cost	3,834
Gas gathering and other expense
Operating lease cost:
Operating lease cost	6,164
General and administrative expense
Operating lease cost:
Operating lease cost	$ 2,299

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COMMITMENTS AND CONTINGENCIES - Cash Paid for Leases (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash paid for amounts included in the measurement of lease liabilities:
Financing cash outflows from finance lease	$ 635	$ 0
Operating cash outflows from operating leases	12,493
Cash paid for short-term leases and variable lease payments:
Investing cash outflows from operating leases	$ 139,473

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COMMITMENTS AND CONTINGENCIES - Weighted-Average Remaining Lease Term and Discount Rate (Details)	Mar. 31, 2019
Weighted-average remaining lease term (in years):
Finance lease	6 years 4 months 25 days
Operating leases	4 years 8 months 12 days
Weighted-average discount rate:
Finance leases (as a percent)	6.70%
Operating leases (as a percent)	4.10%

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COMMITMENTS AND CONTINGENCIES - Maturity Analysis of Leases (Details) $ in Thousands	Mar. 31, 2019 USD ($)
Operating Leases
April 1, 2019 — March 31, 2020	$ 71,895
April 1, 2020 — March 31, 2021	59,020
April 1, 2021 — March 31, 2022	53,649
April 1, 2022 — March 31, 2023	45,801
April 1, 2023 — March 31, 2024	21,665
Remaining periods	21,836
Total undiscounted future cash flows	273,866
Less effects of discounting	(24,685)
Lease liabilities recognized	249,181
Finance Lease
April 1, 2019 — March 31, 2020	6,808
April 1, 2020 — March 31, 2021	5,950
April 1, 2021 — March 31, 2022	5,658
April 1, 2022 — March 31, 2023	5,366
April 1, 2023 — March 31, 2024	5,075
Remaining periods	6,690
Total undiscounted future cash flows	35,547
Less effects of discounting	(6,111)
Lease liabilities recognized	$ 29,436

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COMMITMENTS AND CONTINGENCIES - Future Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
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

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SUPPLEMENTAL CASH FLOW INFORMATION - Summary (Details) - USD ($) $ in Thousands		3 Months Ended
	Mar. 01, 2019	Mar. 31, 2019	Mar. 31, 2018
Cash paid during the period for:
Interest (net of capitalized amounts of $740 and $156, respectively) (1)		$ 18,588	$ 389
Income taxes		6	0
Cash received for income tax refunds		1	2
Interest capitalized		$ 740	$ 156
Resolute Energy Corporation
Cash paid during the period for:
Interest (net of capitalized amounts of $740 and $156, respectively) (1)	$ 17,600

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RELATED PARTY TRANSACTIONS - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Helmerich & Payne
Related Party Transaction [Line Items]
Contract drilling service costs	$ 24.5	$ 23.6

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ACQUISITIONS - Narrative (Details) - USD ($)		1 Months Ended	3 Months Ended
	Mar. 01, 2019	Mar. 31, 2019	Mar. 31, 2019	Mar. 31, 2018	Mar. 08, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Purchase price allocation period			12 months
Loss on early extinguishment of debt	$ (4,300,000)		$ (4,250,000)	$ 0
Goodwill		$ 727,573,000	$ 727,573,000			$ 620,232,000
Resolute Energy Corporation
Business Acquisition [Line Items]
Proportion of voting interests acquired (as a percent)	100.00%
Total consideration transferred	$ 820,312,000
Long-term debt acquired	870,000,000
Goodwill	107,341,000
Acquisition-related costs	8,300,000
Revenue of acquiree since acquisition date		24,200,000
Direct operating expenses of acquiree since acquisition date		$ 5,300,000
Senior Notes | Resolute Energy Corporation
Business Acquisition [Line Items]
Long-term debt acquired	600,000,000
Senior Notes | 4.375% Notes due 2029
Business Acquisition [Line Items]
Senior notes principal					$ 500,000,000
Stated interest rate (as a percent)		4.375%	4.375%
Credit Facility | Resolute Energy Corporation
Business Acquisition [Line Items]
Long-term debt acquired	270,000,000
Resolute Energy Corporation
Business Acquisition [Line Items]
Acquisition-related costs	$ 60,000,000

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ACQUISITIONS - Consideration Transferred (Details) - Resolute Energy Corporation shares in Thousands, $ in Thousands	Mar. 01, 2019 USD ($) shares
Business Acquisition [Line Items]
Cash	$ 325,677
Total consideration transferred	820,312
Common stock (5,652 shares issued)
Business Acquisition [Line Items]
Stock	$ 413,015
Stock issued in acquisition (shares) | shares	5,652
Preferred stock (63 shares issued)
Business Acquisition [Line Items]
Stock	$ 81,620
Stock issued in acquisition (shares) | shares	63

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ACQUISITIONS - Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Mar. 01, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Goodwill	$ 727,573		$ 620,232
Resolute Energy Corporation
Business Acquisition [Line Items]
Cash		$ 41,236
Accounts receivable		50,739
Other current assets		13,280
Proved oil and gas properties		692,600
Unproved oil and gas properties		1,054,200
Fixed assets		5,355
Other assets		142
Goodwill		107,341
Current liabilities		(202,735)
Long-term debt		(870,000)
Deferred income taxes	(62,400)	(62,409)
Asset retirement obligation	$ (9,400)	(9,437)
Total identifiable net assets		$ 820,312

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ACQUISITIONS - Pro Forma Information (Details) - Resolute Energy Corporation - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Business Acquisition, Pro Forma Information [Abstract]
Revenue	$ 630,093	$ 638,078
Net income	$ 12,617	$ 187,079
Net income per share:
Basic (USD per share)	$ 0.11	$ 1.84
Diluted (USD per share)	$ 0.11	$ 1.84