Table of Contents




 


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 September
June 30, 20182019
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.CO.
(Exact name of registrant as specified in its charter)
Delaware 45-0466694
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
   
1700 Lincoln Street, Suite 3700DenverColorado 80203
(Address of principal executive offices) (Zip Code)
(303) (303) 295-3995
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes ý  No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit 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 filerý
Accelerated filero
Non-accelerated filero
Smaller reporting companyo
   
Emerging growth companyo
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 OctoberJuly 31, 20182019 was 95,602,883.101,457,009.



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CIMAREX ENERGY CO.
Table of Contents
 
 Page
 
  
 
   
 
   
 
   
 
   
 
   
 
   
   
   
   
 
  
   
   
   





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GLOSSARY


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

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

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

Throughout this Form 10-Q, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, 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)
 September 30, December 31, June 30, December 31,
 2018 2017 2019 2018
Assets  
  
  
  
Current assets:  
  
  
  
Cash and cash equivalents $863,946
 $400,534
 $19,414
 $800,666
Accounts receivable, net of allowance:  
  
  
  
Trade 112,884
 100,356
 111,745
 122,065
Oil and gas sales 346,380
 344,552
 267,821
 315,063
Gas gathering, processing, and marketing 12,159
 15,266
 7,796
 17,072
Oil and gas well equipment and supplies 55,546
 49,722
 58,306
 55,553
Derivative instruments 31,176
 15,151
 42,957
 101,939
Prepaid expenses 4,133
 8,518
 8,985
 7,554
Other current assets 1,491
 1,536
 3,032
 4,227
Total current assets 1,427,715
 935,635
 520,056
 1,424,139
Oil and gas properties at cost, using the full cost method of accounting:  
  
  
  
Proved properties 18,047,645
 17,513,460
 19,846,426
 18,566,757
Unproved properties and properties under development, not being amortized 564,982
 476,903
 1,564,074
 436,325
 18,612,627
 17,990,363
 21,410,500
 19,003,082
Less—accumulated depreciation, depletion, amortization, and impairment (15,124,111) (14,748,833) (15,659,363) (15,287,752)
Net oil and gas properties 3,488,516
 3,241,530
 5,751,137
 3,715,330
Fixed assets, net of accumulated depreciation of $324,270 and $290,114, respectively 244,125
 210,922
Fixed assets, net of accumulated depreciation of $356,631 and $324,631, respectively 526,429
 257,686
Goodwill 620,232
 620,232
 727,573
 620,232
Derivative instruments 154
 2,086
 613
 9,246
Other assets 37,693
 32,234
 70,126
 35,451
 $5,818,435
 $5,042,639
 $7,595,934
 $6,062,084
Liabilities and Stockholders’ Equity  
  
Liabilities, Redeemable Preferred Stock, and Stockholders’ Equity  
  
Current liabilities:  
  
  
  
Accounts payable:    
    
Trade $118,104
 $68,883
 $104,142
 $76,927
Gas gathering, processing, and marketing 23,322
 29,503
 14,934
 29,887
Accrued liabilities:  
  
  
  
Exploration and development 154,783
 115,762
 108,299
 124,674
Taxes other than income 35,044
 23,687
 38,201
 33,622
Other 222,920
 212,400
 250,710
 221,159
Derivative instruments 97,480
 42,066
 50,056
 27,627
Revenue payable 193,692
 187,273
 186,206
 194,811
Operating leases 62,119
 
Total current liabilities 845,345
 679,574
 814,667
 708,707
Long-term debt:  
  
Principal 1,500,000
 1,500,000
Less—unamortized debt issuance costs and discount (11,853) (13,080)
Long-term debt principal 2,000,000
 1,500,000
Less—unamortized debt issuance costs and discounts (15,770) (11,446)
Long-term debt, net 1,488,147
 1,486,920
 1,984,230
 1,488,554
Deferred income taxes 244,592
 101,618
 439,429
 334,473
Asset retirement obligation 151,868
 158,421
 157,381
 152,758
Derivative instruments 14,076
 4,268
 840
 2,267
Operating leases 191,413
 
Other liabilities 48,585
 43,560
 64,461
 45,539
Total liabilities 2,792,613
 2,474,361
 3,652,421
 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, 95,602,550 and 95,437,434 shares issued, respectively 956
 954
Common stock, $0.01 par value, 200,000,000 shares authorized, 101,473,177 and 95,755,797 shares issued, respectively 1,015
 958
Additional paid-in capital 2,778,203
 2,764,384
 3,223,331
 2,785,188
Retained earnings (accumulated deficit) 243,923
 (199,259)
Retained earnings 635,339
 542,885
Accumulated other comprehensive income 2,740
 2,199
 2,208
 755
Total stockholders’ equity 3,025,822
 2,568,278
 3,861,893
 3,329,786
 $5,818,435
 $5,042,639
 $7,595,934
 $6,062,084

See accompanying Notes to Condensed Consolidated Financial Statements.


4







CIMAREX ENERGY CO.
Condensed Consolidated Statements of Operations and Comprehensive Income
(in thousands, except per share information)
(Unaudited)
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 Three Months Ended
June 30,
 Six Months Ended
June 30,
 2018 2017 2018 2017 2019 2018 2019 2018
Revenues:  
  
  
  
  
  
  
  
Oil sales $342,495
 $231,441
 $1,036,402
 $687,960
 $411,766
 $342,184
 $761,072
 $693,907
Gas and NGL sales 240,087
 220,898
 646,007
 646,629
 126,044
 202,202
 343,959
 405,920
Gas gathering and other 9,244
 11,056
 32,506
 32,416
 9,769
 11,810
 20,031
 23,262
Gas marketing (338) 286
 (19) 304
 (1,116) 78
 (1,642) 319
 591,488
 463,681
 1,714,896
 1,367,309
 546,463
 556,274
 1,123,420
 1,123,408
Costs and expenses:  
  
  
  
  
  
  
  
Depreciation, depletion, and amortization 136,302
 111,396
 412,549
 315,096
 213,327
 143,388
 403,744
 276,247
Asset retirement obligation 1,893
 1,497
 5,006
 4,077
 2,157
 2,053
 4,206
 3,113
Production 76,272
 65,410
 226,758
 190,409
 87,726
 79,215
 164,959
 150,486
Transportation, processing, and other operating 49,720
 58,387
 146,818
 172,034
 48,331
 51,933
 101,939
 97,098
Gas gathering and other 10,569
 8,856
 29,859
 25,930
 13,605
 9,467
 25,925
 19,290
Taxes other than income 28,431
 24,314
 86,549
 63,104
 41,033
 27,930
 74,727
 58,118
General and administrative 21,148
 21,039
 64,208
 58,835
 24,911
 19,739
 53,995
 43,060
Stock compensation 6,437
 7,038
 16,262
 19,619
 6,494
 3,095
 13,207
 9,825
Loss (gain) on derivative instruments, net 54,006
 16,109
 71,546
 (50,261)
(Gain) loss on derivative instruments, net (40,768) 21,699
 74,684
 17,540
Other operating expense, net 10,015
 95
 15,470
 977
 590
 5,252
 8,916
 5,455
 394,793
 314,141
 1,075,025
 799,820
 397,406
 363,771
 926,302
 680,232
Operating income 196,695
 149,540
 639,871
 567,489
 149,057
 192,503
 197,118
 443,176
Other (income) and expense:  
  
  
  
  
  
  
  
Interest expense 17,159
 16,838
 50,837
 57,985
 24,674
 16,895
 45,079
 33,678
Capitalized interest (5,457) (5,373) (15,117) (17,456) (16,805) (4,850) (25,547) (9,660)
Loss on early extinguishment of debt 
 
 
 28,169
 
 
 4,250
 
Other, net (7,544) (4,563) (14,716) (9,004) (2,167) (2,605) (4,408) (7,172)
Income before income tax 192,537
 142,638
 618,867
 507,795
 143,355
 183,063
 177,744
 426,330
Income tax expense 44,183
 51,239
 143,198
 188,162
 34,046
 42,066
 42,119
 99,015
Net income $148,354
 $91,399
 $475,669
 $319,633
 $109,309
 $140,997
 $135,625
 $327,315
                
Earnings per share to common stockholders:  
  
  
  
  
  
  
  
Basic $1.56
 $0.96
 $5.00
 $3.36
 $1.07
 $1.48
 $1.34
 $3.44
Diluted $1.56
 $0.96
 $5.00
 $3.36
 $1.07
 $1.48
 $1.34
 $3.44
                
Dividends declared per share $0.18
 $0.08
 $0.50
 $0.24
        
Comprehensive income:  
  
  
  
  
  
  
  
Net income $148,354
 $91,399
 $475,669
 $319,633
 $109,309
 $140,997
 $135,625
 $327,315
Other comprehensive income:  
  
  
  
  
  
  
  
Change in fair value of investments, net of tax of $159, $134, $160, and $494, respectively 539
 234
 541
 860
Change in fair value of investments, net of tax of $89, $57, $428 and $1, respectively 304
 192
 1,453
 2
Total comprehensive income $148,893
 $91,633
 $476,210
 $320,493
 $109,613
 $141,189
 $137,078
 $327,317







See accompanying Notes to Condensed Consolidated Financial Statements.


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CIMAREX ENERGY CO.
Condensed Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
 Nine Months Ended
September 30,
 Six Months Ended
June 30,
 2018 2017 2019 2018
Cash flows from operating activities:  
  
  
  
Net income $475,669
 $319,633
 $135,625
 $327,315
Adjustments to reconcile net income to net cash provided by operating activities:  
  
  
  
Depreciation, depletion, and amortization 412,549
 315,096
 403,744
 276,247
Asset retirement obligation 5,006
 4,077
 4,206
 3,113
Deferred income taxes 142,815
 188,168
 42,119
 99,732
Stock compensation 16,262
 19,619
 13,207
 9,825
Loss (gain) on derivative instruments, net 71,546
 (50,261)
Loss on derivative instruments, net 74,684
 17,540
Settlements on derivative instruments (20,418) (2,742) (2,814) (19,919)
Loss on early extinguishment of debt 
 28,169
 4,250
 
Amortization of debt issuance costs and discounts 1,502
 1,456
Changes in non-current assets and liabilities (1,244) 2,144
 2,749
 713
Other, net 3,242
 4,630
 8,152
 723
Changes in operating assets and liabilities:  
  
  
  
Accounts receivable (11,772) (128,921) 117,692
 15,012
Other current assets 4,421
 (19,372) (761) 1,886
Accounts payable and other current liabilities 59,737
 75,565
 (140,272) (29,304)
Net cash provided by operating activities 1,157,813
 755,805
 664,083
 704,339
Cash flows from investing activities:  
  
  
  
Acquisition of Resolute Energy, net of cash acquired (Note 13) (284,441) 
Oil and gas capital expenditures (1,151,484) (901,949) (711,757) (650,807)
Other capital expenditures (75,037) (31,332) (40,141) (56,112)
Sales of oil and gas assets 573,367
 8,136
 13,233
 34,842
Sales of other assets 990
 510
 434
 525
Net cash used by investing activities (652,164) (924,635) (1,022,672) (671,552)
Cash flows from financing activities:  
  
  
  
Borrowings of long-term debt 
 748,110
 1,710,310
 
Repayments of long-term debt 
 (750,000) (2,081,000) 
Call premium, financing, and underwriting fees 
 (29,194)
Financing, underwriting, and debt redemption fees (11,791) 
Finance lease payments (1,555) 
Dividends paid (38,038) (22,743) (38,647) (22,801)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards (6,410) (7,637) (654) (946)
Proceeds from exercise of stock options 2,211
 226
 674
 1,249
Net cash used by financing activities (42,237) (61,238) (422,663) (22,498)
Net change in cash and cash equivalents 463,412
 (230,068) (781,252) 10,289
Cash and cash equivalents at beginning of period 400,534
 652,876
 800,666
 400,534
Cash and cash equivalents at end of period $863,946
 $422,808
 $19,414
 $410,823






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 
 
 33
 20
 
 53
 
 
 
 2
 
 2
Dividends declared 
 
 (15,250) (32,507) 
 (47,757)
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 
 
 
 475,669
 
 475,669
 
 
 
 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 
 
 
 
 541
 541
 
 
 
 
 1,149
 1,149
Issuance of restricted stock awards 289
 3
 (3) 
 
 
 11
 
 
 
 
 
Common stock reacquired and retired (64) 
 (6,410) 
 
 (6,410) (10) 
 (654) 
 
 (654)
Restricted stock forfeited and retired (92) (1) 1
 
 
 
 (4) 
 
 
 
 
Exercise of stock options 33
 
 2,211
 
 
 2,211
 3
 
 80
 
 
 80
Stock-based compensation 
 
 33,237
 
 
 33,237
 
 
 13,245
 
 
 13,245
Balance, September 30, 2018 95,603
 $956
 $2,778,203
 $243,923
 $2,740
 $3,025,822
Balance, March 31, 2019 101,408
 1,014
 3,210,818
 547,626
 1,904
 3,761,362
Dividends paid on stock awards subsequently forfeited 
 
 1
 4
 
 5
Dividends declared on common stock ($0.20 per share) 
 
 
 (20,330) 
 (20,330)
Dividends declared on redeemable preferred stock ($20.31 per share) 
 
 
 (1,270) 
 (1,270)
Net income 
 
 
 109,309
 
 109,309
Unrealized change in fair value of investments, net of tax 
 
 
 
 304
 304
Issuance of restricted stock awards 54
 1
 (1) 
 
 
Restricted stock forfeited and retired (4) 
 
 
 
 
Exercise of stock options 15
 
 594
 
 
 594
Stock-based compensation 
 
 11,919
 
 
 11,919
Balance, June 30, 2019 101,473
 $1,015
 $3,223,331
 $635,339
 $2,208
 $3,861,893







See accompanying Notes to Condensed Consolidated Financial Statements.


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

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









See accompanying Notes to Condensed Consolidated Financial Statements.


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Table of Contents
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20182019
(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 marketvalue of our proved reserves or future results.




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


We did not recognize a ceiling test impairment during the ninethree and six months ended SeptemberJune 30, 20182019 and 20172018 because the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation. However, at June 30, 2019, a decline in the value of our ceiling limitation of approximately 4% or more would have resulted in an impairment. 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
September 30, 2018
(Unaudited)



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 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
September 30,
  2018 2017
(in thousands) Pre-
ASC 606 Adoption
 Impact of
ASC 606
 Post-
ASC 606 Adoption
 As Reported
Oil sales $342,495
 $
 $342,495
 $231,441
Gas sales 98,321
 (3,888) 94,433
 125,707
NGL sales 151,648
 (5,994) 145,654
 95,191
Total oil, gas, and NGL sales $592,464
 $(9,882) $582,582
 $452,339
         
Transportation, processing, and other operating costs $59,602
 $(9,882) $49,720
 $58,387
  Nine Months Ended
September 30,
  2018 2017
(in thousands) Pre-
ASC 606 Adoption
 Impact of
ASC 606
 Post-
ASC 606 Adoption
 As Reported
Oil sales $1,036,402
 $
 $1,036,402
 $687,960
Gas sales 295,725
 (10,784) 284,941
 390,126
NGL sales 382,387
 (21,321) 361,066
 256,503
Total oil, gas, and NGL sales $1,714,514
 $(32,105) $1,682,409
 $1,334,589
         
Transportation, processing, and other operating costs $178,923
 $(32,105) $146,818
 $172,034

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 SeptemberJune 30, 2018,2019, 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.

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



Our gas and NGLs are sold under a limited number of contract structure types common in our industry. Under these contracts the gas and its components, including NGLs, may be sold to a single purchaser or the residue gas and NGLs may be sold to separate purchasers. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product,product. However, depending on the contract structure type, certain transportation, processing, and are disaggregated inother charges may be deducted against the tables above on that basis.prices received for the product. Our oil typically is sold at specific delivery points under contract terms that also are common in our industry.

Gas Gathering

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

Gas Marketing

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

Gas Imbalances

Revenue from the sale of gas is recorded on the basis of gas actually sold by us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.
Recently Issued



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


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 assetassets for a period of time. The scope of Topic 842 excludes leases to explore for or use minerals, oil, natural gas, and similar nonregenerative resources. We adopted Topic 842 effective January 1, 2019, using the modified retrospective method applied to all leases that existed on that date, which resulted in exchange for consideration.  Only the lease components 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 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 liabilities on3) initial direct costs for existing leases;
an election not to apply 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 torecognition requirements in Topic 842. This ASU provides an optional transition 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 evaluate under Topic 842 (discussed above) existing or expiredreassess certain 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 capitalizeexistence prior 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.January 1, 2019.


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


2.LONG-TERM DEBT

Long-term debt at SeptemberJune 30, 20182019 and December 31, 20172018 consisted of the following:
  September 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
 $(4,671) $745,329
 $750,000
 $(5,383) $744,617
3.90% Senior Notes 750,000
 (7,182) 742,818
 750,000
 (7,697) 742,303
Total long-term debt $1,500,000
 $(11,853) $1,488,147
 $1,500,000
 $(13,080) $1,486,920
  June 30, 2019 December 31, 2018
(in thousands) Principal 
Unamortized Debt
Issuance Costs
and Discounts (1)
 
Long-term
Debt, net
 Principal 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
4.375% Notes due 2024 $750,000
 $(3,982) $746,018
 $750,000
 $(4,439) $745,561
3.90% Notes due 2027 750,000
 (6,651) 743,349
 750,000
 (7,007) 742,993
4.375% Notes due 2029 500,000
 (5,137) 494,863
 
 
 
  $2,000,000
 $(15,770) $1,984,230
 $1,500,000
 $(11,446) $1,488,554

(1)At SeptemberJune 30, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.1 million and $1.5 million, respectively. At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% notesNotes due 2027 were $5.5$5.4 million and $1.7$1.6 million, respectively. At December 31, 2017,June 30, 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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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)


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 SeptemberJune 30, 2018,2019, 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.$1.248 billion. During the three months ended June 30, 2019, we borrowed and repaid an aggregate of $528.0 million on the Credit Facility to meet cash requirements as needed.

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

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of SeptemberJune 30, 2018,2019, we were in compliance with all of the financial covenants.

At SeptemberJune 30, 20182019 and December 31, 2017,2018, we had $2.4$4.6 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 due 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 SeptemberJune 30, 2018.2019.





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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20182019
(Unaudited)




3.DERIVATIVE INSTRUMENTS
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 SeptemberJune 30, 2018,2019, 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 SeptemberJune 30, 2018:2019:
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) 
 
 
 3,404,000
 3,404,000
Weighted Avg Price - Floor $
 $
 $
 $52.97
 $52.97
Weighted Avg Price - Ceiling $
 $
 $
 $64.79
 $64.79
2019:          
          
WTI (1)
          
          
Volume (Bbls) 2,790,000
 2,821,000
 2,208,000
 1,472,000
 9,291,000
 
 
 3,312,000
 2,576,000
 5,888,000
Weighted Avg Price - Floor $53.94
 $53.94
 $55.67
 $58.50
 $55.07
 $
 $
 $54.28
 $55.50
 $54.81
Weighted Avg Price - Ceiling $66.88
 $66.88
 $70.03
 $71.94
 $68.43
 $
 $
 $67.88
 $68.36
 $68.09
2020:          
          
WTI (1)
          
          
Volume (Bbls) 728,000
 
 
 
 728,000
 1,820,000
 1,092,000
 368,000
 368,000
 3,648,000
Weighted Avg Price - Floor $60.00
 $
 $
 $
 $60.00
 $54.90
 $51.50
 $50.00
 $50.00
 $52.89
Weighted Avg Price - Ceiling $75.85
 $
 $
 $
 $75.85
 $68.49
 $63.59
 $62.15
 $62.15
 $65.74

(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
SeptemberJune 30, 20182019
(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) 
 
 
 10,120,000
 10,120,000
Weighted Avg Price - Floor $
 $
 $
 $2.10
 $2.10
Weighted Avg Price - Ceiling $
 $
 $
 $2.42
 $2.42
Perm EP (2)
          
Volume (MMBtu) 
 
 
 7,360,000
 7,360,000
Weighted Avg Price - Floor $
 $
 $
 $1.81
 $1.81
Weighted Avg Price - Ceiling $
 $
 $
 $2.03
 $2.03
Waha (3)
          
Volume (MMBtu) 
 
 
 1,840,000
 1,840,000
Weighted Avg Price - Floor $
 $
 $
 $1.38
 $1.38
Weighted Avg Price - Ceiling $
 $
 $
 $1.66
 $1.66
2019:                    
PEPL (1)
                    
Volume (MMBtu) 9,000,000
 9,100,000
 6,440,000
 3,680,000
 28,220,000
 
 
 12,880,000
 10,120,000
 23,000,000
Weighted Avg Price - Floor $2.06
 $2.06
 $1.91
 $1.90
 $2.01
 $
 $
 $1.93
 $1.92
 $1.92
Weighted Avg Price - Ceiling $2.39
 $2.39
 $2.27
 $2.35
 $2.36
 $
 $
 $2.32
 $2.36
 $2.33
Perm EP (2)
                    
Volume (MMBtu) 6,300,000
 6,370,000
 4,600,000
 1,840,000
 19,110,000
 
 
 8,280,000
 5,520,000
 13,800,000
Weighted Avg Price - Floor $1.73
 $1.73
 $1.50
 $1.35
 $1.64
 $
 $
 $1.46
 $1.38
 $1.43
Weighted Avg Price - Ceiling $1.95
 $1.95
 $1.74
 $1.55
 $1.86
 $
 $
 $1.76
 $1.71
 $1.74
Waha (3)
                    
Volume (MMBtu) 1,800,000
 1,820,000
 1,840,000
 1,840,000
 7,300,000
 
 
 5,520,000
 5,520,000
 11,040,000
Weighted Avg Price - Floor $1.38
 $1.38
 $1.38
 $1.38
 $1.38
 $
 $
 $1.48
 $1.48
 $1.48
Weighted Avg Price - Ceiling $1.66
 $1.66
 $1.66
 $1.66
 $1.66
 $
 $
 $1.82
 $1.82
 $1.82
2020:                    
PEPL (1)
                    
Volume (MMBtu) 910,000
 
 
 
 910,000
 7,280,000
 4,550,000
 1,840,000
 1,840,000
 15,510,000
Weighted Avg Price - Floor $1.90
 $
 $
 $
 $1.90
 $1.93
 $1.91
 $1.85
 $1.85
 $1.91
Weighted Avg Price - Ceiling $2.38
 $
 $
 $
 $2.38
 $2.36
 $2.28
 $2.31
 $2.31
 $2.32
Perm EP (2)
          
Volume (MMBtu) 3,640,000
 2,730,000
 1,840,000
 1,840,000
 10,050,000
Weighted Avg Price - Floor $1.40
 $1.40
 $1.35
 $1.35
 $1.38
Weighted Avg Price - Ceiling $1.79
 $1.82
 $1.66
 $1.66
 $1.75
Waha (3)
                    
Volume (MMBtu) 910,000
 
 
 
 910,000
 4,550,000
 2,730,000
 
 
 7,280,000
Weighted Avg Price - Floor $1.40
 $
 $
 $
 $1.40
 $1.50
 $1.57
 $
 $
 $1.53
Weighted Avg Price - Ceiling $1.76
 $
 $
 $
 $1.76
 $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
SeptemberJune 30, 20182019
(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) 
 
 
 2,668,000
 2,668,000
Weighted Avg Differential (2) $
 $
 $
 $(5.01) $(5.01)
2019:          
          
WTI Midland (1)
          
          
Volume (Bbls) 2,610,000
 2,639,000
 2,208,000
 1,472,000
 8,929,000
 
 
 3,266,000
 3,266,000
 6,532,000
Weighted Avg Differential (2) $(5.46) $(5.46) $(6.50) $(7.79) $(6.10) $
 $
 $(7.36) $(6.32) $(6.84)
2020:          
WTI Midland (1)
          
Volume (Bbls) 2,093,000
 1,365,000
 736,000
 736,000
 4,930,000
Weighted Avg Differential (2) $0.16
 $0.19
 $0.71
 $0.71
 $0.33

(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 lessplus or minus, as applicable, the weighted average differential shown in the table.


14
Oil Swaps 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 Fourth Quarter Total
2019:          
WTI (1)
          
Volume (Bbls) 
 
 460,000
 460,000
 920,000
Weighted Avg Price $
 $
 $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) 
 
 3,220,000
 3,220,000
 6,440,000
Weighted Avg Price $
 $
 $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) 
 
 337,640
 337,640
 675,280
Weighted Avg Call Price $
 $
 $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
SeptemberJune 30, 20182019
(Unaudited)




The following tables summarizetable summarizes our derivative contracts entered into subsequent to SeptemberJune 30, 20182019 through November 5, 2018:August 1, 2019:
 Gas Collars 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 Fourth Quarter Total
2018:          
PEPL (1)
          
Volume (MMBtu) 
 
 
 1,220,000
 1,220,000
Weighted Avg Price - Floor $
 $
 $
 $2.00
 $2.00
Weighted Avg Price - Ceiling $
 $
 $
 $2.58
 $2.58
Perm EP (2)
          
Volume (MMBtu) 
 
 
 610,000
 610,000
Weighted Avg Price - Floor $
 $
 $
 $1.40
 $1.40
Weighted Avg Price - Ceiling $
 $
 $
 $1.70
 $1.70
Waha (3)
          
Volume (MMBtu) 
 
 
 610,000
 610,000
Weighted Avg Price - Floor $
 $
 $
 $1.40
 $1.40
Weighted Avg Price - Ceiling $
 $
 $
 $1.70
 $1.70
2019:          
PEPL (1)
          
Volume (MMBtu) 1,800,000
 1,820,000
 1,840,000
 1,840,000
 7,300,000
Weighted Avg Price - Floor $2.00
 $2.00
 $2.00
 $2.00
 $2.00
Weighted Avg Price - Ceiling $2.58
 $2.58
 $2.58
 $2.58
 $2.58
Perm EP (2)
          
Volume (MMBtu) 900,000
 910,000
 920,000
 920,000
 3,650,000
Weighted Avg Price - Floor $1.40
 $1.40
 $1.40
 $1.40
 $1.40
Weighted Avg Price - Ceiling $1.70
 $1.70
 $1.70
 $1.70
 $1.70
Waha (3)
  
  
  
  
  
Volume (MMBtu) 900,000
 910,000
 920,000
 920,000
 3,650,000
Weighted Avg Price - Floor $1.40
 $1.40
 $1.40
 $1.40
 $1.40
Weighted Avg Price - Ceiling $1.70
 $1.70
 $1.70
 $1.70
 $1.70
2020:          
PEPL (1)
          
Volume (MMBtu) 1,820,000
 
 
 
 1,820,000
Weighted Avg Price - Floor $2.00
 $
 $
 $
 $2.00
Weighted Avg Price - Ceiling $2.58
 $
 $
 $
 $2.58
Perm EP (2)
          
Volume (MMBtu) 910,000
 
 
 
 910,000
Weighted Avg Price - Floor $1.40
 $
 $
 $
 $1.40
Weighted Avg Price - Ceiling $1.70
 $
 $
 $
 $1.70
Waha (3)
          
Volume (MMBtu) 910,000
 
 
 
 910,000
Weighted Avg Price - Floor $1.40
 $
 $
 $
 $1.40
Weighted Avg Price - Ceiling $1.70
 $
 $
 $
 $1.70

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

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


Oil Collars First
Quarter
 Second
Quarter
 Third
Quarter
 Fourth Quarter Total
2019:          
WTI          
Volume (Bbls) 
 
 368,000
 368,000
 736,000
Wtd Avg Price - Floor $
 $
 $50.00
 $50.00
 $50.00
Wtd Avg Price - Ceiling $
 $
 $63.45
 $63.45
 $63.45
2020:          
WTI          
Volume (Bbls) 364,000
 364,000
 368,000
 368,000
 1,464,000
Wtd Avg Price - Floor $50.00
 $50.00
 $50.00
 $50.00
 $50.00
Wtd Avg Price - Ceiling $63.45
 $63.45
 $63.45
 $63.45
 $63.45


 Oil Basis Swaps 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 Fourth Quarter Total
2020:          
WTI Midland (1)
          
Volume (Bbls) 637,000
 637,000
 
 
 1,274,000
Weighted Avg Differential (2) $(0.40) $(0.40) $
 $
 $(0.40)

(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)(Gain) loss on derivative instruments, net for the periods indicated.
  Three Months Ended
June 30,
 Six Months Ended
June 30,
(in thousands) 2019 2018 2019 2018
(Increase) decrease in fair value of derivative instruments, net:  
  
    
Gas contracts $(6,370) $14,566
 $(16,216) $2,777
Oil contracts (28,161) (397) 88,086
 (5,156)
  (34,531) 14,169
 71,870
 (2,379)
Cash (receipts) payments on derivative instruments, net:  
  
    
Gas contracts (21,176) (9,918) (17,412) (15,037)
Oil contracts 14,939
 17,448
 20,226
 34,956
  (6,237) 7,530
 2,814
 19,919
(Gain) loss on derivative instruments, net $(40,768) $21,699
 $74,684
 $17,540





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

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
(in thousands) 2018 2017 2018 2017
Decrease (increase) in fair value of derivative instruments, net:  
  
    
Gas contracts $6,378
 $1,156
 $9,155
 $(26,783)
Oil contracts 47,129
 17,929
 41,973
 (26,220)
  53,507
 19,085
 51,128
 (53,003)
Cash (receipts) payments on derivative instruments, net:  
  
    
Gas contracts (3,462) (2,067) (18,499) (931)
Oil contracts 3,961
 (909) 38,917
 3,673
  499
 (2,976) 20,418
 2,742
Loss (gain) on derivative instruments, net $54,006
 $16,109
 $71,546
 $(50,261)

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
September 30, 2018
(Unaudited)



The following tables present the amounts and classifications of our derivative assets and liabilities as of SeptemberJune 30, 20182019 and December 31, 2017,2018, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.
    June 30, 2019
(in thousands) Balance Sheet Location Asset Liability
Oil contracts Current assets — Derivative instruments $23,060
 $
Gas contracts Current assets — Derivative instruments 19,897
 
Oil contracts Non-current assets — Derivative instruments 613
 
Oil contracts Current liabilities — Derivative instruments 
 50,056
Oil contracts Non-current liabilities — Derivative instruments 
 171
Gas contracts Non-current liabilities — Derivative instruments 
 669
Total gross amounts presented in the balance sheet 43,570
 50,896
Less: gross amounts not offset in the balance sheet (23,966) (23,966)
Net amount $19,604
 $26,930
       
       
    December 31, 2018
(in thousands) Balance Sheet Location Asset Liability
Oil contracts Current assets — Derivative instruments $94,240
 $
Gas contracts Current assets — Derivative instruments 7,699
 
Oil contracts Non-current assets — Derivative instruments 9,246
 
Oil contracts Current liabilities — Derivative instruments 
 23,378
Gas contracts Current liabilities — Derivative instruments 
 4,249
Oil contracts Non-current liabilities — Derivative instruments 
 311
Gas contracts Non-current liabilities — Derivative instruments 
 1,956
Total gross amounts presented in the balance sheet 111,185
 29,894
Less: gross amounts not offset in the balance sheet (29,894) (29,894)
Net amount $81,291
 $

    September 30, 2018
(in thousands) Balance Sheet Location Asset Liability
Oil contracts Current assets — Derivative instruments $20,127
 $
Gas contracts Current assets — Derivative instruments 11,049
 
Oil contracts Non-current assets — Derivative instruments 154
 
Oil contracts Current liabilities — Derivative instruments 
 96,240
Gas contracts Current liabilities — Derivative instruments 
 1,240
Oil contracts Non-current liabilities — Derivative instruments 
 12,348
Gas contracts Non-current liabilities — Derivative instruments 
 1,728
Total gross amounts presented in the balance sheet 31,330
 111,556
Less: gross amounts not offset in the balance sheet (31,330) (31,330)
Net amount $
 $80,226
       
       
    December 31, 2017
(in thousands) Balance Sheet Location Asset Liability
Gas contracts Current assets — Derivative instruments $15,151
 $
Gas contracts Non-current assets — Derivative instruments 2,086
 
Oil contracts Current liabilities — Derivative instruments 
 42,066
Oil contracts Non-current liabilities — Derivative instruments 
 4,268
Total gross amounts presented in the balance sheet 17,237
 46,334
Less: gross amounts not offset in the balance sheet (17,237) (17,237)
Net amount $
 $29,097

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

4.FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and



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


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
September 30, 2018
(Unaudited)



The following table provides fair value measurement information for certain assets and liabilities as of SeptemberJune 30, 20182019 and December 31, 2017:2018:
  June 30, 2019 December 31, 2018
(in thousands) 
Book
Value
 
Fair
Value
 
Book
Value
 
Fair
Value
Financial Assets (Liabilities):  
      
4.375% Notes due 2024 $(750,000) $(793,913) $(750,000) $(744,578)
3.90% Notes due 2027 $(750,000) $(769,643) $(750,000) $(701,273)
4.375% Notes due 2029 $(500,000) $(530,535) $
 $
Derivative instruments — assets $43,570
 $43,570
 $111,185
 $111,185
Derivative instruments — liabilities $(50,896) $(50,896) $(29,894) $(29,894)

  September 30, 2018 December 31, 2017
(in thousands) 
Book
Value
 
Fair
Value
 
Book
Value
 
Fair
Value
Financial Assets (Liabilities):  
      
4.375% Notes due 2024 $(750,000) $(756,915) $(750,000) $(797,010)
3.90% Notes due 2027 $(750,000) $(716,318) $(750,000) $(767,813)
Derivative instruments — assets $31,330
 $31,330
 $17,237
 $17,237
Derivative instruments — liabilities $(111,556) $(111,556) $(46,334) $(46,334)

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.quoted market prices. The fair value of our derivative instruments (Level 2) was estimated using discounted cash flow and option pricing models. These models use certain observable variables including forward price andprices, volatility curves, interest rates, and the strike prices for the instruments.credit ratings and spreads. The fair value estimates are adjusted relative to non-performance risk as appropriate. See Note 3 for further information on the fair value of our derivative instruments.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Included in “Accrued liabilities — Other” at SeptemberJune 30, 20182019 were accrued operating expenses (e.g. production, transportation, and gathering expenses) of approximately $69.7$82.8 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 SeptemberJune 30, 20182019 and December 31, 2017,2018, the allowance for doubtful accounts was $2.7$3.2 million and $2.2$2.7 million, respectively.




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


5.CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At SeptemberJune 30, 2018,2019, there were 95.6101.5 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 Preferred Stock”). Holders of the Convertible Preferred Stock are entitled to receive, when, as, and if declared by the Board out of funds of Cimarex legally available for payment, cumulative cash dividends at the annual rate of 8.125% of each share’s liquidation preference of $1,000. Dividends on the preferred stock are payable quarterly in arrears and accumulate from the most recent date as to which dividends have been paid. In the event of any liquidation, winding up, or dissolution of Cimarex, whether voluntary or involuntary, each holder will be entitled to receive in respect of its shares and to be paid out of the assets of Cimarex legally available for distribution to its stockholders, after satisfaction of liabilities to Cimarex’s creditors and any senior stock (of which there is currently none) and before any payment or distribution is made to holders of junior stock (including common stock), the liquidation preference of $1,000 per share, with the total liquidation preference being $62.5 million in the aggregate. Each holder has the right at any time, at its option, to convert any or all of such holder’s shares of Convertible Preferred Stock at an initial conversion rate of 8.0421 shares of fully paid and nonassessable shares of our common stock and $471.40 in cash per share of Convertible Preferred Stock. Additionally, at any time on or after October 15, 2021, we shall have the right, at our option, if the closing sale price of our common stock meets certain criteria, to elect to cause all, and not part, of the outstanding shares of Convertible Preferred Stock to be automatically converted into that number of shares of Cimarex common stock for each share of Convertible Preferred Stock equal to the conversion rate in effect on the mandatory conversion date as such terms are defined in the Certificate of Designations for the Convertible Preferred Stock and $471.40 in cash per share of Convertible Preferred Stock. As a result of the cash redemption features included in the Convertible Preferred Stock conversion option, with such conversion not solely within our control, the instruments are classified as Redeemable preferred stock in temporary equity on the Condensed Consolidated Balance Sheet.

Dividends

Common Stock

In August 2018,May 2019, our Board of Directors declared a cash dividend of $0.18$0.20 per share.share of common stock. The dividend is payable on or before NovemberAugust 30, 20182019 to stockholders of record on NovemberAugust 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. During 2018, the $15.3The $20.3 million dividend declared during the firstsecond quarter 2019 was recorded as a reduction of additional paid-in capital, while the $15.3 millionretained earnings and the $17.2 million dividends declared during the second and third quarters, respectively, were recordedis included as a reduction of retained earnings.

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CIMAREX ENERGY CO.
Notes topayable in “Accrued liabilities — Other” on the Condensed Consolidated Financial Statements
September 30, 2018
(Unaudited)


Balance Sheet. Nonforfeitable dividends paid on stock awards that subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to stock compensation expense in the period in which the forfeitures occur. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Preferred Stock

In May 2019, our Board of Directors declared a cash dividend of $20.31 per share of Convertible Preferred Stock. The dividend was paid in July to stockholders of record on July 1, 2019. The $1.3 million dividend declared during the second 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
June 30, 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,
(in thousands) 2019 2018 2019 2018
Restricted stock awards:        
Performance stock awards $5,535
 $3,809
 $10,929
 $10,538
Service-based stock awards 5,993
 4,247
 13,224
 9,319
  11,528
 8,056
 24,153
 19,857
Stock option awards 396
 637
 1,018
 1,254
Total stock compensation cost 11,924
 8,693
 25,171
 21,111
Less amounts capitalized to oil and gas properties (5,430) (5,598) (11,964) (11,286)
Stock compensation expense $6,494
 $3,095
 $13,207
 $9,825

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
(in thousands) 2018 2017 2018 2017
Restricted stock awards:        
Performance stock awards $6,364
 $6,508
 $16,902
 $19,348
Service-based stock awards 5,244
 5,317
 14,563
 14,449
  11,608
 11,825
 31,465
 33,797
Stock option awards 571
 698
 1,825
 1,943
Total stock compensation cost 12,179
 12,523
 33,290
 35,740
Less amounts capitalized to oil and gas properties (5,742) (5,485) (17,028) (16,121)
Stock compensation expense $6,437
 $7,038
 $16,262
 $19,619

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 decreaseincrease in total stock compensation cost in the nine months ended September 30, 20182019 periods as compared to the nine months ended September 30, 20172018 periods is primarily due to awards granted either during or subsequent to the 2018 periods and performance stock award forfeitures that occurred during the second quarter 2018.of 2018, both of which were partially offset by awards vesting prior to or during the 2019 periods. 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
SeptemberJune 30, 20182019
(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 ninesix months ended SeptemberJune 30, 2018:2019:
(in thousands) Six Months Ended
June 30, 2019
Asset retirement obligation at January 1, 2019 $166,904
Liabilities incurred 12,611
Liability settlements and disposals (11,771)
Accretion expense 3,714
Revisions of estimated liabilities 2,415
Asset retirement obligation at June 30, 2019 173,873
Less current obligation (16,492)
Long-term asset retirement obligation $157,381

(in thousands) Nine Months Ended
September 30, 2018
Asset retirement obligation at January 1, 2018 $169,469
Liabilities incurred 7,157
Liability settlements and disposals (19,769)
Accretion expense 5,540
Revisions of estimated liabilities 1,055
Asset retirement obligation at September 30, 2018 163,452
Less current obligation (11,584)
Long-term asset retirement obligation $151,868

For the ninesix months ended SeptemberJune 30, 2018, liability settlements and disposals2019, liabilities incurred included disposals of $13.7 million.$9.4 million for the Resolute acquisition.



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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20182019
(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 September 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 $148,354
  
   $91,399
    
Less: net income attributable to participating securities (2,069)     (1,572)    
Basic earnings per share            
Income available to common stockholders 146,285
 93,845
 $1.56
 89,827
 93,501
 $0.96
Effects of dilutive securities            
Options (1) 
 22
   
 30
  
Diluted earnings per share            
Income available to common stockholders and assumed conversions $146,285
 93,867
 $1.56
 $89,827
 93,531
 $0.96

 Nine Months Ended September 30, Three Months Ended June 30,
 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 $475,669
  
   $319,633
     $109,309
  
   $140,997
    
Less: net income attributable to participating securities (6,610)     (5,478)     (1,596)     (1,892)    
Less: preferred stock dividends (1,270)     
    
Basic earnings per share                        
Income available to common stockholders 469,059
 93,758
 $5.00
 314,155
 93,431
 $3.36
 106,443
 99,658
 $1.07
 139,105
 93,728
 $1.48
Effects of dilutive securities            
Options (1) 2
 30
   2
 34
  
Effects of dilutive securities (1)
            
Options 
 7
   
 31
  
Diluted earnings per share                        
Income available to common stockholders and assumed conversions $469,061
 93,788
 $5.00
 $314,157
 93,465
 $3.36
 $106,443
 99,665
 $1.07
 $139,105
 93,759
 $1.48

(1)Inclusion of certain potential common shares would have an anti-dilutive effect;effect, therefore, 378.1 thousand and 387.7 thousandthese shares were excluded from the calculations forof diluted earnings per share. Excluded from the three and nine months ended SeptemberJune 30, 2019 calculation were 387.5 thousand potential common shares from the assumed exercise of employee stock options and 502.6 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock. Excluded from the three months ended June 30, 2018 respectively, and 298.7calculation were 292.1 thousand and 302.9 thousandpotential common shares were excluded from the calculations for the three and nine months ended September 30, 2017, respectively.assumed exercise of employee stock options.




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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20182019
(Unaudited)




  Six Months Ended June 30,
  2019 2018
(in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount Income (Numerator) Shares (Denominator) Per-Share Amount
Net income $135,625
  
   $327,315
    
Less: net income attributable to participating securities (2,067)     (4,546)    
Less: preferred stock dividends (2,539)     
    
Basic earnings per share            
Income available to common stockholders 131,019
 97,800
 $1.34
 322,769
 93,713
 $3.44
Effects of dilutive securities (1)
            
Options 
 9
   1
 35
  
Diluted earnings per share            
Income available to common stockholders and assumed conversions $131,019
 97,809
 $1.34
 $322,770
 93,748
 $3.44

(1)Inclusion of certain potential common shares would have an anti-dilutive effect, therefore, these shares were excluded from the calculations of diluted earnings per share. Excluded from the six months ended June 30, 2019 calculation were 391.1 thousand potential common shares from the assumed exercise of employee stock options and 502.6 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock. Excluded from the six months ended June 30, 2018 calculation were 295.6 thousand potential common shares from the assumed exercise of employee stock options.

9.INCOME TAXES

The components of our provision for income taxes areand our combined federal and state effective income tax rates were as follows:
  Three Months Ended
June 30,
 Six Months Ended
June 30,
(in thousands) 2019 2018 2019 2018
Current tax (benefit) $
 $(717) $
 $(717)
Deferred tax expense 34,046
 42,783
 42,119
 99,732
  $34,046
 $42,066
 $42,119
 $99,015
         
Combined federal and state effective income tax rate 23.7% 23.0% 23.7% 23.2%

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
(in thousands) 2018 2017 2018 2017
Current tax expense (benefit) $1,100
 $
 $383
 $(6)
Deferred tax expense 43,083
 51,239
 142,815
 188,168
  $44,183
 $51,239
 $143,198
 $188,162
Combined federal and state effective income tax rate 22.9% 35.9% 23.1% 37.1%

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 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 carryforwardcarryforwards. The carryforwards are subject to an annual limitation under Internal Revenue Code Section 382.



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Table of approximately $3.0 million and other credits of $0.9 million.Contents
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)



At SeptemberJune 30, 2018,2019, 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 20152016 through 20172018 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 20142015 through 2017.2018.

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 June 30, 2019, these leases had remaining lease terms ranging from 4.9 to 7.2 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 Septembercommencement of each real estate lease we were not reasonably certain to exercise the option to renew or terminate such lease.
The discount rate used to calculate each lease liability was based on our incremental borrowing rate, which was estimated utilizing trading metrics for our senior unsecured notes as adjusted using relevant market factors to develop a synthetic secured yield curve.
As an accounting policy we have elected not to separate nonlease components from lease components for our real estate class of assets.
Where applicable, we determined that the effect of accounting for the right to use land separately from other lease components would be insignificant.

Production-Related Leases

We have operating leases for equipment used in connection with our oil and gas production operations, including well-head compressors, pipeline compressors, and artificial lift mechanisms. These leases provide us the right to control the use of explicitly or implicitly identified equipment during the term of the contract. These leases often include an “evergreen” provision that allows the contract term to continue on a month-to-month basis following expiration of the initial term stated in the contract. As of June 30, 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



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


cost of renting the equipment and, in some cases, the cost of maintaining the leased equipment. These leases do not typically require us to make variable lease payments. These leases do not contain residual value guarantees, options to purchase the underlying equipment, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of production-related equipment.

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

For leases with an evergreen provision, the term of the lease was determined to be the noncancellable period in the contract plus the period beyond the noncancellable period that we believe it is reasonably certain we will need the equipment for operational purposes, limited to the point in time at which both we and the lessor each have the right to terminate the lease without permission from the other party with no more than an insignificant penalty.
The discount rate used to calculate each lease liability was based on our incremental borrowing rate, which was estimated utilizing trading metrics for our senior unsecured notes as adjusted using relevant market factors to develop a synthetic secured yield curve.
As an accounting policy we have elected not to separate nonlease components from lease components for our production-related class of assets.

We have one finance lease, which results from a gathering agreement (the “Gathering Agreement”) on a gathering system. Under terms of the Gathering Agreement, we have the option to acquire a portion of the underlying gathering system upon termination of the Gathering Agreement. We make monthly payments under the Gathering Agreement based on the volume of oil gathered and a gathering rate per barrel, which is adjusted periodically. As of June 30, 2019, this lease had a remaining term of 6.2 years.

Exploration and Development-Related Leases

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

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




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


Balance Sheet Presentation

The following tables present the amounts and classifications of our right-of-use assets and estimated lease liabilities as of June 30, 2019:
(in thousands) Balance Sheet Location June 30, 2019
Operating lease right-of-use assets Non-current assets — Fixed assets, net $243,089
Finance lease right-of-use asset Non-current assets — Other assets 27,042
Total right-of-use assets $270,131

(in thousands) Balance Sheet Location June 30, 2019
Operating lease liabilities — current Current liabilities — Operating leases $62,119
Operating lease liabilities — non-current Non-current liabilities — Operating leases 191,413
Finance lease liability — current Current liabilities — Accrued liabilities-Other 6,576
Finance lease liability — non-current Non-current liabilities — Other liabilities 21,895
Total lease liabilities $282,003


Lease Cost and Cash Flows

The following table summarizes estimated total lease cost, which includes amounts recognized in income and amounts capitalized for the indicated period:
(in thousands) Three Months Ended June 30, 2019 Six Months Ended June 30, 2019
Finance lease cost:    
Amortization of right-of-use asset $1,097
 $2,193
Interest on lease liability 457
 943
Operating lease cost: (1)    
Production expense 3,943
 7,777
Gas gathering and other expense 6,522
 12,686
General and administrative expense 2,335
 4,634
Short-term lease cost (2) 162,334
 317,044
Total lease cost $176,688
 $345,277

(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
June 30, 2019
(Unaudited)


The following table summarizes estimated cash paid for our leases for the indicated period:
(in thousands) Six Months Ended
June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:  
Financing cash outflows from finance lease $1,555
Operating cash outflows from operating leases $25,466
   
Cash paid for short-term leases and variable lease payments:  
Investing cash outflows from operating leases $309,150


During the six months ended June 30, 2019, we recognized $49.1 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:
June 30, 2019
Weighted-average remaining lease term (in years):
Finance lease6.2
Operating leases4.5
Weighted-average discount rate:
Finance lease6.5%
Operating leases4.0%


The following table reflects the undiscounted future cash flows utilized in the calculation of the lease liabilities recorded at June 30, 2019:
  June 30, 2019
(in thousands) Operating Leases Finance Lease
July 1, 2019 — June 30, 2020 $72,320
 $6,802
July 1, 2020 — June 30, 2021 64,198
 5,846
July 1, 2021 — June 30, 2022 58,280
 5,562
July 1, 2022 — June 30, 2023 45,166
 5,279
July 1, 2023 — June 30, 2024 21,977
 4,995
Remaining periods 18,814
 5,469
Total undiscounted future cash flows 280,755
 33,953
Less effects of discounting (27,223) (5,482)
Lease liabilities recognized $253,532
 $28,471





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Table of Contents
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)


As of December 31, 2018 the following future minimum cash payments were required under leases for office space:
(in thousands) December 31, 2018
2019 $9,849
2020 10,790
2021 11,000
2022 11,130
2023 11,433
Remaining periods 20,831
Total future minimum lease payments $75,033

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

Other Commitments

At June 30, 2019, we had estimated commitments of approximately: (i) $263.3$304.6 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $13.1$19.2 million to finish gathering system construction in progress.

At SeptemberJune 30, 2018,2019, we had firm sales contracts to deliver approximately 339.0290.7 Bcf of gas over the next 6.35.6 years. If we do not deliver this gas, our estimated financial commitment, calculated using the October 2018July 2019 index price, would be approximately $598.3$303.3 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 9.39.5 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 SeptemberJune 30, 2018,2019, would be approximately $345.2$655.2 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
September 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 SeptemberJune 30, 2018,2019, would be approximately $12.3$153.3 million. Of this total, we have accrued a liability of $2.5$4.6 million, representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.

At SeptemberJune 30, 2018,2019, we have various firm transportation agreements for gas and oil pipeline capacity with end dates ranging from 20192020 - 20252028 under which we will have to pay an estimated $30.0$70.5 million over the remaining terms of the agreements. These agreements were entered into to support our residue gas and oil marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation.
At September 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 7.9 years, total approximately $78.3 million. The commitments under the compressor equipment operating leases, which have lease terms expiring within the next 1 - 36 months, total approximately $25.6 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
June 30, 2019
(Unaudited)


accruals accordingly. Though some of the related claims may be significant, we believe the resolution of them, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals.

11.SUPPLEMENTAL CASH FLOW INFORMATION
  Three Months Ended
June 30,
 Six Months Ended
June 30,
(in thousands) 2019 2018 2019 2018
Cash paid during the period for:  
  
  
  
Interest (net of capitalized amounts of $19,381, $9,233, $20,121 and $9,389, respectively) (1) $14,396
 $22,954
 $32,984
 $23,343
Income taxes $1,200
 $
 $1,206
 $
Cash received for income tax refunds $335
 $717
 $336
 $718

(1)The six months ended June 30, 2019 includes $17.6 million in interest paid upon the redemption of Resolute’s senior notes and credit facility on March 1, 2019.
  Three Months Ended
September 30,
 Nine Months Ended
September 30,
(in thousands) 2018 2017 2018 2017
Cash paid during the period for:  
  
  
  
Interest expense (net of capitalized amounts of $407, $477, $9,796, and $12,439, respectively) $
 $109
 $23,343
 $28,881
Income taxes $
 $
 $
 $3
Cash received for income tax refunds $
 $
 $718
 $21


12.RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to Cimarex. Cimarex incurred drilling costs of approximately $17.0$22.1 million and $57.0$46.6 million related to these services during the three and ninesix months ended SeptemberJune 30, 2018, respectively,2019 and $15.4$16.4 million and $36.6$40.0 million during the three and ninesix months ended SeptemberJune 30, 2017, respectively.2018. The amount incurred in 2019 is included in the short-term lease costs disclosed in Note 10. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.


13.ACQUISITIONS

On March 1, 2019, we completed the acquisition of Resolute Energy Corporation, an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the Permian Basin of west Texas. The principal factors considered by management in making this acquisition included: (i) our expectation that 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:
23
(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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Table of Contents
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20182019
(Unaudited)




13.PROPERTY SALES
On August 31, 2018, we closed
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 salefair 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, finalization of the fair value of certain assets and liabilities, including pre-acquisition working capital balances and completion of the final Resolute tax returns that will provide the underlying tax basis of Resolute’s assets and liabilities and net operating losses. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.

The following table sets forth the preliminary purchase price allocation:
(in thousands) March 1, 2019
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 $8.4 million. These costs, which are comprised primarily of advisory, legal, and other professional and consulting fees, are included in the Other operating expense, net line item on our Condensed Consolidated Statements of Operations and Comprehensive Income.




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CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 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 June 30, 2019 is $100.0 million and $21.9 million, respectively.

Pro Forma Financial Information

The following supplemental pro forma information for the three and six month periods ended June 30, 2019 and 2018 has been prepared to give effect to the Resolute acquisition as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of the combined company’s proved oil and gas properties, principally located in Ward County, Texas for a sales price(ii) the capitalization of $544.5interest expense, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by Cimarex of $8.4 million asand transaction-related costs incurred by Resolute of $60.0 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by Cimarex to integrate the Resolute assets. The pro forma financial data has not been adjusted to reflect any other acquisitions or dispositions made during the resolutionperiods presented as their results were not deemed material.

The pro forma information is not necessarily indicative of all asserted defects. As of September 30, 2018, wethe results that might have received $534.6 million in net cash proceeds as adjusted for customary closing adjustments to reflect an effective date of Apriloccurred had the transaction actually taken place on January 1, 2018 and transaction costs. Final settlement, which will reflect customary post-closing adjustments, will occur byis not intended to be a projection of future results. Future results may vary significantly from the endresults reflected in the following pro forma information because of first quarter 2019. It was determined that this disposition would not significantly alter the relationship between capitalized costsnormal production declines, changes in commodity prices, future acquisitions and proved reserves, therefore, in accordance with the full cost method of accounting, no gain or loss was recognized on this sale. This sale is part of our continuous portfolio optimizationdivestitures, future development and high-grading of our investment opportunities.

exploration activities, and other factors.
24
  Three Months Ended
June 30,
 Six Months Ended
June 30,
(in thousands) 2019 2018 2019 2018
Revenue $546,463
 $625,332
 $1,176,556
 $1,263,410
Net income $109,365
 $148,486
 $121,909
 $335,544
Net income per share:        
Basic $1.07
 $1.48
 $1.18
 $3.33
Diluted $1.07
 $1.47
 $1.18
 $3.33






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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 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 the nine months ended September 30, 2018, as compared to the nine months ended September 30, 2017, market prices for oil have improved, while market prices for gas have declined. For the 2018 period, average NYMEX oil and gas prices were $66.75 per barrel and $2.90 per Mcf, respectively, representing an increase of 35% and a decrease of 9%, respectively, from the average NYMEX oil and gas prices for the 2017 period. However, local Local market prices for oil and gas can be impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials. Gas production growth and pipeline constraints

As demonstrated in the table below, our company-wide average realized prices for the three and six months ended June 30, 2019 as compared to the same periods in 2018 have declined for all products. In the case of oil sales, these decreases result from a combination of declining NYMEX prices in the 2019 periods and differentials in our Mid-Continent region, which deteriorated in the 2019 periods, and differentials in our Permian Basin andregion, which improved in the second quarter of 2019 but worsened in the six months ended June 30, 2019. In the case of gas sales, these decreases are driven largely by differentials in our Permian Basin region, which deteriorated significantly in the 2019 periods, partially offset by differentials in our Mid-Continent region, and oil production growth and pipeline constraintswhich improved in the Permian Basin have resulted in higher basis differentials and, therefore, lower realized prices. 2019 periods.




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  Three Months Ended
June 30,
 Variance Between 2019 / 2018 Six Months Ended
June 30,
 Variance Between 2019 / 2018
  2019 2018  2019 2018 
Average NYMEX price            
Oil — per barrel $59.82
 $67.88
 (12)% $57.36
 $65.37
 (12)%
Gas — per Mcf $2.64
 $2.80
 (6)% $2.90
 $2.90
 —%
             
Average realized price  
  
    
  
  
Oil — per barrel $54.24
 $60.99
 (11)% $51.64
 $60.45
 (15)%
Gas — per Mcf $0.50
 $1.65
 (70)% $1.19
 $1.96
 (39)%
             
Average price differential  
  
    
  
  
Oil — per barrel $(5.58) $(6.89) (19)% $(5.72) $(4.92) 16%
Gas — per Mcf $(2.14) $(1.15) 86% $(1.71) $(0.94) 82%

The average prices per barrel of oil and Mcf of gasprice differentials that we realized were less than the WTI Cushing and Henry Hub indices by the amountsin our two primary areas of operation are shown in the table below for the periods indicated.
  Average Price Differentials
  
Third
Quarter 2018
 
Second
Quarter 2018
 
First
Quarter 2018
 
Third
Quarter 2017
Permian Basin oil $14.34
 $8.05
 $3.12
 $4.06
Mid-Continent oil $1.08
 $2.18
 $2.34
 $2.99
Permian Basin gas $1.25
 $1.31
 $0.78
 $0.29
Mid-Continent gas $0.94
 $1.03
 $0.70
 $0.38
  Average Price Differentials
  2019 2018
  
Second
Quarter
 
First
Quarter
 
Fourth
Quarter
 
Third
Quarter
 
Second
Quarter
 
First
Quarter
             
Oil            
Permian Basin $(5.80) $(6.90) $(11.64) $(14.34) $(8.05) $(3.12)
Mid-Continent $(4.39) $(2.17) $(2.33) $(1.08) $(2.18) $(2.34)
             
Gas            
Permian Basin $(3.10) $(1.91) $(2.21) $(1.25) $(1.31) $(0.78)
Mid-Continent $(0.86) $(0.46) $(0.83) $(0.94) $(1.03) $(0.70)

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


25

TableIf the trend of Contentsdecreasing market prices and significant basis differentials continues, coupled with continued exploration and development capital spending, we will incur a ceiling test impairment by year-end. At June 30, 2019, a decline in the value of our ceiling limitation of approximately 4% or more would have resulted in an impairment.



See “Risk Factors” in Item 1A of this Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 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.




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Summary of Operating and Financial Results for the NineSix Months Ended SeptemberJune 30, 20182019 Compared to the NineSix Months Ended SeptemberJune 30, 2017:2018:

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%28% to 212.1266.9 MBOE per day.

Oil volumes increased 14%28% to 63.681.4 MBbls per day.

Gas volumes increased 7%21% to 544.4652.5 MMcf per day.

NGL volumes increased 23%37% to 57.776.7 MBbls per day.

Total production revenue increased 26% to $1.68remained flat at $1.11 billion.

Cash flow provided by operating activities increased 53%decreased 6% to $1.16 billion.$664.1 million.

Exploration and development expenditures increased 27%1% to $1.19 billion.$693.0 million.

Net income was $475.7$135.6 million, or $5.00$1.34 per diluted share, for the first ninesix months of 2018,2019, as compared to net income of $319.6$327.3 million, or $3.36$3.44 per diluted share, for the first ninesix months of 2017.2018.

RESULTS OF OPERATIONS

Three and NineSix Months Ended SeptemberJune 30, 20182019 vs. Three and NineSix Months Ended SeptemberJune 30, 20172018
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 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
September 30,
  2018 2017
(in thousands) Pre-
ASC 606 Adoption
 
Impact of
ASC 606
 Post-
ASC 606 Adoption
 As Reported
Oil sales $342,495
 $
 $342,495
 $231,441
Gas sales 98,321
 (3,888) 94,433
 125,707
NGL sales 151,648
 (5,994) 145,654
 95,191
Total oil, gas, and NGL sales $592,464
 $(9,882) $582,582
 $452,339
         
Transportation, processing, and other operating costs $59,602
 $(9,882) $49,720
 $58,387

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  Nine Months Ended
September 30,
  2018 2017
(in thousands) Pre-
ASC 606 Adoption
 
Impact of
ASC 606
 Post-
ASC 606 Adoption
 As Reported
Oil sales $1,036,402
 $
 $1,036,402
 $687,960
Gas sales 295,725
 (10,784) 284,941
 390,126
NGL sales 382,387
 (21,321) 361,066
 256,503
Total oil, gas, and NGL sales $1,714,514
 $(32,105) $1,682,409
 $1,334,589
         
Transportation, processing, and other operating costs $178,923
 $(32,105) $146,818
 $172,034

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

Production volumes were higher for all products during the three and ninesix months ended SeptemberJune 30, 20182019 as compared to the three and ninesix months ended SeptemberJune 30, 2017. Realized oil and NGL prices also were higher,2018, while realized gas prices were lower. Our acquisition of Resolute and ongoing completion of new wells have increased our volumes. However, lower market prices and large basis differentials, both of which are out of our control, have lowered our realized prices and, therefore, our revenue. In addition, transportation and processing charges for sales contracts that transfer control of the product at the wellhead versus the tailgate of processing plants are reflected as reductions to revenue increased 29%under Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”) and, therefore, negatively impact our realized prices. The largest sales contract we acquired with Resolute is this type of contract and sales volumes under legacy Cimarex contracts structured this way have increased. See below “Transportation, Processing, and Other Operating” for additional information. Our revenue decreased 1%, or $130.2$6.6 million, during the three months ended SeptemberJune 30, 20182019 as compared to the three months ended SeptemberJune 30, 20172018, and increased 26%less than 1%, or $347.8$5.2 million, during the ninesix months ended SeptemberJune 30, 20182019 as compared to the ninesix months ended SeptemberJune 30, 2017.2018. The following tables show our production revenue for the periods indicated as well as the change in revenue due to changes in volumes and prices.



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 Three Months Ended
September 30,
 Variance Between 2018 / 2017 Price/Volume Variance Three Months Ended
June 30,
 Variance Between 2019 / 2018 Price/Volume Variance
Production Revenue (in thousands)
 2018 2017 Price Volume Total 2019 2018 Price Volume Total
Oil sales $342,495
 $231,441
 $111,054
 48% $81,550
 $29,504
 $111,054
 $411,766
 $342,184
 $69,582
 20% $(51,247) $120,829
 $69,582
Gas sales 94,433
 125,707
 (31,274) (25)% (41,639) 10,365
 (31,274) 30,362
 80,787
 (50,425) (62)% (69,681) 19,256
 (50,425)
NGL sales 145,654
 95,191
 50,463
 53% 23,164
 27,299
 50,463
 95,682
 121,415
 (25,733) (21)% (67,352) 41,619
 (25,733)
 $582,582
 $452,339
 $130,243
 29% $63,075
 $67,168
 $130,243
 $537,810
 $544,386
 $(6,576) (1)% $(188,280) $181,704
 $(6,576)


 Nine Months Ended
September 30,
 Variance Between 2018 / 2017 Price/Volume Variance Six Months Ended
June 30,
 Variance Between 2019 / 2018 Price/Volume Variance
Production Revenue (in thousands)
 2018 2017 Price Volume Total 2019 2018 Price Volume Total
Oil sales $1,036,402
 $687,960
 $348,442
 51% $249,448
 $98,994
 $348,442
 $761,072
 $693,907
 $67,165
 10% $(129,855) $197,020
 $67,165
Gas sales 284,941
 390,126
 (105,185) (27)% (133,762) 28,577
 (105,185) 140,338
 190,508
 (50,170) (26)% (90,943) 40,773
 (50,170)
NGL sales 361,066
 256,503
 104,563
 41% 44,615
 59,948
 104,563
 203,621
 215,412
 (11,791) (5)% (92,295) 80,504
 (11,791)
 $1,682,409
 $1,334,589
 $347,820
 26% $160,301
 $187,519
 $347,820
 $1,105,031
 $1,099,827
 $5,204
 —% $(313,093) $318,297
 $5,204

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The table below presents our production volumes by region.
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 Three Months Ended
June 30,
 Six Months Ended
June 30,
Production Volumes 2018 2017 2018 2017 2019 2018 2019 2018
Oil (Bbls per day)                
Permian Basin 49,001
 43,735
 49,211
 43,544
 70,669
 48,797
 67,835
 49,318
Mid-Continent 14,755
 12,846
 14,149
 11,937
 12,623
 12,473
 13,419
 13,841
Other 153
 106
 226
 115
 138
 381
 179
 263
 63,909
 56,687
 63,586
 55,596
 83,430
 61,651
 81,433
 63,422
Gas (MMcf per day)                
Permian Basin 239.4
 217.9
 239.3
 212.9
 379.3
 240.5
 360.1
 239.2
Mid-Continent 317.9
 296.8
 303.6
 292.4
 285.5
 297.0
 291.3
 296.2
Other 1.5
 1.2
 1.5
 1.4
 1.0
 2.0
 1.1
 1.7
 558.8
 515.9
 544.4
 506.7
 665.8
 539.5
 652.5
 537.1
NGL (Bbls per day)                
Permian Basin 31,919
 24,659
 29,863
 23,771
 54,813
 32,865
 50,567
 28,817
Mid-Continent 29,603
 23,142
 27,829
 22,999
 25,496
 26,894
 26,060
 26,927
Other 38
 39
 56
 36
 53
 98
 53
 66
 61,560
 47,840
 57,748
 46,806
 80,362
 59,857
 76,680
 55,810
Total (BOE per day)                
Permian Basin 120,822
 104,703
 118,952
 102,798
 188,703
 121,744
 178,413
 118,002
Mid-Continent 97,346
 85,451
 92,569
 83,676
 85,696
 88,864
 88,028
 90,142
Other 427
 364
 548
 384
 368
 816
 427
 608
 218,595
 190,518
 212,069
 186,858
 274,767
 211,424
 266,868
 208,752
Our total production increased 15%, or 28,077 BOE per day, during the three months ended September 30, 2018, as compared to the three months ended September 30, 2017 and increased 13%, or 25,211 BOE per day, during the nine months ended September 30, 2018, as compared to the nine months ended September 30, 2017. This increase was the result of our ongoing drilling and completion activity throughout 2017 and into 2018. See LIQUIDITY AND CAPITAL RESOURCES Capital Expendituresfor 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 six months ended June 30, 2019, approximately 77%83% of our oil production was in the Permian Basin.Basin, up from approximately 78% during the six months ended June 30, 2018. Our realized prices do not include settlements of commodity derivative contracts.
 Three Months Ended
September 30,
 Variance Between 2018 / 2017 Nine Months Ended
September 30,
 Variance Between 2018 / 2017 Three Months Ended
June 30,
 Variance Between 2019 / 2018 Six Months Ended
June 30,
 Variance Between 2019 / 2018
 2018 2017 2018 2017  2019 2018 2019 2018 
Oil                        
Total volume — MBbls 5,880
 5,215
 13% 17,359
 15,178
 14% 7,592
 5,610
 35% 14,739
 11,479
 28%
Total volume — MBbls per day 63.9
 56.7
 13% 63.6
 55.6
 14% 83.4
 61.7
 35% 81.4
 63.4
 28%
Percentage of total production 29% 30%   30% 30%   30% 29%   30% 30%  
Average realized price — per barrel $58.25
 $44.38
 31% $59.70
 $45.33
 32% $54.24
 $60.99
 (11)% $51.64
 $60.45
 (15)%
Average WTI Midland price — per barrel $56.89
 $47.44
 20% $60.97
 $49.14
 24% $57.72
 $62.76
 (8)% $54.35
 $63.01
 (14)%
Average WTI Cushing price — per barrel $69.50
 $48.20
 44% $66.75
 $49.46
 35% $59.82
 $67.88
 (12)% $57.36
 $65.37
 (12)%
                  
Gas  
  
    
  
    
  
    
  
  
Total volume — MMcf 51,406
 47,467
 8% 148,625
 138,338
 7% 60,592
 49,094
 23% 118,108
 97,219
 21%
Total volume — MMcf per day 558.8
 515.9
 8% 544.4
 506.7
 7% 665.8
 539.5
 23% 652.5
 537.1
 21%
Percentage of total production 43% 45%   43% 45%   41% 43%   41% 43%  
Average realized price — per Mcf(1) $1.84
(1)$2.65
 (31)% $1.92
(1)$2.82
 (32)% $0.50

$1.65
 (70)% $1.19

$1.96
 (39)%
Average Henry Hub price — per Mcf $2.91
 $2.99
 (3)% $2.90
 $3.17
 (9)% $2.64
 $2.80
 (6)% $2.90
 $2.90
 —%
                  
NGL  
  
    
  
    
  
    
  
  
Total volume — MBbls 5,663
 4,401
 29% 15,765
 12,778
 23% 7,313
 5,447
 34% 13,879
 10,102
 37%
Total volume — MBbls per day 61.6
 47.8
 29% 57.7
 46.8
 23% 80.4
 59.9
 34% 76.7
 55.8
 37%
Percentage of total production 28% 25%   27% 25%   29% 28%   29% 27%  
Average realized price — per barrel(2) $25.72
(2)$21.63
 19% $22.90
(2)$20.07
 14% $13.08
 $22.29
 (41)% $14.67
 $21.32
 (31)%
                  
Total  
  
    
  
    
  
    
  
  
Total production — MBOE 20,111
 17,528
 15% 57,895
 51,012
 13% 25,004
 19,240
 30% 48,303
 37,784
 28%
Total production — MBOE per day 218.6
 190.5
 15% 212.1
 186.9
 13% 274.8
 211.4
 30% 266.9
 208.8
 28%
Average realized price — per BOE(3) $28.97
(3)$25.81
 12% $29.06
(3)$26.16
 11% $21.51
 $28.30
 (24)% $22.88
 $29.11
 (21)%

The average realized gas, NGL, and total prices shown in the table above reflect the deduction of certain transportation, processing, and other costs as reductions of revenue under ASC 606, which reduced the average realized prices as follows:
(1)ASC 606 reduced theThe average realized gas priceprices were reduced by $0.07$0.25 per Mcf, $0.08 per Mcf, $0.21 per Mcf, and $0.07 per Mcf for the three and nine months ended SeptemberJune 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively.
(2)ASC 606 reduced theThe average realized NGL priceprices were reduced by $1.06$1.29 per barrel, $0.68 per barrel, $1.29 per barrel, and $1.36$1.52 per barrel for the three and nine months ended SeptemberJune 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively.
(3)ASC 606 reduced theThe average realized total priceprices were reduced by $0.49$0.99 per BOE, $0.39 per BOE, $0.88 per BOE, and $0.55$0.59 per BOE for the three and nine months ended SeptemberJune 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively.


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Other revenues

We transport, process, and market some third-party gas that is associated with our equity gas.  We market and sell gas for other working interest owners under short-term agreements and may earn a fee for such services.  The table below reflects income from third-party gas gathering and processing and our net marketing margin for marketing third-party gas. 
 Three Months Ended
September 30,
 Variance Between 2018 / 2017 Nine Months Ended
September 30,
 Variance Between 2018 / 2017 Three Months Ended
June 30,
 Variance Between 2019 / 2018 Six Months Ended
June 30,
 Variance Between 2019 / 2018
Gas Gathering and Marketing Revenues (in thousands)
 2018 2017 2018 2017  2019 2018 2019 2018 
Gas gathering and other $9,244
 $11,056
 $(1,812) $32,506
 $32,416
 $90
 $9,769
 $11,810
 $(2,041) $20,031
 $23,262
 $(3,231)
Gas marketing $(338) $286
 $(624) $(19) $304
 $(323) $(1,116) $78
 $(1,194) $(1,642) $319
 $(1,961)

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, otherssome 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 SeptemberJune 30, 20182019 were higher by 26%9%, or $80.7$33.6 million, compared to the three months ended SeptemberJune 30, 2017.2018.  The primary reasons for the increase were: (i) the $37.9 million increase in net losses on derivative instruments, (ii) the $24.9$69.9 million increase in depreciation, depletion, and amortization, (ii) the $13.1 million increase in taxes other than income, and (iii) the $10.9$8.5 million increase in production expense. expense, partially offset by the $62.5 million increase in net gains on derivative instruments.
 Three Months Ended
September 30,
 
Variance Between
2018 / 2017
 Per BOE Three Months Ended
June 30,
 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 $136,302
 $111,396
 $24,906
 $6.78
 $6.36
 $213,327
 $143,388
 $69,939
 $8.53
 $7.45
Asset retirement obligation 1,893
 1,497
 396
 $0.09
 $0.09
 2,157
 2,053
 104
 $0.09
 $0.11
Production 76,272
 65,410
 10,862
 $3.79
 $3.73
 87,726
 79,215
 8,511
 $3.51
 $4.12
Transportation, processing, and other operating 49,720
 58,387
 (8,667) $2.47
 $3.33
 48,331
 51,933
 (3,602) $1.93
 $2.70
Gas gathering and other 10,569
 8,856
 1,713
 $0.53
 $0.51
 13,605
 9,467
 4,138
 $0.54
 $0.49
Taxes other than income 28,431
 24,314
 4,117
 $1.41
 $1.39
 41,033
 27,930
 13,103
 $1.64
 $1.45
General and administrative 21,148
 21,039
 109
 $1.05
 $1.20
 24,911
 19,739
 5,172
 $1.00
 $1.03
Stock compensation 6,437
 7,038
 (601) $0.32
 $0.40
 6,494
 3,095
 3,399
 $0.26
 $0.16
Loss on derivative instruments, net 54,006
 16,109
 37,897
 N/A
 N/A
(Gain) loss on derivative instruments, net (40,768) 21,699
 (62,467) N/A
 N/A
Other operating expense, net 10,015
 95
 9,920
 N/A
 N/A
 590
 5,252
 (4,662) N/A
 N/A
 $394,793
 $314,141
 $80,652
  
  
 $397,406
 $363,771
 $33,635
  
  

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Total operating costs and expenses for the ninesix months ended SeptemberJune 30, 20182019 were higher by 34%36%, or $275.2$246.1 million, compared to the ninesix months ended SeptemberJune 30, 2017.2018.  The primary reasons for the increase were:were due to the following increases: (i) the $121.8$127.5 million decrease in net gains on derivative instruments to an overall net loss, (ii) the $97.5 million increase in depreciation, depletion, and amortization, (ii) $57.1 million in net losses on derivative instruments, (iii) the $36.3$16.6 million increase in production expense, (iv) the $23.4 million increase in taxes other than income, (iv) $14.5 million in production expense, and (v) the $14.5$10.9 million increase in other operating expense, partially offset by the $25.2 million decrease in transportation, processing,general and other operating expense. administrative.



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 Nine Months Ended
September 30,
 
Variance Between
2018 / 2017
 Per BOE Six Months Ended
June 30,
 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 $412,549
 $315,096
 $97,453
 $7.13
 $6.18
 $403,744
 $276,247
 $127,497
 $8.36
 $7.31
Asset retirement obligation 5,006
 4,077
 929
 $0.09
 $0.08
 4,206
 3,113
 1,093
 $0.09
 $0.08
Production 226,758
 190,409
 36,349
 $3.92
 $3.73
 164,959
 150,486
 14,473
 $3.42
 $3.98
Transportation, processing, and other operating 146,818
 172,034
 (25,216) $2.54
 $3.37
 101,939
 97,098
 4,841
 $2.11
 $2.57
Gas gathering and other 29,859
 25,930
 3,929
 $0.52
 $0.51
 25,925
 19,290
 6,635
 $0.54
 $0.51
Taxes other than income 86,549
 63,104
 23,445
 $1.49
 $1.24
 74,727
 58,118
 16,609
 $1.55
 $1.54
General and administrative 64,208
 58,835
 5,373
 $1.11
 $1.15
 53,995
 43,060
 10,935
 $1.12
 $1.14
Stock compensation 16,262
 19,619
 (3,357) $0.28
 $0.38
 13,207
 9,825
 3,382
 $0.27
 $0.26
Loss (gain) on derivative instruments, net 71,546
 (50,261) 121,807
 N/A
 N/A
Loss on derivative instruments, net 74,684
 17,540
 57,144
 N/A
 N/A
Other operating expense, net 15,470
 977
 14,493
 N/A
 N/A
 8,916
 5,455
 3,461
 N/A
 N/A
 $1,075,025
 $799,820
 $275,205
  
  
 $926,302
 $680,232
 $246,070
  
  

Depreciation, Depletion, and Amortization

Depletion of our producing properties is computed using the units-of-production method. The economic life of each producing well depends upon the estimated proved reserves for that well, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved, and impairments of oil and gas properties will also impact depletion expense. While the increase in oil prices has more than offset the decrease in gas pricesOur net proved properties, production, and reserves have increased during 20182019 as compared to 2017, thus increasing our reserves, the increase in production combined with2018 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, with the depreciation of our finance lease gathering system right-of-use asset being included in our depreciation expense. The increase in depreciation expense during the 2019 periods as compared to 2018 periods is primarily due to: (i) increased depreciation on our gathering and plant facilities due to ongoing expenditures on this infrastructure and (ii) the depreciation on our gathering system right-of-use asset. Depreciation, depletion, and amortization (“DD&A”) consisted of the following for the periods indicated:
 Three Months Ended
September 30,
 
Variance Between
2018 / 2017
 Per BOE Three Months Ended
June 30,
 
Variance Between
2019 / 2018
 Per BOE
DD&A Expense (in thousands, except per BOE)
 2018 2017 2018 2017 2019 2018 2019 2018
Depletion $123,668
 $99,633
 $24,035
 $6.15
 $5.68
 $196,899
 $131,220
 $65,679
 $7.87
 $6.82
Depreciation 12,634
 11,763
 871
 0.63
 0.68
 16,428
 12,168
 4,260
 0.66
 0.63
 $136,302
 $111,396
 $24,906
 $6.78
 $6.36
 $213,327
 $143,388
 $69,939
 $8.53
 $7.45





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 Nine Months Ended
September 30,
 
Variance Between
2018 / 2017
 Per BOE Six Months Ended
June 30,
 
Variance Between
2019 / 2018
 Per BOE
DD&A Expense (in thousands, except per BOE)
 2018 2017 2018 2017 2019 2018 2019 2018
Depletion $375,278
 $280,379
 $94,899
 $6.48
 $5.50
 $371,611
 $251,610
 $120,001
 $7.69
 $6.66
Depreciation 37,271
 34,717
 2,554
 0.65
 0.68
 32,133
 24,637
 7,496
 0.67
 0.65
 $412,549
 $315,096
 $97,453
 $7.13
 $6.18
 $403,744
 $276,247
 $127,497
 $8.36
 $7.31

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Production

Production expense generally consists of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating, and miscellaneous other costs (lease operating expense). Production expense also includes well workover activity necessary to maintain production from existing wells. Production expense consisted of lease operating expense and workover expense as follows:
 Three Months Ended
September 30,
 
Variance Between
2018 / 2017
 Per BOE Three Months Ended
June 30,
 
Variance Between
2019 / 2018
 Per BOE
Production Expense (in thousands, except per BOE)
 2018 2017 2018 2017 2019 2018 2019 2018
Lease operating expense $61,568
 $55,296
 $6,272
 $3.06
 $3.15
 $71,778
 $62,355
 $9,423
 $2.87
 $3.24
Workover expense 14,704
 10,114
 4,590
 0.73
 0.58
 15,948
 16,860
 (912) 0.64
 0.88
 $76,272
 $65,410
 $10,862
 $3.79
 $3.73
 $87,726
 $79,215
 $8,511
 $3.51
 $4.12


 Nine Months Ended
September 30,
 
Variance Between
2018 / 2017
 Per BOE Six Months Ended
June 30,
 
Variance Between
2019 / 2018
 Per BOE
Production Expense (in thousands, except per BOE)
 2018 2017 2018 2017 2019 2018 2019 2018
Lease operating expense $184,400
 $156,644
 $27,756
 $3.19
 $3.07
 $134,186
 $122,831
 $11,355
 $2.78
 $3.25
Workover expense 42,358
 33,765
 8,593
 0.73
 0.66
 30,773
 27,655
 3,118
 0.64
 0.73
 $226,758
 $190,409
 $36,349
 $3.92
 $3.73
 $164,959
 $150,486
 $14,473
 $3.42
 $3.98

Lease operating expense in the thirdsecond quarter 20182019 increased 11%15%, or $6.3$9.4 million, compared to the thirdsecond quarter of 2017.2018. Lease operating expense for the ninesix months ended SeptemberJune 30, 20182019 increased 18%9%, or $27.8$11.4 million, as compared to the ninesix months ended SeptemberJune 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. Additional wells and increased productionThese increases were partially offset by expense reductions related to the sale of non-core properties principally located in Ward County, Texas in August 2018. The following types of expenses have increased in the following costs between2019 periods as compared to the two quarters:2018 periods: (i) saltwater disposal, due to increased water volumes,compressor rentals, (ii) labor, and (iii) equipment rental, primarily additional compressors. The preceding costs also increased between the two nine-month periods, as did the following costs: (i) electricity, (ii) environmental compliance, primarily emissions-related, (iii) tank battery and processing equipment and maintenance, and (iv) chemicals and treating, due to increased water volumes and chemical treating.electricity.

Workover expense in the thirdsecond quarter 2018 increased 45%2019 decreased 5%, or $4.6$0.9 million, compared to the thirdsecond quarter of 2017.2018. Workover expense for the ninesix months ended SeptemberJune 30, 20182019 increased 25%11%, or $8.6$3.1 million, compared to the nine months ended September 30, 2017. During both the three and nine months ended September 30, 2018, we had more workover projects in progress than we did during the comparable 2017 periods. Additionally, during the 2018 periods the largest area of increased expenditures as compared to the 2017 periodssix months ended June 30, 2018. During the six months ended June 30, 2018, our workover expense was for artificial lift conversions. Generally, workover costs will fluctuate based onreduced due to receiving approximately $4.0 million in insurance proceeds related to the amountremediation and repairs incurred as a result of maintenance and remedial activity required during the period.a 2015 flooding event.




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Transportation, Processing, and Other Operating

Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, including gathering, fuel, compression, and processing costs. Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs, and structure of sales contracts. If the sales contract transfers control of the product at the wellhead, transportation and processing costs are included as a reduction in the revenue we record and are not included in transportation, processing, and other operating costs.
The largest sales contract that we acquired with Resolute is structured this way and sales volumes under legacy Cimarex contracts structured this way have increased, therefore, our transportation and processing costs have not increased commensurate with production volume increases. Transportation, processing, and other operating costs in the thirdsecond quarter 20182019 were 15%7%, or $8.7$3.6 million, lower than the same costs in the thirdfirst quarter 2017. Transportation, processing, and other operating costs in2018. For the ninesix months ended SeptemberJune 30, 2018 were 15%, or $25.2 million, lower than the same costs in the nine months ended September 30, 2017. These decreases were primarily due to our adoption of ASC 606 effective January 1, 2018, whereby certain transportation and processing costs are now reclassified out of2019, transportation, processing, and other operating costs were 5%, or $4.8 million, higher than for the six months ended June 30, 2018. Transportation and are treatedprocessing costs included as a deduction from revenue. Thereduction in revenue since our adoption of ASC 606 reduced Transportation, processing,on January 1, 2018 were $24.7 million and other operating costs by $9.9$42.6 million infor the third quarter 2018three and by $32.1 million in the ninesix months ended SeptemberJune 30, 2018. These reductions were partially offset by increased costs due to increased production volumes. See Note 1 to2019 and $7.7 million and $22.2 million for the Condensed Consolidated Financial Statements for additional information regarding the adoption of ASC 606.three and six months ended June 30, 2018.

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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 SeptemberJune 30, 20182019 was 19%44%, or $1.7$4.1 million, higher than gas gathering and other in the three months ended SeptemberJune 30, 2017.2018. Gas gathering and other in the ninesix months ended SeptemberJune 30, 20182019 was 15%34%, or $3.9$6.6 million, higher than gas gathering and other in the ninesix months ended SeptemberJune 30, 2017.2018. The increases wereare primarily due to overall increases in operating costs partially offset by lower product costs associated with processing third-party production due primarily to lower volumes.volumes and prices. The increase in operating costs was due primarily to an increase in compression costs.

Taxes Other than Income

Taxes other than income consist of production (or severance) taxes, ad valorem taxes, and other taxes.  State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production and ad valorem taxes being based on the value of properties.  Production taxes make up the majority of this expense for us, with revenue-based production taxes being the largest component of these taxes.us.  Taxes other than income increased $4.1$13.1 million, or 17%47%, in the thirdsecond quarter of 20182019 as compared to the thirdsecond quarter of 2017.2018. Taxes other than income increased $23.4$16.6 million, or 37%29%, in the ninesix months ended SeptemberJune 30, 20182019 as compared to the ninesix months ended SeptemberJune 30, 2017. The increases are2018. Production taxes have increased primarily due to increased production volumes. However, the majority of the increase seen in the 2019 periods as compared to the 2018 periods was due to increases in revenue seen betweenad valorem taxes. Ad valorem taxes increased by $7.5 million, or 210%, in the comparable periodssecond quarter of 2019 as wellcompared to the second quarter of 2018 and by $10.4 million, or 145%, in the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. These increases are due to increased ad valorem taxes in 2018 due to higher assessed valuations as well as additional wells. All periods included credits for tax refunds, generally for high-cost gas wellsnew properties, including those acquired in the State of Texas. The refunds in the threeResolute acquisition, and nine months ended September 30, 2018 were $11.3 million and $6.7 million, respectively, higher than the refunds in the three and nine months ended September 30, 2017. The three months ended September 30, 2018 included a $10.1 million Texas marketing cost deduction refund.expected increased assessed values. Taxes other than income was 4.9%7.6% and 5.4%5.1% of production revenues for the three months ended SeptemberJune 30, 20182019 and 2017,2018, respectively, and was 5.1%6.8% and 4.7%5.3% of production revenues for the ninesix months ended SeptemberJune 30, 2019 and 2018, and 2017, respectively.




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General and Administrative

General and administrative (“G&A”) expense consists primarily of salaries and related benefits, office rent, legal and consulting fees, systems costs, and other administrative costs incurred. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting. The amount of expense capitalized varies and depends on whether the cost incurred can be directly identified with acquisition, exploration, and development activities. The percentage of gross G&A capitalized ranged from 47%44% to 49%50% during the periods presented in the table below, which shows our G&A costs.
 Three Months Ended
September 30,
 Variance Between 2018 / 2017 Nine Months Ended
September 30,
 Variance Between 2018 / 2017 Three Months Ended
June 30,
 Variance Between 2019 / 2018 Six Months Ended
June 30,
 Variance Between 2019 / 2018
General and Administrative Expense
(in thousands)
 2018 2017 2018 2017  2019 2018 2019 2018 
Gross G&A $41,584
 $39,885
 $1,699
 $121,708
 $112,516
 $9,192
 $46,930
 $39,276
 $7,654
 $96,166
 $80,124
 $16,042
Less amounts capitalized to oil and gas properties (20,436) (18,846) (1,590) (57,500) (53,681) (3,819) (22,019) (19,537) (2,482) (42,171) (37,064) (5,107)
G&A expense $21,148
 $21,039
 $109
 $64,208
 $58,835
 $5,373
 $24,911
 $19,739
 $5,172
 $53,995
 $43,060
 $10,935

G&A expense for the nine months ended September 30, 2018second quarter of 2019 was 9%26%, or $5.4$5.2 million, higher than G&A expense for the ninesecond quarter of 2018. G&A expense for the six months ended SeptemberJune 30, 2017. This increase2019 was 25%, or $10.9 million, higher than G&A expense for the six months ended June 30, 2018. These increases were primarily due to increased employee headcount and increasedemployee-related costs such as salaries and wages, benefits, primarily consistingother compensation, and benefits. Included in the six months ended June 30, 2019 was $2.9 million of profit sharing, consulting,severance expense related to former Resolute employees who performed transition work at Cimarex and legal expense.then were subsequently terminated. 

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Stock Compensation

Stock compensation expense consists of non-cash charges resulting from the amortization of the cost of restricted stock and stock option awards, net of amounts capitalized to oil and gas properties. We have recognized stock-based compensation cost as follows:
 Three Months Ended
September 30,
 Variance Between 2018 / 2017 Nine Months Ended
September 30,
 Variance Between 2018 / 2017 Three Months Ended
June 30,
 Variance Between 2019 / 2018 Six Months Ended
June 30,
 Variance Between 2019 / 2018
Stock Compensation Expense (in thousands)
 2018 2017 2018 2017  2019 2018 2019 2018 
Restricted stock awards:                        
Performance stock awards $6,364
 $6,508
 $(144) $16,902
 $19,348
 $(2,446) $5,535
 $3,809
 $1,726
 $10,929
 $10,538
 $391
Service-based stock awards 5,244
 5,317
 (73) 14,563
 14,449
 114
 5,993
 4,247
 1,746
 13,224
 9,319
 3,905
 11,608
 11,825
 (217) 31,465
 33,797
 (2,332) 11,528
 8,056
 3,472
 24,153
 19,857
 4,296
Stock option awards 571
 698
 (127) 1,825
 1,943
 (118) 396
 637
 (241) 1,018
 1,254
 (236)
Total stock compensation cost 12,179
 12,523
 (344) 33,290
 35,740
 (2,450) 11,924
 8,693
 3,231
 25,171
 21,111
 4,060
Less amounts capitalized to oil and gas properties (5,742) (5,485) (257) (17,028) (16,121) (907) (5,430) (5,598) 168
 (11,964) (11,286) (678)
Stock compensation expense $6,437
 $7,038
 $(601) $16,262
 $19,619
 $(3,357) $6,494
 $3,095
 $3,399
 $13,207
 $9,825
 $3,382

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 decreaseincrease in total stock compensation cost in the nine months ended September 30, 20182019 periods as compared to the nine months ended September 30, 20172018 periods is primarily due to awards granted either during or subsequent to the 2018 periods and performance stock award forfeitures that occurred during the second quarter 2018.of 2018, both of which were partially offset by awards vesting prior to or during the 2019 periods. Our accounting policy is to account for forfeitures in compensation cost when they occur.




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(Gain) Loss (Gain) on Derivative Instruments, Net

The following table presents the components of Loss (gain)(Gain) loss on derivative instruments, net for the periods indicated. See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.
 Three Months Ended
September 30,
 Variance Between 2018 / 2017 Nine Months Ended
September 30,
 Variance Between 2018 / 2017 Three Months Ended
June 30,
 Variance Between 2019 / 2018 Six Months Ended
June 30,
 Variance Between 2019 / 2018
Loss (Gain) on Derivative Instruments, Net (in thousands)
 2018 2017 2018 2017 
Decrease (increase) in fair value of derivative instruments, net:  
  
  
      
(Gain) Loss on Derivative Instruments, Net (in thousands)
 2019 2018 Variance Between 2019 / 2018 2019 2018 Variance Between 2019 / 2018
(Increase) decrease in fair value of derivative instruments, net:  
  
     
Gas contracts $6,378
 $1,156
 $5,222
 $9,155
 $(26,783) $35,938
 $(6,370) $14,566
 $(20,936) $(16,216) $2,777
 $(18,993)
Oil contracts 47,129
 17,929
 29,200
 41,973
 (26,220) 68,193
 (28,161) (397) (27,764) 88,086
 (5,156) 93,242
 53,507
 19,085
 34,422
 51,128
 (53,003) 104,131
 (34,531) 14,169
 (48,700) 71,870
 (2,379) 74,249
Cash (receipts) payments on derivative instruments, net:  
  
          
  
        
Gas contracts (3,462) (2,067) (1,395) (18,499) (931) (17,568) (21,176) (9,918) (11,258) (17,412) (15,037) (2,375)
Oil contracts 3,961
 (909) 4,870
 38,917
 3,673
 35,244
 14,939
 17,448
 (2,509) 20,226
 34,956
 (14,730)
 499
 (2,976) 3,475
 20,418
 2,742
 17,676
 (6,237) 7,530
 (13,767) 2,814
 19,919
 (17,105)
Loss (gain) on derivative instruments, net $54,006
 $16,109
 $37,897
 $71,546
 $(50,261) $121,807
(Gain) loss on derivative instruments, net $(40,768) $21,699
 $(62,467) $74,684
 $17,540
 $57,144

Other Operating Expense, Net

Other operating expense, net isduring the six months ended June 30, 2019 was comprised primarily of $8.4 million in acquisition-related costs incurred to effect the Resolute acquisition. These costs consisted primarily of advisory, legal, and other professional and consulting fees. Other operating expense, net during the three months ended June 30, 2018 was comprised primarily of $4.9 million in litigation settlements and allowance for doubtful accounts adjustments.settlements.

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Other Income and Expense
 Three Months Ended
September 30,
 Variance Between 2018 / 2017 Nine Months Ended
September 30,
 Variance Between 2018 / 2017 Three Months Ended
June 30,
 Variance Between 2019 / 2018 Six Months Ended
June 30,
 Variance Between 2019 / 2018
Other Income and Expense (in thousands)
 2018 2017 2018 2017  2019 2018 2019 2018 
Interest expense $17,159
 $16,838
 $321
 $50,837
 $57,985
 $(7,148) $24,674
 $16,895
 $7,779
 $45,079
 $33,678
 $11,401
Capitalized interest (5,457) (5,373) (84) (15,117) (17,456) 2,339
 (16,805) (4,850) (11,955) (25,547) (9,660) (15,887)
Loss on early extinguishment of debt 
 
 
 
 28,169
 (28,169) 
 
 
 4,250
 
 4,250
Other, net (7,544) (4,563) (2,981) (14,716) (9,004) (5,712) (2,167) (2,605) 438
 (4,408) (7,172) 2,764
 $4,158
 $6,902
 $(2,744) $21,004
 $59,694
 $(38,690) $5,702
 $9,440
 $(3,738) $19,374
 $16,846
 $2,528

The majority of our interest expense relates to interest on our senior unsecured notes. Also included in interest expense is interest expense on our Credit Facility borrowings, the amortization of debt issuance costs and discount as well asdiscounts, and 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 nine months ended September 30, 20182019 periods as compared to the nine months ended September 30, 20172018 periods 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) borrowings on our Credit Facility in 2019 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.thereafter to meet cash requirements as needed (we did not borrow on our Credit Facility in 2018), and (iii) interest expense on our finance lease. The $28.2$4.3 million loss on early extinguishment of debt incurred during the ninesix months ended SeptemberJune 30, 20172019 was also associated with the debt tender offer$600 million of



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8.5% senior notes we acquired with Resolute and redemption.elected to immediately repay. The loss was composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.  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 ninethree and six months ended SeptemberJune 30, 20182019 as compared to the ninethree and six months ended September 30, 2017, thus reducing our capitalized interest between the year-to-date periods. Also contributing to lower capitalized interest in the nine months ended SeptemberJune 30, 2018, was a lower average interest rate on borrowings outstandingprimarily due to the replacement of our 5.875% notes with 3.90% notesResolute acquisition. Included in the second quarterpreliminary purchase price allocation of 2017.the Resolute acquisition was non-producing leasehold costs of $1.05 billion.

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

Income Tax Expense (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
September 30,
 Variance Between 2018 / 2017 Nine Months Ended
September 30,
 Variance Between 2018 / 2017 Three Months Ended
June 30,
 Variance Between 2019 / 2018 Six Months Ended
June 30,
 Variance Between 2019 / 2018
Income Tax Expense (Benefit) (in thousands)
 2018 2017 2018 2017 
Current tax expense (benefit) $1,100
 $
 $1,100
 $383
 $(6) $389
Income Tax Expense (in thousands)
 2019 2018 Variance Between 2019 / 2018 2019 2018 Variance Between 2019 / 2018
Current tax (benefit) $
 $(717) $
 $(717) 
Deferred tax expense 43,083
 51,239
 (8,156) 142,815
 188,168
 (45,353) 34,046
 42,783
 (8,737) 42,119
 99,732
 (57,613)
 $44,183
 $51,239
 $(7,056) $143,198
 $188,162
 $(44,964) $34,046
 $42,066
 $(8,020) $42,119
 $99,015
 $(56,896)
            
Combined federal and state effective income tax rate 22.9% 35.9%   23.1% 37.1%   23.7% 23.0%   23.7% 23.2%  

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.


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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, including our Ward County asset sale that closed in August 2018, 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 $80 million to $90be approximately $70 million for the year.2019. See Capital Expenditures below for information regarding our E&D activities for the three and ninesix months ended SeptemberJune 30, 20182019 and 2017.2018.



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We periodically use derivative instruments to mitigate volatility in commodity prices. At SeptemberJune 30, 2018,2019, we had derivative contracts covering a portion of our 20182019 - 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 SeptemberJune 30, 20182019 were $863.9$19.4 million. At SeptemberJune 30, 2018,2019, 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 SeptemberJune 30, 2018,2019, 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.$1.248 billion. See Long-term Debt below for more information regarding our debt.

Our debt to total capitalization ratio at SeptemberJune 30, 20182019 was 33%35%, 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 debt and (ii) redeemable preferred stock by the sum of (i) the principal amount of long-term debt, (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.

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

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

Analysis of Cash Flow Changes

The following table presents the totals of the major cash flow classification categories from our Condensed Consolidated Statements of Cash Flows for the periods indicated.
 Nine Months Ended
September 30,
 Six Months Ended
June 30,
(in thousands) 2018 2017 2019 2018
Net cash provided by operating activities $1,157,813
 $755,805
 $664,083
 $704,339
Net cash used by investing activities $(652,164) $(924,635) $(1,022,672) $(671,552)
Net cash used by financing activities $(42,237) $(61,238) $(422,663) $(22,498)


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Net cash provided by operating activities for the ninesix months ended SeptemberJune 30, 20182019 was $1.16 billion, up $402.0$664.1 million, down $40.3 million, or 53%6%, from $755.8$704.3 million for the ninesix months ended SeptemberJune 30, 2017.2018. The $402.0$40.3 million increasedecrease resulted primarily from the increaseincreased operating expenses. Partially offsetting this decrease in production revenue, which increased due to increased production volumes and realized oil and NGL prices. Also contributing to the increaseoperating cash flows was a decreased investmentdecrease in working capital. These increases were partially offset by a net increase in operating costs and expenses and increased cash outflows for settlements of derivative instruments. Despite increased production volumes, revenue remained flat between the two periods due to decreased pricing and, therefore, did not offset the increased cash outflows for operating expenses. See RESULTS OF OPERATIONS above for more information regarding the changes in revenue and operating expenses.

Net cash used by investing activities for the ninesix months ended SeptemberJune 30, 2019 and 2018 was $1.02 billion and 2017 was $652.2 million and $924.6$671.6 million, respectively. The majority of our cash flows used by investing activities are for E&D expenditures, which totaled $1.15 billion$711.8 million and $901.9$650.8 million for the ninesix months ended SeptemberJune 30, 2019 and 2018, and 2017, respectively. Cash used by investing activities in the six months ended June 30, 2019 includes the $325.7 million in cash paid for the Resolute acquisition, net of the $41.2 million in cash acquired with Resolute. The remaining investing cash outflows are primarily for midstream asset expenditures. Included in net cash used by investing activities are the proceeds of miscellaneous asset sales. On August 31, 2018, we closed the previously disclosed sale ofsales, including non-core oil and gas properties principally located in Ward County, Texas for a sales priceproperties.



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Table of $544.5 million, as adjusted to reflect the resolution of all asserted defects. As of September 30, 2018, we have received $534.6 million in net cash proceeds as adjusted for customary closing adjustments to reflect an effective date of April 1, 2018 and transaction costs. Final settlement, which will reflect customary post-closing adjustments, will occur by the end of first quarter 2019. This sale is part of our continuous portfolio optimization and high-grading of our investment opportunities. Additional proceeds from the sales of non-core assets slightly offset capital expenditure cash outflows in both periods.Contents



Net cash used by financing activities forwas $422.7 million and $22.5 million during the ninesix months ended SeptemberJune 30, 20182019 and 2017 was $42.2 million and $61.2 million,2018, respectively. During the ninesix months ended SeptemberJune 30, 2017,2019, 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$4.6 million in underwriting financing,fees and otherfinancing costs. Additionally, netwe borrowed and repaid an aggregate of $1.21 billion on our credit facility during the six months ended June 30, 2019 to assist in funding the Resolute acquisition and thereafter to meet cash requirements as needed. In connection with the acquisition of Resolute, we assumed $870.0 million in principal amount of long-term debt that we immediately repaid, incurring a redemption fee of $4.3 million. During the six months ended June 30, 2019, we amended our credit facility, paying $3.0 million in financing costs. We had no long-term debt-related investing cash flows during the six months ended June 30, 2018. Net cash used by financing activities during both periods included: (i) the payment of dividends, (ii) the payment of income tax withholdings made on behalf of our employees upon the net settlement of employee stock awards, and (iii) the receipt of proceeds from exercises of stock options. During the ninesix months ended SeptemberJune 30, 2019, we paid one $0.18 per common share dividend, one $0.20 per common share dividend, and one $20.31 per preferred share dividend, totaling $38.6 million. During the six months ended June 30, 2018, we paid one $0.08 per common share dividend and twoone $0.16 per share dividends, totaling $38.0 million, and during the nine months ended September 30, 2017, we paid an $0.08 percommon share dividend, in each quarter, totaling $22.7$22.8 million. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Capital Expenditures

The following table presents capitalized expenditures for oil and gas acquisition, exploration, and development activities and property sales, net of credits for property sales.applicable purchase price adjustments.
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 Three Months Ended
June 30,
 Six Months Ended
June 30,
(in thousands) 2018 2017 2018 2017 2019 2018 2019 2018
Acquisitions:                
Proved $
 $
 $62
 $260
 $1,200
 $
 $693,800
 $62
Unproved 10,015
 438
 12,251
 4,263
 1,000
 77
 1,051,782
 2,236
 10,015
 438
 12,313
 4,523
 2,200
 77
 1,745,582
 2,298
Exploration and development:  
        
      
Land and seismic 55,603
 12,872
 76,027
 123,359
 14,552
 10,327
 24,079
 20,424
Exploration and development 445,429
 322,651
 1,113,898
 813,693
 310,428
 365,097
 668,919
 668,469
 501,032
 335,523
 1,189,925
 937,052
 324,980
 375,424
 692,998
 688,893
Property sales:                
Proved (527,650) 1,807
 (557,191) (85) (22,058) (4,577) (18,028) (29,541)
Unproved (12,022) (780) (17,323) (8,051) (6,253) (441) (9,754) (5,301)
 (539,672) 1,027
 (574,514) (8,136) (28,311) (5,018) (27,782) (34,842)
 $(28,625) $336,988
 $627,724
 $933,439
 $298,869
 $370,483
 $2,410,798
 $656,349

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 recorded in the preliminary purchase price allocation for 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.

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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.



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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.

The following table reflects wells completed by region during the periods indicated.
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 Three Months Ended
June 30,
 Six Months Ended
June 30,
 2018 2017 2018 2017 2019 2018 2019 2018
Gross wells                
Permian Basin 33
 29
 82
 65
 44
 32
 56
 49
Mid-Continent 82
 48
 176
 133
 66
 57
 92
 94
 115
 77
 258
 198
 110
 89
 148
 143
Net wells                
Permian Basin 24
 16
 46
 42
 32
 13
 37
 22
Mid-Continent 20
 14
 36
 32
 8
 10
 11
 16
 44
 30
 82
 74
 40
 23
 48
 38

As of SeptemberJune 30, 2018,2019, we had 2927 gross (10(13 net) wells in the process of being drilled: 1014 gross (8(12 net) in the Permian Basin and 1913 gross (2(1 net) in the Mid-Continent region. As of SeptemberJune 30, 2018,2019, there were 9899 gross (41(24 net) wells waiting on completion: 4544 gross (32(20 net) in the Permian Basin and 5355 gross (9(4 net) in the Mid-Continent region. As of SeptemberJune 30, 2018,2019, we had 147 operated rigs running: 11running, all in the Permian Basin and 3 in the Mid-Continent region.Basin.

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



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Long-term Debt

Long-term debt at SeptemberJune 30, 20182019 and December 31, 20172018 consisted of the following:
  September 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
 $(4,671) $745,329
 $750,000
 $(5,383) $744,617
3.90% Senior Notes 750,000
 (7,182) 742,818
 750,000
 (7,697) 742,303
Total long-term debt $1,500,000
 $(11,853) $1,488,147
 $1,500,000
 $(13,080) $1,486,920
  June 30, 2019 December 31, 2018
(in thousands) Principal 
Unamortized Debt
Issuance Costs
and Discounts (1)
 
Long-term
Debt, net
 Principal 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
4.375% Notes due 2024 $750,000
 $(3,982) $746,018
 $750,000
 $(4,439) $745,561
3.90% Notes
due 2027
 750,000
 (6,651) 743,349
 750,000
 (7,007) 742,993
4.375% Notes due 2029 500,000
 (5,137) 494,863
 
 
 
  $2,000,000
 $(15,770) $1,984,230
 $1,500,000
 $(11,446) $1,488,554

(1)At SeptemberJune 30, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.1 million and $1.5 million, respectively. At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% notesNotes due 2027 were $5.5$5.4 million and $1.7$1.6 million, respectively. At December 31, 2017,June 30, 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 SeptemberJune 30, 2018,2019, 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.$1.248 billion. During the three months ended June 30, 2019, we borrowed and repaid an aggregate of $528.0 million on the Credit Facility to meet cash requirements as needed.

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

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of SeptemberJune 30, 2018,2019, we were in compliance with all of the financial and non-financial covenants.

At SeptemberJune 30, 20182019 and December 31, 2017,2018, we had $2.4$4.6 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.




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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 due 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 SeptemberJune 30, 2018.2019.

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 SeptemberJune 30, 2018,2019, we had a working capital deficit of $582.4$294.6 million, an increasea decrease of $326.3 million$1.01 billion or 127% compared to141% from a working capital surplus of $256.1$715.4 million at December 31, 2017.2018.

Our working capital increaseddecreased primarily due to the increasedecrease in Cash and cash equivalents of $463.4$781.3 million, which was a result of receiving $510.1 million atour acquisition of Resolute and subsequent repayment of Resolute’s long-term debt. See Note 13 to the August 31, 2018 closing of our Ward County asset sale. Partially offsetting thisCondensed Consolidated Financial Statements for more information regarding the acquisition. In addition to the decrease in cash, other significant changes to working capital increase were working capital decreases consistingconsisted primarily of the following:following decreases: 
Operations-related accounts payable and accrued liabilities increased by $70.2 million.
CurrentOur net current derivative instrument netposition decreased by $81.4 million from an asset at December 31, 2018 to a liability at June 30, 2019.
The adoption of Topic 842 increased our current liabilities by $39.4$68.7 million, representing estimated lease liabilities, primarily for office space, well-head compressors, pipeline compressors, and artificial lift mechanisms. See Note 10 to the Condensed Consolidated Financial Statements for more information regarding our lease liabilities and the adoption of Topic 842.
Accounts receivable decreased by $66.8 million.
Accrued liabilities related to our E&D expenditures increased by $39.0 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.

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Dividends

A quarterly cash dividend has been paid to stockholderson our common stock every quarter since the first quarter of 2006. In August 2018, an $0.18May 2019, our Board of Directors declared a cash dividend of $0.20 per common share, dividend was declared,totaling $20.3 million, which is payable on or before NovemberAugust 30, 20182019 to stockholders of record on NovemberAugust 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 May 2019, our Board of Directors declared a cash dividend



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of $20.31 per preferred share, totaling $1.3 million. The dividend was paid in July to preferred stockholders of record on July 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 SeptemberJune 30, 2018,2019, 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.
Contractual Obligations and Material Commitments

At SeptemberJune 30, 2018,2019, we had the following contractual obligations and material commitments:
 Payments Due by Period  Payments Due by Period 
Contractual obligations (in thousands)
 Total 10/1/18 - 9/30/19 10/1/19 - 9/30/21 10/1/21 - 9/30/23 10/1/23 and Thereafter  Total 7/1/19 - 6/30/20 7/1/20 - 6/30/22 7/1/22 - 6/30/24 7/1/24 and Thereafter 
Long-term debt—principal (1) $1,500,000
 $
 $
 $
 $1,500,000
  $2,000,000
 $
 $
 $750,000
 $1,250,000
 
Long-term debt—interest (1) 460,044
 60,844
 124,125
 124,125
 150,950
  617,313
 82,307
 167,875
 167,875
 199,256
 
Operating leases (2) 103,891
 19,954
 37,279
 22,632
 24,026
  101,885
 24,961
 38,238
 23,551
 15,135
 
Unconditional purchase obligations (3) 80,032
 34,293
 32,480
 6,926
 6,333
  99,006
 24,556
 27,235
 19,153
 28,062
 
Derivative liabilities 111,556
 97,480
 14,076
 
 
  50,896
 50,056
 840
 
 
 
Asset retirement obligation (4) 163,452
 11,584
 
(4)
(4)
(4) 173,873
 16,492
 
(4)
(4)
(4)
Other long-term liabilities (5) 40,861
 2,521
 3,252
 5,237
 29,851
  43,066
 2,670
 3,401
 5,217
 31,778
 
 $2,459,836
 $226,676
 $211,212
 $158,920
 $1,711,160
  $3,086,039
 $201,042
 $237,589
 $965,796
 $1,524,231
 

(1)The interest payments presented above include the accrued interest payable on our long-term debt as of SeptemberJune 30, 20182019 as well as future payments calculated using the long-term debt’s fixed rates, stated maturity dates, and principal amounts outstanding as of SeptemberJune 30, 2018.2019. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.
(2)Operating leases include variousthe estimated remaining contractual payments under lease commitmentsagreements as of June 30, 2019. These lease agreements are primarily comprised of leases for commercial real estate, which consists primarily of office space, and compressor equipment.
(3)Of the total Unconditionalunconditional purchase obligations, $40.0$28.2 million represents obligations for the purchase of sand for well completions and $30.0$70.5 million represents obligations for firm transportation agreements for gas and oil pipeline capacity.
(4)We have excluded the presentation of the timing of the cash flows associated with our long-term asset retirement obligations because we cannot make a reasonably reliable estimate of the future period of cash settlement. The long-term asset retirement obligation is included in the total asset retirement obligation presented.
(5)Other long-term liabilities include contractual obligations associated with our employee supplemental savings plan, gas balancing liabilities, and other miscellaneous liabilities. All of these liabilities are accrued on our Condensed Consolidated Balance Sheet. The current portion associated with these long-term liabilities is also presented in the table above.




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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.above, unless otherwise noted.

At SeptemberJune 30, 2018,2019, we had estimated commitments of approximately: (i) $263.3$304.6 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $13.1$19.2 million to finish gathering system construction in progress.

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At SeptemberJune 30, 2018,2019, we had firm sales contracts to deliver approximately 339.0290.7 Bcf of gas over the next 6.35.6 years. If we do not deliver this gas, our estimated financial commitment, calculated using the October 2018July 2019 index price, would be approximately $598.3$303.3 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 9.39.5 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 SeptemberJune 30, 2018,2019, would be approximately $345.2$655.2 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 SeptemberJune 30, 2018,2019, would be approximately $12.3$153.3 million. Of this total, we have accrued a liability of $2.5$4.6 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points. This accrual is reflected in the table above in Other long-term liabilities.

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

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We consider accounting policies and estimates related to oil and gas reserves, full cost accounting, and income taxes to be critical accounting policies and estimates. These are summarized in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 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 SeptemberJune 30, 2018,2019, our total production revenue was comprised of 59%approximately 76% oil sales, 16%6% gas sales, and 25%18% NGL sales. For the ninesix months ended SeptemberJune 30, 2018,2019, our total production revenue was comprised of 62%approximately 69% oil sales, 17%13% gas sales, and 21%18% 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.



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    Impact on Revenue
 Change in Realized Price Three Months Ended
September
June
30, 20182019
 NineSix Months Ended
September
June
30, 20182019
    (in thousands)
Oil± $1.00per barrel ± $5,880$7,592 ± $17,359$14,739
Gas± $0.10per Mcf ± $5,141$6,059 ± $14,863$11,811
NGL± $1.00per barrel ± $5,663$7,313 ± $15,765$13,879
    ± $16,684$20,964 ± $47,987$40,429

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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 SeptemberJune 30, 2018,2019, we had oil and gas derivatives covering a portion of our 2018 -2019 and 2020 production, which were recorded as current and non-current assets and liabilities. At SeptemberJune 30, 2018,2019, our oil and gas derivatives had a gross asset fair value of $31.3$43.6 million and a gross liability fair value of $111.6$50.9 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 SeptemberJune 30, 2018.2019.
 Impact on Fair Value Impact on Fair Value
Change in Forward Price September 30, 2018Change in Forward Price June 30, 2019
 (in thousands) (in thousands)
Oil-$1.00 $9,948
-$1.00 $5,969
Oil+$1.00 $(10,222)+$1.00 $(6,035)
Gas-$0.10 $5,708
-$0.10 $7,056
Gas+$0.10 $(5,684)+$0.10 $(6,963)

Interest Rate Risk

At SeptemberJune 30, 2018,2019, 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 SeptemberJune 30, 2018.2019.  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 SeptemberJune 30, 20182019 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. 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. Material changes from the risk factors previously disclosed in our Form 10-K for the year ended December 31, 2018 are set forth below.

Oil, gas, and NGL prices fluctuate due to a number of factors beyond our control, creating a component of uncertainty in our development plans and overall operations. Declines in prices adversely affect our financial results and rate of growth in proved reserves and production.
Oil and gas markets are volatile. We cannot predict future prices. The prices we receive for our production heavily influence our revenue, profitability, access to capital, and future rate of growth. The prices we receive depend on numerous factors beyond our control. These factors include, but are not limited to, changes in domestic and global supply and demand for oil and gas, the level of domestic and global oil and gas exploration and production activity, pipeline capacity constraints limiting takeaway and increasing basis differentials, geopolitical instability, the actions of the Organization of Petroleum Exporting Countries, weather conditions, technological advances affecting energy consumption, governmental regulations and taxes, and the price and technological advancement of alternative fuels.
Our proved oil and gas reserves and production volumes will decrease unless those reserves are replaced with new discoveries or acquisitions. Accordingly, for the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations, our revolving credit facility, and proceeds from the sale of senior notes or equity. Low prices reduce our cash flow and the amount of oil and gas that we can economically produce and may cause us to curtail, delay, or defer certain exploration and development projects. Moreover, low prices may impact our abilities to borrow under our revolving credit facility and to raise additional debt or equity capital to fund acquisitions.

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

Under the full cost method of accounting, we are required to perform quarterly ceiling test calculations to test our oil and gas properties for possible impairment. At June 30, 2019, a decline of approximately 4% or more in the value of our ceiling limitation would have resulted in an impairment. If commodity pricing conditions stay at current levels or decline further we will incur full cost ceiling impairments in future quarters. Because the ceiling calculation uses trailing twelve-month average commodity prices, the effect of declining prices is a lower ceiling value each quarter. This will result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.




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ITEM 6. EXHIBITS

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

101.INSXBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCHInline XBRL Taxonomy Extension Schema Document
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document
101.LABInline XBRL Taxonomy Extension Label Linkbase Document
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document
101.DEFInline XBRL 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.
November 6, 2018August 5, 2019 
  
  
 CIMAREX ENERGY CO.
  
  
 /s/ G. Mark Burford
 G. Mark Burford
 Senior Vice President and Chief Financial Officer
 (Principal Financial Officer)
  
  
 /s/ Timothy A. Ficker
 Timothy A. Ficker
 Vice President, Controller, and Chief Accounting Officer
 (Principal Accounting Officer)




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