Cimarex Energy (CIMXP) 10-Q 2017 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

☒	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the Quarterly Period ended June 30, 2017
☐	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File No. 001-31446

CIMAREX ENERGY CO.

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 ☒  No ☐

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 ☒  No ☐

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 ☒ Accelerated filer ☐ Non-accelerated filer ☐
(Do not check if a smaller
reporting company) Smaller reporting company ☐
Emerging growth company ☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐  No ☒.

The number of shares of Cimarex Energy Co. common stock outstanding as of July 31, 2017 was 95,278,037.

EXPLANATORY NOTE

The comparative period financial information for 2016 included in this Form 10-Q reflects the corrected financial information for 2016 included under the heading “Supplemental Quarterly Financial Data (Unaudited)” in an amendment to our Annual Report on Form 10-K for the year ended December 31, 2016 (the “Form 10-K/A”) filed with the Securities and Exchange Commission on May 10, 2017 in order to reflect corrections to financial information.  For additional information, see the “Explanatory Note” to the Form 10-K/A.

CIMAREX ENERGY CO.

Table of Contents

		Page
PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets (Unaudited) as of June  30, 2017 and December 31, 2016	5
	Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (Unaudited) for the three and six months ended June 30, 2017 and 2016	6
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the six months ended June 30, 2017 and 2016	7
	Condensed Consolidated Statement of Stockholders’ Equity (Unaudited) for the six months ended June 30, 2017	8
	Notes to Condensed Consolidated Financial Statements (Unaudited)	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	40
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 6.	Exhibits	42
Signatures		43

GLOSSARY

Bbl/d—Barrels per day

Bbls—Barrels

Bcf—Billion cubic feet

Bcfe—Billion cubic feet equivalent

Btu—British thermal unit

Gross Acres or Gross Wells—The total acres or wells, as the case may be, in which a working interest is owned.

MBbls—Thousand barrels

Mcf—Thousand cubic feet

Mcfe—Thousand cubic feet equivalent

MMBbl/MMBbls—Million barrels

MMBtu—Million British thermal units

MMcf—Million cubic feet

MMcf/d—Million cubic feet per day

MMcfe—Million cubic feet equivalent

MMcfe/d—Million cubic feet equivalent per day

Net Acres or Net Wells—The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.

Net Production—Gross production multiplied by net revenue interest

NGL or NGLs—Natural gas liquids

Tcf—Trillion cubic feet

Tcfe—Trillion cubic feet equivalent

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, the effectiveness of our internal control over financial reporting and our ability to remediate a material weakness in our internal control over financial reporting, 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, and availability of financing.  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.

4

PART I

ITEM 1. - Financial Statements

CIMAREX ENERGY CO.

Condensed Consolidated Balance Sheets

(Unaudited)

	June 30,		December 31,
	2017		2016
	(in thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	519,595	$	652,876
Accounts receivable, net of allowance:
Trade		85,397		42,287
Oil and gas sales		236,988		217,395
Gas gathering, processing, and marketing		13,146		14,888
Oil and gas well equipment and supplies		45,486		33,342
Derivative instruments		19,803		—
Prepaid expenses		5,894		7,335
Other current assets		1,567		1,181
Total current assets		927,876		969,304
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties		16,769,915		16,225,495
Unproved properties and properties under development, not being amortized		535,779		478,277
		17,305,694		16,703,772
Less—accumulated depreciation, depletion, amortization, and impairment		(14,530,251)		(14,349,505)
Net oil and gas properties		2,775,443		2,354,267
Fixed assets, net of accumulated depreciation of $268,778 and $246,901, respectively		206,114		205,465
Goodwill		620,232		620,232
Derivative instruments		442		—
Deferred income taxes		—		55,835
Other assets		32,873		32,621
	$	4,562,980	$	4,237,724
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	61,397	$	49,163
Gas gathering, processing, and marketing		26,436		25,323
Accrued liabilities:
Exploration and development		95,048		82,320
Taxes other than income		17,719		18,766
Other		182,580		177,695
Derivative instruments		98		49,370
Revenue payable		142,943		119,715
Total current liabilities		526,221		522,352
Long-term debt:
Principal		1,500,000		1,500,000
Less—unamortized debt issuance costs and discount		(13,903)		(12,061)
Long-term debt, net		1,486,097		1,487,939
Deferred income taxes		48,322		—
Asset retirement obligation		147,363		140,770
Derivative instruments		—		2,570
Other liabilities		43,222		41,104
Total liabilities		2,251,225		2,194,735
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, 95,341,554 and 95,123,525 shares issued, respectively		953		951
Additional paid-in capital		2,774,597		2,763,452
Retained earnings (accumulated deficit)		(465,366)		(722,359)
Accumulated other comprehensive income		1,571		945
Total stockholders’ equity		2,311,755		2,042,989
	$	4,562,980	$	4,237,724

See accompanying Notes to Condensed Consolidated Financial Statements.

5

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
	(in thousands, except per share data)
Revenues:
Oil sales	$	232,453	$	162,005	$	456,519	$	279,578
Gas sales		132,474		76,615		264,419		159,223
NGL sales		80,886		51,939		161,312		85,291
Gas gathering and other		10,735		8,211		21,360		15,452
Gas marketing, net of related costs of $38,884, $26,435, $78,737, and $51,747, respectively		(96)		103		18		(71)
		456,452		298,873		903,628		539,473
Costs and expenses:
Impairment of oil and gas properties		—		333,291		—		652,077
Depreciation, depletion, and amortization		107,884		102,086		203,700		212,722
Asset retirement obligation		960		1,750		2,580		4,048
Production		62,578		57,213		124,999		127,915
Transportation, processing, and other operating		58,624		44,436		113,647		90,879
Gas gathering and other		8,647		7,492		17,074		15,572
Taxes other than income		17,477		14,066		38,790		27,905
General and administrative		19,762		21,424		37,796		35,321
Stock compensation		6,293		7,490		12,581		13,018
(Gain) loss on derivative instruments, net		(22,509)		33,236		(66,370)		32,808
Other operating expense, net		266		24		882		114
		259,982		622,508		485,679		1,212,379
Operating income (loss)		196,470		(323,635)		417,949		(672,906)
Other (income) and expense:
Interest expense		20,095		20,824		41,147		41,629
Capitalized interest		(5,442)		(5,633)		(12,083)		(10,537)
Loss on early extinguishment of debt		28,169		—		28,169		—
Other, net		(2,231)		(2,011)		(4,441)		(3,661)
Income (loss) before income tax		155,879		(336,815)		365,157		(700,337)
Income tax expense (benefit)		58,617		(122,361)		136,923		(254,424)
Net income (loss)	$	97,262	$	(214,454)	$	228,234	$	(445,913)
Earnings (loss) per share to common stockholders:
Basic	$	1.02	$	(2.31)	$	2.40	$	(4.79)
Diluted	$	1.02	$	(2.31)	$	2.40	$	(4.79)
Dividends declared per share	$	0.08	$	0.08	$	0.16	$	0.16
Comprehensive income (loss):
Net income (loss)	$	97,262	$	(214,454)	$	228,234	$	(445,913)
Other comprehensive income:
Change in fair value of investments, net of tax of $128, $112, $359, and $161, respectively		224		195		626		280
Total comprehensive income (loss)	$	97,486	$	(214,259)	$	228,860	$	(445,633)

See accompanying Notes to Condensed Consolidated Financial Statements.

6

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended
	June 30,
	2017		2016
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	228,234	$	(445,913)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of oil and gas properties		—		652,077
Depreciation, depletion, and amortization		203,700		212,722
Asset retirement obligation		2,580		4,048
Deferred income taxes		136,929		(254,424)
Stock compensation		12,581		13,018
(Gain) loss on derivative instruments, net		(66,370)		32,808
Settlements on derivative instruments		(5,717)		8,927
Loss on early extinguishment of debt		28,169		—
Changes in non-current assets and liabilities		1,076		2,548
Other, net		3,445		2,644
Changes in operating assets and liabilities:
Receivables		(61,145)		(4,327)
Other current assets		(11,104)		17,328
Accounts payable and other current liabilities		32,422		(23,670)
Net cash provided by operating activities		504,800		217,786
Cash flows from investing activities:
Oil and gas capital expenditures		(582,172)		(325,058)
Sales of oil and gas assets		9,163		12,630
Sales of other assets		394		224
Other capital expenditures		(18,209)		(17,774)
Net cash used by investing activities		(590,824)		(329,978)
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)		(1)
Dividends paid		(15,153)		(22,655)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards		(1,215)		(4,082)
Proceeds from exercise of stock options and other		36		1,287
Net cash used by financing activities		(47,257)		(25,451)
Net decrease in cash and cash equivalents		(133,281)		(137,643)
Cash and cash equivalents at beginning of period		652,876		779,382
Cash and cash equivalents at end of period	$	519,595	$	641,739

See accompanying Notes to Condensed Consolidated Financial Statements.

7

CIMAREX ENERGY CO.

Condensed Consolidated Statement of Stockholders’ Equity

(Unaudited)

						Retained		Accumulated
						Earnings		Other		Total
	Common Stock			Additional Paid-in		(Accumulated		Comprehensive		Stockholders’
	Shares	Amount		Capital		Deficit)		Income		Equity
	(in thousands)
Balance, December 31, 2016	95,124	$	951	$	2,763,452	$	(722,359)	$	945	$	2,042,989
Dividends paid on stock awards subsequently forfeited	—		—		3		20		—		23
Dividends in excess of retained earnings	—		—		(15,237)		—		—		(15,237)
Net income	—		—		—		228,234		—		228,234
Unrealized change in fair value of investments, net of tax	—		—		—		—		626		626
Issuance of restricted stock awards	244		2		(2)		—		—		—
Common stock reacquired and retired	(10)		—		(1,215)		—		—		(1,215)
Restricted stock forfeited and retired	(17)		—		—		—		—		—
Exercise of stock options	1		—		36		—		—		36
Stock-based compensation	—		—		23,193		—		—		23,193
Cumulative effect adjustment of adopting ASU 2016-09 (Note 6)	—		—		4,393		28,739		—		33,132
Other	—		—		(26)		—		—		(26)
Balance, June 30, 2017	95,342	$	953	$	2,774,597	$	(465,366)	$	1,571	$	2,311,755

See accompanying Notes to Condensed Consolidated Financial Statements.

8

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(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 “Explanatory Note”, financial statements, summary of significant accounting policies, and footnotes included in our Annual Report on Form 10-K/A for the year ended December 31, 2016.

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 2017 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 completion, disposal, and transportation.  An analysis of our oil and gas well equipment and supplies was performed as of June 30, 2017, and no impairment was required.  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.  Accounting rules require us 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.  Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.

At June 30, 2017 and March 31, 2017, the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we have not recognized a ceiling test impairment during the six months ended June 30, 2017. During the three and six months ended June 30, 2016, we recognized ceiling test impairments of $333.3 million ($211.8 million, net of tax) and $652.1 million ($414.3 million, net of tax), respectively.  These impairments resulted primarily from decreases in the trailing twelve-month average prices for oil, natural gas, and NGLs utilized in determining the future net revenues from proved reserves.  The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes.  If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters.  The calculated ceiling limitation is not intended to be indicative of the fair market

9

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.  Any impairment of oil and gas properties is not reversible at a later date. 

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606).  In July 2015, the FASB deferred the effective date by one year to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.  Early adoption is permitted, but not before the original effective date of reporting periods beginning after December 15, 2016.  The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized.  The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification.  Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach.  We intend to adopt this standard on January 1, 2018, utilizing a modified retrospective approach.  Management does not believe the effect of adoption will be material to our financial statements because we follow the sales method of accounting for our oil, gas, and NGL production, which is generally consistent with the revenue recognition provisions of the new standard.  However, we anticipate the new standard will result in more robust footnote disclosures. 

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842).  The key provision of this ASU is that a lessee must recognize (i) liabilities to make lease payments and (ii) right-of-use assets on its balance sheet.  The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months.  Under current generally accepted accounting principles (“GAAP”), 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.  Upon transition, lessees will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach.  We are in the process of 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.

10

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

2.LONG-TERM DEBT

Long-term debt at June 30, 2017 and December 31, 2016 consisted of the following:

	June 30, 2017						December 31, 2016
			Unamortized Debt
			Issuance Costs		Long-term				Unamortized Debt		Long-term
(in thousands)	Principal		and Discount (1)		Debt, net		Principal		Issuance Costs		Debt, net
5.875% Senior Notes	$	—	$	—	$	—	$	750,000	$	(5,691)	$	744,309
4.375% Senior Notes		750,000		(5,872)		744,128		750,000		(6,370)		743,630
3.90% Senior Notes		750,000		(8,031)		741,969		—		—		—
Total long-term debt	$	1,500,000	$	(13,903)	$	1,486,097	$	1,500,000	$	(12,061)	$	1,487,939

(1) At June 30, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $6.2 million and $1.9 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 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, 2017, 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 1.125 – 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 – 1.0%, based on the credit rating for our senior unsecured long-term debt.  Unused borrowings are subject to a commitment fee of 0.125 – 0.35%, based on the credit rating for our senior unsecured long-term debt.

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%.  As of June 30, 2017, we were in compliance with all of the financial covenants.

At June 30, 2017 and December 31, 2016, we had $3.9 million and $4.5 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

On April 10, 2017, we completed a cash tender offer to purchase any of our 5.875% notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5 million aggregate principal amount of the notes validly tendered.  We settled these tendered notes for $268.1 million, including accrued interest.  On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for $512.0 million, including accrued interest.  During the three months ended June 30, 2017, we recognized a loss on early extinguishment of debt related to these transactions of $28.2 million, 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 of the 5.875% notes was 2022. 

11

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

On April 10, 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes due May 15, 2027 at 99.748% of par to yield 3.93% per annum.  We have received $741.9 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs as of June 30, 2017.  The notes bear an interest rate of 3.90% and interest is payable semiannually on May 15 and November 15, with the first payment to be made November 15, 2017.  Along with cash on hand, we used the proceeds to fund the settlement of the tendered and redeemed 5.875% notes. 

Each of our senior unsecured notes is governed by an indenture containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of June 30, 2017.  The 4.375% notes are due in 2024.  Interest on each of the senior notes is payable semiannually.  The effective interest rate on the 4.375% notes and the 3.90% notes, including the amortization of debt issuance costs and discount, as applicable, is 4.50% and 4.01%, respectively.

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 revenues from favorable price changes.  We may enter into derivative instruments covering up to 50% of our oil and natural gas production on a forward five quarter basis.  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. 

The following tables summarize our outstanding derivative contracts as of June 30, 2017:

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
Oil Collars:
2017:
WTI (1)
Volume (Bbls)		—		—		2,024,000		1,564,000		3,588,000
Wtd Avg Price - Floor	$	—	$	—	$	46.25	$	47.35	$	46.73
Wtd Avg Price - Ceiling	$	—	$	—	$	56.06	$	57.18	$	56.55
2018:
WTI (1)
Volume (Bbls)		1,080,000		546,000		184,000		—		1,810,000
Wtd Avg Price - Floor	$	48.33	$	49.33	$	48.00	$	—	$	48.60
Wtd Avg Price - Ceiling	$	58.33	$	57.56	$	54.76	$	—	$	57.74

(1) The index price for these collars is WTI, which refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange.

12

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
Gas Collars:
2017:
PEPL (1)
Volume (MMBtu)		—		—		11,040,000		8,280,000		19,320,000
Wtd Avg Price - Floor	$	—	$	—	$	2.60	$	2.72	$	2.65
Wtd Avg Price - Ceiling	$	—	$	—	$	3.12	$	3.20	$	3.15
Perm EP (2)
Volume (MMBtu)		—		—		7,360,000		5,520,000		12,880,000
Wtd Avg Price - Floor	$	—	$	—	$	2.63	$	2.74	$	2.68
Wtd Avg Price - Ceiling	$	—	$	—	$	3.13	$	3.20	$	3.16
2018:
PEPL (1)
Volume (MMBtu)		5,400,000		2,730,000		—		—		8,130,000
Wtd Avg Price - Floor	$	2.73	$	2.57	$	—	$	—	$	2.68
Wtd Avg Price - Ceiling	$	3.23	$	3.14	$	—	$	—	$	3.20
Perm EP (2)
Volume (MMBtu)		3,600,000		1,820,000		—		—		5,420,000
Wtd Avg Price - Floor	$	2.75	$	2.50	$	—	$	—	$	2.67
Wtd Avg Price - Ceiling	$	3.22	$	3.04	$	—	$	—	$	3.16

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

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

The following tables summarize our derivative contracts entered into subsequent to June 30, 2017:

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
Oil Collars:
2017:
WTI (1)
Volume (Bbls)		—		—		182,000		368,000		550,000
Wtd Avg Price - Floor	$	—	$	—	$	41.49	$	41.75	$	41.67
Wtd Avg Price - Ceiling	$	—	$	—	$	53.89	$	54.34	$	54.19
2018:
WTI (1)
Volume (Bbls)		360,000		364,000		368,000		—		1,092,000
Wtd Avg Price - Floor	$	41.75	$	41.75	$	41.75	$	—	$	41.75
Wtd Avg Price - Ceiling	$	54.34	$	54.34	$	54.34	$	—	$	54.34

(1) The index price for these collars is WTI, which refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange.

13

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
Gas Collars:
2017:
PEPL (1)
Volume (MMBtu)		—		—		910,000		1,840,000		2,750,000
Wtd Avg Price - Floor	$	—	$	—	$	2.47	$	2.45	$	2.46
Wtd Avg Price - Ceiling	$	—	$	—	$	2.66	$	2.65	$	2.65
Perm EP (2)
Volume (MMBtu)		—		—		910,000		1,840,000		2,750,000
Wtd Avg Price - Floor	$	—	$	—	$	2.37	$	2.35	$	2.36
Wtd Avg Price - Ceiling	$	—	$	—	$	2.57	$	2.55	$	2.56
2018:
PEPL (1)
Volume (MMBtu)		1,800,000		1,820,000		1,840,000		—		5,460,000
Wtd Avg Price - Floor	$	2.45	$	2.45	$	2.45	$	—	$	2.45
Wtd Avg Price - Ceiling	$	2.65	$	2.65	$	2.65	$	—	$	2.65
Perm EP (2)
Volume (MMBtu)		1,800,000		1,820,000		1,840,000		—		5,460,000
Wtd Avg Price - Floor	$	2.35	$	2.35	$	2.35	$	—	$	2.35
Wtd Avg Price - Ceiling	$	2.55	$	2.55	$	2.55	$	—	$	2.55

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

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

Under a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor price.  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.

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 and, therefore, we do not apply hedge accounting treatment to our derivative instruments.  Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments.  Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows.  The following table presents the components of (Gain) loss on derivative instruments, net for the periods indicated.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Gain) Loss on Derivative Instruments, Net (in thousands):	2017		2016		2017		2016
Change in fair value of derivative instruments, net	$	(22,166)	$	37,095	$	(72,087)	$	41,735
Cash (receipts) payments on derivative instruments, net		(343)		(3,859)		5,717		(8,927)
(Gain) loss on derivative instruments, net	$	(22,509)	$	33,236	$	(66,370)	$	32,808

14

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

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

The following tables present the amounts and classifications of our derivative assets and liabilities as of June 30, 2017 and December 31, 2016, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.

June 30, 2017:
(in thousands)	Balance Sheet Location	Asset		Liability
Oil contracts	Current assets — Derivative instruments	$	14,756	$	—
Gas contracts	Current assets — Derivative instruments		5,047		—
Oil contracts	Non-current assets — Derivative instruments		442		—
Gas contracts	Current liabilities — Derivative instruments		—		98
Total gross amounts presented in the balance sheet			20,245		98
Less: gross amounts not offset in the balance sheet			(98)		(98)
Net amount:		$	20,147	$	—
December 31, 2016:
(in thousands)	Balance Sheet Location	Asset		Liability
Oil contracts	Current liabilities — Derivative instruments	$	—	$	27,892
Gas contracts	Current liabilities — Derivative instruments		—		21,478
Oil contracts	Non-current liabilities — Derivative instruments		—		1,059
Gas contracts	Non-current liabilities — Derivative instruments		—		1,511
Total gross amounts presented in the balance sheet			—		51,940
Less: gross amounts not offset in the balance sheet			—		—
Net amount:		$	—	$	51,940

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.

15

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

The following table provides fair value measurement information for certain assets and liabilities as of June 30, 2017 and December 31, 2016:

	June 30, 2017				December 31, 2016
	Book		Fair		Book		Fair
(in thousands)	Value		Value		Value		Value
Financial Assets (Liabilities):
5.875% Notes due 2022	$	—	$	—	$	(750,000)	$	(782,835)
4.375% Notes due 2024	$	(750,000)	$	(787,748)	$	(750,000)	$	(779,453)
3.90% Notes due 2027	$	(750,000)	$	(754,335)	$	—	$	—
Derivative instruments — assets	$	20,245	$	20,245	$	—	$	—
Derivative instruments — liabilities	$	(98)	$	(98)	$	(51,940)	$	(51,940)

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, 2017 are: (i) accrued operating expenses of approximately $55.2 million; (ii) liabilities of approximately $39.5 million representing the amount by which checks issued, but not yet presented to our banks, exceeded balances in applicable bank accounts prior to being funded from other bank accounts; and (iii) accrued general and administrative, primarily payroll-related, costs of approximately $28.7 million.  Included in “Accrued liabilities — other” at December 31, 2016 are: (i) accrued operating expenses of approximately $53.9 million; (ii) accrued general and administrative, primarily payroll-related, costs of approximately $43.5 million, and (iii) liabilities of approximately $19.3 million representing the amount by which checks issued, but not yet presented to our banks, exceeded balances in applicable bank accounts prior to being funded from other bank accounts.

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry.  Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.

We 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, 2017 and December 31, 2016, the allowance for doubtful accounts was $1.8 million and $1.6 million, respectively.

16

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

5.CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock.  At June 30, 2017, there were 95.3 million shares of common stock and no shares of preferred stock outstanding. 

Dividends

In May 2017, our Board of Directors declared a cash dividend of $0.08 per share.  The dividend is payable on September 1, 2017, to stockholders of record on August 15, 2017.  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 $15.2 million in dividends declared year-to-date June 30, 2017 were recorded as a reduction of additional paid-in capital.  Nonforfeitable dividends paid on stock awards that 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, financing 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				Six Months Ended
	June 30,				June 30,
(in thousands)	2017		2016		2017		2016
Restricted stock awards
Performance stock awards	$	6,438	$	7,215	$	12,840	$	12,909
Service-based stock awards		4,208		4,751		9,132		8,916
		10,646		11,966		21,972		21,825
Stock option awards		579		748		1,245		1,403
Total stock compensation cost		11,225		12,714		23,217		23,228
Less amounts capitalized to oil and gas properties		(4,932)		(5,224)		(10,636)		(10,210)
Compensation expense	$	6,293	$	7,490	$	12,581	$	13,018

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 2017 periods presented above as compared to 2016 periods presented above is primarily due to awards vesting prior to the 2017 periods and retirements that occurred during the second quarter of 2016 that involved the accelerated vesting of awards during that period, both of which were partially offset by awards granted either during or subsequent to the 2016 periods. 

We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017.  ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, accounting for forfeitures, and classification on the statement of cash flows.  Pursuant to ASU 2016-09, we made an accounting policy election to account for forfeitures in compensation cost when they occur, rather than including an estimate of the number of awards that are expected to vest in our compensation cost.  The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a modified retrospective method.  In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by $33.1 million, reduced beginning accumulated deficit by $28.7 million, and increased beginning additional paid-in capital by $4.4 million.  The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method.  In accordance with this method, we adjusted the statement of cash flows for the six months ended June 30, 2016 by increasing net cash provided by operating activities by $4.1 million and

17

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

increasing net cash used by financing activities by $4.1 million for the payment of tax withholdings on the net settlement of equity-classified awards.  There were no cash flows related to excess tax benefits during the six months ended June 30, 2017 and 2016.

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, 2017:

(in thousands)
Asset retirement obligation at January 1, 2017	$	154,523
Liabilities incurred		4,104
Liability settlements and disposals		(7,550)
Accretion expense		3,749
Revisions of estimated liabilities		1,763
Asset retirement obligation at June 30, 2017		156,589
Less current obligation		(9,226)
Long-term asset retirement obligation	$	147,363

18

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

8.EARNINGS (LOSS) PER SHARE

The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands, except per share data)	2017		2016		2017		2016
Basic:
Net income (loss)	$	97,262	$	(214,454)	$	228,234	$	(445,913)
Participating securities’ share in earnings (1)		(1,643)		—		(3,898)		—
Net income (loss) available to common stockholders	$	95,619	$	(214,454)	$	224,336	$	(445,913)
Diluted:
Net income (loss)	$	97,262	$	(214,454)	$	228,234	$	(445,913)
Participating securities’ share in earnings (1)		(1,642)		—		(3,897)		—
Net income (loss) available to common stockholders	$	95,620	$	(214,454)	$	224,337	$	(445,913)
Shares:
Basic shares outstanding		93,402		93,075		93,396		93,075
Dilutive effect of potential common shares (2)		33		—		35		—
Fully diluted common stock		93,435		93,075		93,431		93,075
Earnings (loss) per share to common stockholders (3):
Basic	$	1.02	$	(2.31)	$	2.40	$	(4.79)
Diluted	$	1.02	$	(2.31)	$	2.40	$	(4.79)

(1) Participating securities are not included in undistributed earnings when a loss exists.

(2) Inclusion of certain shares would have an anti-dilutive effect; therefore, 300.5 thousand and 255.0 thousand shares were excluded from the calculations for the three and six months ended June 30, 2017 and 2.3 million and 2.3 million shares were excluded from the calculations for the three and six months ended June 30, 2016.

(3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented.

19

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

9.INCOME TAXES

The components of our provision for income taxes are as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Income Tax Expense (Benefit) (in thousands):	2017			2016			2017			2016
Current tax benefit	$	—		$	—		$	(6)		$	—
Deferred tax expense (benefit)		58,617			(122,361)			136,929			(254,424)
	$	58,617		$	(122,361)		$	136,923		$	(254,424)
Combined federal and state effective income tax rate		37.6	%		36.3	%		37.5	%		36.3	%

At December 31, 2016, we had a U.S. net tax operating loss carryforward of approximately $1,182.4 million, which will expire in tax years 2031 through 2036.  We believe that the carryforward will be utilized before it expires.  We also had an alternative minimum tax credit carryforward of approximately $6.0 million.

At June 30, 2017, 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 2013 through 2015 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 2012 through 2015.

Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 35% primarily due to state income taxes and non-deductible expenses.

10.COMMITMENTS AND CONTINGENCIES

Commitments

At June 30, 2017, we had estimated commitments of approximately: (i) $159.6 million to finish drilling and completing wells and various other infrastructure projects in progress and (ii) $13.7 million to finish gathering system construction in progress. 

At June 30, 2017, we had firm sales contracts to deliver approximately 181.3 Bcf of natural gas over the next 7.6years.  If we do not deliver this gas, our estimated financial commitment, calculated using the July 2017 index price, would be approximately $451.9 million.  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 obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next nine years.  If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2017, would be approximately $322.3 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 obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines.  If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2017, would be approximately $13.5 million.  Of this total, we have accrued a liability of $1.9 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points. 

As of June 30, 2017, we have various firm transportation agreements for pipeline capacity with end dates ranging from 2017 - 2025 under which we will have to pay an estimated $40.0 million over the remaining terms of the agreements.

20

CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

June 30, 2017

(Unaudited)

We have various future commitments for office space under operating lease arrangements totaling approximately $92.0 million at June 30, 2017.

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 DISCLOSURE OF CASH FLOW INFORMATION

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2017		2016		2017		2016
Cash paid during the period for:
Interest expense (net of capitalized amounts of $11,659, $9,917, $11,962, and $10,057, respectively)	$	28,115	$	29,223	$	28,772	$	29,677
Income taxes	$	1	$	2	$	3	$	13
Cash received for income tax refunds	$	—	$	—	$	21	$	25

21

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 region.  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.  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 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 fluctuations in commodity prices.

Market Conditions

The oil and gas industry is cyclical and commodity prices can be volatile.  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. 

Oil prices have improved from early 2016; however, they continue to be unstable due to growing U.S. supply, large inventory balances, and concern over demand.  Further, local market prices for oil and gas can be impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials.  The Permian Basin and Mid-Continent region natural gas production growth has resulted in higher differentials and 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 natural gas production.  See Revenues below for further information regarding our realized commodity prices.

The U.S. oil and gas industry continues to confront weak commodity prices, which has had adverse effects on our business and financial position.  Our ability to access capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions.  Further, oversupply and high oil and natural gas inventory storage levels could put downward pressure on commodity prices and have an adverse impact on our business partners, customers and lenders, potentially causing them to fail to meet their obligations to us.

See “Risk Factors” in Item 1A of our Annual Report on Form 10-K/A for the year ended December 31, 2016, for a discussion of risk factors that affect our business, financial condition, and results of operations.  Also see CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in this report for important information about these types of statements.

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Summary of Operating and Financial Results for the Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016:

· Production increased 14% to 1,110.0 MMcfe per day.

· Oil volumes increased 22% to 55,042 barrels per day, gas volumes increased 7% to 502.0 MMcf per day, and NGL volumes increased 18% to 46,281 barrels per day.

· Production revenues rose 68% to $882.3 million.

· Cash flow provided by operating activities increased 132% to $504.8 million.

· Net income was $228.2 million, or $2.40 per diluted share, for the first six months of 2017, as compared to a net loss of $445.9 million, or $(4.79) per diluted share, for the first six months of 2016.

· In response to improved commodity prices, we increased our exploration and development expenditures to $491.0 million for the first six months of 2017, as compared to $285.7 million for the first six months of 2016.

· Total debt at both June 30, 2017 and 2016 consisted of $1.5 billion of senior notes.  During the second quarter 2017, we repaid our $750 million notes due 2022 and issued $750 million notes due 2027.  Our other $750 million notes are due 2024.   

RESULTS OF OPERATIONS

Three and Six Months Ended June 30, 2017 vs. Three and Six Months Ended June 30, 2016

Revenues

Almost all our revenues are derived from sales of our oil, natural gas, and NGL production.  Increases or decreases in our revenue, 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, and geopolitical and economic factors.

Both commodity prices and production volumes have increased during the three and six months ended June 30, 2017 as compared to the three and six months ended June 30, 2016, contributing to the increase in revenue seen in the 2017 periods.  The following tables show our production revenues for the periods as well as the change in revenues due to changes in volumes and prices.  

	Three Months Ended				Change
Production Revenue	June 30,				Between		Price/Volume Change
(in thousands)	2017		2016		2017 / 2016		Price		Volume		Total
Oil sales	$	232,453	$	162,005	43	%	$	21,433	$	49,015	$	70,448
Gas sales		132,474		76,615	73	%		47,021		8,838		55,859
NGL sales		80,886		51,939	56	%		19,111		9,836		28,947
	$	445,813	$	290,559	53	%	$	87,565	$	67,689	$	155,254
		Six Months Ended			Change
Production Revenue		June 30,			Between		Price/Volume Change
(in thousands)	2017		2016		2017 / 2016		Price		Volume		Total
Oil sales	$	456,519	$	279,578	63	%	$	118,360	$	58,581	$	176,941
Gas sales		264,419		159,223	66	%		94,506		10,690		105,196
NGL sales		161,312		85,291	89	%		60,985		15,036		76,021
	$	882,250	$	524,092	68	%	$	273,851	$	84,307	$	358,158

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For the three and six months ended June 30, 2017, oil sales, gas sales, and NGL sales accounted for 52%, 30%, and 18% of our total production revenue, respectively.  For the three and six months ended June 30, 2017, a ±$1.00 per barrel change in our realized oil price would have resulted in a ±$5.3 million and ±$10.0 million change in revenues, respectively.  For the three and six months ended June 30, 2017, a ±$0.10 per Mcf change in our realized gas price would have resulted in a ±$4.7 million and ±$9.1 million change in revenues, respectively.  For the three and six months ended June 30, 2017, a ±$1.00 per barrel change in our realized NGL price would have resulted in a ±$4.4 million and ±$8.4 million change in revenues, respectively. 

The table below presents our regional production volumes.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2017	2016	2017	2016
Oil (Bbls per day)
Permian Basin	45,828	35,338	43,446	35,944
Mid-Continent	11,893	8,933	11,475	9,093
Other	150	153	121	230
	57,871	44,424	55,042	45,267
Gas (MMcf per day)
Permian Basin	219.8	181.2	210.4	177.4
Mid-Continent	295.4	279.1	290.2	288.7
Other	1.5	1.6	1.4	1.3
	516.7	461.9	502.0	467.4
NGL (Bbls per day)
Permian Basin	24,996	19,219	23,319	16,639
Mid-Continent	23,693	21,716	22,926	22,432
Other	42	26	36	41
	48,731	40,961	46,281	39,112
Total (MMcfe per day)
Permian Basin	644.7	508.5	611.0	492.9
Mid-Continent	509.0	463.0	496.6	477.9
Other	2.6	2.7	2.4	2.9
	1,156.3	974.2	1,110.0	973.7

During the three and six months ended June 30, 2017, approximately 55% of our total production was in the Permian Basin.  This has increased from the three and six months ended June 30, 2016, when approximately 51% of our total production was in the Permian Basin.  The increase is due to increased drilling and completion activity.  During each of the periods presented, approximately 79% of our oil production was in the Permian Basin. 

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The table below presents our production volumes by commodity, 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.  Our realized prices do not include settlements of commodity derivative contracts.

	Three Months Ended						Change		Six Months Ended						Change
	June 30,						Between		June 30,						Between
	2017			2016			2017 / 2016		2017			2016			2017 / 2016
Oil
Total volume — MBbls		5,266			4,043		30	%		9,963			8,239		21	%
Total volume — barrels per day		57,871			44,424		30	%		55,042			45,267		22	%
Percentage of total production		30	%		28	%				30	%		28	%
Average realized price — per barrel	$	44.14		$	40.07		10	%	$	45.82		$	33.94		35	%
Average WTI Midland price — per barrel	$	47.44		$	45.42		4	%	$	50.00		$	39.83		26	%
Average WTI Cushing price — per barrel	$	48.29		$	45.59		6	%	$	50.10		$	39.52		27	%
Gas
Total volume — MMcf		47,021			42,034		12	%		90,871			85,068		7	%
Total volume — MMcf per day		516.7			461.9		12	%		502.0			467.4		7	%
Percentage of total production		45	%		47	%				45	%		48	%
Average realized price — per Mcf	$	2.82		$	1.82		55	%	$	2.91		$	1.87		56	%
Average Henry Hub price — per Mcf	$	3.19		$	1.95		64	%	$	3.25		$	2.02		61	%
NGL
Total volume — MBbls		4,434			3,727		19	%		8,377			7,118		18	%
Total volume — barrels per day		48,731			40,961		19	%		46,281			39,112		18	%
Percentage of total production		25	%		25	%				25	%		24	%
Average realized price — per barrel	$	18.24		$	13.93		31	%	$	19.26		$	11.98		61	%
Total
Total production — MMcfe		105,225			88,654		19	%		200,907			177,210		13	%
Total production — MMcfe per day		1,156.3			974.2		19	%		1,110.0			973.7		14	%

Other revenues

We transport, process, and market some third-party gas that is associated with our equity gas.  We market and sell natural gas for other working interest owners under short-term sales and supply 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 (revenues less purchases) for marketing third-party gas. 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
Gas Gathering and Marketing(in thousands):
Gas gathering and other revenues	$	10,735	$	8,211	$	21,360	$	15,452
Gas marketing revenues, net of related costs	$	(96)	$	103	$	18	$	(71)

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.

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Operating Costs and Expenses

Costs associated with producing oil and natural gas are substantial.  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, 2017 were lower by 58% compared to the three months ended June 30, 2016.  The primary reasons for the decrease are: (i) the $333.3 million ($211.8 million, net of tax) ceiling test impairment recorded in the 2016 period and (ii) increased net gains on derivative instruments in 2017, partially offset by (iii) increased transportation, processing, and other operating costs in 2017. 

	Three Months Ended				Variance
	June 30,				Between		Per Mcfe
	2017		2016		2017 / 2016		2017		2016
Operating Costs and Expenses (in thousands, except per Mcfe):
Impairment of oil and gas properties	$	—	$	333,291	$	(333,291)		N/A		N/A
Depreciation, depletion, and amortization		107,884		102,086		5,798	$	1.03	$	1.15
Asset retirement obligation		960		1,750		(790)	$	0.01	$	0.02
Production		62,578		57,213		5,365	$	0.59	$	0.65
Transportation, processing, and other operating		58,624		44,436		14,188	$	0.56	$	0.50
Gas gathering and other		8,647		7,492		1,155	$	0.08	$	0.09
Taxes other than income		17,477		14,066		3,411	$	0.17	$	0.16
General and administrative		19,762		21,424		(1,662)	$	0.19	$	0.24
Stock compensation		6,293		7,490		(1,197)	$	0.06	$	0.08
(Gain) loss on derivative instruments, net		(22,509)		33,236		(55,745)		N/A		N/A
Other operating expense, net		266		24		242		N/A		N/A
	$	259,982	$	622,508	$	(362,526)

Total operating costs and expenses for the six months ended June 30, 2017 were lower by 60% compared to the six months ended June 30, 2016.  The primary reasons for the decrease are: (i) the $652.1 million ($414.3 million, net of tax) ceiling test impairment recorded in the 2016 period and (ii) increased net gains on derivative instruments in 2017, partially offset by (iii) increased transportation, processing, and other operating costs in 2017.

	Six Months Ended				Variance
	June 30,				Between		Per Mcfe
	2017		2016		2017 / 2016		2017		2016
Operating Costs and Expenses (in thousands, except per Mcfe):
Impairment of oil and gas properties	$	—	$	652,077	$	(652,077)		N/A		N/A
Depreciation, depletion, and amortization		203,700		212,722		(9,022)	$	1.01	$	1.20
Asset retirement obligation		2,580		4,048		(1,468)	$	0.01	$	0.02
Production		124,999		127,915		(2,916)	$	0.62	$	0.72
Transportation, processing and other operating		113,647		90,879		22,768	$	0.57	$	0.51
Gas gathering and other		17,074		15,572		1,502	$	0.08	$	0.09
Taxes other than income		38,790		27,905		10,885	$	0.19	$	0.16
General and administrative		37,796		35,321		2,475	$	0.19	$	0.20
Stock compensation		12,581		13,018		(437)	$	0.06	$	0.07
(Gain) loss on derivative instruments, net		(66,370)		32,808		(99,178)		N/A		N/A
Other operating expense, net		882		114		768		N/A		N/A
	$	485,679	$	1,212,379	$	(726,700)

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Ceiling Test Impairment

We use the full cost method of accounting for our oil and gas operations.  Accounting rules require us to perform a quarterly ceiling test calculation to test our capitalized oil and gas property costs 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.  Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.

At June 30, 2017 and March 31, 2017, the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we have not recognized a ceiling test impairment during the six months ended June 30, 2017.  At June 30, 2016 and March 31, 2016, we recognized ceiling test impairments of $333.3 million ($211.8 million, net of tax) and $318.8 million ($202.6 million, net of tax), respectively, for a total impairment of $652.1 million ($414.3 million, net of tax) recognized during the six months ended June 30, 2016.  These impairments were primarily the result of decreases in the trailing twelve-month average prices for oil, natural gas, and NGLs utilized in determining the estimated future net cash flows from proved reserves.  The commodity prices used in the June 30, 2017 ceiling calculation, based on the required trailing twelve-month average prices, were $3.01 per Mcf of gas and $48.95 per barrel of oil.  A decline of approximately 19% or more in the value of the ceiling limitation would have resulted in an impairment at June 30, 2017.  Because the ceiling calculation uses trailing twelve-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation.  In addition, other factors that impact the ceiling limitation calculation include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, depletion expense, and all related tax effects.  Depending on fluctuations in these factors, including a decline in prices, we may incur full cost ceiling test impairments in future quarters. 

The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.  Any impairment of oil and gas properties is not reversible at a later date.

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.  Depletion is calculated quarterly before the ceiling test impairment calculation. 

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”) consists of the following:

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	Three Months Ended				Variance
	June 30,				Between		Per Mcfe
DD&A Expense(in thousands, except per Mcfe)	2017		2016		2017 / 2016		2017		2016
Depletion	$	95,735	$	90,577	$	5,158	$	0.91	$	1.02
Depreciation		12,149		11,509		640		0.12		0.13
	$	107,884	$	102,086	$	5,798	$	1.03	$	1.15
	Six Months Ended				Variance
	June 30,				Between		Per Mcfe
DD&A Expense(in thousands, except per Mcfe)	2017		2016		2017 / 2016		2017		2016
Depletion	$	180,746	$	189,484	$	(8,738)	$	0.90	$	1.07
Depreciation		22,954		23,238		(284)		0.11		0.13
	$	203,700	$	212,722	$	(9,022)	$	1.01	$	1.20

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 consists of lease operating expense and workover expense as follows:

	Three Months Ended				Variance
	June 30,				Between		Per Mcfe
Production Expense(in thousands, except per Mcfe)	2017		2016		2017 / 2016		2017		2016
Lease operating expense	$	55,812	$	46,952	$	8,860	$	0.53	$	0.53
Workover expense		6,766		10,261		(3,495)		0.06		0.12
	$	62,578	$	57,213	$	5,365	$	0.59	$	0.65
	Six Months Ended				Variance
	June 30,				Between		Per Mcfe
Production Expense(in thousands, except per Mcfe)	2017		2016		2017 / 2016		2017		2016
Lease operating expense	$	101,347	$	102,646	$	(1,299)	$	0.50	$	0.58
Workover expense		23,652		25,269		(1,617)		0.12		0.14
	$	124,999	$	127,915	$	(2,916)	$	0.62	$	0.72

Lease operating expense in the second quarter 2017 increased 19%, or $8.9 million, compared to the second quarter of 2016.  The increase was primarily caused by: (i) increased labor costs due to increased salaries, bonuses, and number of employees, (ii) increased saltwater disposal costs due to increased trucked water related to new and recompleted wells and various issues (e.g., capacity and power) at third-party disposal wells, and (iii) increased gas lift compression and fuel costs.  Higher lease operating expense in the second quarter 2017 combined with a 19% increase in production volumes during the quarter resulted in holding per unit lease operating expenses flat at $0.53 per Mcfe.  Lease operating expense for the six months ended June 30, 2017 decreased 1%, or $1.3 million, compared to the six months ended June 30, 2016.  In 2017, we have had less rental equipment expense including compressor rentals due to adding wells on central compression and, therefore, releasing rented wellhead compressors, downsizing some compressors, and converting some wells from gas lift compression to plunger lift.  We have also reduced the usage of roustabout crews in some areas, which has decreased maintenance and equipment costs.  These decreases in expense were mostly offset by increases in expense due to the same reasons discussed above for the quarterly period.  Lower lease operating expense in the first six months of 2017 combined with a 14% increase in production volumes during the period resulted in a decrease in per unit lease operating expenses to $0.50 per Mcfe in the 2017 period from $0.58 per Mcfe in the 2016 period. 

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Workover expense during the three and six months ended June 30, 2017 decreased 34%, or $3.5 million, and 6%, or $1.6 million, respectively, compared to the three and six months ended June 30, 2016.  During the 2017 periods, we had more workover projects underway than during the 2016 periods, which actually increased expense; however, these increases were offset by the receipt of partial insurance proceeds in the second quarter 2017 related to a flooding event in 2015 and subsequent remediation and repairs.  During the first four months of 2016, water was still being pumped out of the flooded area, which further increased the workover expense for the six months ended June 30, 2016.  Generally, workover costs will fluctuate based on the amount of maintenance and remedial activity planned and/or 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, together with gas processing costs and costs to transport production to a specified sales point.  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 three months ended June 30, 2017 were 32% or $14.2 million higher than transportation, processing, and other operating costs in the three months ended June 30, 2016.  Transportation, processing, and other operating costs in the six months ended June 30, 2017 were 25% or $22.8 million higher than transportation, processing, and other operating costs in the six months ended June 30, 2016.  The increases are due to increased production volumes, rates, and gas and NGL prices in the 2017 periods as compared to the 2016 periods.

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, 2017 was 15%, or $1.2 million, higher than gas gathering and other in the three months ended June 30, 2016.  Gas gathering and other in the six months ended June 30, 2017 was 10%, or $1.5 million, higher than gas gathering and other in the six months ended June 30, 2016.  The increases from 2016 are primarily due to increases in product costs due to increased gas and NGL prices. 

Taxes Other than Income

Taxes other than income consist of production (or severance) taxes, ad valorem taxes, and other taxes.  State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production and ad valorem taxes being based on the value of properties.  Production taxes make up the majority of this expense for us, with revenue-based production taxes being the largest component of these taxes.  Taxes other than income increased $3.4 million, or 24%, in the second quarter of 2017 as compared to the second quarter of 2016.  Taxes other than income increased $10.9 million, or 39%, in the six months ended June 30, 2017 as compared to the six months ended June 30, 2016.  These increases are due to the increase in revenue seen between the comparable periods.  Taxes other than income was 3.9% and 4.8% of production revenues for the three months ended June 30, 2017 and 2016, respectively, and was 4.4% and 5.3% of production revenues for the six months ended June 30, 2017 and 2016, respectively.  The decrease in the percentages in the 2017 periods as compared to the 2016 periods is due to refunds received for, and reduced tax rates approved on, certain of our Texas high cost gas wells in 2017. 

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General and Administrative

General and administrative (“G&A”) expenses consist primarily of salaries and related benefits, office rent, legal and consultant fees, systems costs, and other administrative costs incurred in our offices 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.  G&A costs were as follows:

	Three Months Ended				Variance		Six Months Ended				Variance
	June 30,				Between		June 30,				Between
General and Administrative Expense (in thousands):	2017		2016		2017 / 2016		2017		2016		2017 / 2016
Gross G&A	$	38,541	$	39,397	$	(856)	$	72,631	$	69,456	$	3,175
Less amounts capitalized to oil and gas properties		(18,779)		(17,973)		(806)		(34,835)		(34,135)		(700)
G&A expense	$	19,762	$	21,424	$	(1,662)	$	37,796	$	35,321	$	2,475

G&A expense for the second quarter of 2017 was 8%, or $1.7 million, lower than for the second quarter of 2016.  This decrease is primarily due to the severance paid out in the second quarter of 2016 associated with the voluntary Early Retirement Incentive Program that was offered to certain employees at that time.  This decrease was partially offset by increased bonus accruals and salaries in 2017.  G&A expense for the six months ended June 30, 2017 was 7%, or $2.5 million, higher than for the six months ended June 30, 2016.  This increase is primarily due to increased bonus accruals and various office-related expenses in 2017, partially offset by decreased severance.  The amount of expense capitalized varies and depends on whether the cost incurred can be directly identified with acquisition, exploration, and development activities.

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 expense as follows:

	Three Months Ended				Variance		Six Months Ended				Variance
	June 30,				Between		June 30,				Between
Stock Compensation Expense (in thousands):	2017		2016		2017 / 2016		2017		2016		2017 / 2016
Restricted stock awards
Performance stock awards	$	6,438	$	7,215	$	(777)	$	12,840	$	12,909	$	(69)
Service-based stock awards		4,208		4,751		(543)		9,132		8,916		216
		10,646		11,966		(1,320)		21,972		21,825		147
Stock option awards		579		748		(169)		1,245		1,403		(158)
Total stock compensation cost		11,225		12,714		(1,489)		23,217		23,228		(11)
Less amounts capitalized to oil and gas properties		(4,932)		(5,224)		292		(10,636)		(10,210)		(426)
Stock compensation expense	$	6,293	$	7,490	$	(1,197)	$	12,581	$	13,018	$	(437)

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 2017 periods presented above as compared to 2016 periods presented above is primarily due to awards vesting prior to the 2017 periods and retirements that occurred during the second quarter of 2016 that involved the accelerated vesting of awards during that period, both of which were partially offset by awards granted either during or subsequent to the 2016 periods. 

We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017.  ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, accounting for forfeitures, and classification on the statement of cash flows.  Pursuant to ASU 2016-09, we made an accounting

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policy election to account for forfeitures in compensation cost when they occur, rather than including an estimate of the number of awards that are expected to vest in our compensation cost.  The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a modified retrospective method.  In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by $33.1 million, reduced beginning accumulated deficit by $28.7 million, and increased beginning additional paid-in capital by $4.4 million.  The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method.  In accordance with this method, we adjusted the statement of cash flows for the six months ended June 30, 2016 by increasing net cash provided by operating activities by $4.1 million and increasing net cash used by financing activities by $4.1 million for the payment of tax withholdings on the net settlement of equity-classified awards.  There were no cash flows related to excess tax benefits during the six months ended June 30, 2017 and 2016.

(Gain) Loss on Derivative Instruments, Net

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Gain) Loss on Derivative Instruments, Net (in thousands):	2017		2016		2017		2016
Change in fair value of derivative instruments, net	$	(22,166)	$	37,095	$	(72,087)	$	41,735
Cash (receipts) payments on derivative instruments, net		(343)		(3,859)		5,717		(8,927)
(Gain) loss on derivative instruments, net	$	(22,509)	$	33,236	$	(66,370)	$	32,808

Other (Income) and Expense

	Three Months Ended				Variance		Six Months Ended				Variance
	June 30,				Between		June 30,				Between
Other Income and Expense (in thousands):	2017		2016		2017 / 2016		2017		2016		2017 / 2016
Interest expense	$	20,095	$	20,824	$	(729)	$	41,147	$	41,629	$	(482)
Capitalized interest		(5,442)		(5,633)		191		(12,083)		(10,537)		(1,546)
Loss on early extinguishment of debt		28,169		—		28,169		28,169		—		28,169
Other, net		(2,231)		(2,011)		(220)		(4,441)		(3,661)		(780)
	$	40,591	$	13,180	$	27,411	$	52,792	$	27,431	$	25,361

The majority of our interest expense relates to interest on our senior unsecured notes and amortization of the related debt issuance costs and discount.  See Long-term Debt below for further information regarding our debt.

We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing qualified assets.  Capitalized interest will fluctuate based on the rates applicable to borrowings outstanding during the period and the amount of costs on which interest is capitalized.  Despite there being higher capital costs upon which to capitalize interest in 2017 than in 2016, capitalized interest was lower in the second quarter 2017 than in the second quarter 2016 due to a lower interest rate.  This is because we replaced our 5.875% notes with 3.90% notes in the second quarter of 2017.  Capitalized interest was higher during the six months ended June 30, 2017 as compared to during the six months ended June 30, 2016 due to higher capital costs upon which to capitalize interest, partially offset by a lower interest rate.  Our capital expenditures have increased during 2017 from the 2016 periods due to improved commodity prices.  See Capital Expenditures below for further information regarding our capital expenditures.

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The $28.2 million loss on early extinguishment of debt incurred during the three and six months ended June 30, 2017 was due to the completion of a tender offer and redemption of $750 million 5.875% senior notes during the second quarter.  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 of the 5.875% notes was 2022.

Components of Other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss related to the sale or value of oil and gas well equipment and supplies, gain or loss on miscellaneous asset sales, interest income, 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						Six Months Ended
	June 30,						June 30,
Income Tax Expense (Benefit) (in thousands):	2017			2016			2017			2016
Current tax benefit	$	—		$	—		$	(6)		$	—
Deferred tax expense (benefit)		58,617			(122,361)			136,929			(254,424)
	$	58,617		$	(122,361)		$	136,923		$	(254,424)
Combined federal and state effective income tax rate		37.6	%		36.3	%		37.5	%		36.3	%

Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 35% 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.

Our liquidity is highly dependent on prices we receive for the oil, natural 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 and analysis of the impact realized prices have had on our 2017 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 2017 exploration and development expenditures are projected to range from $1.1 – $1.2 billion.  Investments in gathering and processing infrastructure and other fixed assets are expected to approximate an additional $60 million for the year.  See Capital Expenditures below for information regarding our exploration and development (“E&D”) activities for the three and six months ended June 30, 2017 and 2016.

We periodically use derivative instruments to mitigate volatility in commodity prices.  At June 30, 2017, we had derivative contracts covering a portion of our 2017 and 2018 production.  Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may hedge up to 50% of our oil and natural gas production on a forward five-quarter basis.  See Note 3 to the Condensed Consolidated Financial Statements for information regarding our derivative instruments.

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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, 2017 were $519.6 million.  At June 30, 2017, 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.  During the second quarter of 2017, we completed a tender offer and redemption of $750 million 5.875% notes due 2022 and issued the aforementioned 3.90% notes.  At June 30, 2017, 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, 2017 was 39%, down from 42% at December 31, 2016.  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.  At June 30, 2017, the ratio calculation is $1.5 billion ÷ ($1.5 billion + $2.31 billion).  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 in 2017 and beyond.

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)	2017		2016
Net cash provided by operating activities	$	504,800	$	217,786
Net cash used by investing activities	$	(590,824)	$	(329,978)
Net cash used by financing activities	$	(47,257)	$	(25,451)

Net cash provided by operating activities for the first six months of 2017 was $504.8 million, up $287.0 million or 132% from $217.8 million for the first six months of 2016.  The $287.0 million increase resulted primarily from a period-over-period increase in production revenue, which increased due to increased realized commodity prices and production volumes.  This increase was partially offset by net increases in certain operating costs and expenses, increased cash outflows for settlements of derivative instruments, and an increase in our investment in working capital.  See RESULTS OF OPERATIONS above for information regarding the changes in revenue and operating expenses.

Net cash used by investing activities for the first six months of 2017 was $590.8 million, up $260.8 million or 79% from $330.0 million for the first six months of 2016.  The majority of our cash flows used by investing activities are E&D expenditures.  In response to improved commodity prices, we have increased our 2017 capital spending over 2016 levels.

Net cash used by financing activities for the first six months of 2017 was $47.3 million, up $21.8 million or 86% from $25.5 million for the first six months of 2016.  Net cash used by financing activities for the first six months of 2017 includes $772.8 million used for the early extinguishment of the $750 million 5.875% senior notes due 2022, which included $22.6 million in tender and redemption premiums.  Additionally, the 2017 period includes $741.9 million proceeds, net of underwriters’ fees, discount, and issuance costs, that we received for the issuance of $750 million 3.90% senior notes due 2027.  The other primary components of net cash used by financing activities are the payment of dividends and the payment of income tax withholdings made on behalf of our employees upon the net settlement of employee stock awards.  During each of the first two quarters of 2017, we paid an $0.08 per share dividend, totaling $15.2 million in dividends paid during the six months ended June 30, 2017.  We paid a $0.16 per share dividend in the first quarter of 2016 and an $0.08 per share dividend in the second quarter of 2016, totaling $22.7 million in dividends paid during the six months ended June 30, 2016. 

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Adjusted Cash Flow from Operations

Adjusted cash flow from operations is a non-GAAP financial measure.  Management uses the non-GAAP financial measure of adjusted cash flow from operations as a means of measuring our ability to fund our capital program and dividends, without fluctuations caused by changes in current assets and liabilities, which are included in the GAAP measure of net cash provided by operating activities.  Management believes this non-GAAP financial measure provides useful information to investors for the same reason, and that it is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry.  The following table presents adjusted cash flow from operations and a reconciliation to the most directly comparable GAAP financial measure, net cash provided by operating activities. 

	Six Months Ended
	June 30,
(in thousands)	2017		2016
Net cash provided by operating activities	$	504,800	$	217,786
Change in operating assets and liabilities		39,827		10,669
Adjusted cash flow from operations	$	544,627	$	228,455

Capital Expenditures

The following table presents capitalized expenditures for oil and gas property acquisitions and exploration and development (“E&D”) activities, as well as sales proceeds for property sales.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2017		2016		2017		2016
Acquisitions:
Proved	$	250	$	—	$	250	$	3,324
Unproved		792		—		3,825		10,568
Net purchase price adjustments		5		34		10		(2,928)
		1,047		34		4,085		10,964
Exploration and development:
Land and seismic		33,302		17,474		110,487		28,636
Exploration and development		262,575		138,686		491,042		285,708
		295,877		156,160		601,529		314,344
Sales proceeds:
Proved		(2,000)		—		(2,000)		(12,500)
Unproved		(2,305)		(16)		(7,271)		(16)
Net purchase price adjustments		43		357		108		(114)
		(4,262)		341		(9,163)		(12,630)
	$	292,662	$	156,535	$	596,451	$	312,678

Amounts in the table above are presented on an accrual basis.  The Condensed Consolidated Statements of Cash Flows in this report reflect activities on a cash basis, when payments are made or received.

Our 2017 E&D capital investment is expected to approximate $1.1 - $1.2 billion.  Approximately 62% of our 2017 capital investment is projected to be in the Permian Basin with most of the remainder in the Mid-Continent region.

As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on increases or decreases in commodity prices, service costs, and drilling success.  We have the flexibility to adjust our capital expenditures based upon market conditions. 

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We intend to continue to fund our capital investment program with cash on hand and cash flow from our operating activities.  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 Debt—Bank Debt below for further information regarding our credit facility.

The following table reflects wells brought on production by region during the periods indicated.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2017	2016	2017	2016
Gross wells
Permian Basin	11	13	36	20
Mid-Continent	40	21	85	36
	51	34	121	56
Net wells
Permian Basin	10	9	26	12
Mid-Continent	8	5	18	7
	18	14	44	19

As of June 30, 2017, we had 98 gross (29 net) wells awaiting completion: 27 gross (13 net) in the Permian Basin and 71 gross (16 net) in the Mid-Continent region.  We also had 15 operated rigs running: nine in the Permian Basin and six 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. 

Long-term Debt

Long-term debt at June 30, 2017 and December 31, 2016, consisted of the following:

	June 30, 2017						December 31, 2016
			Unamortized Debt
			Issuance Costs		Long-term				Unamortized Debt		Long-term
(in thousands)	Principal		and Discount (1)		Debt, net		Principal		Issuance Costs		Debt, net
5.875% Senior Notes	$	—	$	—	$	—	$	750,000	$	(5,691)	$	744,309
4.375% Senior Notes		750,000		(5,872)		744,128		750,000		(6,370)		743,630
3.90% Senior Notes		750,000		(8,031)		741,969		—		—		—
Total long-term debt	$	1,500,000	$	(13,903)	$	1,486,097	$	1,500,000	$	(12,061)	$	1,487,939

(1) At June 30, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $6.2 million and $1.9 million, respectively.  The 4.375% notes were issued at par. 

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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 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, 2017, 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 1.125 – 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 – 1.0%, based on the credit rating for our senior unsecured long-term debt.  Unused borrowings are subject to a commitment fee of 0.125 – 0.35%, based on the credit rating for our senior unsecured long-term debt.

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%.  As of June 30, 2017, we were in compliance with all of the financial and non-financial covenants.

At June 30, 2017 and December 31, 2016, we had $3.9 million and $4.5 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

On April 10, 2017, we completed a cash tender offer to purchase any of our 5.875% notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5 million aggregate principal amount of the notes validly tendered.  We settled these tendered notes for $268.1 million, including accrued interest.  On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for $512.0 million, including accrued interest.  During the three months ended June 30, 2017, we recognized a loss on early extinguishment of debt related to these transactions of $28.2 million, 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 of the 5.875% notes was 2022. 

On April 10, 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes due May 15, 2027 at 99.748% of par to yield 3.93% per annum.  We have received $741.9 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs as of June 30, 2017.  The notes bear an interest rate of 3.90% and interest is payable semiannually on May 15 and November 15, with the first payment to be made November 15, 2017.  Along with cash on hand, we used the proceeds to fund the settlement of the tendered and redeemed 5.875% notes. 

Each of our senior unsecured notes is governed by an indenture containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of June 30, 2017.  The 4.375% notes are due in 2024.  Interest on each of the senior notes is payable semiannually.  The effective interest rate on the 4.375% notes and the 3.90% notes, including the amortization of debt issuance costs and discount, as applicable, is 4.50% and 4.01%, respectively.

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Working Capital Analysis

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

At June 30, 2017, we had working capital of $401.7 million, a decrease of $45.3 million or 10% compared to working capital of $447.0 million at December 31, 2016.

Working capital decreases consisted primarily of the following: 

· Cash and cash equivalents decreased by $133.3 million.

· Operations-related accounts payable and accrued liabilities increased by $40.4 million.

· Accrued liabilities related to our E&D expenditures increased by $12.7 million.

Decreases in working capital were partially offset by the following primary increases:

· Operations-related accounts receivable increased by $61.0 million.

· Current derivative instruments increased by $69.1 million to a net asset.

· Oil and gas well equipment and supplies increased by $12.1 million.

Cash on hand was used during the six months ended June 30, 2017, along with cash flow from operations, primarily to fund our capital expenditures.  Accounts receivable are a major component of our working capital and include 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 2017, an $0.08 per share dividend was declared, which is payable on September 1, 2017 to stockholders of record on August 15, 2017.  Future dividend payments will depend on our level of earnings, financing requirements, and other factors considered relevant by our Board of Directors.  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. 

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, 2017, our material off-balance sheet arrangements consisted of operating lease agreements, which are customary in the oil and gas industry and are included in the table below.

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Contractual Obligations and Material Commitments

At June 30, 2017, we had contractual obligations and material commitments as follows:

	Payments Due by Period
Contractual obligations:			1 Year or		2 - 3			4 - 5			More than
(in thousands)	Total		Less		Years			Years			5 Years
Long-term debt-principal (1)	$	1,500,000	$	—		—			—			1,500,000
Long-term debt-interest (1)		525,032		63,769		124,125			124,125			213,013
Operating leases		92,049		9,672		21,458			22,232			38,687
Unconditional purchase obligations (2)		42,570		9,791		10,630			8,785			13,364
Derivative liabilities		98		98
Asset retirement obligation (3)		156,589		9,226		—	(3)		—	(3)		—	(3)
Other long-term liabilities (4)		34,501		1,528		2,992			2,040			27,941
	$	2,350,839	$	94,084	$	159,205		$	157,182		$	1,793,005

(1) The interest payments presented above include the accrued interest payable on our long-term debt as of June 30, 2017 as well as future payments calculated using the long-term debt’s fixed rates and principal amounts outstanding as of June 30, 2017.  See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.

(2) Of the total Unconditional purchase obligations, $40.0 million represents obligations for firm transportation agreements for pipeline capacity. 

(3) 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. 

(4) Other long-term liabilities, which are included in the Other liabilities line item on the Condensed Consolidated Balance Sheet, include contractual obligations associated with our employee supplemental savings plan, gas balancing liabilities, and other miscellaneous liabilities.

The following discusses various commercial commitments that we have, which include potential future cash payments if we fail to meet various performance obligations.  These are not reflected in the table above. 

At June 30, 2017, we had estimated commitments of approximately: (i) $159.6 million to finish drilling and completing wells and various other infrastructure projects in progress and (ii) $13.7 million to finish gathering system construction in progress. 

At June 30, 2017, we had firm sales contracts to deliver approximately 181.3 Bcf of natural gas over the next 7.6 years.  If we do not deliver this gas, our estimated financial commitment, calculated using the July 2017 index price, would be approximately $451.9 million.  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 obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next nine years.  If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2017, would be approximately $322.3 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 obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines.  If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2017, would be approximately $13.5 million.  Of this total, we have accrued a liability of $1.9 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.

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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 related to oil and gas reserves, full cost accounting, goodwill, contingencies, asset retirement obligations, and income taxes to be critical 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/A for the year ended December 31, 2016.

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 and six months ended June 30, 2017, oil sales, gas sales, and NGL sales accounted for 52%, 30%, and 18% of our total production revenue, respectively.  For the three and six months ended June 30, 2017, a ±$1.00 per barrel change in our realized oil price would have resulted in a ±$5.3 million and ±$10.0 million change in revenues, respectively.  For the three and six months ended June 30, 2017, a ±$0.10 per Mcf change in our realized gas price would have resulted in a ±$4.7 million and ±$9.1 million change in revenues, respectively.  For the three and six months ended June 30, 2017, a ±$1.00 per barrel change in our realized NGL price would have resulted in a ±$4.4 million and ±$8.4 million change in revenues, respectively.

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, 2017, we had oil and gas collars covering a portion of our 2017 and 2018 production, which were recorded as current and non-current assets and current liabilities.  At June 30, 2017, our oil and gas collars had a gross asset fair value of $20.2 million and a gross liability fair value of $0.1 million.  See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.

While these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.  For our oil collars outstanding at June 30, 2017, a hypothetical $1.00 decrease in the forward prices used to calculate the fair value as of June 30, 2017 would result in an increase of approximately $3.3 million to the net asset fair value of the derivatives and a hypothetical $1.00 increase in the forward prices used to calculate the fair value as of June 30, 2017 would result in a decrease of approximately $3.2 million to the net asset fair value of the derivatives.  For our gas collars outstanding as of June 30, 2017, a hypothetical $0.10 decrease in the forward prices used to calculate the fair value as of June 30, 2017 would result in an increase of approximately $3.0 million to the net asset fair value of the derivatives and a hypothetical $0.10 increase in the forward prices used to calculate the fair value as of June 30, 2017 would result in a decrease of approximately $2.9 million to the net asset fair value of the derivatives.

Interest Rate Risk

At June 30, 2017, our long-term debt consisted of $750 million in 4.375% senior unsecured notes that will mature on June 1, 2024 and $750 million in 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. 

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ITEM 4.  CONTROLS AND PROCEDURES 

Evaluation of Disclosure Controls and Procedures

Cimarex management, under the supervision and with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of June 30, 2017.  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 with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  The disclosure controls and procedures are designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow such persons to make 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, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting, except that we completed execution of our remediation plan and successfully remediated a material weakness in internal control surrounding the full cost ceiling test calculation previously reported in the company’s 2016 Annual Report on Form 10-K/A and our March 31, 2017 Quarterly Report on Form 10-Q.  

In response to the identified material weakness, the company developed a plan with oversight from the Audit Committee of the Board of Directors to remediate the material weakness.  Our remediation plan, which was implemented during the second quarter and applied in the financial reporting for the quarters ended March 31, 2017 and June 30, 2017, included the following:

· Enhancement of the control over the preparation and review of the full cost ceiling test calculation to include examining SEC SAB Topic 12 to reinforce the understanding of the requirements associated with appropriately performing this calculation, particularly as it relates to the income tax effects in the calculation;

· Refinement of the spreadsheet template used to prepare the full cost ceiling test calculation to ensure that the appropriate application of accounting for all components of the full cost ceiling test calculation is embedded within the template; and

· Revision and communication of the accounting controls, policies, and procedures relating to identifying and assessing changes that could potentially impact the system of internal control governing the full cost ceiling test calculation.

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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/A for the year ended December 31, 2016.  There have been no material changes in our risk factors from those described in the Annual Report on Form 10-K/A for the year ended December 31, 2016.  The risks described in the Annual Report on Form 10-K/A for the year ended December 31, 2016 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.

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ITEM 6.   EXHIBITS

4.1	Indenture dated as of April 10, 2017, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on April 10, 2017 and incorporated herein by reference).
4.2	First Supplemental Indenture dated as of April 10, 2017, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 10, 2017 and incorporated herein by reference).
4.3	Form of 3.90% Senior Notes due 2027 (included in Exhibit 4.2).
10.1	Form of Notice of Grant of Restricted Stock (Director) and Award Agreement
31.1	Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
32.2	Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

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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 9, 2017
	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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