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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
FORM 10-Q
 
(Mark One)
ý   
Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period ended June 30, 2018
or
o
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _______________ to _______________
 
Commission File No. 001-31446
CIMAREX ENERGY CO.
(Exact name of registrant as specified in its charter)
Delaware
 
45-0466694
(State of other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
1700 Lincoln Street, Suite 3700, Denver, Colorado
 
80203
(Address of principal executive offices)
 
(Zip Code)
 
(303) 295-3995
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ý  No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 
Yes ý  No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ý
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
 
 
(Do not check if a smaller
reporting company)
Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 
Yes o  No ý
The number of shares of Cimarex Energy Co. common stock outstanding as of July 31, 2018 was 95,356,074.


Table of Contents

CIMAREX ENERGY CO.
Table of Contents
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



Table of Contents

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 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, 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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Table of Contents

PART I
ITEM 1. - Financial Statements
CIMAREX ENERGY CO.
Condensed Consolidated Balance Sheets
(in thousands, except share and per share information)
(Unaudited)
 
 
June 30,
 
December 31,
 
 
2018
 
2017
Assets
 
 

 
 

Current assets:
 
 

 
 

Cash and cash equivalents
 
$
410,823

 
$
400,534

Accounts receivable, net of allowance:
 
 

 
 

Trade
 
128,984

 
100,356

Oil and gas sales
 
304,255

 
344,552

Gas gathering, processing, and marketing
 
11,416

 
15,266

Oil and gas well equipment and supplies
 
53,375

 
49,722

Derivative instruments
 
72,943

 
15,151

Prepaid expenses
 
7,419

 
8,518

Other current assets
 
927

 
1,536

Total current assets
 
990,142

 
935,635

Oil and gas properties at cost, using the full cost method of accounting:
 
 

 
 

Proved properties
 
18,112,548

 
17,513,460

Unproved properties and properties under development, not being amortized
 
532,715

 
476,903

 
 
18,645,263

 
17,990,363

Less—accumulated depreciation, depletion, amortization, and impairment
 
(15,000,443
)
 
(14,748,833
)
Net oil and gas properties
 
3,644,820

 
3,241,530

Fixed assets, net of accumulated depreciation of $312,927 and $290,114, respectively
 
238,964

 
210,922

Goodwill
 
620,232

 
620,232

Derivative instruments
 
2,330

 
2,086

Other assets
 
34,905

 
32,234

 
 
$
5,531,393

 
$
5,042,639

Liabilities and Stockholders’ Equity
 
 

 
 

Current liabilities:
 
 

 
 

Accounts payable:
 
 
 
 

Trade
 
$
74,596

 
$
68,883

Gas gathering, processing, and marketing
 
20,643

 
29,503

Accrued liabilities:
 
 

 
 

Exploration and development
 
146,886

 
115,762

Taxes other than income
 
24,392

 
23,687

Other
 
199,093

 
212,400

Derivative instruments
 
90,480

 
42,066

Revenue payable
 
180,869

 
187,273

Total current liabilities
 
736,959

 
679,574

Long-term debt:
 
 

 
 

Principal
 
1,500,000

 
1,500,000

Less—unamortized debt issuance costs and discount
 
(12,261
)
 
(13,080
)
Long-term debt, net
 
1,487,739

 
1,486,920

Deferred income taxes
 
201,350

 
101,618

Asset retirement obligation
 
159,568

 
158,421

Derivative instruments
 
11,511

 
4,268

Other liabilities
 
47,768

 
43,560

Total liabilities
 
2,644,895

 
2,474,361

Commitments and contingencies (Note 10)
 


 


Stockholders’ equity:
 
 

 
 

Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued
 

 

Common stock, $0.01 par value, 200,000,000 shares authorized, 95,392,547 and 95,437,434 shares issued, respectively
 
954

 
954

Additional paid-in capital
 
2,770,532

 
2,764,384

Retained earnings (accumulated deficit)
 
112,811

 
(199,259
)
Accumulated other comprehensive income
 
2,201

 
2,199

Total stockholders’ equity
 
2,886,498

 
2,568,278

 
 
$
5,531,393

 
$
5,042,639


See accompanying Notes to Condensed Consolidated Financial Statements.
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CIMAREX ENERGY CO.
Condensed Consolidated Statements of Operations and Comprehensive Income
(in thousands, except per share information)
(Unaudited)
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 

 
 

 
 

 
 

Oil sales
 
$
342,184

 
$
232,453

 
$
693,907

 
$
456,519

Gas and NGL sales
 
202,202

 
213,360

 
405,920

 
425,731

Gas gathering and other
 
11,810

 
10,735

 
23,262

 
21,360

Gas marketing
 
78

 
(96
)
 
319

 
18

 
 
556,274

 
456,452

 
1,123,408

 
903,628

Costs and expenses:
 
 

 
 

 
 

 
 

Depreciation, depletion, and amortization
 
143,388

 
107,884

 
276,247

 
203,700

Asset retirement obligation
 
2,053

 
960

 
3,113

 
2,580

Production
 
79,215

 
62,578

 
150,486

 
124,999

Transportation, processing, and other operating
 
51,933

 
58,624

 
97,098

 
113,647

Gas gathering and other
 
9,467

 
8,647

 
19,290

 
17,074

Taxes other than income
 
27,930

 
17,477

 
58,118

 
38,790

General and administrative
 
19,739

 
19,762

 
43,060

 
37,796

Stock compensation
 
3,095

 
6,293

 
9,825

 
12,581

Loss (gain) on derivative instruments, net
 
21,699

 
(22,509
)
 
17,540

 
(66,370
)
Other operating expense, net
 
5,252

 
266

 
5,455

 
882

 
 
363,771

 
259,982

 
680,232

 
485,679

Operating income
 
192,503

 
196,470

 
443,176

 
417,949

Other (income) and expense:
 
 

 
 

 
 

 
 

Interest expense
 
16,895

 
20,095

 
33,678

 
41,147

Capitalized interest
 
(4,850
)
 
(5,442
)
 
(9,660
)
 
(12,083
)
Loss on early extinguishment of debt
 

 
28,169

 

 
28,169

Other, net
 
(2,605
)
 
(2,231
)
 
(7,172
)
 
(4,441
)
Income before income tax
 
183,063

 
155,879

 
426,330

 
365,157

Income tax expense
 
42,066

 
58,617

 
99,015

 
136,923

Net income
 
$
140,997

 
$
97,262

 
$
327,315

 
$
228,234

 
 
 
 
 
 
 
 
 
Earnings per share to common stockholders:
 
 

 
 

 
 

 
 

Basic
 
$
1.48

 
$
1.02

 
$
3.44

 
$
2.40

Diluted
 
$
1.48

 
$
1.02

 
$
3.44

 
$
2.40

 
 
 
 
 
 
 
 
 
Dividends declared per share
 
$
0.16

 
$
0.08

 
$
0.32

 
$
0.16

 
 
 
 
 
 
 
 
 
Comprehensive income:
 
 

 
 

 
 

 
 

Net income
 
$
140,997

 
$
97,262

 
$
327,315

 
$
228,234

Other comprehensive income:
 
 

 
 

 
 

 
 

Change in fair value of investments, net of tax of $57, $128, $1, and $359, respectively
 
192

 
224

 
2

 
626

Total comprehensive income
 
$
141,189

 
$
97,486

 
$
327,317

 
$
228,860

 


See accompanying Notes to Condensed Consolidated Financial Statements.
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CIMAREX ENERGY CO.
Condensed Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
 
 
Six Months Ended
June 30,
 
 
2018
 
2017
Cash flows from operating activities:
 
 

 
 

Net income
 
$
327,315

 
$
228,234

Adjustments to reconcile net income to net cash provided by operating activities:
 
 

 
 

Depreciation, depletion, and amortization
 
276,247

 
203,700

Asset retirement obligation
 
3,113

 
2,580

Deferred income taxes
 
99,732

 
136,929

Stock compensation
 
9,825

 
12,581

Loss (gain) on derivative instruments, net
 
17,540

 
(66,370
)
Settlements on derivative instruments
 
(19,919
)
 
(5,717
)
Loss on early extinguishment of debt
 

 
28,169

Changes in non-current assets and liabilities
 
713

 
1,076

Other, net
 
2,179

 
3,445

Changes in operating assets and liabilities:
 
 

 
 

Accounts receivable
 
15,012

 
(61,145
)
Other current assets
 
1,886

 
(11,104
)
Accounts payable and other current liabilities
 
(29,304
)
 
32,422

Net cash provided by operating activities
 
704,339

 
504,800

Cash flows from investing activities:
 
 

 
 

Oil and gas capital expenditures
 
(650,807
)
 
(582,172
)
Other capital expenditures
 
(56,112
)
 
(18,209
)
Sales of oil and gas assets
 
34,842

 
9,163

Sales of other assets
 
525

 
394

Net cash used by investing activities
 
(671,552
)
 
(590,824
)
Cash flows from financing activities:
 
 

 
 

Borrowings of long-term debt
 

 
748,110

Repayments of long-term debt
 

 
(750,000
)
Call premium, financing, and underwriting fees
 

 
(29,035
)
Dividends paid
 
(22,801
)
 
(15,153
)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards
 
(946
)
 
(1,215
)
Proceeds from exercise of stock options
 
1,249

 
36

Net cash used by financing activities
 
(22,498
)
 
(47,257
)
Net change in cash and cash equivalents
 
10,289

 
(133,281
)
Cash and cash equivalents at beginning of period
 
400,534

 
652,876

Cash and cash equivalents at end of period
 
$
410,823

 
$
519,595

  


See accompanying Notes to Condensed Consolidated Financial Statements.
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CIMAREX ENERGY CO.
Condensed Consolidated Statement 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
 

 

 
29

 
17

 

 
46

Dividends
 

 

 

 
(15,262
)
 

 
(15,262
)
Dividends in excess of retained earnings
 

 

 
(15,250
)
 

 

 
(15,250
)
Net income
 

 

 

 
327,315

 

 
327,315

Unrealized change in fair value of investments, net of tax
 

 

 

 

 
2

 
2

Issuance of restricted stock awards
 
29

 

 

 

 

 

Common stock reacquired and retired
 
(8
)
 

 
(946
)
 

 

 
(946
)
Restricted stock forfeited and retired
 
(82
)
 

 

 

 

 

Exercise of stock options
 
17

 

 
1,249

 

 

 
1,249

Stock-based compensation
 

 

 
21,066

 

 

 
21,066

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



1.
BASIS OF PRESENTATION
The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex,” “we,” or “us”) 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.
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. Certain amounts in the prior year financial statements have been reclassified to conform to the 2018 financial statement presentation.
Use of Estimates
Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, and contingencies.
Oil and Gas Well Equipment and Supplies
Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of disposal and transportation. Declines in the price of oil and gas well equipment and supplies in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.
Oil and Gas Properties
We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Under the full cost method of accounting, we are required to perform a quarterly ceiling test calculation to test our oil and gas properties for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures. The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results.
We did not recognize a ceiling test impairment during the six months ended June 30, 2018 and 2017 because the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation. If pricing conditions deteriorate, including the further widening of local market basis differentials, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date.

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Table of Contents
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 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 expenses in the statement of operations under prior accounting standards are now reflected as deductions from revenue under ASC 606. The following tables present the impact on our Oil sales, Gas sales, and NGL sales and on our Transportation, processing, and other operating costs from the application of ASC 606 in the current reporting period:
 
 
Three Months Ended
June 30,
 
 
2018
 
2017
(in thousands)
 
Pre-
ASC 606 Adoption
 
Impact of
ASC 606
 
Post-
ASC 606 Adoption
 
As Reported
Oil sales
 
$
342,184

 
$

 
$
342,184

 
$
232,453

Gas sales
 
84,727

 
(3,940
)
 
80,787

 
132,474

NGL sales
 
125,126

 
(3,711
)
 
121,415

 
80,886

Total oil, gas, and NGL sales
 
$
552,037

 
$
(7,651
)
 
$
544,386

 
$
445,813

 
 
 
 
 
 
 
 
 
Transportation, processing, and other operating costs
 
$
59,584

 
$
(7,651
)
 
$
51,933

 
$
58,624

 
 
Six Months Ended
June 30,
 
 
2018
 
2017
(in thousands)
 
Pre-
ASC 606 Adoption
 
Impact of
ASC 606
 
Post-
ASC 606 Adoption
 
As Reported
Oil sales
 
$
693,907

 
$

 
$
693,907

 
$
456,519

Gas sales
 
197,404

 
(6,896
)
 
190,508

 
264,419

NGL sales
 
230,739

 
(15,327
)
 
215,412

 
161,312

Total oil, gas, and NGL sales
 
$
1,122,050

 
$
(22,223
)
 
$
1,099,827

 
$
882,250

 
 
 
 
 
 
 
 
 
Transportation, processing, and other operating costs
 
$
119,321

 
$
(22,223
)
 
$
97,098

 
$
113,647

Revenue is recognized from the sales of oil, gas, and NGLs when the customer obtains control of the product, when we have no further obligations to perform related to the sale, and when collectability is probable. All of our sales of oil, gas, and NGLs are made under contracts with customers, which typically include variable consideration based on monthly pricing tied to local indices and monthly volumes delivered. The nature of our contracts with customers does not require us to constrain that variable consideration or to estimate the amount of transaction price attributable to future performance obligations for accounting purposes. As of June 30, 2018, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas, and/or NGLs. Our contracts with customers typically require payment within one month of delivery.
Our gas and NGLs are sold under a limited number of contract structure types common in our industry. Under these contracts the gas and its components, including NGLs, may be sold to a single purchaser or the residue gas and NGLs may be sold

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


to separate purchasers. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product, and are disaggregated in the tables above on that basis. 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 Accounting Standards
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (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 permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than 12 months.  Under current generally accepted accounting principles, a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases.  Under this ASU, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease.  Leases convey the right to control the use of an identified asset in 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 assets and liabilities on the balance sheet.  This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are evaluating the potential impact of adopting this guidance, but believe the primary effect will be to record assets and liabilities for contracts currently accounted for as operating leases.  We do not intend to adopt the standard early.
In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842. This ASU provides an optional transition practical expedient to not evaluate under Topic 842 (discussed above) existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. Under the full cost method of accounting, we capitalize to oil and gas properties all property acquisition, exploration, and development costs, which include the costs of land easements. We plan to elect this practical expedient and continue to apply our current accounting policy to account for land easements that existed before our adoption of Topic 842 and will evaluate new or modified land easements under Topic 842 upon our adoption of Topic 842. We are evaluating the potential impact of adopting this guidance and do not intend to adopt the standard early.

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


2.
LONG-TERM DEBT
Long-term debt at June 30, 2018 and December 31, 2017 consisted of the following:
 
 
June 30, 2018
 
December 31, 2017
(in thousands)
 
Principal
 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
 
Principal
 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
4.375% Senior Notes
 
$
750,000

 
$
(4,906
)
 
$
745,094

 
$
750,000

 
$
(5,383
)
 
$
744,617

3.90% Senior Notes
 
750,000

 
(7,355
)
 
742,645

 
750,000

 
(7,697
)
 
742,303

Total long-term debt
 
$
1,500,000

 
$
(12,261
)
 
$
1,487,739

 
$
1,500,000

 
$
(13,080
)
 
$
1,486,920

________________________________________
(1)
At June 30, 2018, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.7 million and $1.7 million, respectively. At December 31, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.9 million and $1.8 million, respectively. The 4.375% notes were issued at par.
Bank Debt
We have a senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020. The Credit Facility has aggregate commitments of $1.0 billion, with an option for us to increase the aggregate commitments to $1.25 billion at any time. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. As of June 30, 2018, 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.
At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.1252.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.1251.0%, based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of 0.1250.35%, based on the credit rating for our senior unsecured long-term debt.
The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of June 30, 2018, we were in compliance with all of the financial covenants.
At June 30, 2018 and December 31, 2017, we had $2.7 million and $3.4 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.
Senior Notes
In April 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes at 99.748% of par to yield 3.93% per annum. These notes are due May 15, 2027 and interest is payable semiannually on May 15 and November 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.01%.
In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and interest is payable semiannually on June 1 and December 1. The effective interest rate on these notes, including the amortization of debt issuance costs, is 4.50%.
Our senior unsecured notes are governed by indentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of June 30, 2018.


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


3.
DERIVATIVE INSTRUMENTS
We periodically use derivative instruments to mitigate volatility in commodity prices.  While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future cash flow from favorable price changes.  Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. 
As of June 30, 2018, we have entered into oil and gas collars and oil basis swaps. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the ceiling price and the index price if the index price is above the ceiling price.  No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price minus a fixed differential 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. The following tables summarize our outstanding derivative contracts as of June 30, 2018 (subsequent to June 30, 2018 through August 6, 2018, we have not entered into any additional derivative contracts):
 Oil Collars
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth Quarter
 
Total
2018:
 
 
 
 
 
 
 
 
 
 

WTI (1)
 
 
 
 
 
 
 
 
 
 

Volume (Bbls)
 

 

 
3,220,000

 
2,668,000

 
5,888,000

Weighted Avg Price - Floor
 
$

 
$

 
$
49.80

 
$
51.03

 
$
50.36

Weighted Avg Price - Ceiling
 
$

 
$

 
$
60.49

 
$
61.74

 
$
61.06

2019:
 
 
 
 
 
 
 
 
 
 

WTI (1)
 
 
 
 
 
 
 
 
 
 

Volume (Bbls)
 
2,070,000

 
2,093,000

 
1,472,000

 
736,000

 
6,371,000

Weighted Avg Price - Floor
 
$
51.83

 
$
51.83

 
$
53.50

 
$
57.00

 
$
52.81

Weighted Avg Price - Ceiling
 
$
63.77

 
$
63.77

 
$
67.13

 
$
68.04

 
$
65.04

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

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


 Gas Collars
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth Quarter
 
Total
2018:
 
 
 
 
 
 
 
 
 
 
PEPL (1)
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu)
 

 

 
11,960,000

 
9,200,000

 
21,160,000

Weighted Avg Price - Floor
 
$

 
$

 
$
2.19

 
$
2.12

 
$
2.16

Weighted Avg Price - Ceiling
 
$

 
$

 
$
2.48

 
$
2.42

 
$
2.45

Perm EP (2)
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu)
 

 

 
9,200,000

 
7,360,000

 
16,560,000

Weighted Avg Price - Floor
 
$

 
$

 
$
1.92

 
$
1.81

 
$
1.87

Weighted Avg Price - Ceiling
 
$

 
$

 
$
2.14

 
$
2.03

 
$
2.09

Waha (3)
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu)
 

 

 
920,000

 
920,000

 
1,840,000

Weighted Avg Price - Floor
 
$

 
$

 
$
1.35

 
$
1.35

 
$
1.35

Weighted Avg Price - Ceiling
 
$

 
$

 
$
1.56

 
$
1.56

 
$
1.56

2019:
 
 
 
 
 
 
 
 
 
 
PEPL (1)
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu)
 
8,100,000

 
8,190,000

 
5,520,000

 
2,760,000

 
24,570,000

Weighted Avg Price - Floor
 
$
2.08

 
$
2.08

 
$
1.92

 
$
1.90

 
$
2.02

Weighted Avg Price - Ceiling
 
$
2.39

 
$
2.39

 
$
2.26

 
$
2.33

 
$
2.36

Perm EP (2)
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu)
 
6,300,000

 
6,370,000

 
4,600,000

 
1,840,000

 
19,110,000

Weighted Avg Price - Floor
 
$
1.73

 
$
1.73

 
$
1.50

 
$
1.35

 
$
1.64

Weighted Avg Price - Ceiling
 
$
1.95

 
$
1.95

 
$
1.74

 
$
1.55

 
$
1.86

Waha (3)
 
 
 
 
 
 
 
 
 
 
Volume (MMBtu)
 
900,000

 
910,000

 
920,000

 
920,000

 
3,650,000

Weighted Avg Price - Floor
 
$
1.35

 
$
1.35

 
$
1.35

 
$
1.35

 
$
1.35

Weighted Avg Price - Ceiling
 
$
1.56

 
$
1.56

 
$
1.56

 
$
1.56

 
$
1.56

________________________________________
(1)
The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.
(2)
The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.
(3)
The index price for these collars is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.

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


 Oil Basis Swaps
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth Quarter
 
Total
2018:
 
 
 
 
 
 
 
 
 
 

WTI Midland (1)
 
 
 
 
 
 
 
 
 
 

Volume (Bbls)
 

 

 
2,484,000

 
2,024,000

 
4,508,000

Weighted Avg Differential (2)
 
$

 
$

 
$
(3.89
)
 
$
(4.56
)
 
$
(4.19
)
2019:
 
 
 
 
 
 
 
 
 
 

WTI Midland (1)
 
 
 
 
 
 
 
 
 
 

Volume (Bbls)
 
1,710,000

 
1,729,000

 
1,288,000

 
552,000

 
5,279,000

Weighted Avg Differential (2)
 
$
(5.17
)
 
$
(5.17
)
 
$
(6.84
)
 
$
(10.73
)
 
$
(6.16
)
________________________________________
(1)
The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.
(2)
The index price we receive under these basis swaps is WTI as quoted on the NYMEX less the weighted average differential shown in the table.
Derivative Gains and Losses
Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the components of Loss (gain) on derivative instruments, net for the periods indicated.
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in thousands)
 
2018
 
2017
 
2018
 
2017
Change in fair value of derivative instruments, net:
 
 

 
 

 
 
 
 
Gas contracts
 
$
14,566

 
$
(5,748
)
 
$
2,777

 
$
(27,939
)
Oil contracts
 
(397
)
 
(16,418
)
 
(5,156
)
 
(44,148
)
 
 
14,169

 
(22,166
)
 
(2,379
)
 
(72,087
)
Cash (receipts) payments on derivative instruments, net:
 
 

 
 

 
 
 
 
Gas contracts
 
(9,918
)
 
(1,308
)
 
(15,037
)
 
1,136

Oil contracts
 
17,448

 
965

 
34,956

 
4,581

 
 
7,530

 
(343
)
 
19,919

 
5,717

Loss (gain) on derivative instruments, net
 
$
21,699

 
$
(22,509
)
 
$
17,540

 
$
(66,370
)
Derivative Fair Value
Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty. Our accounting policy is to not offset asset and liability positions in our balance sheets.

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


The following tables present the amounts and classifications of our derivative assets and liabilities as of June 30, 2018 and December 31, 2017, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.
 
 
 
 
June 30, 2018
(in thousands)
 
Balance Sheet Location
 
Asset
 
Liability
Oil contracts
 
Current assets — Derivative instruments
 
$
57,768

 
$

Gas contracts
 
Current assets — Derivative instruments
 
15,175

 

Oil contracts
 
Non-current assets — Derivative instruments
 
1,106

 

Gas contracts
 
Non-current assets — Derivative instruments
 
1,224

 

Oil contracts
 
Current liabilities — Derivative instruments
 

 
88,814

Gas contracts
 
Current liabilities — Derivative instruments
 

 
1,666

Oil contracts
 
Non-current liabilities — Derivative instruments
 

 
11,237

Gas contracts
 
Non-current liabilities — Derivative instruments
 

 
274

Total gross amounts presented in the balance sheet
 
75,273

 
101,991

Less: gross amounts not offset in the balance sheet
 
(68,377
)
 
(68,377
)
Net amount
 
$
6,896

 
$
33,614

 
 
 
 
 
 
 
 
 
 
 
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 have a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our derivative liability positions. Because some of the member banks have discontinued derivative activities, in the future we may enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.
4.
FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

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


The following table provides fair value measurement information for certain assets and liabilities as of June 30, 2018 and December 31, 2017:
 
 
June 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
)
 
$
(758,228
)
 
$
(750,000
)
 
$
(797,010
)
3.90% Notes due 2027
 
$
(750,000
)
 
$
(721,763
)
 
$
(750,000
)
 
$
(767,813
)
Derivative instruments — assets
 
$
75,273

 
$
75,273

 
$
17,237

 
$
17,237

Derivative instruments — liabilities
 
$
(101,991
)
 
$
(101,991
)
 
$
(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. The fair value of our derivative instruments (Level 2) was estimated using option pricing models. These models use certain variables including forward price and volatility curves and the strike prices for the instruments. The fair value estimates are adjusted relative to non-performance risk as appropriate. See Note 3 for further information on the fair value of our derivative instruments.
Other Financial Instruments
The carrying amounts of our cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Included in “Accrued liabilities — Other” at June 30, 2018 were accrued operating expenses of approximately $59.6 million. Included in “Accrued liabilities — Other” at December 31, 2017 were: (i) accrued operating expenses of approximately $61.3 million and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $54.6 million.
Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.
We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary.
We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At June 30, 2018 and December 31, 2017, the allowance for doubtful accounts was $2.7 million and $2.2 million, respectively.
5.
CAPITAL STOCK
Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At June 30, 2018, there were 95.4 million shares of common stock and no shares of preferred stock outstanding.
Dividends
In May 2018, our Board of Directors declared a cash dividend of $0.16 per share. The dividend is payable on or before August 31, 2018 to stockholders of record on August 15, 2018. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. The $15.3 million dividend declared during the first quarter 2018 was recorded as a reduction of additional paid-in capital, while the $15.3 million dividend declared during the second quarter 2018 was recorded as a reduction of retained earnings. Nonforfeitable dividends paid on stock awards that

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


subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to 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.
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)
 
2018
 
2017
 
2018
 
2017
Restricted stock awards:
 
 
 
 
 
 
 
 
Performance stock awards
 
$
3,809

 
$
6,438

 
$
10,538

 
$
12,840

Service-based stock awards
 
4,247

 
4,208

 
9,319

 
9,132

 
 
8,056

 
10,646

 
19,857

 
21,972

Stock option awards
 
637

 
579

 
1,254

 
1,245

Total stock compensation cost
 
8,693

 
11,225

 
21,111

 
23,217

Less amounts capitalized to oil and gas properties
 
(5,598
)
 
(4,932
)
 
(11,286
)
 
(10,636
)
Stock compensation expense
 
$
3,095

 
$
6,293

 
$
9,825

 
$
12,581

Periodic stock compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards. The decrease in total stock compensation cost in the 2018 periods as compared to the 2017 periods is primarily due to performance stock award forfeitures during the three months ended June 30, 2018. Our accounting policy is to account for forfeitures in compensation cost when they occur.

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


7.
ASSET RETIREMENT OBLIGATIONS
We recognize the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the plugging and abandonment of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is accreted each period. If there is a change in the estimated cost or timing of retirement, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are included as a component of the depreciation and depletion calculations.
The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2018:
(in thousands)
 
Six Months Ended
June 30, 2018
Asset retirement obligation at January 1, 2018
 
$
169,469

Liabilities incurred
 
3,921

Liability settlements and disposals
 
(10,103
)
Accretion expense
 
3,712

Revisions of estimated liabilities
 
999

Asset retirement obligation at June 30, 2018
 
167,998

Less current obligation
 
(8,430
)
Long-term asset retirement obligation
 
$
159,568



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


8.
EARNINGS PER SHARE
The calculations of basic and diluted net earnings per common share under the two-class method are presented below for the periods indicated:
 
 
Three Months Ended June 30,
 
 
2018
 
2017
(in thousands, except per share information)
 
Income (Numerator)
 
Shares (Denominator)
 
Per-Share Amount
 
Income (Numerator)
 
Shares (Denominator)
 
Per-Share Amount
Net income
 
$
140,997

 
 

 
 
 
$
97,262

 
 
 
 
Less: net income attributable to participating securities
 
(1,892
)
 
 
 
 
 
(1,643
)
 
 
 
 
Basic earnings per share
 
 
 
 
 
 
 
 
 
 
 
 
Income available to common stockholders
 
139,105

 
93,728

 
$
1.48

 
95,619

 
93,402

 
$
1.02

Effects of dilutive securities
 
 
 
 
 
 
 
 
 
 
 
 
Options (1)
 

 
31

 
 
 
1

 
33

 
 
Diluted earnings per share
 
 
 
 
 
 
 
 
 
 
 
 
Income available to common stockholders and assumed conversions
 
$
139,105

 
93,759

 
$
1.48

 
$
95,620

 
93,435

 
$
1.02


 
 
Six Months Ended June 30,
 
 
2018
 
2017
(in thousands, except per share information)
 
Income (Numerator)
 
Shares (Denominator)
 
Per-Share Amount
 
Income (Numerator)
 
Shares (Denominator)
 
Per-Share Amount
Net income
 
$
327,315

 
 

 
 
 
$
228,234

 
 
 
 
Less: net income attributable to participating securities
 
(4,546
)
 
 
 
 
 
(3,898
)
 
 
 
 
Basic earnings per share
 
 
 
 
 
 
 
 
 
 
 
 
Income available to common stockholders
 
322,769

 
93,713

 
$
3.44

 
224,336

 
93,396

 
$
2.40

Effects of dilutive securities
 
 
 
 
 
 
 
 
 
 
 
 
Options (1)
 
1

 
35

 
 
 
1

 
35

 
 
Diluted earnings per share
 
 
 
 
 
 
 
 
 
 
 
 
Income available to common stockholders and assumed conversions
 
$
322,770

 
93,748

 
$
3.44

 
$
224,337

 
93,431

 
$
2.40

________________________________________
(1)
Inclusion of certain shares would have an anti-dilutive effect; therefore, 292.1 thousand and 295.6 thousand shares were excluded from the calculations for the three and six months ended June 30, 2018 and 300.5 thousand and 255.0 thousand shares were excluded from the calculations for the three and six months ended June 30, 2017.


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


9.
INCOME TAXES
The components of our provision for income taxes are as follows:
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in thousands)
 
2018
 
2017
 
2018
 
2017
Current tax benefit
 
$
(717
)
 
$

 
$
(717
)
 
$
(6
)
Deferred tax expense
 
42,783

 
58,617

 
99,732

 
136,929

 
 
$
42,066

 
$
58,617

 
$
99,015

 
$
136,923

Combined federal and state effective income tax rate
 
23.0
%
 
37.6
%
 
23.2
%
 
37.5
%
At December 31, 2017, we had a U.S. net tax operating loss carryforward of approximately $1,377.7 million, which will expire in tax years 2031 through 2037. We believe that the carryforward will be utilized before it expires. We also had an alternative minimum tax credit carryforward of approximately $3.0 million and other credits of $0.9 million.
At June 30, 2018, 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 2014 through 2016 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 2013 through 2016.
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
Commitments
At June 30, 2018, we had estimated commitments of approximately: (i) $154.4 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $14.4 million to finish gathering system construction in progress.
At June 30, 2018, we had firm sales contracts to deliver approximately 330.7 Bcf of gas over the next 6.6 years. If we do not deliver this gas, our estimated financial commitment, calculated using the July 2018 index price, would be approximately $659.9 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 9.5 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 June 30, 2018, would be approximately $351.0 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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Table of Contents
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2018
(Unaudited)


We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2018, would be approximately $7.4 million. Of this total, we have accrued a liability of $2.5 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.
At June 30, 2018, we have various firm transportation agreements for gas pipeline capacity with end dates ranging from 2018 - 2025 under which we will have to pay an estimated $26.6 million over the remaining terms of the agreements. These agreements were entered into to support our residue gas marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation.
At June 30, 2018, we have various future commitments under operating lease arrangements for commercial real estate, consisting primarily of office space, and compressor equipment. The commitments under the commercial real estate operating leases, which have lease terms expiring within the next 8.2 years, total approximately $80.9 million. The commitments under the compressor equipment operating leases, which have lease terms expiring within the next 2 - 24 months, total approximately $9.3 million.
All of the noted commitments were routine and made in the ordinary course of our business.
Litigation
We have various litigation matters related to the ordinary course of our business. We assess the probability of estimable amounts related to these matters in accordance with guidance established by the FASB and adjust our 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)
 
2018
 
2017
 
2018
 
2017
Cash paid during the period for:
 
 

 
 

 
 

 
 

Interest expense (net of capitalized amounts of $9,233, $11,659, $9,389, and $11,962, respectively)
 
$
22,954

 
$
28,115

 
$
23,343

 
$
28,772

Income taxes
 
$

 
$
1

 
$

 
$
3

Cash received for income tax refunds
 
$
717

 
$

 
$
718

 
$
21



21

Table of Contents

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 grow 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 reinvesting that cash flow in exploration and development activities. We consider property acquisitions, dispositions, and occasional mergers to enhance our competitive position.
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-strategic assets, and occasional 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 first six months of 2018 as compared to the first six months of 2017, market prices for oil have improved, while market prices for gas have declined. For the first six months of 2018, average NYMEX oil and gas prices were $65.37 per barrel and $2.90 per Mcf, respectively, representing an increase of 30% and a decrease of 11%, respectively, from the average NYMEX oil and gas prices for the first six months of 2017. However, 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 in the Permian Basin and Mid-Continent region and oil production growth and pipeline constraints in the Permian Basin have resulted in higher basis differentials and, therefore, lower realized prices. The average realized price per barrel for our Permian oil production was less than the WTI Cushing index by $8.05, $3.12, and $4.14 in the three months ended June 30, 2018, March 31, 2018, and June 30, 2017, respectively. The average realized price per Mcf for our Permian gas production was less than the Henry Hub index by $1.31, $0.78, and $0.42 in the three months ended June 30, 2018, March 31, 2018, and June 30, 2017, respectively. The average realized price per Mcf for our Mid-Continent gas production was less than the Henry Hub index by $1.03, $0.70, and $0.34 in the three months ended June 30, 2018, March 31, 2018, and June 30, 2017, respectively. If pipeline constraints remain, higher differentials will persist or potentially worsen. Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and gas production. See RESULTS OF OPERATIONS Revenues below for further information regarding our realized commodity prices.
See “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2017, 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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Table of Contents

Summary of Operating and Financial Results for the Six Months Ended June 30, 2018 Compared to the Six Months Ended June 30, 2017:
Total production volumes increased 13% to 208.8 MBOE per day.
Oil volumes increased 15% to 63.4 MBbls per day.
Gas volumes increased 7% to 537.1 MMcf per day.
NGL volumes increased 21% to 55.8 MBbls per day.
Total production revenue increased 25% to $1.1 billion.
Cash flow provided by operating activities increased 40% to $704.3 million.
Exploration and development expenditures increased 15% to $688.9 million.
Net income was $327.3 million, or $3.44 per diluted share, for the first six months of 2018, as compared to net income of $228.2 million, or $2.40 per diluted share, for the first six months of 2017.
RESULTS OF OPERATIONS
Three and Six Months Ended June 30, 2018 vs. Three and Six Months Ended June 30, 2017
Effective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”), utilizing the modified retrospective approach, which we applied to contracts that were not completed as of that date. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of ASC 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating expenses in the statement of operations under prior accounting standards are now reflected as deductions from revenue under ASC 606. The following tables present the impact on our Oil sales, Gas sales, and NGL sales and on our Transportation, processing, and other operating costs from the application of ASC 606 in the current reporting period:
 
 
Three Months Ended
June 30,
 
 
2018
 
2017
(in thousands)
 
Pre-
ASC 606 Adoption
 
Impact of
ASC 606
 
Post-
ASC 606 Adoption
 
As Reported
Oil sales
 
$
342,184

 
$

 
$
342,184

 
$
232,453

Gas sales
 
84,727

 
(3,940
)
 
80,787

 
132,474

NGL sales
 
125,126

 
(3,711
)
 
121,415

 
80,886

Total oil, gas, and NGL sales
 
$
552,037

 
$
(7,651
)
 
$
544,386

 
$
445,813

 
 
 
 
 
 
 
 
 
Transportation, processing, and other operating costs
 
$
59,584

 
$
(7,651
)
 
$
51,933

 
$
58,624

 
 
Six Months Ended
June 30,
 
 
2018
 
2017
(in thousands)
 
Pre-
ASC 606 Adoption
 
Impact of
ASC 606
 
Post-
ASC 606 Adoption
 
As Reported
Oil sales
 
$
693,907

 
$

 
$
693,907

 
$
456,519

Gas sales
 
197,404

 
(6,896
)
 
190,508

 
264,419

NGL sales
 
230,739

 
(15,327
)
 
215,412

 
161,312

Total oil, gas, and NGL sales
 
$
1,122,050

 
$
(22,223
)
 
$
1,099,827

 
$
882,250

 
 
 
 
 
 
 
 
 
Transportation, processing, and other operating costs
 
$
119,321

 
$
(22,223
)
 
$
97,098

 
$
113,647


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Table of Contents

Revenues
Almost all of 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, seasonality, 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 six months ended June 30, 2018 as compared to the three and six months ended June 30, 2017. Realized oil and NGL prices also were higher, while realized gas prices were lower. Our revenue increased 22%, or $98.6 million, during the three months ended June 30, 2018 as compared to the three months ended June 30, 2017 and increased 25%, or $217.6 million, during the six months ended June 30, 2018 as compared to the six months ended June 30, 2017. The following tables show our production revenue for the periods indicated as well as the change in revenue due to changes in volumes and prices.
 
 
Three Months Ended
June 30,
 
Variance Between 2018 / 2017
 
Price/Volume Variance
Production Revenue (in thousands)
 
2018
 
2017
 
 
Price
 
Volume
 
Total
Oil sales
 
$
342,184

 
$
232,453

 
$
109,731

 
47%
 
$
94,533

 
$
15,198

 
$
109,731

Gas sales
 
80,787

 
132,474

 
(51,687
)
 
(39)%
 
(57,440
)
 
5,753

 
(51,687
)
NGL sales
 
121,415

 
80,886

 
40,529

 
50%
 
22,060

 
18,469

 
40,529

 
 
$
544,386

 
$
445,813

 
$
98,573

 
22%
 
$
59,153

 
$
39,420

 
$
98,573


 
 
Six Months Ended
June 30,
 
Variance Between 2018 / 2017
 
Price/Volume Variance
Production Revenue (in thousands)
 
2018
 
2017
 
 
Price
 
Volume
 
Total
Oil sales
 
$
693,907

 
$
456,519

 
$
237,388

 
52%
 
$
167,943

 
$
69,445

 
$
237,388

Gas sales
 
190,508

 
264,419

 
(73,911
)
 
(28)%
 
(92,358
)
 
18,447

 
(73,911
)
NGL sales
 
215,412

 
161,312

 
54,100

 
34%
 
20,809

 
33,291

 
54,100

 
 
$
1,099,827

 
$
882,250

 
$
217,577

 
25%
 
$
96,394

 
$
121,183

 
$
217,577


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Table of Contents

The table below presents our production volumes by region.
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Production Volumes
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
 
Oil (Bbls per day)
 
 
 
 
 
 
 
 
Permian Basin
 
48,797

 
45,828

 
49,318

 
43,446

Mid-Continent
 
12,473

 
11,893

 
13,841

 
11,475

Other
 
381

 
150

 
263

 
121

 
 
61,651

 
57,871

 
63,422

 
55,042

Gas (MMcf per day)
 
 
 
 
 
 
 
 
Permian Basin
 
240.5

 
219.8

 
239.2

 
210.4

Mid-Continent
 
297.0

 
295.4

 
296.2

 
290.2

Other
 
2.0

 
1.5

 
1.7

 
1.4

 
 
539.5

 
516.7

 
537.1

 
502.0

NGL (Bbls per day)
 
 
 
 
 
 
 
 
Permian Basin
 
32,865

 
24,996

 
28,817

 
23,319

Mid-Continent
 
26,894

 
23,693

 
26,927

 
22,926

Other
 
98

 
42

 
66

 
36

 
 
59,857

 
48,731

 
55,810

 
46,281

Total (BOE per day)
 
 
 
 
 
 
 
 
Permian Basin
 
121,744

 
107,456

 
118,002

 
101,829

Mid-Continent
 
88,864

 
84,827

 
90,142

 
82,774

Other
 
816

 
437

 
608

 
395

 
 
211,424

 
192,720

 
208,752

 
184,998

Our total production increased 10%, or 18,704 BOE per day, during the three months ended June 30, 2018, as compared to the three months ended June 30, 2017 and increased 13%, or 23,754 BOE per day, during the six months ended June 30, 2018, as compared to the six months ended June 30, 2017. This increase was the result of our ongoing drilling and completion activity throughout 2017 and into 2018. See LIQUIDITY AND CAPITAL RESOURCES Capital Expenditures for information on our capital expenditures.

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Table of Contents

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, approximately 79% of our oil production was in the Permian Basin. Our realized prices do not include settlements of commodity derivative contracts.
 
 
Three Months Ended
June 30,
 
Change Between 2018 / 2017
 
Six Months Ended
June 30,
 
Change Between 2018 / 2017
 
 
2018
 
2017
 
 
2018
 
2017
 
Oil
 
 
 
 
 
 
 
 
 
 
 
 
Total volume — MBbls
 
5,610

 
5,266

 
7%
 
11,479

 
9,963

 
15%
Total volume — MBbls per day
 
61.7

 
57.9

 
7%
 
63.4

 
55.0

 
15%
Percentage of total production
 
29
%
 
30
%
 
 
 
30
%
 
30
%
 
 
Average realized price — per barrel
 
$
60.99

 
$
44.14

 
38%
 
$
60.45

 
$
45.82

 
32%
Average WTI Midland price — per barrel
 
$
62.76

 
$
47.44

 
32%
 
$
63.01

 
$
50.00

 
26%
Average WTI Cushing price — per barrel
 
$
67.88

 
$
48.29

 
41%
 
$
65.37

 
$
50.10

 
30%
 
 
 
 
 
 
 
 
 
 
 
 
 
Gas
 
 

 
 

 
 
 
 

 
 

 
 
Total volume — MMcf
 
49,094

 
47,021

 
4%
 
97,219

 
90,871

 
7%
Total volume — MMcf per day
 
539.5

 
516.7

 
4%
 
537.1

 
502.0

 
7%
Percentage of total production
 
43
%
 
45
%
 
 
 
43
%
 
45
%
 
 
Average realized price — per Mcf
 
$
1.65

(1)
$
2.82

 
(41)%
 
$
1.96

(1)
$
2.91

 
(33)%
Average Henry Hub price — per Mcf
 
$
2.80

 
$
3.19

 
(12)%
 
$
2.90

 
$
3.25

 
(11)%
 
 
 
 
 
 
 
 
 
 
 
 
 
NGL
 
 

 
 

 
 
 
 

 
 

 
 
Total volume — MBbls
 
5,447

 
4,434

 
23%
 
10,102

 
8,377

 
21%
Total volume — MBbls per day
 
59.9

 
48.7

 
23%
 
55.8

 
46.3

 
21%
Percentage of total production
 
28
%
 
25
%
 
 
 
27
%
 
25
%
 
 
Average realized price — per barrel
 
$
22.29

(2)
$
18.24

 
22%
 
$
21.32

(2)
$
19.26

 
11%
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
 

 
 

 
 
 
 

 
 

 
 
Total production — MBOE
 
19,240

 
17,538

 
10%
 
37,784

 
33,485

 
13%
Total production — MBOE per day
 
211.4

 
192.7

 
10%
 
208.8

 
185.0

 
13%
Average realized price — per BOE
 
$
28.30

(3)
$
25.42

 
11%
 
$
29.11

(3)
$
26.35

 
10%
________________________________________
(1)
ASC 606 reduced the average realized gas price by $0.08 per Mcf and $0.07 per Mcf for the three and six months ended June 30, 2018, respectively.
(2)
ASC 606 reduced the average realized NGL price by $0.68 per barrel and $1.52 per barrel for the three and six months ended June 30, 2018, respectively.
(3)
ASC 606 reduced the average realized total price by $0.39 per BOE and $0.59 per BOE for the three and six months ended June 30, 2018, respectively.

26

Table of Contents

Other revenues
We transport, process, and market some third-party gas that is associated with our equity gas.  We market and sell gas for other working interest owners under short-term agreements and may earn a fee for such services.  The table below reflects income from third-party gas gathering and processing and our net marketing margin for marketing third-party gas. 
 
 
Three Months Ended
June 30,
 
Variance Between 2018 / 2017
 
Six Months Ended
June 30,
 
Variance Between 2018 / 2017
Gas Gathering and Marketing Revenues (in thousands)
 
2018
 
2017
 
 
2018
 
2017
 
Gas gathering and other
 
$
11,810

 
$
10,735

 
$
1,075

 
$
23,262

 
$
21,360

 
$
1,902

Gas marketing
 
$
78

 
$
(96
)
 
$
174

 
$
319

 
$
18

 
$
301

Fluctuations in revenues from gas gathering and gas marketing activities are a function of increases and decreases in volumes, commodity prices, and gathering rate charges.
Operating Costs and Expenses
Costs associated with producing oil and gas are substantial.  Among other factors, some of these costs vary with commodity prices, some trend with the volume of production, others are a function of the number of wells we own, and some depend on the prices charged by service companies. 
Total operating costs and expenses for the three months ended June 30, 2018 were higher by 40%, or $103.8 million, compared to the three months ended June 30, 2017.  The primary reasons for the increase are: (i) the $44.2 million decrease in net gains on derivative instruments to an overall net loss, (ii) the $35.5 million increase in depreciation, depletion, and amortization, (iii) the $16.6 million increase in production expense, and (iv) the $10.5 million increase in taxes other than income, partially offset by the $6.7 million decrease in transportation, processing, and other operating expense. 
 
 
Three Months Ended
June 30,
 
Variance Between
2018 / 2017
 
Per BOE
Operating Costs and Expenses
(in thousands, except per BOE)
 
2018
 
2017
 
 
2018
 
2017
Depreciation, depletion, and amortization
 
$
143,388

 
$
107,884

 
$
35,504

 
$
7.45

 
$
6.15

Asset retirement obligation
 
2,053

 
960

 
1,093

 
$
0.11

 
$
0.05

Production
 
79,215

 
62,578

 
16,637

 
$
4.12

 
$
3.57

Transportation, processing, and other operating
 
51,933

 
58,624

 
(6,691
)
 
$
2.70

 
$
3.34

Gas gathering and other
 
9,467

 
8,647

 
820

 
$
0.49

 
$
0.49

Taxes other than income
 
27,930

 
17,477

 
10,453

 
$
1.45

 
$
1.00

General and administrative
 
19,739

 
19,762

 
(23
)
 
$
1.03

 
$
1.13

Stock compensation
 
3,095

 
6,293

 
(3,198
)
 
$
0.16

 
$
0.36

Loss (gain) on derivative instruments, net
 
21,699

 
(22,509
)
 
44,208

 
N/A

 
N/A

Other operating expense, net
 
5,252

 
266

 
4,986

 
N/A

 
N/A

 
 
$
363,771

 
$
259,982

 
$
103,789

 
 

 
 


27

Table of Contents

Total operating costs and expenses for the six months ended June 30, 2018 were higher by 40%, or $194.6 million, compared to the six months ended June 30, 2017.  The primary reasons for the increase are: (i) the $83.9 million decrease in net gains on derivative instruments to an overall net loss, (ii) the $72.5 million increase in depreciation, depletion, and amortization, (iii) the $25.5 million increase in production expense, and (iv) the $19.3 million increase in taxes other than income, partially offset by the $16.5 million decrease in transportation, processing, and other operating expense. 
 
 
Six Months Ended
June 30,
 
Variance Between
2018 / 2017
 
Per BOE
Operating Costs and Expenses
(in thousands, except per BOE)
 
2018
 
2017
 
 
2018
 
2017
Depreciation, depletion, and amortization
 
$
276,247

 
$
203,700

 
$
72,547

 
$
7.31

 
$
6.08

Asset retirement obligation
 
3,113

 
2,580

 
533

 
$
0.08

 
$
0.08

Production
 
150,486

 
124,999

 
25,487

 
$
3.98

 
$
3.73

Transportation, processing, and other operating
 
97,098

 
113,647

 
(16,549
)
 
$
2.57

 
$
3.39

Gas gathering and other
 
19,290

 
17,074

 
2,216

 
$
0.51

 
$
0.51

Taxes other than income
 
58,118

 
38,790

 
19,328

 
$
1.54

 
$
1.16

General and administrative
 
43,060

 
37,796

 
5,264

 
$
1.14

 
$
1.13

Stock compensation
 
9,825

 
12,581

 
(2,756
)
 
$
0.26

 
$
0.38

Loss (gain) on derivative instruments, net
 
17,540

 
(66,370
)
 
83,910

 
N/A

 
N/A

Other operating expense, net
 
5,455

 
882

 
4,573

 
N/A

 
N/A

 
 
$
680,232

 
$
485,679

 
$
194,553

 
 

 
 

Depreciation, Depletion, and Amortization
Depletion of our producing properties is computed using the units-of-production method. The economic life of each producing well depends upon the estimated proved reserves for that well, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion 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 prices during 2018 as compared to 2017, thus increasing our reserves, the increase in production combined with our ongoing exploration and development capital expenditures throughout 2017 and into 2018, have resulted in an overall increase in depletion 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.  Depreciation, depletion, and amortization (“DD&A”) consisted of the following for the periods indicated:
 
 
Three Months Ended
June 30,
 
Variance Between
2018 / 2017
 
Per BOE
DD&A Expense (in thousands, except per BOE)
 
2018
 
2017
 
 
2018
 
2017
Depletion
 
$
131,220

 
$
95,735

 
$
35,485

 
$
6.82

 
$
5.46

Depreciation
 
12,168

 
12,149

 
19

 
0.63

 
0.69

 
 
$
143,388

 
$
107,884

 
$
35,504

 
$
7.45

 
$
6.15


 
 
Six Months Ended
June 30,
 
Variance Between
2018 / 2017
 
Per BOE
DD&A Expense (in thousands, except per BOE)
 
2018
 
2017
 
 
2018
 
2017
Depletion
 
$
251,610

 
$
180,746

 
$
70,864

 
$
6.66

 
$
5.40

Depreciation
 
24,637

 
22,954

 
1,683

 
0.65

 
0.68

 
 
$
276,247

 
$
203,700

 
$
72,547

 
$
7.31

 
$
6.08



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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
June 30,
 
Variance Between
2018 / 2017
 
Per BOE
Production Expense (in thousands, except per BOE)
 
2018
 
2017
 
 
2018
 
2017
Lease operating expense
 
$
62,355

 
$
55,812

 
$
6,543

 
$
3.24

 
$
3.18

Workover expense
 
16,860

 
6,766

 
10,094

 
0.88

 
0.39

 
 
$
79,215

 
$
62,578

 
$
16,637

 
$
4.12

 
$
3.57


 
 
Six Months Ended
June 30,
 
Variance Between
2018 / 2017
 
Per BOE
Production Expense (in thousands, except per BOE)
 
2018
 
2017
 
 
2018
 
2017
Lease operating expense
 
$
122,831

 
$
101,347

 
$
21,484

 
$
3.25

 
$
3.03

Workover expense
 
27,655

 
23,652

 
4,003

 
0.73

 
0.70

 
 
$
150,486

 
$
124,999

 
$
25,487

 
$
3.98

 
$
3.73

Lease operating expense in the second quarter 2018 increased 12%, or $6.5 million, compared to the second quarter of 2017. Lease operating expense for the six months ended June 30, 2018 increased 21%, or $21.5 million, compared to the six months ended June 30, 2017. The increases have primarily stemmed from the addition of new wells as a result of our ongoing exploration and development activities. Additional wells and increased production have increased the following costs between the two quarters: (i) equipment rental, primarily flowback equipment and compressors, (ii) saltwater disposal, due to increased water volumes, (iii) environmental compliance, primarily emissions-related, and (iv) labor. The preceding costs also increased between the two six-month periods, as did the following costs: (i) tank battery and processing equipment and maintenance, (ii) electricity, and (iii) chemicals and treating, due to increased water volumes and chemical treating.
Workover expense in the second quarter 2018 increased 149%, or $10.1 million, compared to the second quarter of 2017. Workover expense for the six months ended June 30, 2018 increased 17%, or $4.0 million, compared to the six months ended June 30, 2017. We had a larger quantity of workover projects during the six months ended June 30, 2018 as compared to the six months ended June 30, 2017. Additionally, during the second quarter 2018, we had several artificial lift conversions underway, which increased workover expense. We received insurance proceeds of $4.0 million in the first quarter 2018 and $4.9 million in the second quarter 2017 related to remediation and repairs incurred as a result of a 2015 flooding event. These insurance proceeds decreased workover expense in the periods received, thus resulting in the following increases in workover expense when comparing periods: (i) a $4.9 million increase in the second quarter 2018 as compared to the second quarter 2017 and (ii) a $0.9 million increase during the six months ended June 30, 2018 as compared to the six months ended June 30, 2017. Generally, workover costs will fluctuate based on the amount of maintenance and remedial activity required during the period.
Transportation, Processing, and Other Operating
Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, including gathering, fuel, compression, and processing costs. Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.
Transportation, processing, and other operating costs in the second quarter 2018 were 11%, or $6.7 million, lower than the costs in the second quarter 2017. Transportation, processing, and other operating costs in the six months ended June 30, 2018 were 15%, or $16.5 million, lower than the costs in the six months ended June 30, 2017. These decreases were primarily due to our adoption of ASC 606 effective January 1, 2018, whereby certain transportation and processing costs are now reclassified out of transportation, processing, and other operating costs and are treated as a deduction from revenue. The adoption of ASC 606 reduced Transportation, processing, and other operating costs by $7.7 million in the second quarter 2018 and by $22.2 million in the six months ended June 30, 2018. These reductions were partially offset by increased costs due to increased production volumes. See Note 1 to the Condensed Consolidated Financial Statements for additional information regarding the adoption of ASC 606.

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Table of Contents

Gas Gathering and Other
Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs and operating and maintenance expenses. Gas gathering and other in the three months ended June 30, 2018 was 9%, or $0.8 million, higher than gas gathering and other in the three months ended June 30, 2017. Gas gathering and other in the six months ended June 30, 2018 was 13%, or $2.2 million, higher than gas gathering and other in the six months ended June 30, 2017. The increases were primarily due to overall increases in operating costs partially offset by lower product costs associated with processing third-party production due to lower commodity prices and volumes.
Taxes Other than Income
Taxes other than income consist of production (or severance) taxes, ad valorem taxes, and other taxes.  State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production and ad valorem taxes being based on the value of properties.  Production taxes make up the majority of this expense for us, with revenue-based production taxes being the largest component of these taxes.  Taxes other than income increased $10.5 million, or 60%, in the second quarter of 2018 as compared to the second quarter of 2017. Taxes other than income increased $19.3 million, or 50%, in the six months ended June 30, 2018 as compared to the six months ended June 30, 2017. The increases are due to the increases in revenue seen between the comparable periods. All periods included credits for tax refunds related to high-cost gas wells in the State of Texas, however, the refunds in the three and six months ended June 30, 2018 were $3.6 million and $4.6 million, respectively, lower than the refunds in the three and six months ended June 30, 2017. Taxes other than income was 5.1% and 3.9% of production revenues for the three months ended June 30, 2018 and 2017, respectively, and was 5.3% and 4.4% of production revenues for the six months ended June 30, 2018 and 2017, respectively.
General and Administrative
General and administrative (“G&A”) expense consists primarily of salaries and related benefits, office rent, legal and consulting fees, systems costs, and other administrative costs incurred that are not directly associated with exploration, development, or production activities. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting. The amount of expense capitalized varies and depends on whether the cost incurred can be directly identified with acquisition, exploration, and development activities. The percentage of gross G&A capitalized ranged from 46% to 50% during the periods presented in the table below, which shows our G&A costs.
 
 
Three Months Ended
June 30,
 
Variance Between 2018 / 2017
 
Six Months Ended
June 30,
 
Variance Between 2018 / 2017
General and Administrative Expense 
(in thousands)
 
2018
 
2017
 
 
2018
 
2017
 
Gross G&A
 
$
39,276

 
$
38,541

 
$
735

 
$
80,124

 
$
72,631

 
$
7,493

Less amounts capitalized to oil and gas properties
 
(19,537
)
 
(18,779
)
 
(758
)
 
(37,064
)
 
(34,835
)
 
(2,229
)
G&A expense
 
$
19,739

 
$
19,762

 
$
(23
)
 
$
43,060

 
$
37,796

 
$
5,264

G&A expense for the six months ended June 30, 2018 was 14%, or $5.3 million, higher than G&A expense for the six months ended June 30, 2017. This increase was primarily due to increased employee headcount and increased salaries and wages, other compensation, consisting of incentive bonuses and vacation pay, benefits, primarily consisting of profit sharing, and consulting expense. 

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Table of Contents

Stock Compensation
Stock compensation expense consists of non-cash charges resulting from the amortization of the cost of restricted stock and stock option awards, net of amounts capitalized to oil and gas properties. We have recognized stock-based compensation cost as follows:
 
 
Three Months Ended
June 30,
 
Variance Between 2018 / 2017
 
Six Months Ended
June 30,
 
Variance Between 2018 / 2017
Stock Compensation Expense (in thousands)
 
2018
 
2017
 
 
2018
 
2017
 
Restricted stock awards:
 
 
 
 
 
 
 
 
 
 
 
 
Performance stock awards
 
$
3,809

 
$
6,438

 
$
(2,629
)
 
$
10,538

 
$
12,840

 
$
(2,302
)
Service-based stock awards
 
4,247

 
4,208

 
39

 
9,319

 
9,132

 
187

 
 
8,056

 
10,646

 
(2,590
)
 
19,857

 
21,972

 
(2,115
)
Stock option awards
 
637

 
579

 
58

 
1,254

 
1,245

 
9

Total stock compensation cost
 
8,693

 
11,225

 
(2,532
)
 
21,111

 
23,217

 
(2,106
)
Less amounts capitalized to oil and gas properties
 
(5,598
)
 
(4,932
)
 
(666
)
 
(11,286
)
 
(10,636
)
 
(650
)
Stock compensation expense
 
$
3,095

 
$
6,293

 
$
(3,198
)
 
$
9,825

 
$
12,581

 
$
(2,756
)
Periodic stock compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards.  The decrease in total stock compensation cost in the 2018 periods as compared to the 2017 periods is primarily due to performance stock award forfeitures during the three months ended June 30, 2018. Our accounting policy is to account for forfeitures in compensation cost when they occur.
Loss (Gain) on Derivative Instruments, Net
The following table presents the components of Loss (gain) on derivative instruments, net for the periods indicated. See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.
 
 
Three Months Ended
June 30,
 
Variance Between 2018 / 2017
 
Six Months Ended
June 30,
 
Variance Between 2018 / 2017
Loss (Gain) on Derivative Instruments, Net (in thousands)
 
2018
 
2017
 
 
2018
 
2017
 
Change in fair value of derivative instruments, net:
 
 

 
 

 
 

 
 
 
 
 
 
Gas contracts
 
$
14,566

 
$
(5,748
)
 
$
20,314

 
$
2,777

 
$
(27,939
)
 
$
30,716

Oil contracts
 
(397
)
 
(16,418
)
 
16,021

 
(5,156
)
 
(44,148
)
 
38,992

 
 
14,169

 
(22,166
)
 
36,335

 
(2,379
)
 
(72,087
)
 
69,708

Cash (receipts) payments on derivative instruments, net:
 
 

 
 

 
 
 
 
 
 
 
 
Gas contracts
 
(9,918
)
 
(1,308
)
 
(8,610
)
 
(15,037
)
 
1,136

 
(16,173
)
Oil contracts
 
17,448

 
965

 
16,483

 
34,956

 
4,581

 
30,375

 
 
7,530

 
(343
)
 
7,873

 
19,919

 
5,717

 
14,202

Loss (gain) on derivative instruments, net
 
$
21,699

 
$
(22,509
)
 
$
44,208

 
$
17,540

 
$
(66,370
)
 
$
83,910

Other Operating Expense, Net
Other operating expense, net is comprised primarily of litigation settlements and allowance for doubtful accounts adjustments.

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Other Income and Expense
 
 
Three Months Ended
June 30,
 
Variance Between 2018 / 2017
 
Six Months Ended
June 30,
 
Variance Between 2018 / 2017
Other Income and Expense (in thousands)
 
2018
 
2017
 
 
2018
 
2017
 
Interest expense
 
$
16,895

 
$
20,095

 
$
(3,200
)
 
$
33,678

 
$
41,147

 
$
(7,469
)
Capitalized interest
 
(4,850
)
 
(5,442
)
 
592

 
(9,660
)
 
(12,083
)
 
2,423

Loss on early extinguishment of debt
 

 
28,169

 
(28,169
)
 

 
28,169

 
(28,169
)
Other, net
 
(2,605
)
 
(2,231
)
 
(374
)
 
(7,172
)
 
(4,441
)
 
(2,731
)
 
 
$
9,440

 
$
40,591

 
$
(31,151
)
 
$
16,846

 
$
52,792

 
$
(35,946
)
The majority of our interest expense relates to interest on our senior unsecured notes. Also included in interest expense is the amortization of debt issuance costs and discount.  See LIQUIDITY AND CAPITAL RESOURCES Long-term Debt below for further information regarding our debt. The decrease in interest expense in the 2018 periods as compared to the 2017 periods is primarily due to the completion of a tender offer and redemption of $750 million 5.875% senior unsecured notes and the issuance of $750 million 3.90% senior unsecured notes, both of which occurred during the second quarter of 2017. The $28.2 million loss on early extinguishment of debt incurred during the three and six months ended June 30, 2017 was also associated with the debt tender offer and redemption. The loss was composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.  The original maturity date of the 5.875% notes was May 1, 2022.
We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing 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 lower in the 2018 periods as compared to the 2017 periods, thus reducing our capitalized interest. Also contributing to lower capitalized interest in the 2018 periods was a lower average interest rate on borrowings outstanding due to the replacement of our 5.875% notes with 3.90% notes in the second quarter of 2017.
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 are as follows:
 
 
Three Months Ended
June 30,
 
Variance Between 2018 / 2017
 
Six Months Ended
June 30,
 
Variance Between 2018 / 2017
Income Tax Expense (Benefit) (in thousands)
 
2018
 
2017
 
 
2018
 
2017
 
Current tax benefit
 
$
(717
)
 
$

 
$
(717
)
 
$
(717
)
 
$
(6
)
 
$
(711
)
Deferred tax expense
 
42,783

 
58,617

 
(15,834
)
 
99,732

 
136,929

 
(37,197
)
 
 
$
42,066

 
$
58,617

 
$
(16,551
)
 
$
99,015

 
$
136,923

 
$
(37,908
)
Combined federal and state effective income tax rate
 
23.0
%
 
37.6
%
 
 
 
23.2
%
 
37.5
%
 
 
Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 21% in 2018 and 35% in 2017 primarily due to state income taxes and non-deductible expenses. See Note 9 to the Condensed Consolidated Financial Statements for additional information regarding our income taxes.
LIQUIDITY AND CAPITAL RESOURCES
Overview
We strive to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include our cash flow from operations, cash on hand, available borrowing capacity under our revolving credit facility, proceeds from sales of non-core assets, and occasional public financings based on our monitoring of capital markets and our balance sheet.

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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 2018 exploration and development (“E&D”) expenditures are projected to range from $1.6 billion to $1.7 billion. Investments in midstream and other assets are projected to range from $80 million to $90 million for the year. See Capital Expenditures below for information regarding our E&D activities for the three and six months ended June 30, 2018 and 2017.
We periodically use derivative instruments to mitigate volatility in commodity prices. At June 30, 2018, we had derivative contracts covering a portion of our 2018 and 2019 production. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. See Note 3 to the Condensed Consolidated Financial Statements for information regarding our derivative instruments.
We believe our conservative use of leverage, strong balance sheet, and hedging activities will mitigate our exposure to lower prices. Cash and cash equivalents at June 30, 2018 were $410.8 million. At June 30, 2018, our long-term debt consisted of $1.5 billion of senior unsecured notes, with $750 million 4.375% notes due in 2024 and $750 million 3.90% notes due in 2027. At June 30, 2018, 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. See Long-term Debt below for more information regarding our debt.
Our debt to total capitalization ratio at June 30, 2018 was 34%, down from 37% at December 31, 2017. This ratio is calculated by dividing the principal amount of long-term debt by the sum of (i) the principal amount of long-term debt and (ii) total stockholders’ equity, with all numbers coming directly from the Condensed Consolidated Balance Sheet. Management uses this ratio as one indicator of our financial condition and believes professional research analysts and rating agencies use this ratio for this purpose and to compare our financial condition to other companies’ financial conditions. Additionally, our credit facility includes a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%.
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.
 
 
Six Months Ended
June 30,
(in thousands)
 
2018
 
2017
Net cash provided by operating activities
 
$
704,339

 
$
504,800

Net cash used by investing activities
 
$
(671,552
)
 
$
(590,824
)
Net cash used by financing activities
 
$
(22,498
)
 
$
(47,257
)
Net cash provided by operating activities for the six months ended June 30, 2018 was $704.3 million, up $199.5 million, or 40%, from $504.8 million for the six months ended June 30, 2017. The $199.5 million increase resulted primarily from the increase in production revenue, which increased due to increased production volumes and realized oil and NGL prices. Also contributing to the increase was a decreased investment 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. See RESULTS OF OPERATIONS above for more information regarding the changes in revenue and operating expenses.
Net cash used by investing activities for the six months ended June 30, 2018 and 2017 was $671.6 million and $590.8 million, respectively. The majority of our cash flows used by investing activities are for E&D expenditures, which totaled $650.8 million and $582.2 million for the six months ended June 30, 2018 and 2017, respectively. The remaining investing cash outflows are primarily for midstream asset expenditures. Proceeds from the sales of non-core assets slightly offset capital expenditure cash outflows in both periods.

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Table of Contents

Net cash used by financing activities for the six months ended June 30, 2018 and 2017 was $22.5 million and $47.3 million, respectively. During the six months ended June 30, 2017, we extinguished our $750 million principal amount 5.875% senior 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 notes at 99.748% of par for proceeds of $748.1 million, paying $6.2 million in underwriting, financing, and other costs. Additionally, 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 six months ended June 30, 2018, we paid one $0.08 per share dividend and one $0.16 per share dividend, totaling $22.8 million and during the six months ended June 30, 2017, we paid two $0.08 per share dividends totaling $15.2 million.
Capital Expenditures
The following table presents capitalized expenditures for oil and gas acquisition, exploration, and development activities, net of proceeds from property sales.
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in thousands)
 
2018
 
2017
 
2018
 
2017
Acquisitions:
 
 
 
 
 
 
 
 
Proved
 
$

 
$
255

 
$
62

 
$
260

Unproved
 
77

 
792

 
2,236

 
3,825

 
 
77

 
1,047

 
2,298

 
4,085

Exploration and development:
 
 

 
 
 
 
 
 
Land and seismic
 
10,327

 
33,302

 
20,424

 
110,487

Exploration and development
 
365,097

 
262,575

 
668,469

 
491,042

 
 
375,424

 
295,877

 
688,893

 
601,529

Property sales:
 
 
 
 
 
 
 
 
Proved
 
(4,577
)
 
(1,957
)
 
(29,541
)
 
(1,892
)
Unproved
 
(441
)
 
(2,305
)
 
(5,301
)
 
(7,271
)
 
 
(5,018
)
 
(4,262
)
 
(34,842
)
 
(9,163
)
 
 
$
370,483

 
$
292,662

 
$
656,349

 
$
596,451

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.
Our 2018 E&D capital investment is projected to range from $1.6 billion to $1.7 billion, with the majority expected to be invested in the Permian Basin.
As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on increases or decreases in commodity prices, service costs, and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions.
We intend to continue to fund our 2018 capital investment program with cash flow from our operating activities and cash on hand. Sales of non-core assets and borrowings under our credit facility may also be used to supplement funding of capital expenditures. The timing of capital expenditures and the receipt of cash flows do not necessarily match, which may cause us to borrow and repay funds under our credit facility from time-to-time. See Long-term DebtBank Debt below for further information regarding our credit facility.
On May 23, 2018, we entered into a Purchase and Sale Agreement with Callon Petroleum Operating Company (“Callon”) pursuant to which we agreed to sell, and Callon agreed to purchase, oil and gas properties principally located in Ward County, Texas for $570 million in cash. This sale is part of our continuous portfolio optimization and high-grading of our investment opportunities. The Purchase and Sale Agreement contains representations, warranties, covenants, conditions to closing, purchase price adjustments, and other terms customary in transactions of this type. We expect to complete this transaction on August 31, 2018.

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Table of Contents

The following table reflects wells completed by region during the periods indicated.
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2018
 
2017
 
2018
 
2017
Gross wells
 
 
 
 
 
 
 
 
Permian Basin
 
32

 
11

 
49

 
36

Mid-Continent
 
57

 
40

 
94

 
85

 
 
89

 
51

 
143

 
121

Net wells
 
 
 
 
 
 
 
 
Permian Basin
 
13

 
10

 
22

 
26

Mid-Continent
 
10

 
8

 
16

 
18

 
 
23

 
18

 
38

 
44

As of June 30, 2018, we had 29 gross (11 net) wells in the process of being drilled: 14 gross (9 net) in the Permian Basin and 15 gross (2 net) in the Mid-Continent region. As of June 30, 2018, there were 141 gross (57 net) wells waiting on completion: 45 gross (32 net) in the Permian Basin and 96 gross (25 net) in the Mid-Continent region. As of June 30, 2018, we had 12 operated rigs running: nine in the Permian Basin and three in the Mid-Continent region.
We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations. While we expect current pending legislation or regulations to increase the cost of business, we do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact, based on current laws and regulations. However, compliance with new legislation or regulations could increase our costs or adversely affect demand for oil or gas and result in a material adverse effect on our financial position or operations. See our Form 10-K for the year ended December 31, 2017, Item 1A Risk Factors, for a description of risks related to current and potential future environmental and safety regulations and requirements that could adversely affect our operations and financial condition.
Long-term Debt
Long-term debt at June 30, 2018 and December 31, 2017 consisted of the following:
 
 
June 30, 2018
 
December 31, 2017
(in thousands)
 
Principal
 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
 
Principal
 
Unamortized Debt
Issuance Costs
and Discount (1)
 
Long-term
Debt, net
4.375% Senior Notes
 
$
750,000

 
$
(4,906
)
 
$
745,094

 
$
750,000

 
$
(5,383
)
 
$
744,617

3.90% Senior Notes
 
750,000

 
(7,355
)
 
742,645

 
750,000

 
(7,697
)
 
742,303

Total long-term debt
 
$
1,500,000

 
$
(12,261
)
 
$
1,487,739

 
$
1,500,000

 
$
(13,080
)
 
$
1,486,920

________________________________________
(1)
At June 30, 2018, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.7 million and $1.7 million, respectively. At December 31, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.9 million and $1.8 million, respectively. The 4.375% notes were issued at par.
Bank Debt
We have a senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020. The Credit Facility has aggregate commitments of $1.0 billion, with an option for us to increase the aggregate commitments to $1.25 billion at any time. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. As of June 30, 2018, 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.
At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.1252.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.1251.0%,

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based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of 0.1250.35%, based on the credit rating for our senior unsecured long-term debt.
The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of June 30, 2018, we were in compliance with all of the financial and non-financial covenants.
At June 30, 2018 and December 31, 2017, we had $2.7 million and $3.4 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.
Senior Notes
In April 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes at 99.748% of par to yield 3.93% per annum. These notes are due May 15, 2027 and interest is payable semiannually on May 15 and November 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.01%.
In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and interest is payable semiannually on June 1 and December 1. The effective interest rate on these notes, including the amortization of debt issuance costs, is 4.50%.
Our senior unsecured notes are governed by indentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of June 30, 2018.
Working Capital Analysis
Our working capital fluctuates primarily as a result of our realized commodity prices, increases or decreases in our production volumes, changes in receivables and payables related to our operating and E&D activities, changes in our oil and gas well equipment and supplies, and changes in the fair value of our derivative instruments.
At June 30, 2018, we had working capital of $253.2 million, a decrease of $2.9 million or 1% compared to working capital of $256.1 million at December 31, 2017.
Working capital decreases consisted primarily of the following: 
Accrued liabilities related to our E&D expenditures increased by $31.1 million.
Operations-related accounts receivable decreased by $15.5 million.
Working capital increases consisted primarily of the following:
Operations-related accounts payable and accrued liabilities decreased by $22.2 million.
Cash and cash equivalents increased by $10.3 million.
Current derivative instrument net liability decreased by $9.4 million.
Oil and gas well equipment and supplies increased by $3.7 million.
Accounts receivable are a major component of our working capital and include amounts due from a diverse group of companies comprised of major energy companies, pipeline companies, local distribution companies, and other end-users. Historically, losses associated with uncollectible receivables have not been significant. The fair value of derivative instruments fluctuates based on changes in the underlying price indices as compared to the contracted prices.
Dividends
A quarterly cash dividend has been paid to stockholders every quarter since the first quarter of 2006. In May 2018, a $0.16 per share dividend was declared, which is payable on or before August 31, 2018 to stockholders of record on August 15, 2018. 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.

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Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2018, our material off-balance sheet arrangements consisted of operating lease agreements, which are included in the contractual obligations table below.
Contractual Obligations and Material Commitments
At June 30, 2018, we had the following contractual obligations and material commitments:
 
 
Payments Due by Period
 
Contractual obligations (in thousands)
 
Total
 
1 Year or Less
 
2-3
Years
 
4-5
Years
 
More than 5 Years
 
Long-term debt—principal (1)
 
$
1,500,000

 
$

 
$

 
$

 
$
1,500,000

 
Long-term debt—interest (1)
 
460,044

 
60,844

 
124,125

 
124,125

 
150,950

 
Operating leases (2)
 
90,206

 
15,372

 
25,399

 
22,512

 
26,923

 
Unconditional purchase obligations (3)
 
80,863

 
31,176

 
35,585

 
6,900

 
7,202

 
Derivative liabilities
 
101,991

 
90,480

 
11,511

 

 

 
Asset retirement obligation (4)
 
167,998

 
8,430

 

(4)

(4)

(4)
Other long-term liabilities (5)
 
39,567

 
2,034

 
3,540

 
5,138

 
28,855

 
 
 
$
2,440,669

 
$
208,336

 
$
200,160

 
$
158,675

 
$
1,713,930

 
________________________________________
(1)
The interest payments presented above include the accrued interest payable on our long-term debt as of June 30, 2018 as well as future payments calculated using the long-term debt’s fixed rates, stated maturity dates, and principal amounts outstanding as of June 30, 2018. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.
(2)
Operating leases include various lease commitments for commercial real estate, which consists primarily of office space, and compressor equipment.
(3)
Of the total Unconditional purchase obligations, $43.9 million represents obligations for the purchase of sand for well completions and $26.6 million represents obligations for firm transportation agreements for gas pipeline capacity.
(4)
We have excluded the presentation of the timing of the cash flows associated with our long-term asset retirement obligations because we cannot make a reasonably reliable estimate of the future period of cash settlement. The long-term asset retirement obligation is included in the total asset retirement obligation presented.
(5)
Other long-term liabilities include contractual obligations associated with our employee supplemental savings plan, gas balancing liabilities, and other miscellaneous liabilities. All of these liabilities are accrued on our Condensed Consolidated Balance Sheet. The current portion associated with these long-term liabilities is also presented in the table above in the “1 Year or Less” column.
The following discusses various commercial commitments that we have made that may include potential future cash payments if we fail to meet various performance obligations. These are not reflected in the table above.
At June 30, 2018, we had estimated commitments of approximately: (i) $154.4 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $14.4 million to finish gathering system construction in progress.
At June 30, 2018, we had firm sales contracts to deliver approximately 330.7 Bcf of gas over the next 6.6 years. If we do not deliver this gas, our estimated financial commitment, calculated using the July 2018 index price, would be approximately $659.9 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 9.5 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 June 30, 2018, would be approximately $351.0 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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We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2018, would be approximately $7.4 million. Of this total, we have accrued a liability of $2.5 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.
All of the noted commitments were routine and made in the ordinary course of our business.
Taking into account current commodity prices and anticipated levels of production, we believe that our net cash flow generated from operations and our other capital resources will be adequate to meet future obligations.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We consider accounting policies and estimates related to oil and gas reserves, full cost accounting, and income taxes to be critical accounting policies and estimates. These are summarized in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2017.
Recent Accounting Developments
See Note 1 to the Condensed Consolidated Financial Statements in this report for a discussion of recently issued accounting pronouncements and their anticipated effect on our financial statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk including the risk of loss arising from adverse changes in commodity prices and interest rates.
Price Fluctuations
Our major market risk is pricing applicable to our oil, gas, and NGL production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil, gas, and NGL production has been volatile and unpredictable. For the three months ended June 30, 2018, our total production revenue was comprised of 63% oil sales, 15% gas sales, and 22% NGL sales. For the six months ended June 30, 2018, our total production revenue was comprised of 63% oil sales, 17% gas sales, and 20% NGL sales. The following table shows how hypothetical changes in the realized prices we receive for our commodity sales may have impacted revenue for the periods indicated.
 
 
 
 
Impact on Revenue
 
Change in Realized Price
 
Three Months Ended
June 30, 2018
 
Six Months Ended
June 30, 2018
 
 
 
 
(in thousands)
Oil
± $1.00
per barrel
 
± $5,610
 
± $11,479
Gas
± $0.10
per Mcf
 
± $4,909
 
± $9,722
NGL
± $1.00
per barrel
 
± $5,447
 
± $10,102
 
 
 
 
± $15,966
 
± $31,303
We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. At June 30, 2018, we had oil and gas derivatives covering a portion of our 2018 and 2019 production, which were recorded as current and non-current assets and liabilities. At June 30, 2018, our oil and gas derivatives had a gross asset fair value of $75.3 million and a gross liability fair value of $102.0 million. See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.

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While these contracts limit the downside risk of adverse price movements, they may also limit future cash flow from favorable price movements. The following table shows how hypothetical changes in the forward prices used to calculate the fair value of our derivatives may have impacted the fair value as of June 30, 2018.
 
 
 
Impact on Fair Value
 
Change in Forward Price
 
June 30, 2018
 
 
 
(in thousands)
Oil
-$1.00
 
$
9,870

Oil
+$1.00
 
$
(10,056
)
Gas
-$0.10
 
$
6,714

Gas
+$0.10
 
$
(6,728
)
Interest Rate Risk
At June 30, 2018, 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. Because all of our outstanding long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.
ITEM 4. CONTROLS AND PROCEDURES 
Evaluation of Disclosure Controls and Procedures
Cimarex’s management, under the supervision and with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of Cimarex’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of June 30, 2018.  Based on that evaluation, the CEO and CFO concluded that the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods required by the U.S. Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including the CEO and CFO, to allow timely decisions regarding required disclosures.
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting that occurred during the fiscal quarter ended June 30, 2018 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. The risks described in the Annual Report on Form 10-K for the year ended December 31, 2017 are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or future results.
ITEM 6. EXHIBITS

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


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
August 7, 2018
 
 
 
 
 
 
CIMAREX ENERGY CO.
 
 
 
 
 
/s/ G. Mark Burford
 
G. Mark Burford
 
Vice President and Chief Financial Officer
 
(Principal Financial Officer)
 
 
 
 
 
/s/ Timothy A. Ficker
 
Timothy A. Ficker
 
Vice President, Controller, and Chief Accounting Officer
 
(Principal Accounting Officer)


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