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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 June 30, 2018March 31, 2019
or
oTransition 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 ofor 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 
Yes ý  No o
Indicate by check mark 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
  
(Do not check if a smaller
reporting company)
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 July 31, 2018April 30, 2019 was 95,356,074.101,433,207.

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock ($0.01 par value)XECNew York Stock Exchange



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CIMAREX ENERGY CO.
Table of Contents
 
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GLOSSARY

Bbls—Barrels
Bcf—Billion cubic feet
BOE—Barrels of oil equivalent
Gross Wells—The total wells in which a working interest is owned.
MBbls—Thousand barrels
MBOE—Thousand barrels of oil equivalent
Mcf—Thousand cubic feet
MMBtu—Million British thermal units
MMcf—Million cubic feet
Net Wells—The sum of the fractional working interest owned in gross wells expressed in whole numbers and fractions of whole numbers.
NGL or NGLs—Natural gas liquids

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

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.




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PART I
ITEM 1. - Financial Statements
CIMAREX ENERGY CO.
Condensed Consolidated Balance Sheets
(in thousands, except share and per share information)
(Unaudited)
 June 30, December 31, March 31, December 31,
 2018 2017 2019 2018
Assets  
  
  
  
Current assets:  
  
  
  
Cash and cash equivalents $410,823
 $400,534
 $20,930
 $800,666
Accounts receivable, net of allowance:  
  
  
  
Trade 128,984
 100,356
 123,192
 122,065
Oil and gas sales 304,255
 344,552
 329,661
 315,063
Gas gathering, processing, and marketing 11,416
 15,266
 13,049
 17,072
Oil and gas well equipment and supplies 53,375
 49,722
 62,600
 55,553
Derivative instruments 72,943
 15,151
 35,830
 101,939
Prepaid expenses 7,419
 8,518
 8,135
 7,554
Other current assets 927
 1,536
 2,811
 4,227
Total current assets 990,142
 935,635
 596,208
 1,424,139
Oil and gas properties at cost, using the full cost method of accounting:  
  
  
  
Proved properties 18,112,548
 17,513,460
 19,410,269
 18,566,757
Unproved properties and properties under development, not being amortized 532,715
 476,903
 1,707,089
 436,325
 18,645,263
 17,990,363
 21,117,358
 19,003,082
Less—accumulated depreciation, depletion, amortization, and impairment (15,000,443) (14,748,833) (15,462,464) (15,287,752)
Net oil and gas properties 3,644,820
 3,241,530
 5,654,894
 3,715,330
Fixed assets, net of accumulated depreciation of $312,927 and $290,114, respectively 238,964
 210,922
Fixed assets, net of accumulated depreciation of $340,147 and $324,631, respectively 509,554
 257,686
Goodwill 620,232
 620,232
 727,573
 620,232
Derivative instruments 2,330
 2,086
 626
 9,246
Other assets 34,905
 32,234
 68,337
 35,451
 $5,531,393
 $5,042,639
 $7,557,192
 $6,062,084
Liabilities and Stockholders’ Equity  
  
Liabilities, Redeemable Preferred Stock, and Stockholders’ Equity  
  
Current liabilities:  
  
  
  
Accounts payable:    
    
Trade $74,596
 $68,883
 $65,664
 $76,927
Gas gathering, processing, and marketing 20,643
 29,503
 25,190
 29,887
Accrued liabilities:  
  
  
  
Exploration and development 146,886
 115,762
 183,940
 124,674
Taxes other than income 24,392
 23,687
 32,084
 33,622
Other 199,093
 212,400
 247,041
 221,159
Derivative instruments 90,480
 42,066
 77,557
 27,627
Revenue payable 180,869
 187,273
 215,613
 194,811
Operating leases 62,825
 
Total current liabilities 736,959
 679,574
 909,914
 708,707
Long-term debt:  
  
Principal 1,500,000
 1,500,000
Less—unamortized debt issuance costs and discount (12,261) (13,080)
Long-term debt, net 1,487,739
 1,486,920
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 201,350
 101,618
 405,294
 334,473
Asset retirement obligation 159,568
 158,421
 165,529
 152,758
Derivative instruments 11,511
 4,268
 756
 2,267
Operating leases 186,356
 
Other liabilities 47,768
 43,560
 62,634
 45,539
Total liabilities 2,644,895
 2,474,361
 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:  
  
  
  
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued 
 
Common stock, $0.01 par value, 200,000,000 shares authorized, 95,392,547 and 95,437,434 shares issued, respectively 954
 954
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 2,770,532
 2,764,384
 3,210,818
 2,785,188
Retained earnings (accumulated deficit) 112,811
 (199,259)
Retained earnings 547,626
 542,885
Accumulated other comprehensive income 2,201
 2,199
 1,904
 755
Total stockholders’ equity 2,886,498
 2,568,278
 3,761,362
 3,329,786
 $5,531,393
 $5,042,639
 $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
June 30,
 Six Months Ended
June 30,
 Three Months Ended
March 31,
 2018 2017 2018 2017 2019 2018
Revenues:  
  
  
  
  
  
Oil sales $342,184
 $232,453
 $693,907
 $456,519
 $349,306
 $351,723
Gas and NGL sales 202,202
 213,360
 405,920
 425,731
 217,915
 203,718
Gas gathering and other 11,810
 10,735
 23,262
 21,360
 10,262
 11,452
Gas marketing 78
 (96) 319
 18
 (526) 241
 556,274
 456,452
 1,123,408
 903,628
 576,957
 567,134
Costs and expenses:  
  
  
  
  
  
Depreciation, depletion, and amortization 143,388
 107,884
 276,247
 203,700
 190,417
 132,859
Asset retirement obligation 2,053
 960
 3,113
 2,580
 2,049
 1,060
Production 79,215
 62,578
 150,486
 124,999
 77,233
 71,271
Transportation, processing, and other operating 51,933
 58,624
 97,098
 113,647
 53,608
 45,165
Gas gathering and other 9,467
 8,647
 19,290
 17,074
 12,320
 9,823
Taxes other than income 27,930
 17,477
 58,118
 38,790
 33,694
 30,188
General and administrative 19,739
 19,762
 43,060
 37,796
 29,084
 23,321
Stock compensation 3,095
 6,293
 9,825
 12,581
 6,713
 6,730
Loss (gain) on derivative instruments, net 21,699
 (22,509) 17,540
 (66,370) 115,452
 (4,159)
Other operating expense, net 5,252
 266
 5,455
 882
 8,326
 203
 363,771
 259,982
 680,232
 485,679
 528,896
 316,461
Operating income 192,503
 196,470
 443,176
 417,949
 48,061
 250,673
Other (income) and expense:  
  
  
  
  
  
Interest expense 16,895
 20,095
 33,678
 41,147
 20,405
 16,783
Capitalized interest (4,850) (5,442) (9,660) (12,083) (8,742) (4,810)
Loss on early extinguishment of debt 
 28,169
 
 28,169
 4,250
 
Other, net (2,605) (2,231) (7,172) (4,441) (2,241) (4,567)
Income before income tax 183,063
 155,879
 426,330
 365,157
 34,389
 243,267
Income tax expense 42,066
 58,617
 99,015
 136,923
 8,073
 56,949
Net income $140,997
 $97,262
 $327,315
 $228,234
 $26,316
 $186,318
            
Earnings per share to common stockholders:  
  
  
  
  
  
Basic $1.48
 $1.02
 $3.44
 $2.40
 $0.26
 $1.96
Diluted $1.48
 $1.02
 $3.44
 $2.40
 $0.26
 $1.96
            
Dividends declared per share $0.16
 $0.08
 $0.32
 $0.16
        
Comprehensive income:  
  
  
  
  
  
Net income $140,997
 $97,262
 $327,315
 $228,234
 $26,316
 $186,318
Other comprehensive income:  
  
  
  
  
  
Change in fair value of investments, net of tax of $57, $128, $1, and $359, respectively 192
 224
 2
 626
Change in fair value of investments, net of tax of $339 and ($56), respectively 1,149
 (190)
Total comprehensive income $141,189
 $97,486
 $327,317
 $228,860
 $27,465
 $186,128
 





See accompanying Notes to Condensed Consolidated Financial Statements.


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CIMAREX ENERGY CO.
Condensed Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
 Six Months Ended
June 30,
 Three Months Ended
March 31,
 2018 2017 2019 2018
Cash flows from operating activities:  
  
  
  
Net income $327,315
 $228,234
 $26,316
 $186,318
Adjustments to reconcile net income to net cash provided by operating activities:  
  
  
  
Depreciation, depletion, and amortization 276,247
 203,700
 190,417
 132,859
Asset retirement obligation 3,113
 2,580
 2,049
 1,060
Deferred income taxes 99,732
 136,929
 8,073
 56,949
Stock compensation 9,825
 12,581
 6,713
 6,730
Loss (gain) on derivative instruments, net 17,540
 (66,370) 115,452
 (4,159)
Settlements on derivative instruments (19,919) (5,717) (9,051) (12,389)
Loss on early extinguishment of debt 
 28,169
 4,250
 
Amortization of debt issuance costs and discounts 719
 729
Changes in non-current assets and liabilities 713
 1,076
 2,148
 (900)
Other, net 2,179
 3,445
 3,976
 37
Changes in operating assets and liabilities:  
  
  
  
Accounts receivable 15,012
 (61,145) 33,976
 44,722
Other current assets 1,886
 (11,104) 350
 1,603
Accounts payable and other current liabilities (29,304) 32,422
 (135,297) (30,466)
Net cash provided by operating activities 704,339
 504,800
 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 (650,807) (582,172) (332,742) (323,455)
Other capital expenditures (56,112) (18,209) (17,828) (19,056)
Sales of oil and gas assets 34,842
 9,163
 5,000
 29,824
Sales of other assets 525
 394
 200
 432
Net cash used by investing activities (671,552) (590,824) (629,811) (312,255)
Cash flows from financing activities:  
  
  
  
Borrowings of long-term debt 
 748,110
 1,182,310
 
Repayments of long-term debt 
 (750,000) (1,553,000) 
Call premium, financing, and underwriting fees 
 (29,035)
Financing, underwriting, and debt redemption fees (10,938) 
Finance lease payments (635) 
Dividends paid (22,801) (15,153) (17,179) (7,602)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards (946) (1,215) (654) (305)
Proceeds from exercise of stock options 1,249
 36
 80
 345
Net cash used by financing activities (22,498) (47,257) (400,016) (7,562)
Net change in cash and cash equivalents 10,289
 (133,281) (779,736) 63,276
Cash and cash equivalents at beginning of period 400,534
 652,876
 800,666
 400,534
Cash and cash equivalents at end of period $410,823
 $519,595
 $20,930
 $463,810
  




See accompanying Notes to Condensed Consolidated Financial Statements.


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CIMAREX ENERGY CO.
Condensed Consolidated StatementStatements of Stockholders’ Equity
(in thousands)
(Unaudited)

     Additional Paid-in Capital 
Retained
Earnings
(Accumulated Deficit)
 
Accumulated
Other
Comprehensive
Income
 
Total
Stockholders’
Equity
     Additional Paid-in Capital 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income
 
Total
Stockholders’
Equity
Common StockCommon Stock
Shares AmountShares Amount
Balance, December 31, 2017 95,437
 $954
 $2,764,384
 $(199,259) $2,199
 $2,568,278
Balance, December 31, 2018 95,756
 $958
 $2,785,188
 $542,885
 $755
 $3,329,786
Dividends paid on stock awards subsequently forfeited 
 
 29
 17
 
 46
 
 
 
 2
 
 2
Dividends 
 
 
 (15,262) 
 (15,262)
Dividends in excess of retained earnings 
 
 (15,250) 
 
 (15,250)
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 
 
 
 327,315
 
 327,315
 
 
 
 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 
 
 
 
 2
 2
 
 
 
 
 1,149
 1,149
Issuance of restricted stock awards 29
 
 
 
 
 
 11
 
 
 
 
 
Common stock reacquired and retired (8) 
 (946) 
 
 (946) (10) 
 (654) 
 
 (654)
Restricted stock forfeited and retired (82) 
 
 
 
 
 (4) 
 
 
 
 
Exercise of stock options 17
 
 1,249
 
 
 1,249
 3
 
 80
 
 
 80
Stock-based compensation 
 
 21,066
 
 
 21,066
 
 
 13,245
 
 
 13,245
Balance, June 30, 2018 95,393
 $954
 $2,770,532
 $112,811
 $2,201
 $2,886,498
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.


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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018March 31, 2019
(Unaudited)



1.BASIS OF PRESENTATION
The accompanying unaudited financial statements have been prepared by
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, 2017.2018.

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 20182019 financial statement presentation.

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

Use of Estimates

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

Oil and Gas Well Equipment and Supplies

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

Oil and Gas Properties

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




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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
March 31, 2019
(Unaudited)


We did not recognize a ceiling test impairment during the sixthree months ended June 30,March 31, 2019 and 2018 and 2017 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.

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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018
(Unaudited)Revenue Recognition


Revenue Recognition
Oil, Gas, and NGL Sales
Effective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”), utilizing the modified retrospective approach, which we applied to contracts that were not completed as of that date. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of ASC 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating expenses in the statement of operations under prior accounting standards are now reflected as deductions from revenue under ASC 606. The following tables present the impact on our Oil sales, Gas sales, and NGL sales and on our Transportation, processing, and other operating costs from the application of ASC 606 in the current reporting period:
  Three Months Ended
June 30,
  2018 2017
(in thousands) Pre-
ASC 606 Adoption
 Impact of
ASC 606
 Post-
ASC 606 Adoption
 As Reported
Oil sales $342,184
 $
 $342,184
 $232,453
Gas sales 84,727
 (3,940) 80,787
 132,474
NGL sales 125,126
 (3,711) 121,415
 80,886
Total oil, gas, and NGL sales $552,037
 $(7,651) $544,386
 $445,813
         
Transportation, processing, and other operating costs $59,584
 $(7,651) $51,933
 $58,624
  Six Months Ended
June 30,
  2018 2017
(in thousands) Pre-
ASC 606 Adoption
 Impact of
ASC 606
 Post-
ASC 606 Adoption
 As Reported
Oil sales $693,907
 $
 $693,907
 $456,519
Gas sales 197,404
 (6,896) 190,508
 264,419
NGL sales 230,739
 (15,327) 215,412
 161,312
Total oil, gas, and NGL sales $1,122,050
 $(22,223) $1,099,827
 $882,250
         
Transportation, processing, and other operating costs $119,321
 $(22,223) $97,098
 $113,647

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 June 30, 2018,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

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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018
(Unaudited)


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, and are disaggregated in the tables above on that basis.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.
Recently Issued
Lease Accounting Standards

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) (“Topic 842”).  The key provision of this ASU is that a lessee must recognize on its balance sheet: (i) liabilities to make lease payments and (ii) right-of-use assets.  The ASU permitsFASB subsequently issued various ASUs which provided additional implementation guidance. Topic 842 requires lessees to make a policy election to not recognize lease liabilities and right-of-use assets and liabilitieson the balance sheet for leasescontracts that provide lessees with terms of less than 12 months.  Under current generally accepted accounting principles, a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases.  Under this ASU, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease.  Leases convey the right to control the use of an identified asset in exchangeassets for consideration.  Only the lease componentsa period of a contract must be accounted for in accordance with this ASU.  Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics.  An entity may make a policy election to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component.  This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and comprehensive income and cash flows, however, both types of leases require the recognition of assets and liabilities on the balance sheet.  This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are evaluating the potential impact of adopting this guidance, but believe the primary effect will be to record assets and liabilities for contracts currently accounted for as operating leases.  We do not intend to adopt the standard early.
In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842. This ASU provides an optional transition practical expedient to not evaluate under Topic 842 (discussed above) existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. Under the full cost method of accounting, we capitalize to oil and gas properties all property acquisition, exploration, and development costs, which include the costs of land easements. We plan to elect this practical expedient and continue to apply our current accounting policy to account for land easements that existed before our adoption of Topic 842 and will evaluate new or modified land easements under Topic 842 upon our adoption of Topic 842. We are evaluating the potential impact of adopting this guidance and do not intend to adopt the standard early.time. The

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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018March 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 June 30, 2018March 31, 2019 and December 31, 20172018 consisted of the following:
  June 30, 2018 December 31, 2017
(in thousands) Principal 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
 Principal 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
4.375% Senior Notes $750,000
 $(4,906) $745,094
 $750,000
 $(5,383) $744,617
3.90% Senior Notes 750,000
 (7,355) 742,645
 750,000
 (7,697) 742,303
Total long-term debt $1,500,000
 $(12,261) $1,487,739
 $1,500,000
 $(13,080) $1,486,920
  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 June 30,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% notesNotes due 2027 were $5.7$5.4 million and $1.7$1.6 million, respectively. At DecemberMarch 31, 2017,2019, the unamortized debt issuance costs and discount related to the 3.90% notes4.375% Notes due 2029 were $5.9$4.5 million and $1.8$0.7 million, respectively. The 4.375% notesNotes due 2024 were issued at par.

Bank Debt
We have a
On February 5, 2019, we entered into an Amended and Restated Credit Agreement for our senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020. The Credit Facility has. Among other things, the amended and restated credit facility increased the aggregate commitments of $1.0to $1.25 billion with an option for us to increase the aggregate commitments to $1.25$1.5 billion, at any time. There is no borrowing base subjectand extended the maturity date to the discretion of the lenders based on the value of our proved reserves under the Credit Facility.February 5, 2024. As of June 30, 2018,March 31, 2019, we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $997.5 million.$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.




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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 June 30, 2018,March 31, 2019, we were in compliance with all of the financial covenants.

At June 30, 2018March 31, 2019 and December 31, 2017,2018, we had $2.7$4.9 million and $3.4$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 June 30, 2018.March 31, 2019.





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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018March 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 June 30, 2018,March 31, 2019, we have entered into oil and gas collars, and oil basis swaps.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 June 30, 2018 (subsequent to June 30, 2018 through August 6, 2018, we have not entered into any additional derivative contracts):March 31, 2019:
Oil Collars
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 Fourth Quarter Total 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 Fourth Quarter Total
2018:          
WTI (1)
        �� 
Volume (Bbls) 
 
 3,220,000
 2,668,000
 5,888,000
Weighted Avg Price - Floor $
 $
 $49.80
 $51.03
 $50.36
Weighted Avg Price - Ceiling $
 $
 $60.49
 $61.74
 $61.06
2019:          
          
WTI (1)
          
          
Volume (Bbls) 2,070,000
 2,093,000
 1,472,000
 736,000
 6,371,000
 
 3,094,000
 2,944,000
 2,208,000
 8,246,000
Weighted Avg Price - Floor $51.83
 $51.83
 $53.50
 $57.00
 $52.81
 $
 $53.68
 $54.81
 $56.42
 $54.82
Weighted Avg Price - Ceiling $63.77
 $63.77
 $67.13
 $68.04
 $65.04
 $
 $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”).



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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018March 31, 2019
(Unaudited)


Gas Collars
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 Fourth Quarter Total 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 Fourth Quarter Total
2018:          
PEPL (1)
          
Volume (MMBtu) 
 
 11,960,000
 9,200,000
 21,160,000
Weighted Avg Price - Floor $
 $
 $2.19
 $2.12
 $2.16
Weighted Avg Price - Ceiling $
 $
 $2.48
 $2.42
 $2.45
Perm EP (2)
          
Volume (MMBtu) 
 
 9,200,000
 7,360,000
 16,560,000
Weighted Avg Price - Floor $
 $
 $1.92
 $1.81
 $1.87
Weighted Avg Price - Ceiling $
 $
 $2.14
 $2.03
 $2.09
Waha (3)
          
Volume (MMBtu) 
 
 920,000
 920,000
 1,840,000
Weighted Avg Price - Floor $
 $
 $1.35
 $1.35
 $1.35
Weighted Avg Price - Ceiling $
 $
 $1.56
 $1.56
 $1.56
2019:                    
PEPL (1)
                    
Volume (MMBtu) 8,100,000
 8,190,000
 5,520,000
 2,760,000
 24,570,000
 
 13,650,000
 11,040,000
 8,280,000
 32,970,000
Weighted Avg Price - Floor $2.08
 $2.08
 $1.92
 $1.90
 $2.02
 $
 $2.03
 $1.94
 $1.94
 $1.98
Weighted Avg Price - Ceiling $2.39
 $2.39
 $2.26
 $2.33
 $2.36
 $
 $2.39
 $2.32
 $2.37
 $2.36
Perm EP (2)
                    
Volume (MMBtu) 6,300,000
 6,370,000
 4,600,000
 1,840,000
 19,110,000
 
 8,190,000
 6,440,000
 3,680,000
 18,310,000
Weighted Avg Price - Floor $1.73
 $1.73
 $1.50
 $1.35
 $1.64
 $
 $1.67
 $1.49
 $1.40
 $1.55
Weighted Avg Price - Ceiling $1.95
 $1.95
 $1.74
 $1.55
 $1.86
 $
 $1.95
 $1.79
 $1.73
 $1.85
Waha (3)
                    
Volume (MMBtu) 900,000
 910,000
 920,000
 920,000
 3,650,000
 
 3,640,000
 5,520,000
 5,520,000
 14,680,000
Weighted Avg Price - Floor $1.35
 $1.35
 $1.35
 $1.35
 $1.35
 $
 $1.41
 $1.48
 $1.48
 $1.46
Weighted Avg Price - Ceiling $1.56
 $1.56
 $1.56
 $1.56
 $1.56
 $
 $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.



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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018March 31, 2019
(Unaudited)


Oil Basis Swaps
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 Fourth Quarter Total 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 Fourth Quarter Total
2018:          
WTI Midland (1)
          
Volume (Bbls) 
 
 2,484,000
 2,024,000
 4,508,000
Weighted Avg Differential (2) $
 $
 $(3.89) $(4.56) $(4.19)
2019:          
          
WTI Midland (1)
          
          
Volume (Bbls) 1,710,000
 1,729,000
 1,288,000
 552,000
 5,279,000
 
 3,685,500
 3,266,000
 2,530,000
 9,481,500
Weighted Avg Differential (2) $(5.17) $(5.17) $(6.84) $(10.73) $(6.16) $
 $(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.




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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
June 30,
 Six Months Ended
June 30,
 Three Months Ended
March 31,
(in thousands) 2018 2017 2018 2017 2019 2018
Change in fair value of derivative instruments, net:  
  
    
Decrease (increase) in fair value of derivative instruments, net:  
  
Gas contracts $14,566
 $(5,748) $2,777
 $(27,939) $(9,846) $(11,789)
Oil contracts (397) (16,418) (5,156) (44,148) 116,247
 (4,759)
 14,169
 (22,166) (2,379) (72,087) 106,401
 (16,548)
Cash (receipts) payments on derivative instruments, net:  
  
      
  
Gas contracts (9,918) (1,308) (15,037) 1,136
 3,764
 (5,119)
Oil contracts 17,448
 965
 34,956
 4,581
 5,287
 17,508
 7,530
 (343) 19,919
 5,717
 9,051
 12,389
Loss (gain) on derivative instruments, net $21,699
 $(22,509) $17,540
 $(66,370) $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.

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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018March 31, 2019
(Unaudited)


The following tables present the amounts and classifications of our derivative assets and liabilities as of June 30, 2018March 31, 2019 and December 31, 2017,2018, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.
   June 30, 2018   March 31, 2019
(in thousands) Balance Sheet Location Asset Liability Balance Sheet Location Asset Liability
Oil contracts Current assets — Derivative instruments $57,768
 $
 Current assets — Derivative instruments $19,328
 $
Gas contracts Current assets — Derivative instruments 15,175
 
 Current assets — Derivative instruments 16,502
 
Oil contracts Non-current assets — Derivative instruments 1,106
 
 Non-current assets — Derivative instruments 222
 
Gas contracts Non-current assets — Derivative instruments 1,224
 
 Non-current assets — Derivative instruments 404
 
Oil contracts Current liabilities — Derivative instruments 
 88,814
 Current liabilities — Derivative instruments 
 73,517
Gas contracts Current liabilities — Derivative instruments 
 1,666
 Current liabilities — Derivative instruments 
 4,040
Oil contracts Non-current liabilities — Derivative instruments 
 11,237
 Non-current liabilities — Derivative instruments 
 749
Gas contracts Non-current liabilities — Derivative instruments 
 274
 Non-current liabilities — Derivative instruments 
 7
Total gross amounts presented in the balance sheetTotal gross amounts presented in the balance sheet 75,273
 101,991
Total gross amounts presented in the balance sheet 36,456
 78,313
Less: gross amounts not offset in the balance sheetLess: gross amounts not offset in the balance sheet (68,377) (68,377)Less: gross amounts not offset in the balance sheet (26,283) (26,283)
Net amountNet amount $6,896
 $33,614
Net amount $10,173
 $52,030
        
   December 31, 2017    
   December 31, 2018
(in thousands) Balance Sheet Location Asset Liability Balance Sheet Location Asset Liability
Gas contracts Current assets — Derivative instruments $15,151
 $
Oil contracts Current assets — Derivative instruments $94,240
 $
Gas contracts Non-current assets — Derivative instruments 2,086
 
 Current assets — Derivative instruments 7,699
 
Oil contracts Current liabilities — Derivative instruments 
 42,066
 Non-current assets — Derivative instruments 9,246
 
Oil contracts Non-current liabilities — Derivative instruments 
 4,268
 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 sheetTotal gross amounts presented in the balance sheet 17,237
 46,334
Total gross amounts presented in the balance sheet 111,185
 29,894
Less: gross amounts not offset in the balance sheetLess: gross amounts not offset in the balance sheet (17,237) (17,237)Less: gross amounts not offset in the balance sheet (29,894) (29,894)
Net amountNet amount $
 $29,097
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 havehas a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our derivative liability positions. Because some of the member banks have discontinued derivative activities, inpositions, nor do we require our counterparties to post collateral for our benefit. In the future we may enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

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.


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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018March 31, 2019
(Unaudited)


The following table provides fair value measurement information for certain assets and liabilities as of June 30, 2018March 31, 2019 and December 31, 2017:2018:
 June 30, 2018 December 31, 2017 March 31, 2019 December 31, 2018
(in thousands) 
Book
Value
 
Fair
Value
 
Book
Value
 
Fair
Value
 
Book
Value
 
Fair
Value
 
Book
Value
 
Fair
Value
Financial Assets (Liabilities):  
      
  
      
4.375% Notes due 2024 $(750,000) $(758,228) $(750,000) $(797,010) $(750,000) $(779,340) $(750,000) $(744,578)
3.90% Notes due 2027 $(750,000) $(721,763) $(750,000) $(767,813) $(750,000) $(748,620) $(750,000) $(701,273)
4.375% Notes due 2029 $(500,000) $(514,380) $
 $
Derivative instruments — assets $75,273
 $75,273
 $17,237
 $17,237
 $36,456
 $36,456
 $111,185
 $111,185
Derivative instruments — liabilities $(101,991) $(101,991) $(46,334) $(46,334) $(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 June 30, 2018March 31, 2019 were accrued operating expenses of approximately $59.6$84.0 million. Included in “Accrued liabilities — Other” at December 31, 20172018 were: (i) accrued operating expenses of approximately $61.3$69.1 million, and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $54.6 million.$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 June 30, 2018March 31, 2019 and December 31, 2017,2018, the allowance for doubtful accounts was $2.7 million and $2.2$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 June 30, 2018,March 31, 2019, there were 95.4101.4 million shares of common stock and nooutstanding.

From the 15 million shares of preferred stock outstanding.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



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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 May 2018,February 2019, our Board of Directors declared a cash dividend of $0.16$0.20 per share.share of common stock. The dividend is payable on or before AugustMay 31, 20182019 to stockholders of record on AugustMay 15, 2018.2019. 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 $15.3$20.3 million dividend declared during the first quarter 2018 was recorded as a reduction of additional paid-in capital, while the $15.3 million dividend declared during the second quarter 20182019 was recorded as a reduction of retained earnings.earnings and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet. Nonforfeitable dividends paid on stock awards that

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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018
(Unaudited)


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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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
June 30,
 Six Months Ended
June 30,
 Three Months Ended
March 31,
(in thousands) 2018 2017 2018 2017 2019 2018
Restricted stock awards:            
Performance stock awards $3,809
 $6,438
 $10,538
 $12,840
 $5,394
 $6,729
Service-based stock awards 4,247
 4,208
 9,319
 9,132
 7,231
 5,072
 8,056
 10,646
 19,857
 21,972
 12,625
 11,801
Stock option awards 637
 579
 1,254
 1,245
 622
 617
Total stock compensation cost 8,693
 11,225
 21,111
 23,217
 13,247
 12,418
Less amounts capitalized to oil and gas properties (5,598) (4,932) (11,286) (10,636) (6,534) (5,688)
Stock compensation expense $3,095
 $6,293
 $9,825
 $12,581
 $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. The decrease in total stock compensation cost in the 2018 periods as compared to the 2017 periods is primarily due to performance stock award forfeitures during the three months ended June 30, 2018. Our accounting policy is to account for forfeitures in compensation cost when they occur.

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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018
(Unaudited)


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 sixthree months ended June 30, 2018:March 31, 2019:
(in thousands) Six Months Ended
June 30, 2018
 Three Months Ended
March 31, 2019
Asset retirement obligation at January 1, 2018 $169,469
Asset retirement obligation at January 1, 2019 $166,904
Liabilities incurred 3,921
 10,009
Liability settlements and disposals (10,103) (1,361)
Accretion expense 3,712
 1,793
Revisions of estimated liabilities 999
 1,912
Asset retirement obligation at June 30, 2018 167,998
Asset retirement obligation at March 31, 2019 179,257
Less current obligation (8,430) (13,728)
Long-term asset retirement obligation $159,568
 $165,529

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


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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018March 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 June 30,
  2018 2017
(in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount Income (Numerator) Shares (Denominator) Per-Share Amount
Net income $140,997
  
   $97,262
    
Less: net income attributable to participating securities (1,892)     (1,643)    
Basic earnings per share            
Income available to common stockholders 139,105
 93,728
 $1.48
 95,619
 93,402
 $1.02
Effects of dilutive securities            
Options (1) 
 31
   1
 33
  
Diluted earnings per share            
Income available to common stockholders and assumed conversions $139,105
 93,759
 $1.48
 $95,620
 93,435
 $1.02

 Six Months Ended June 30, Three Months Ended March 31,
 2018 2017 2019 2018
(in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount Income (Numerator) Shares (Denominator) Per-Share Amount Income (Numerator) Shares (Denominator) Per-Share Amount Income (Numerator) Shares (Denominator) Per-Share Amount
Net income $327,315
  
   $228,234
     $26,316
  
   $186,318
    
Less: net income attributable to participating securities (4,546)     (3,898)     (445)     (2,666)    
Less: preferred stock dividends (1,269)     
    
Basic earnings per share                        
Income available to common stockholders 322,769
 93,713
 $3.44
 224,336
 93,396
 $2.40
 24,602
 95,922
 $0.26
 183,652
 93,699
 $1.96
Effects of dilutive securities            
Options (1) 1
 35
   1
 35
  
Effects of dilutive securities (1)
            
Options 
 10
   
 38
  
Diluted earnings per share                        
Income available to common stockholders and assumed conversions $322,770
 93,748
 $3.44
 $224,337
 93,431
 $2.40
 $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;effect, therefore, 292.1 thousand and 295.6 thousandthese shares were excluded from the calculations for the three and six months ended June 30, 2018 and 300.5 thousand and 255.0 thousand shares were excludedof diluted earnings per share. Excluded from the calculations forMarch 31, 2019 calculation were 388.6 thousand potential common shares from the threeassumed exercise of employee stock options and six months ended June 30, 2017.502.6 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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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018
(Unaudited)


9.INCOME TAXES

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

 Three Months Ended
June 30,
 Six Months Ended
June 30,
 Three Months Ended
March 31,
(in thousands) 2018 2017 2018 2017 2019 2018
Current tax benefit $(717) $
 $(717) $(6)
Deferred tax expense 42,783
 58,617
 99,732
 136,929
 $8,073
 $56,949
 $42,066
 $58,617
 $99,015
 $136,923
    
Combined federal and state effective income tax rate 23.0% 37.6% 23.2% 37.5% 23.5% 23.4%

At December 31, 2017,2018, we had a U.S. net tax operating loss carryforward of approximately $1,377.7 million,$1.16 billion, which will expire in tax years 20312032 through 2037. We believe that the carryforward will be utilized before it expires. We also had an alternative minimumenhanced 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



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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 carryforward of approximately $3.0 million and other credits of $0.9 million.carryforwards. The carryforwards are subject to an annual limitation under Internal Revenue Code Section 382.

At June 30, 2018,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 20142016 through 20162018 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 20132015 through 2016.2018.

Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 21% in 2018 and 35% in 2017 primarily due to state income taxes and non-deductible expenses.
As a result of the enactment of H.R.1, known as the Tax Cuts and Jobs Act, on December 22, 2017, we remeasured our deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the U.S. income tax rate from 35% to 21% for years after 2017. We believe the accounting for the effects of H.R.1 recognized in the December 31, 2017 financial statements is materially complete. However, evolving analyses and interpretations of the law may cause a change to the amounts presented. Any such changes that may arise will be recognized in the period determined, but no later than December 31, 2018. As a result of H.R.1, we expect our effective tax rate in future periods will be lower than in periods prior to enactment.
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 June 30,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



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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.




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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.




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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 lease6.4
Operating leases4.7
Weighted-average discount rate:
Finance lease6.7%
Operating leases4.1%

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) $154.4$447.9 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $14.4$36.3 million to finish gathering system construction in progress.

At June 30, 2018,March 31, 2019, we had firm sales contracts to deliver approximately 330.7456.4 Bcf of gas over the next 6.65.8 years. If we do not deliver this gas, our estimated financial commitment, calculated using the July 2018April 2019 index price, would be approximately $659.9$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 9.59.8 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 June 30, 2018,March 31, 2019, would be approximately $351.0$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.

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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018
(Unaudited)


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 June 30, 2018,March 31, 2019, would be approximately $7.4$55.5 million. Of this total, we have accrued a liability of $2.5$2.7 million, representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.

At June 30, 2018,March 31, 2019, we have various firm transportation agreements for gas pipeline capacity with end dates ranging from 20182019 - 2025 under which we will have to pay an estimated $26.6$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.
At June 30, 2018, we have various future commitments under operating lease arrangements for commercial real estate, consisting primarily of office space, and compressor equipment. The commitments under the commercial real estate operating leases, which have lease terms expiring within the next 8.2 years, total approximately $80.9 million. The commitments under the compressor equipment operating leases, which have lease terms expiring within the next 2 - 24 months, total approximately $9.3 million.
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



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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
June 30,
 Six Months Ended
June 30,
 Three Months Ended
March 31,
(in thousands) 2018 2017 2018 2017 2019 2018
Cash paid during the period for:  
  
  
  
  
  
Interest expense (net of capitalized amounts of $9,233, $11,659, $9,389, and $11,962, respectively) $22,954
 $28,115
 $23,343
 $28,772
Interest (net of capitalized amounts of $740 and $156, respectively) (1) $18,588
 $389
Income taxes $
 $1
 $
 $3
 $6
 $
Cash received for income tax refunds $717
 $
 $718
 $21
 $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.




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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.




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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 profitably growincrease shareholder value through the profitable long-term growth of our proved reserves and production for the long-term benefit of our stockholders through a balanced and abundant drilling inventory while seeking to minimize our impact on the communities in which we operate for the long-term. Our strategy centers on maximizing cash flow from producing properties and profitably reinvestingso that cash flowwe can reinvest in exploration and development activities.opportunities and provide cash returns to shareholders through increasing dividends. We consider property acquisitions, dispositions,merger and occasional mergers toacquisition opportunities that enhance our competitive position.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-strategicnon-core assets, and, occasionalfrom time to time, public financing based on our monitoring of capital markets and our balance sheet. Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand unpredictable fluctuations in commodity prices.

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.
During
Market prices for oil have declined and market prices for gas have increased during the first sixthree months of 20182019 as compared to the first sixthree months of 2017, market prices for oil have improved, while market prices for gas have declined.2018. For the first six months of 2018,2019 period, average NYMEX oil and gas prices were $65.37$54.90 per barrel and $2.90$3.15 per Mcf, respectively, representing a decrease of 13% and an increase of 30% and a decrease of 11%5%, respectively, from the average NYMEX oil and gas prices for the first six months of 2017. However, local2018 period. Local market prices for oil and gas can be impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials. GasOil and gas production growth and pipeline constraints in the Permian Basin and Mid-Continent region and oil production growth and pipeline constraints in the Permian Basin have resulted in higher basis differentials and, therefore, lower realized prices. These factors and lower realized prices have continued beyond March 31, 2019. The average realized priceprices per barrel for our Permianof oil production wasand Mcf of gas that we realized were less than the WTI Cushing indexand Henry Hub indices by $8.05, $3.12, and $4.14the amounts shown in the three months ended June 30, 2018, March 31, 2018, and June 30, 2017, respectively. The average realized price per Mcftable below for our Permian gas production was less than the Henry Hub index by $1.31, $0.78, and $0.42periods 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 three months ended June 30, 2018, March 31, 2018, and June 30, 2017, respectively. The average realized price per Mcf for our Mid-Continent gas production was less thanPermian Basin are expected to ease capacity constraints as they come online over the Henry Hub index by $1.03, $0.70, and $0.34next few years, which is reflected in the three months ended June 30, 2018, March 31, 2018, and June 30, 2017, respectively. Ifcurrent 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, 2017,2018, 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 SixThree Months Ended June 30, 2018March 31, 2019 Compared to the SixThree Months Ended June 30, 2017:March 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 13%26% to 208.8258.9 MBOE per day.

Oil volumes increased 15%22% to 63.479.4 MBbls per day.

Gas volumes increased 7%20% to 537.1639.1 MMcf per day.

NGL volumes increased 21%41% to 55.873.0 MBbls per day.

Total production revenue increased 25%2% to $1.1 billion.$567.2 million.

Cash flow provided by operating activities increased 40%decreased 35% to $704.3$250.1 million.

Exploration and development expenditures increased 15%17% to $688.9$368.0 million.

Net income was $327.3$26.3 million, or $3.44$0.26 per diluted share, for the first sixthree months of 2018,2019, as compared to net income of $228.2$186.3 million, or $2.40$1.96 per diluted share, for the first sixthree months of 2017.2018.

RESULTS OF OPERATIONS

Three and Six Months Ended June 30, 2018March 31, 2019 vs. Three and Six Months Ended June 30, 2017March 31, 2018
Effective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”), utilizing the modified retrospective approach, which we applied to contracts that were not completed as of that date. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of ASC 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating expenses in the statement of operations under prior accounting standards are now reflected as deductions from revenue under ASC 606. The following tables present the impact on our Oil sales, Gas sales, and NGL sales and on our Transportation, processing, and other operating costs from the application of ASC 606 in the current reporting period:
  Three Months Ended
June 30,
  2018 2017
(in thousands) Pre-
ASC 606 Adoption
 
Impact of
ASC 606
 Post-
ASC 606 Adoption
 As Reported
Oil sales $342,184
 $
 $342,184
 $232,453
Gas sales 84,727
 (3,940) 80,787
 132,474
NGL sales 125,126
 (3,711) 121,415
 80,886
Total oil, gas, and NGL sales $552,037
 $(7,651) $544,386
 $445,813
         
Transportation, processing, and other operating costs $59,584
 $(7,651) $51,933
 $58,624
  Six Months Ended
June 30,
  2018 2017
(in thousands) Pre-
ASC 606 Adoption
 
Impact of
ASC 606
 Post-
ASC 606 Adoption
 As Reported
Oil sales $693,907
 $
 $693,907
 $456,519
Gas sales 197,404
 (6,896) 190,508
 264,419
NGL sales 230,739
 (15,327) 215,412
��161,312
Total oil, gas, and NGL sales $1,122,050
 $(22,223) $1,099,827
 $882,250
         
Transportation, processing, and other operating costs $119,321
 $(22,223) $97,098
 $113,647

Revenues

Almost all of ourOur 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



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fluctuations.

Production volumes were higher for all products during the three and six months ended June 30, 2018 as compared to the three and six months ended June 30, 2017. Realized oil and NGL prices also were higher, while realized gas prices were lower. Our revenue increased 22%, or $98.6 million, during the three months ended June 30, 2018March 31, 2019 as compared to the three months ended June 30, 2017 andMarch 31, 2018, while realized prices were lower. Our revenue increased 25%2%, or $217.6$11.8 million, during the sixthree months ended June 30, 2018March 31, 2019 as compared to the sixthree months ended June 30, 2017.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
June 30,
 Variance Between 2018 / 2017 Price/Volume Variance
Production Revenue (in thousands)
 2018 2017  Price Volume Total
Oil sales $342,184
 $232,453
 $109,731
 47% $94,533
 $15,198
 $109,731
Gas sales 80,787
 132,474
 (51,687) (39)% (57,440) 5,753
 (51,687)
NGL sales 121,415
 80,886
 40,529
 50% 22,060
 18,469
 40,529
  $544,386
 $445,813
 $98,573
 22% $59,153
 $39,420
 $98,573

 Six Months Ended
June 30,
 Variance Between 2018 / 2017 Price/Volume Variance Three Months Ended
March 31,
 Variance Between 2019 / 2018 Price/Volume Variance
Production Revenue (in thousands)
 2018 2017 Price Volume Total 2019 2018 Price Volume Total
Oil sales $693,907
 $456,519
 $237,388
 52% $167,943
 $69,445
 $237,388
 $349,306
 $351,723
 $(2,417) (1)% $(79,050) $76,633
 $(2,417)
Gas sales 190,508
 264,419
 (73,911) (28)% (92,358) 18,447
 (73,911) 109,976
 109,721
 255
 —% (21,281) 21,536
 255
NGL sales 215,412
 161,312
 54,100
 34% 20,809
 33,291
 54,100
 107,939
 93,997
 13,942
 15% (24,623) 38,565
 13,942
 $1,099,827
 $882,250
 $217,577
 25% $96,394
 $121,183
 $217,577
 $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
June 30,
 Six Months Ended
June 30,
 Three Months Ended
March 31,
Production Volumes 2018 2017 2018 2017 2019 2018
        
Oil (Bbls per day)            
Permian Basin 48,797
 45,828
 49,318
 43,446
 64,969
 49,845
Mid-Continent 12,473
 11,893
 13,841
 11,475
 14,224
 15,225
Other 381
 150
 263
 121
 222
 142
 61,651
 57,871
 63,422
 55,042
 79,415
 65,212
Gas (MMcf per day)            
Permian Basin 240.5
 219.8
 239.2
 210.4
 340.6
 237.9
Mid-Continent 297.0
 295.4
 296.2
 290.2
 297.2
 295.5
Other 2.0
 1.5
 1.7
 1.4
 1.3
 1.3
 539.5
 516.7
 537.1
 502.0
 639.1
 534.7
NGL (Bbls per day)            
Permian Basin 32,865
 24,996
 28,817
 23,319
 46,273
 24,725
Mid-Continent 26,894
 23,693
 26,927
 22,926
 26,630
 26,959
Other 98
 42
 66
 36
 53
 35
 59,857
 48,731
 55,810
 46,281
 72,956
 51,719
Total (BOE per day)            
Permian Basin 121,744
 107,456
 118,002
 101,829
 168,008
 114,218
Mid-Continent 88,864
 84,827
 90,142
 82,774
 90,386
 91,433
Other 816
 437
 608
 395
 488
 399
 211,424
 192,720
 208,752
 184,998
 258,882
 206,050

Our total production increased 10%26%, or 18,70452,832 BOE per day, during the three months ended June 30, 2018,March 31, 2019, as compared to the three months ended June 30, 2017 and increased 13%, or 23,754 BOE per day, during the six months ended June 30, 2018, as compared to the six months ended June 30, 2017.March 31, 2018. This increase was the result of our ongoing drilling and completion activity, throughout 2017 and into 2018.as well as due to our acquisition of Resolute. See LIQUIDITY AND CAPITAL RESOURCES Capital Expenditures for information on our capital expenditures.



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The table below presents our production volumes by commodity, our average realized commodity prices, and certain major U.S. index prices.  The sale of our Permian Basin oil production is typically tied to the WTI Midland benchmark price and the sale of our Mid-Continent oil production is typically tied to the WTI Cushing benchmark price.  During all periods presented,the three months ended March 31, 2019, approximately 79%82% of our oil production was in the Permian Basin.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
June 30,
 Change Between 2018 / 2017 Six Months Ended
June 30,
 Change Between 2018 / 2017 Three Months Ended
March 31,
 Variance Between 2019 / 2018
 2018 2017 2018 2017  2019 2018 
Oil                  
Total volume — MBbls 5,610
 5,266
 7% 11,479
 9,963
 15% 7,147
 5,869
 22%
Total volume — MBbls per day 61.7
 57.9
 7% 63.4
 55.0
 15% 79.4
 65.2
 22%
Percentage of total production 29% 30%   30% 30%   31% 32%  
Average realized price — per barrel $60.99
 $44.14
 38% $60.45
 $45.82
 32% $48.87
 $59.93
 (18)%
Average WTI Midland price — per barrel $62.76
 $47.44
 32% $63.01
 $50.00
 26% $50.97
 $63.26
 (19)%
Average WTI Cushing price — per barrel $67.88
 $48.29
 41% $65.37
 $50.10
 30% $54.90
 $62.87
 (13)%
              
Gas  
  
    
  
    
  
  
Total volume — MMcf 49,094
 47,021
 4% 97,219
 90,871
 7% 57,516
 48,125
 20%
Total volume — MMcf per day 539.5
 516.7
 4% 537.1
 502.0
 7% 639.1
 534.7
 20%
Percentage of total production 43% 45%   43% 45%   41% 43%  
Average realized price — per Mcf $1.65
(1)$2.82
 (41)% $1.96
(1)$2.91
 (33)% $1.91
 $2.28
 (16)%
Average Henry Hub price — per Mcf $2.80
 $3.19
 (12)% $2.90
 $3.25
 (11)% $3.15
 $3.01
 5%
              
NGL  
  
    
  
    
  
  
Total volume — MBbls 5,447
 4,434
 23% 10,102
 8,377
 21% 6,566
 4,655
 41%
Total volume — MBbls per day 59.9
 48.7
 23% 55.8
 46.3
 21% 73.0
 51.7
 41%
Percentage of total production 28% 25%   27% 25%   28% 25%  
Average realized price — per barrel $22.29
(2)$18.24
 22% $21.32
(2)$19.26
 11% $16.44
 $20.19
 (19)%
              
Total  
  
    
  
    
  
  
Total production — MBOE 19,240
 17,538
 10% 37,784
 33,485
 13% 23,299
 18,545
 26%
Total production — MBOE per day 211.4
 192.7
 10% 208.8
 185.0
 13% 258.9
 206.1
 26%
Average realized price — per BOE $28.30
(3)$25.42
 11% $29.11
(3)$26.35
 10% $24.34
 $29.95
 (19)%

(1)ASC 606 reduced the average realized gas price by $0.08 per Mcf and $0.07 per Mcf for the three and six months ended June 30, 2018, respectively.
(2)ASC 606 reduced the average realized NGL price by $0.68 per barrel and $1.52 per barrel for the three and six months ended June 30, 2018, respectively.
(3)ASC 606 reduced the average realized total price by $0.39 per BOE and $0.59 per BOE for the three and six months ended June 30, 2018, respectively.




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Other revenues

We transport, process, and market some third-party gas that is associated with our equity gas.  We market and sell gas for other working interest owners under short-term agreements and may earn a fee for such services.  The table below reflects income from third-party gas gathering and processing and our net marketing margin for marketing third-party gas. 
 Three Months Ended
June 30,
 Variance Between 2018 / 2017 Six Months Ended
June 30,
 Variance Between 2018 / 2017 Three Months Ended
March 31,
 Variance Between 2019 / 2018
Gas Gathering and Marketing Revenues (in thousands)
 2018 2017 2018 2017  2019 2018 
Gas gathering and other $11,810
 $10,735
 $1,075
 $23,262
 $21,360
 $1,902
 $10,262
 $11,452
 $(1,190)
Gas marketing $78
 $(96) $174
 $319
 $18
 $301
 $(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, and some depend on the prices charged by service companies. companies, and some fluctuate based on a combination of the foregoing. 

Total operating costs and expenses for the three months ended June 30, 2018March 31, 2019 were higher by 40%67%, or $103.8$212.4 million, compared to the three months ended June 30, 2017.March 31, 2018.  The primary reasons for the increase are:were: (i) the $44.2$119.6 million decreaseincrease in net gainslosses on derivative instruments to an overall net loss,and (ii) the $35.5$57.6 million increase in depreciation, depletion, and amortization, (iii) the $16.6 million increase in production expense, and (iv) the $10.5 million increase in taxes other than income, partially offset by the $6.7 million decrease in transportation, processing, and other operating expense.amortization. 
 Three Months Ended
June 30,
 
Variance Between
2018 / 2017
 Per BOE Three Months Ended
March 31,
 Variance Between 2019 / 2018 Per BOE
Operating Costs and Expenses
(in thousands, except per BOE)
 2018 2017 2018 2017 2019 2018 2019 2018
Depreciation, depletion, and amortization $143,388
 $107,884
 $35,504
 $7.45
 $6.15
 $190,417
 $132,859
 $57,558
 $8.17
 $7.16
Asset retirement obligation 2,053
 960
 1,093
 $0.11
 $0.05
 2,049
 1,060
 989
 $0.09
 $0.06
Production 79,215
 62,578
 16,637
 $4.12
 $3.57
 77,233
 71,271
 5,962
 $3.31
 $3.84
Transportation, processing, and other operating 51,933
 58,624
 (6,691) $2.70
 $3.34
 53,608
 45,165
 8,443
 $2.30
 $2.44
Gas gathering and other 9,467
 8,647
 820
 $0.49
 $0.49
 12,320
 9,823
 2,497
 $0.53
 $0.53
Taxes other than income 27,930
 17,477
 10,453
 $1.45
 $1.00
 33,694
 30,188
 3,506
 $1.45
 $1.63
General and administrative 19,739
 19,762
 (23) $1.03
 $1.13
 29,084
 23,321
 5,763
 $1.25
 $1.26
Stock compensation 3,095
 6,293
 (3,198) $0.16
 $0.36
 6,713
 6,730
 (17) $0.29
 $0.36
Loss (gain) on derivative instruments, net 21,699
 (22,509) 44,208
 N/A
 N/A
 115,452
 (4,159) 119,611
 N/A
 N/A
Other operating expense, net 5,252
 266
 4,986
 N/A
 N/A
 8,326
 203
 8,123
 N/A
 N/A
 $363,771
 $259,982
 $103,789
  
  
 $528,896
 $316,461
 $212,435
  
  

Total operating costs and expenses for the six months ended June 30, 2018 were higher by 40%, or $194.6 million, compared to the six months ended June 30, 2017.  The primary reasons for the increase are: (i) the $83.9 million decrease in net gains on derivative instruments to an overall net loss, (ii) the $72.5 million increase in depreciation, depletion, and amortization, (iii) the $25.5 million increase in production expense, and (iv) the $19.3 million increase in taxes other than income, partially offset by the $16.5 million decrease in transportation, processing, and other operating expense. 
  Six Months Ended
June 30,
 
Variance Between
2018 / 2017
 Per BOE
Operating Costs and Expenses
(in thousands, except per BOE)
 2018 2017  2018 2017
Depreciation, depletion, and amortization $276,247
 $203,700
 $72,547
 $7.31
 $6.08
Asset retirement obligation 3,113
 2,580
 533
 $0.08
 $0.08
Production 150,486
 124,999
 25,487
 $3.98
 $3.73
Transportation, processing, and other operating 97,098
 113,647
 (16,549) $2.57
 $3.39
Gas gathering and other 19,290
 17,074
 2,216
 $0.51
 $0.51
Taxes other than income 58,118
 38,790
 19,328
 $1.54
 $1.16
General and administrative 43,060
 37,796
 5,264
 $1.14
 $1.13
Stock compensation 9,825
 12,581
 (2,756) $0.26
 $0.38
Loss (gain) on derivative instruments, net 17,540
 (66,370) 83,910
 N/A
 N/A
Other operating expense, net 5,455
 882
 4,573
 N/A
 N/A
  $680,232
 $485,679
 $194,553
  
  
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



33

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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. WhileOur net proved properties, production, and reserves have increased for the increase in oil prices has more than offset the decrease in gas prices during 2018three months ended March 31, 2019 as compared to 2017, thus increasing our reserves, the increase in production combined withthree months ended March 31, 2018 due to our ongoing exploration and development capital expenditures throughout 2017activities as well as due to our acquisition of Resolute. The increase in net properties and into 2018, haveproduction 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
June 30,
 
Variance Between
2018 / 2017
 Per BOE
DD&A Expense (in thousands, except per BOE)
 2018 2017  2018 2017
Depletion $131,220
 $95,735
 $35,485
 $6.82
 $5.46
Depreciation 12,168
 12,149
 19
 0.63
 0.69
  $143,388
 $107,884
 $35,504
 $7.45
 $6.15

 Six Months Ended
June 30,
 
Variance Between
2018 / 2017
 Per BOE Three Months Ended
March 31,
 
Variance Between
2019 / 2018
 Per BOE
DD&A Expense (in thousands, except per BOE)
 2018 2017 2018 2017 2019 2018 2019 2018
Depletion $251,610
 $180,746
 $70,864
 $6.66
 $5.40
 $174,712
 $120,390
 $54,322
 $7.50
 $6.49
Depreciation 24,637
 22,954
 1,683
 0.65
 0.68
 15,705
 12,469
 3,236
 0.67
 0.67
 $276,247
 $203,700
 $72,547
 $7.31
 $6.08
 $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
June 30,
 
Variance Between
2018 / 2017
 Per BOE Three Months Ended
March 31,
 
Variance Between
2019 / 2018
 Per BOE
Production Expense (in thousands, except per BOE)
 2018 2017 2018 2017 2019 2018 2019 2018
Lease operating expense $62,355
 $55,812
 $6,543
 $3.24
 $3.18
 $62,408
 $60,476
 $1,932
 $2.68
 $3.26
Workover expense 16,860
 6,766
 10,094
 0.88
 0.39
 14,825
 10,795
 4,030
 0.63
 0.58
 $79,215
 $62,578
 $16,637
 $4.12
 $3.57
 $77,233
 $71,271
 $5,962
 $3.31
 $3.84

  Six Months Ended
June 30,
 
Variance Between
2018 / 2017
 Per BOE
Production Expense (in thousands, except per BOE)
 2018 2017  2018 2017
Lease operating expense $122,831
 $101,347
 $21,484
 $3.25
 $3.03
Workover expense 27,655
 23,652
 4,003
 0.73
 0.70
  $150,486
 $124,999
 $25,487
 $3.98
 $3.73
Lease operating expense in the secondfirst quarter 20182019 increased 12%3%, or $6.5$1.9 million, compared to the secondfirst quarter of 2017. Lease operating expense for the six months ended June 30, 2018 increased 21%, or $21.5 million, compared to the six months ended June 30, 2017.2018. 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 coststypes of expenses between the two quarters: (i) equipment rental, primarily flowback equipment and compressors, (ii) saltwater disposal, due to increased water volumes, (iii) environmental compliance, primarily emissions-related, and (iv) labor. The preceding costs also increased between the two six-month periods, as did the following costs: (i) tank battery and processing equipment and maintenance, (ii) electricity,labor, and (iii) chemicals and treating, due to increased water volumes and chemical treating.equipment rental.

Workover expense in the secondfirst quarter 20182019 increased 149%, or $10.1 million, compared to the second quarter of 2017. Workover expense for the six months ended June 30, 2018 increased 17%37%, or $4.0 million, compared to the sixfirst quarter of 2018. During the three months ended June 30, 2017. We had a larger quantity ofMarch 31, 2018, our workover projects during the six months ended June 30, 2018 as comparedexpense was reduced due to the six months ended June 30, 2017. Additionally, during the second quarter 2018, we had several artificial lift conversions underway, which increased workover expense. We received insurance proceeds ofreceiving approximately $4.0 million in the first quarter 2018 and $4.9 million in the second quarter 2017insurance proceeds related to the remediation and repairs incurred as a result of a 2015 flooding event. These insurance proceeds decreased workover expense in the periods received, thus resulting in the following increases in workover expense when comparing periods: (i) a $4.9 million increase in the second quarter 2018 as compared to the second quarter 2017 and (ii) a $0.9 million increase during the six months ended June 30, 2018 as compared to the six months ended June 30, 2017. Generally, workover costs will fluctuate based on the amount



34

Table of maintenance and remedial activity required during the period.Contents



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 secondfirst quarter 20182019 were 11%19%, or $6.7$8.4 million, lowerhigher than the same costs in the secondfirst quarter 2017. Transportation, processing, and other operating costs2018. The increase in the six months ended June 30, 2018 were 15%, or $16.5 million, lower than the costs in the six months ended June 30, 2017. These decreases were primarilyexpense is due to our adoption of ASC 606 effective January 1, 2018, whereby certain transportation and processing costs are now reclassified out of transportation, processing, and other operating costs and are treated as a deduction from revenue. The adoption of ASC 606 reduced Transportation, processing, and other operating costsincreased production volumes, offset slightly by $7.7 million inlower rates. Our production volumes increased by 26% during the second quarter 2018 and by $22.2 million in the sixthree months ended June 30, 2018. These reductions were partially offset by increased costs due to increased production volumes. See Note 1March 31, 2019 as compared to the Condensed Consolidated Financial Statements for additional information regarding the adoption of ASC 606.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 June 30, 2018March 31, 2019 was 9%25%, or $0.8$2.5 million, higher than gas gathering and other in the three months ended June 30, 2017. Gas gathering and other in the six months ended June 30, 2018 was 13%, or $2.2 million, higher than gas gathering and other in the six months ended June 30, 2017.March 31, 2018. The increases wereincrease 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 commodity pricesvolumes and volumes.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 $10.5$3.5 million, or 60%12%, in the secondfirst quarter of 20182019 as compared to the secondfirst quarter of 2017. Taxes other than income2018. Production taxes increased $19.3by $4.0 million or 50%, in the six months ended June 30, 2018first quarter of 2019 as compared to the six months ended June 30, 2017. The increases arefirst quarter of 2018 due to the increasesincreased production volumes and revenues, however, this increase in revenue seen between the comparable periods. All periods includedexpense was nearly offset by an increase of $3.3 million in credits for tax refunds, related togenerally for high-cost gas wells in the State of Texas, however, the refundsTexas. Ad valorem taxes increased by $2.9 million in the three and six months ended June 30,first quarter of 2019 as compared to the first quarter of 2018 were $3.6 million and $4.6 million, respectively, lower thandue to the refunds in the three and six months ended June 30, 2017.addition of new wells as a result of ongoing drilling activities. Taxes other than income was 5.1%5.9% and 3.9%5.4% of production revenues for the three months ended June 30,March 31, 2019 and 2018, and 2017, respectively, and was 5.3% and 4.4% of production revenues for the six months ended June 30, 2018 and 2017, 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 that are not directly associated with exploration, development, or production activities.incurred. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting. The amount of expense capitalized varies and depends on whether the cost incurred can be directly identified with acquisition, exploration, and development activities. The percentage of gross G&A capitalized ranged from 46%41% to 50%43% during the periods presented in the table below, which shows our G&A costs.
 Three Months Ended
June 30,
 Variance Between 2018 / 2017 Six Months Ended
June 30,
 Variance Between 2018 / 2017 Three Months Ended
March 31,
 Variance Between 2019 / 2018
General and Administrative Expense
(in thousands)
 2018 2017 2018 2017  2019 2018 
Gross G&A $39,276
 $38,541
 $735
 $80,124
 $72,631
 $7,493
 $49,236
 $40,848
 $8,388
Less amounts capitalized to oil and gas properties (19,537) (18,779) (758) (37,064) (34,835) (2,229) (20,152) (17,527) (2,625)
G&A expense $19,739
 $19,762
 $(23) $43,060
 $37,796
 $5,264
 $29,084
 $23,321
 $5,763




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Table of Contents


G&A expense for the six months ended June 30, 2018first quarter of 2019 was 14%25%, or $5.3$5.8 million, higher than G&A expense for the six months ended June 30, 2017.first quarter of 2018. This increase was primarily due to increased employee headcountemployee-related costs. Included in the increase is $2.6 million of severance related to former Resolute employees who performed transition work at Cimarex and increased salaries and wages, other compensation, consisting of incentive bonuses and vacation pay, benefits, primarily consisting of profit sharing, and consulting expense.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
June 30,
 Variance Between 2018 / 2017 Six Months Ended
June 30,
 Variance Between 2018 / 2017 Three Months Ended
March 31,
 Variance Between 2019 / 2018
Stock Compensation Expense (in thousands)
 2018 2017 2018 2017  2019 2018 
Restricted stock awards:                  
Performance stock awards $3,809
 $6,438
 $(2,629) $10,538
 $12,840
 $(2,302) $5,394
 $6,729
 $(1,335)
Service-based stock awards 4,247
 4,208
 39
 9,319
 9,132
 187
 7,231
 5,072
 2,159
 8,056
 10,646
 (2,590) 19,857
 21,972
 (2,115) 12,625
 11,801
 824
Stock option awards 637
 579
 58
 1,254
 1,245
 9
 622
 617
 5
Total stock compensation cost 8,693
 11,225
 (2,532) 21,111
 23,217
 (2,106) 13,247
 12,418
 829
Less amounts capitalized to oil and gas properties (5,598) (4,932) (666) (11,286) (10,636) (650) (6,534) (5,688) (846)
Stock compensation expense $3,095
 $6,293
 $(3,198) $9,825
 $12,581
 $(2,756) $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.  The decrease in total stock compensation cost in the 2018 periods as compared to the 2017 periods is primarily due to performance stock award forfeitures during the three months ended June 30, 2018. Our accounting policy is to account for forfeitures in compensation cost when they occur.

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
June 30,
 Variance Between 2018 / 2017 Six Months Ended
June 30,
 Variance Between 2018 / 2017 Three Months Ended
March 31,
 Variance Between 2019 / 2018
Loss (Gain) on Derivative Instruments, Net (in thousands)
 2018 2017 2018 2017  2019 2018 
Change in fair value of derivative instruments, net:  
  
  
      
Decrease (increase) in fair value of derivative instruments, net:  
  
  
Gas contracts $14,566
 $(5,748) $20,314
 $2,777
 $(27,939) $30,716
 $(9,846) $(11,789) $1,943
Oil contracts (397) (16,418) 16,021
 (5,156) (44,148) 38,992
 116,247
 (4,759) 121,006
 14,169
 (22,166) 36,335
 (2,379) (72,087) 69,708
 106,401
 (16,548) 122,949
Cash (receipts) payments on derivative instruments, net:  
  
          
  
  
Gas contracts (9,918) (1,308) (8,610) (15,037) 1,136
 (16,173) 3,764
 (5,119) 8,883
Oil contracts 17,448
 965
 16,483
 34,956
 4,581
 30,375
 5,287
 17,508
 (12,221)
 7,530
 (343) 7,873
 19,919
 5,717
 14,202
 9,051
 12,389
 (3,338)
Loss (gain) on derivative instruments, net $21,699
 $(22,509) $44,208
 $17,540
 $(66,370) $83,910
 $115,452
 $(4,159) $119,611




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Table of Contents


Other Operating Expense, Net

Other operating expense, net isduring the three months ended March 31, 2019 was comprised primarily of litigation settlements$8.3 million in acquisition-related costs incurred to effect the Resolute acquisition. These costs consisted primarily of advisory, legal, and allowance for doubtful accounts adjustments.other professional and consulting fees.

Other Income and Expense
 Three Months Ended
June 30,
 Variance Between 2018 / 2017 Six Months Ended
June 30,
 Variance Between 2018 / 2017 Three Months Ended
March 31,
 Variance Between 2019 / 2018
Other Income and Expense (in thousands)
 2018 2017 2018 2017  2019 2018 
Interest expense $16,895
 $20,095
 $(3,200) $33,678
 $41,147
 $(7,469) $20,405
 $16,783
 $3,622
Capitalized interest (4,850) (5,442) 592
 (9,660) (12,083) 2,423
 (8,742) (4,810) (3,932)
Loss on early extinguishment of debt 
 28,169
 (28,169) 
 28,169
 (28,169) 4,250
 
 4,250
Other, net (2,605) (2,231) (374) (7,172) (4,441) (2,731) (2,241) (4,567) 2,326
 $9,440
 $40,591
 $(31,151) $16,846
 $52,792
 $(35,946) $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 discount.discounts as well as miscellaneous interest expense.  See LIQUIDITY AND CAPITAL RESOURCES Long-term Debt below for further information regarding our debt. The decreaseincrease in interest expense in the 2018 periods2019 as compared to the 2017 periods2018 is primarily due to (i) the completionMarch 8, 2019 issuance of a tender offer and redemption$500 million aggregate principal amount of $750 million 5.875%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 the issuance of $750 million 3.90% senior unsecured notes, both of which occurred during the second quarter of 2017.(iii) interest expense on our finance lease. The $28.2$4.3 million loss on early extinguishment of debt incurred during the three and six months ended June 30, 2017March 31, 2019 was also associated with the debt tender offer and redemption. The loss was composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3$600 million of unamortized debt issuance costs.8.5% senior notes we acquired with Resolute and elected to immediately repay. The original maturity date of the 5.875%Resolute notes was May 1, 2022.2020.

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 lowerhigher in the 2018 periodsthree months ended March 31, 2019 as compared to the 2017 periods, thus reducingthree months ended March 31, 2018, primarily due to the Resolute acquisition, which increased our capitalized interest. Also contributing to lower capitalized interest in the 2018 periods was a lowernon-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 replacement of our 5.875% notes with 3.90% notes in the second quarter of 2017.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 (Benefit)

The components of our provision for income taxes areand our combined federal and state effective income tax rates were as follows:
 Three Months Ended
June 30,
 Variance Between 2018 / 2017 Six Months Ended
June 30,
 Variance Between 2018 / 2017 Three Months Ended
March 31,
 Variance Between 2019 / 2018
Income Tax Expense (Benefit) (in thousands)
 2018 2017 2018 2017 
Current tax benefit $(717) $
 $(717) $(717) $(6) $(711)
Income Tax Expense (in thousands)
 2019 2018 Variance Between 2019 / 2018
Deferred tax expense 42,783
 58,617
 (15,834) 99,732
 136,929
 (37,197) $8,073
 $56,949
 
 $42,066
 $58,617
 $(16,551) $99,015
 $136,923
 $(37,908)      
Combined federal and state effective income tax rate 23.0% 37.6%   23.2% 37.5%   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% in 2018 and 35% in 2017 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, occasionalfrom 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 20182019 exploration and development (“E&D”) expenditures are projected to range from $1.6$1.35 billion to $1.7$1.45 billion. Investments in midstreamgathering, processing, and other assetsinfrastructure are projected to range from $80be an additional $60 million to $90$70 million for the year.2019. See Capital Expenditures below for information regarding our E&D activities for the three and six months ended June 30, 2018March 31, 2019 and 2017.2018.

We periodically use derivative instruments to mitigate volatility in commodity prices. At June 30, 2018,March 31, 2019, we had derivative contracts covering a portion of our 2018 and 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.

We believe our conservative use of leverage, strong balance sheet, and hedging activities will mitigate our exposure to lower prices. Cash and cash equivalents at June 30, 2018March 31, 2019 were $410.8$20.9 million. At June 30, 2018,March 31, 2019, our long-term debt consisted of $1.5$2.0 billion of senior unsecured notes, with $750 million 4.375% notes due in 2024, and $750 million 3.90% notes due in 2027.2027, and $500 million 4.375% notes due in 2029. At June 30, 2018,March 31, 2019, we had no borrowings and $2.5 million in letters of credit outstanding under our credit facility, leaving an unused borrowing availability of $997.5 million.$1.25 billion. See Long-term Debt below for more information regarding our debt.

Our debt to total capitalization ratio at June 30, 2018March 31, 2019 was 34%36%, downup from 37%31% at December 31, 2017.2018. This ratio is calculated by dividing the sum of (i) the principal amount of long-term debtsenior notes and (ii) redeemable preferred stock by the sum of (i) the principal amount of long-term debtsenior notes, (ii) redeemable preferred stock, and (ii)(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. Additionally,

We may, from time to time, seek to repurchase our credit facility includes a financial covenantoutstanding preferred stock through cash repurchases and/or exchanges for the maintenance of a defined total debt-to-capital ratio of no greater than 65%.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.
 Six Months Ended
June 30,
 Three Months Ended
March 31,
(in thousands) 2018 2017 2019 2018
Net cash provided by operating activities $704,339
 $504,800
 $250,091
 $383,093
Net cash used by investing activities $(671,552) $(590,824) $(629,811) $(312,255)
Net cash used by financing activities $(22,498) $(47,257) $(400,016) $(7,562)

Net cash provided by operating activities for the sixthree months ended June 30, 2018March 31, 2019 was $704.3$250.1 million, up $199.5down $133.0 million, or 40%35%, from $504.8$383.1 million for the sixthree months ended June 30, 2017.March 31, 2018. The $199.5$133.0 million increasedecrease resulted primarily from the increaseincreased cash outflows related to changes in production revenue, which increased due to increased production volumes and realized oil and NGL prices.working capital. Also contributing to the increasedecrease was a decreased investment in working capital. These increases were partially offset by a netan increase in operating costs and expensesexpenses. Increased revenues and increaseddecreased cash outflows for settlements of derivative instruments.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 sixthree months ended June 30,March 31, 2019 and 2018 and 2017 was $671.6$629.8 million and $590.8$312.3 million, respectively. The majority of our cash flows used by investing activities are for E&D expenditures, which totaled $650.8$332.7 million and $582.2$323.5 million for the sixthree months ended June 30,March 31, 2019 and 2018, and 2017, 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. Proceeds fromIncluded in net cash used by investing activities are the proceeds of miscellaneous asset sales, ofincluding non-core assets slightly offset capital expenditure cash outflows in both periods.oil and gas properties.

Net cash used by financing activities forwas $400.0 million and $7.6 million during the sixthree months ended June 30,March 31, 2019 and 2018, and 2017 was $22.5 million and $47.3 million, respectively. During the sixthree months ended June 30, 2017,March 31, 2019, we extinguished our $750issued $500 million aggregate principal amount 5.875%of 4.375% senior unsecured notes paying $22.6 million in tender and redemption premiums and $0.2 million in other costs and issued $750 million principal amount 3.90% senior notesdue March 15, 2029 at 99.748%99.862% of par for proceeds of $748.1$499.3 million, paying $6.2$3.7 million in underwriting financing,fees and otherfinancing costs. Additionally, netwe 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 sixthree months ended June 30,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 onean $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 one $0.16 per share dividend, totaling $22.8 million and during the six months ended June 30, 2017, we paid two $0.08 per share dividends totaling $15.2 million.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 proceeds from property sales.applicable purchase price adjustments.
 Three Months Ended
June 30,
 Six Months Ended
June 30,
 Three Months Ended
March 31,
(in thousands) 2018 2017 2018 2017 2019 2018
Acquisitions:            
Proved $
 $255
 $62
 $260
 $692,600
 $62
Unproved 77
 792
 2,236
 3,825
 1,050,782
 2,159
 77
 1,047
 2,298
 4,085
 1,743,382
 2,221
Exploration and development:  
        
  
Land and seismic 10,327
 33,302
 20,424
 110,487
 9,527
 10,097
Exploration and development 365,097
 262,575
 668,469
 491,042
 358,491
 303,372
 375,424
 295,877
 688,893
 601,529
 368,018
 313,469
Property sales:            
Proved (4,577) (1,957) (29,541) (1,892) 4,030
 (24,964)
Unproved (441) (2,305) (5,301) (7,271) (3,501) (4,860)
 (5,018) (4,262) (34,842) (9,163) 529
 (29,824)
 $370,483
 $292,662
 $656,349
 $596,451
 $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 20182019 E&D capital investment is projected to range from $1.6$1.35 billion to $1.7$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 20182019 capital investment program with cash flow from our operating activities, and cash on hand.hand, and borrowings under our credit facility. Sales of non-core assets and borrowings under our credit facilitypossible capital markets transactions may also be used to supplement funding of capital expenditures.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.time to time. See Long-term DebtBank Debt below for further information regarding our credit facility.
On May 23, 2018, we entered into a Purchase and Sale Agreement with Callon Petroleum Operating Company (“Callon”) pursuant to which we agreed to sell, and Callon agreed to purchase, oil and gas properties principally located in Ward County, Texas for $570 million in cash. This sale is part



40

Table of our continuous portfolio optimization and high-grading of our investment opportunities. The Purchase and Sale Agreement contains representations, warranties, covenants, conditions to closing, purchase price adjustments, and other terms customary in transactions of this type. We expect to complete this transaction on August 31, 2018.Contents


The following table reflects wells completed by region during the periods indicated.
 Three Months Ended
June 30,
 Six Months Ended
June 30,
 Three Months Ended
March 31,
 2018 2017 2018 2017 2019 2018
Gross wells            
Permian Basin 32
 11
 49
 36
 12
 17
Mid-Continent 57
 40
 94
 85
 26
 37
 89
 51
 143
 121
 38
 54
Net wells            
Permian Basin 13
 10
 22
 26
 5
 9
Mid-Continent 10
 8
 16
 18
 3
 6
 23
 18
 38
 44
 8
 15

As of June 30, 2018,March 31, 2019, we had 2933 gross (11(9 net) wells in the process of being drilled: 1419 gross (9(7 net) in the Permian Basin and 1514 gross (2 net) in the Mid-Continent region. As of June 30, 2018,March 31, 2019, there were 141131 gross (57(52 net) wells waiting on completion: 4556 gross (32(40 net) in the Permian Basin and 9675 gross (25(12 net) in the Mid-Continent region. As of June 30, 2018,March 31, 2019, we had 129 operated rigs running: nine8 in the Permian Basin and three1 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, 2017,2018, 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 June 30, 2018March 31, 2019 and December 31, 20172018 consisted of the following:
  June 30, 2018 December 31, 2017
(in thousands) Principal 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
 Principal 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
4.375% Senior Notes $750,000
 $(4,906) $745,094
 $750,000
 $(5,383) $744,617
3.90% Senior Notes 750,000
 (7,355) 742,645
 750,000
 (7,697) 742,303
Total long-term debt $1,500,000
 $(12,261) $1,487,739
 $1,500,000
 $(13,080) $1,486,920
  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 June 30,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% notesNotes due 2027 were $5.7$5.4 million and $1.7$1.6 million, respectively. At DecemberMarch 31, 2017,2019, the unamortized debt issuance costs and discount related to the 3.90% notes4.375% Notes due 2029 were $5.9$4.5 million and $1.8$0.7 million, respectively. The 4.375% notesNotes due 2024 were issued at par.




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Bank Debt
We have a
On February 5, 2019, we entered into an Amended and Restated Credit Agreement for our senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020. The Credit Facility has. Among other things, the amended and restated credit facility increased the aggregate commitments of $1.0to $1.25 billion with an option for us to increase the aggregate commitments to $1.25$1.5 billion, at any time. There is no borrowing base subjectand extended the maturity date to the discretion of the lenders based on the value of our proved reserves under the Credit Facility.February 5, 2024. As of June 30, 2018,March 31, 2019, we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $997.5 million.$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 June 30, 2018,March 31, 2019, we were in compliance with all of the financial and non-financial covenants.

At June 30, 2018March 31, 2019 and December 31, 2017,2018, we had $2.7$4.9 million and $3.4$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 June 30, 2018.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 June 30, 2018,March 31, 2019, we had a working capital deficit of $253.2$313.7 million, a decrease of $2.9 million$1.03 billion or 1% compared to144% from a working capital surplus of $256.1$715.4 million at December 31, 2017.2018.
Working


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Our working capital decreasesdecreased 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: 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 $31.1$59.3 million.
Operations-related accounts receivable decreased by $15.5 million.
Working capital increases consisted primarily of the following:
Operations-related accounts payable and accrued liabilities decreased by $22.2 million.
Cash and cash equivalents increased by $10.3 million.
Current derivative instrument net liability decreased by $9.4 million.
Oil and gas well equipment and supplies increased by $3.7 million.
Accounts receivable are a major component of our working capital and include amounts due from a diverse group of companies comprised of major energy companies, pipeline companies, local distribution companies, and other end-users. 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 to stockholderson our common stock every quarter since the first quarter of 2006. In May 2018,February 2019, our Board of Directors declared a $0.16$0.20 per common share dividend, was declared,totaling $20.3 million, which is payable on or before AugustMay 31, 20182019 to stockholders of record on AugustMay 15, 2018.2019. 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 dividends.

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 June 30, 2018,March 31, 2019, our material off-balance sheet arrangements consisted of operating lease agreements which are included inwith lease terms at commencement of 12 months or less. As an accounting policy we have elected not to apply the contractual obligations table below.recognition requirements of Topic 842 to these leases. As such, we have not recorded any lease liabilities associated with these leases.



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Contractual Obligations and Material Commitments

At June 30, 2018,March 31, 2019, we had the following contractual obligations and material commitments:
 Payments Due by Period  Payments Due by Period 
Contractual obligations (in thousands)
 Total 1 Year or Less 
2-3
Years
 
4-5
Years
 More than 5 Years  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) $1,500,000
 $
 $
 $
 $1,500,000
  $2,000,000
 $
 $
 $
 $2,000,000
 
Long-term debt—interest (1) 460,044
 60,844
 124,125
 124,125
 150,950
  648,344
 82,307
 167,875
 167,875
 230,287
 
Operating leases (2) 90,206
 15,372
 25,399
 22,512
 26,923
  105,058
 24,404
 40,015
 22,716
 17,923
 
Unconditional purchase obligations (3) 80,863
 31,176
 35,585
 6,900
 7,202
  58,274
 22,874
 23,898
 6,901
 4,601
 
Derivative liabilities 101,991
 90,480
 11,511
 
 
  78,313
 77,557
 756
 
 
 
Asset retirement obligation (4) 167,998
 8,430
 
(4)
(4)
(4) 179,257
 13,728
 
(4)
(4)
(4)
Other long-term liabilities (5) 39,567
 2,034
 3,540
 5,138
 28,855
  39,631
 2,623
 3,237
 5,182
 28,589
 
 $2,440,669
 $208,336
 $200,160
 $158,675
 $1,713,930
  $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 June 30, 2018March 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 June 30, 2018.March 31, 2019. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.
(2)Operating leases include variousthe remaining contractual payments under lease commitmentsagreements 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 Unconditionalunconditional purchase obligations, $43.9$32.1 million represents obligations for the purchase of sand for well completions and $26.6$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 in the “1 Year or Less” column.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 June 30, 2018,March 31, 2019, we had estimated commitments of approximately: (i) $154.4$447.9 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $14.4$36.3 million to finish gathering system construction in progress.

At June 30, 2018,March 31, 2019, we had firm sales contracts to deliver approximately 330.7456.4 Bcf of gas over the next 6.65.8 years. If we do not deliver this gas, our estimated financial commitment, calculated using the July 2018April 2019 index price, would be approximately $659.9$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.




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In connection with gas gathering and processing agreements, we have volume commitments over the next 9.59.8 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 June 30, 2018,March 31, 2019, would be approximately $351.0$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 June 30, 2018,March 31, 2019, would be approximately $7.4$55.5 million. Of this total, we have accrued a liability of $2.5$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, 2017.2018.
Recent Accounting Developments
See Note 1 to the Condensed Consolidated Financial Statements in this report for a discussion of recently issued accounting pronouncements and their anticipated effect on our financial statements.
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 June 30, 2018,March 31, 2019, our total production revenue was comprised of 63%62% oil sales, 15%19% gas sales, and 22% NGL sales. For the six months ended June 30, 2018, our total production revenue was comprised of 63% oil sales, 17% gas sales, and 20%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
June 30, 2018
Six Months Ended
June 30, 2018March 31, 2019
    (in thousands)
Oil± $1.00per barrel ± $5,610± $11,479$7,147
Gas± $0.10per Mcf ± $4,909± $9,722$5,752
NGL± $1.00per barrel ± $5,447± $10,102$6,566
    ± $15,966± $31,303$19,465




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We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. At June 30, 2018,March 31, 2019, we had oil and gas derivatives covering a portion of our 20182019 and 20192020 production, which were recorded as current and non-current assets and liabilities. At June 30, 2018,March 31, 2019, our oil and gas derivatives had a gross asset fair value of $75.3$36.5 million and a gross liability fair value of $102.0$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 June 30, 2018.March 31, 2019.
 Impact on Fair Value Impact on Fair Value
Change in Forward Price June 30, 2018Change in Forward Price March 31, 2019
 (in thousands) (in thousands)
Oil-$1.00 $9,870
-$1.00 $6,991
Oil+$1.00 $(10,056)+$1.00 $(7,106)
Gas-$0.10 $6,714
-$0.10 $6,444
Gas+$0.10 $(6,728)+$0.10 $(6,797)

Interest Rate Risk

At June 30, 2018,March 31, 2019, our long-term debt consisted of $750 million of 4.375% senior unsecured notes that will mature on June 1, 2024, and $750 million of 3.90% senior unsecured notes that will mature on May 15, 2027.2027, and $500 million of 4.375% senior unsecured notes that mature on March 15, 2029. Because all of our outstanding long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal. See Note 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 June 30, 2018.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 June 30, 2018March 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.





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PART II
 
ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS  

In addition to the other information set forth in this report, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2017.2018. 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, 2017.2018. The risks described in the Annual Report on Form 10-K for the year ended December 31, 20172018 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
101.INSXBRL Instance Document
101.SCHXBRL Taxonomy Extension Schema Document
101.CALXBRL Taxonomy Extension Calculation Linkbase Document
101.LABXBRL Taxonomy Extension Label Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document
101.DEFXBRL Taxonomy Extension Definition Linkbase Document




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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
August 7, 2018May 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)


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