XEC Cimarex Energy Co

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)

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

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PART I

ITEM 1. - Financial Statements

CIMAREX ENERGY CO.

Condensed Consolidated Balance Sheets

(Unaudited)

		September 30,				December 31,
		2017				2016
		(in thousands, except share data)
Assets
Current assets:
Cash and cash equivalents		$	422,808			$	652,876
Accounts receivable, net of allowance:
Trade		101,927				42,287
Oil and gas sales		286,602				217,395
Gas gathering, processing, and marketing		14,656				14,888
Oil and gas well equipment and supplies		54,545				33,342
Derivative instruments		6,924				—
Prepaid expenses		3,913				7,335
Other current assets		2,757				1,181
Total current assets		894,132				969,304
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties		17,071,532				16,225,495
Unproved properties and properties under development, not being amortized		572,651				478,277
		17,644,183				16,703,772
Less—accumulated depreciation, depletion, amortization, and impairment		(14,629,884		)		(14,349,505		)
Net oil and gas properties		3,014,299				2,354,267
Fixed assets, net of accumulated depreciation of $278,991 and $246,901, respectively		208,320				205,465
Goodwill		620,232				620,232
Derivative instruments		129				—
Deferred income taxes		—				55,835
Other assets		31,942				32,621
		$	4,769,054			$	4,237,724
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade		$	61,634			$	49,163
Gas gathering, processing, and marketing		27,254				25,323
Accrued liabilities:
Exploration and development		105,663				82,320
Taxes other than income		22,651				18,766
Other		215,067				177,695
Derivative instruments		5,778				49,370
Revenue payable		154,578				119,715
Total current liabilities		592,625				522,352
Long-term debt:
Principal		1,500,000				1,500,000
Less—unamortized debt issuance costs and discount		(13,491		)		(12,061		)
Long-term debt, net		1,486,509				1,487,939
Deferred income taxes		99,695				—
Asset retirement obligation		144,635				140,770
Derivative instruments		212				2,570
Other liabilities		43,315				41,104
Total liabilities		2,366,991				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, 95,260,701 and 95,123,525 shares issued, respectively		953				951
Additional paid-in capital		2,773,260				2,763,452
Retained earnings (accumulated deficit)		(373,955		)		(722,359		)
Accumulated other comprehensive income		1,805				945
Total stockholders’ equity		2,402,063				2,042,989
		$	4,769,054			$	4,237,724

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

		Three Months Ended September 30,								Nine Months Ended September 30,
		2017				2016				2017				2016
		(in thousands, except per share data)
Revenues:
Oil sales		$	231,441			$	166,079			$	687,960			$	445,657
Gas sales		125,707				109,278				390,126				268,501
NGL sales		95,191				50,464				256,503				135,755
Gas gathering and other		11,056				9,824				32,416				25,276
Gas marketing, net of related costs of $41,978, $32,266, $120,715, and $84,013, respectively		286				72				304				1
		463,681				335,717				1,367,309				875,190
Costs and expenses:
Impairment of oil and gas properties		—				105,593				—				757,670
Depreciation, depletion, and amortization		111,396				90,277				315,096				302,999
Asset retirement obligation		1,497				2,033				4,077				6,081
Production		65,410				52,976				190,409				180,891
Transportation, processing, and other operating		58,387				48,706				172,034				139,585
Gas gathering and other		8,856				7,905				25,930				23,477
Taxes other than income		24,314				15,974				63,104				43,879
General and administrative		21,039				20,118				58,835				55,439
Stock compensation		7,038				5,764				19,619				18,782
(Gain) loss on derivative instruments, net		16,109				(9,758		)		(50,261		)		23,050
Other operating expense, net		95				179				977				293
		314,141				339,767				799,820				1,552,146
Operating income (loss)		149,540				(4,050		)		567,489				(676,956		)
Other (income) and expense:
Interest expense		16,838				20,931				57,985				62,560
Capitalized interest		(5,373		)		(5,421		)		(17,456		)		(15,958		)
Loss on early extinguishment of debt		—				—				28,169				—
Other, net		(4,563		)		(3,828		)		(9,004		)		(7,489		)
Income (loss) before income tax		142,638				(15,732		)		507,795				(716,069		)
Income tax expense (benefit)		51,239				(5,059		)		188,162				(259,483		)
Net income (loss)		$	91,399			$	(10,673	)		$	319,633			$	(456,586	)
Earnings (loss) per share to common stockholders:
Basic		$	0.96			$	(0.12	)		$	3.36			$	(4.90	)
Diluted		$	0.96			$	(0.12	)		$	3.36			$	(4.90	)
Dividends declared per share		$	0.08			$	0.08			$	0.24			$	0.24
Comprehensive income (loss):
Net income (loss)		$	91,399			$	(10,673	)		$	319,633			$	(456,586	)
Other comprehensive income:
Change in fair value of investments, net of tax of $134, $165, $494, and $325, respectively		234				287				860				567
Total comprehensive income (loss)		$	91,633			$	(10,386	)		$	320,493			$	(456,019	)

 

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

		Nine Months Ended September 30,
		2017				2016
		(in thousands)
Cash flows from operating activities:
Net income (loss)		$	319,633			$	(456,586	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of oil and gas properties		—				757,670
Depreciation, depletion, and amortization		315,096				302,999
Asset retirement obligation		4,077				6,081
Deferred income taxes		188,168				(258,368		)
Stock compensation		19,619				18,782
(Gain) loss on derivative instruments, net		(50,261		)		23,050
Settlements on derivative instruments		(2,742		)		9,718
Loss on early extinguishment of debt		28,169				—
Changes in non-current assets and liabilities		2,144				4,121
Other, net		4,630				2,931
Changes in operating assets and liabilities:
Receivables		(128,921		)		(1,723		)
Other current assets		(19,372		)		23,034
Accounts payable and other current liabilities		75,565				9,079
Net cash provided by operating activities		755,805				440,788
Cash flows from investing activities:
Oil and gas capital expenditures		(901,949		)		(485,114		)
Sales of oil and gas assets		8,136				19,013
Sales of other assets		510				5,718
Other capital expenditures		(31,332		)		(24,013		)
Net cash used by investing activities		(924,635		)		(484,396		)
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		(29,194		)		(1		)
Dividends paid		(22,743		)		(30,243		)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards		(7,637		)		(11,457		)
Proceeds from exercise of stock options		226				4,623
Net cash used by financing activities		(61,238		)		(37,078		)
Net decrease in cash and cash equivalents		(230,068		)		(80,686		)
Cash and cash equivalents at beginning of period		652,876				779,382
Cash and cash equivalents at end of period		$	422,808			$	698,696

  

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statement of Stockholders’ Equity

(Unaudited)

 

									Additional Paid-in Capital				Retained Earnings (Accumulated Deficit)				Accumulated Other Comprehensive Income				Total Stockholders’ Equity
		Common Stock
		Shares			Amount
		(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		—			—				10				32				—				42
Dividends in excess of retained earnings		—			—				(22,854		)		—				—				(22,854		)
Net income		—			—				—				319,633				—			319,633
Unrealized change in fair value of investments, net of tax		—			—				—				—				860				860
Issuance of restricted stock awards		250			3				(3		)		—				—				—
Common stock reacquired and retired		(78	)		(1		)		(7,636		)		—				—				(7,637		)
Restricted stock forfeited and retired		(39	)		—				—				—				—				—
Exercise of stock options		4			—				226				—				—				226
Stock-based compensation		—			—				35,698				—				—				35,698
Cumulative effect adjustment of adopting ASU 2016-09 (Note 6)		—			—				4,393				28,739				—				33,132
Other		—			—				(26		)		—				—				(26		)
Balance, September 30, 2017		95,261			$	953			$	2,773,260			$	(373,955	)		$	1,805			$	2,402,063

See accompanying Notes to Condensed Consolidated Financial Statements.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 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.  We have not recorded an impairment to our oil and gas well equipment and supplies during the nine months ended September 30, 2017 .  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 each quarter-end date during the nine months ended September 30, 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 nine months ended September 30, 2017 . During the three and nine months ended September 30, 2016 , we recognized ceiling test impairments of $105.6 million ( $67.1 million , net of tax) and $757.7 million ( $481.4 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 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. 

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2017

(Unaudited) 

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-9, Revenue from Contracts with Customers (Topic 606) , which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. 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 adopt the standard using either the full retrospective approach or a modified retrospective approach. We intend to adopt the standard utilizing a modified retrospective approach. Management does not expect the new standard will have a material impact on net income (loss) or cash flows from operations; however, we continue to evaluate the “gross versus net” presentation of certain revenues and associated expenses in the consolidated statements of operations and comprehensive income. Any such presentation changes would have no impact on operating income or net income (loss). We are currently developing accounting policies, business processes, and control activities that we expect to implement in connection with the new standard.

In February 2016, the FASB issued ASU 2016-2, 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.

2.	LONG-TERM DEBT

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

		September 30, 2017												December 31, 2016
(in thousands)		Principal				Unamortized Debt Issuance Costs and Discount  (1)				Long-term Debt, net				Principal				Unamortized Debt Issuance Costs				Long-term Debt, net
5.875% Senior Notes		$	—			$	—			$	—			$	750,000			$	(5,691	)		$	744,309
4.375% Senior Notes		750,000				(5,626		)		744,374				750,000				(6,370		)		743,630
3.90% Senior Notes		750,000				(7,865		)		742,135				—				—				—
Total long-term debt		$	1,500,000			$	(13,491	)		$	1,486,509			$	1,500,000			$	(12,061	)		$	1,487,939

(1)	At September 30, 2017 , the unamortized debt issuance costs and discount related to the 3.90% notes were $6.0 million and $1.8 million , respectively.  The 4.375% notes were issued at par.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2017

(Unaudited) 

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 September 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 September 30, 2017 , we were in compliance with all of the financial covenants.

At September 30, 2017 and December 31, 2016 , we had $3.6 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 date of the 5.875% notes was May 1, 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 received $741.8 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs.  The notes bear an annual 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. 

In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and interest is payable semiannually on June 1 and December 1.  

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 September 30, 2017 . 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 with durations of five to six quarters covering up to 50% of our oil and natural gas production on a forward eight 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. 

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2017

(Unaudited) 

As of September 30, 2017 , we have entered into collars and basis swaps. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the ceiling price and the index price if the index price is above the ceiling price.  No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price minus a fixed differential and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI Midland price and the WTI NYMEX (Cushing Oklahoma) price. For our Permian and Mid-Continent gas production, the contract prices in the PEPL and Perm EP collars are consistent with the index prices used to sell our production. The following tables summarize our outstanding derivative contracts as of September 30, 2017 :

		First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter				Total
Oil Collars:
2017:
WTI  (1)
Volume (Bbls)		—				—				—				1,932,000				1,932,000
Weighted Avg Price - Floor		$	—			$	—			$	—			$	46.29			$	46.29
Weighted Avg Price - Ceiling		$	—			$	—			$	—			$	56.64			$	56.64
2018:
WTI  (1)
Volume (Bbls)		1,980,000				1,456,000				1,104,000				552,000				5,092,000
Weighted Avg Price - Floor		$	47.05			$	46.94			$	45.92			$	48.00			$	46.87
Weighted Avg Price - Ceiling		$	56.41			$	55.40			$	54.21			$	53.95			$	55.38

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

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2017

(Unaudited) 

		First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter				Total
Gas Collars:
2017:
PEPL  (1)
Volume (MMBtu)		—				—				—				11,040,000				11,040,000
Weighted Avg Price - Floor		$	—			$	—			$	—			$	2.65			$	2.65
Weighted Avg Price - Ceiling		$	—			$	—			$	—			$	3.07			$	3.07
Perm EP  (2)
Volume (MMBtu)		—				—				—				7,360,000				7,360,000
Weighted Avg Price - Floor		$	—			$	—			$	—			$	2.64			$	2.64
Weighted Avg Price - Ceiling		$	—			$	—			$	—			$	3.04			$	3.04
2018:
PEPL  (1)
Volume (MMBtu)		9,000,000				6,370,000				3,680,000				920,000				19,970,000
Weighted Avg Price - Floor		$	2.62			$	2.50			$	2.45			$	2.50			$	2.54
Weighted Avg Price - Ceiling		$	3.00			$	2.87			$	2.67			$	2.65			$	2.88
Perm EP  (2)
Volume (MMBtu)		6,300,000				4,550,000				2,760,000				920,000				14,530,000
Weighted Avg Price - Floor		$	2.59			$	2.42			$	2.37			$	2.40			$	2.48
Weighted Avg Price - Ceiling		$	2.94			$	2.75			$	2.56			$	2.58			$	2.78

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

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

		First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter				Total
Oil Basis Swaps:
2017:
WTI Midland (1)
Volume (Bbls)		—				—				—				460,000				460,000
Weighted Avg Differential (2)		$	—			$	—			$	—			$	0.94			$	0.94
2018:
WTI Midland (1)
Volume (Bbls)		720,000				728,000				736,000				276,000				2,460,000
Weighted Avg Differential (2)		$	0.87			$	0.87			$	0.87			$	0.76			$	0.86

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

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

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2017

(Unaudited) 

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

		First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter				Total
Oil Collars:
2018:
WTI  (1)
Volume (Bbls)		540,000				546,000				552,000				552,000				2,190,000
Weighted Avg Price - Floor		$	48.00			$	48.00			$	48.00			$	48.00			$	48.00
Weighted Avg Price - Ceiling		$	55.21			$	55.21			$	55.21			$	55.21			$	55.21
2019:
WTI  (1)
Volume (Bbls)		540,000				546,000				—				—				1,086,000
Weighted Avg Price - Floor		$	48.00			$	48.00			$	—			$	—			$	48.00
Weighted Avg Price - Ceiling		$	55.21			$	55.21			$	—			$	—			$	55.21

(1)	The index price for these collars is WTI NYMEX.

		First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter				Total
Gas Collars:
2018:
PEPL  (1)
Volume (MMBtu)		1,800,000				1,820,000				1,840,000				1,840,000				7,300,000
Weighted Avg Price - Floor		$	2.40			$	2.40			$	2.40			$	2.40			$	2.40
Weighted Avg Price - Ceiling		$	2.64			$	2.64			$	2.64			$	2.64			$	2.64
Perm EP  (2)
Volume (MMBtu)		900,000				910,000				920,000				920,000				3,650,000
Weighted Avg Price - Floor		$	2.30			$	2.30			$	2.30			$	2.30			$	2.30
Weighted Avg Price - Ceiling		$	2.42			$	2.42			$	2.42			$	2.42			$	2.42
2019:
PEPL  (1)
Volume (MMBtu)		1,800,000				1,820,000				—				—				3,620,000
Weighted Avg Price - Floor		$	2.40			$	2.40			$	—			$	—			$	2.40
Weighted Avg Price - Ceiling		$	2.64			$	2.64			$	—			$	—			$	2.64
Perm EP  (2)
Volume (MMBtu)		900,000				910,000				—				—				1,810,000
Weighted Avg Price - Floor		$	2.30			$	2.30			$	—			$	—			$	2.30
Weighted Avg Price - Ceiling		$	2.42			$	2.42			$	—			$	—			$	2.42

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

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

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2017

(Unaudited) 

		First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter				Total
Oil Basis Swaps:
2018:
WTI Midland (1)
Volume (Bbls)		450,000				455,000				460,000				460,000				1,825,000
Weighted Avg Differential (2)		$	0.47			$	0.47			$	0.47			$	0.47			$	0.47
2019:
WTI Midland (1)
Volume (Bbls)		450,000				455,000				—				—				905,000
Weighted Avg Differential (2)		$	0.47			$	0.47			$	—			$	—			$	0.47

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

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

Derivative Gains and Losses

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

		Three Months Ended September 30,								Nine Months Ended September 30,
(Gain) Loss on Derivative Instruments, Net   (in thousands):		2017				2016				2017				2016
Change in fair value of derivative instruments, net		$	19,085			$	(8,967	)		$	(53,003	)		$	32,768
Cash (receipts) payments on derivative instruments, net		(2,976		)		(791		)		2,742				(9,718		)
(Gain) loss on derivative instruments, net		$	16,109			$	(9,758	)		$	(50,261	)		$	23,050

Derivative Fair Value

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 September 30, 2017 and December 31, 2016 , as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2017

(Unaudited) 

September 30, 2017:
(in thousands)		Balance Sheet Location		Asset				Liability
Oil contracts		Current assets — Derivative instruments		$	2,288			$	—
Gas contracts		Current assets — Derivative instruments		4,636				—
Oil contracts		Non-current assets — Derivative instruments		110				—
Gas contracts		Non-current assets — Derivative instruments		19				—
Oil contracts		Current liabilities — Derivative instruments		—				4,919
Gas contracts		Current liabilities — Derivative instruments		—				859
Oil contracts		Non-current liabilities — Derivative instruments		—				210
Gas contracts		Non-current liabilities — Derivative instruments		—				2
Total gross amounts presented in the balance sheet				7,053				5,990
Less: gross amounts not offset in the balance sheet				(4,540		)		(4,540		)
Net amount				$	2,513			$	1,450
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.

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2017

(Unaudited) 

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

		September 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	)		$	(794,663	)		$	(750,000	)		$	(779,453	)
3.90% Notes due 2027		$	(750,000	)		$	(764,408	)		$	—			$	—
Derivative instruments — assets		$	7,053			$	7,053			$	—			$	—
Derivative instruments — liabilities		$	(5,990	)		$	(5,990	)		$	(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 September 30, 2017 are: (i) accrued operating expenses of approximately $59.1 million and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $36.2 million .  Included in “Accrued liabilities — other” at December 31, 2016 are: (i) accrued operating expenses of approximately $53.9 million and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $43.5 million .

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

We 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 September 30, 2017 and December 31, 2016 , the allowance for doubtful accounts was $1.9 million and $1.6 million , respectively.

5.	CAPITAL STOCK

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

Dividends

In August 2017 , our Board of Directors declared a cash dividend of $0.08 per share.  The dividend is payable on or before December 1, 2017 , to stockholders of record on November 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 $22.9 million in dividends declared year-to-date September 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

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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 September 30,								Nine Months Ended September 30,
(in thousands)		2017				2016				2017				2016
Restricted stock awards:
Performance stock awards		$	6,508			$	5,465			$	19,348			$	18,374
Service-based stock awards		5,317				4,624				14,449				13,540
		11,825				10,089				33,797				31,914
Stock option awards		698				571				1,943				1,974
Total stock compensation cost		12,523				10,660				35,740				33,888
Less amounts capitalized to oil and gas properties		(5,485		)		(4,896		)		(16,121		)		(15,106		)
Compensation expense		$	7,038			$	5,764			$	19,619			$	18,782

    

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 increase in total stock compensation cost in the 2017 periods as compared to the 2016 periods is primarily due to awards granted either during or subsequent to the 2016 periods. These increases were partially offset by the following decreases: (i) awards vesting prior to or during the 2017 periods, (ii) reversals of previously recognized expense on 2017 forfeitures, and (iii) expense associated with the voluntary Early Retirement Incentive Program during the 2016 periods .

We adopted Accounting Standards Update 2016-9, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-9”) on January 1, 2017.  ASU 2016-9 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 2016-9, 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 2016-9 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 2016-9 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to the payment of 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 nine months ended September 30, 2016 by increasing net cash provided by operating activities by $11.5 million and increasing net cash used by financing activities by $11.5 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 nine months ended September 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.

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The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the nine months ended September 30, 2017 :

(in thousands)
Asset retirement obligation at January 1, 2017	$	154,523
Liabilities incurred	5,730
Liability settlements and disposals	(10,287		)
Accretion expense	5,637
Revisions of estimated liabilities	1,644
Asset retirement obligation at September 30, 2017	157,247
Less current obligation	(12,612		)
Long-term asset retirement obligation	$	144,635

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 September 30,								Nine Months Ended September 30,
(in thousands, except per share data)		2017				2016				2017				2016
Basic:
Net income (loss)		$	91,399			$	(10,673	)		$	319,633			$	(456,586	)
Participating securities’ share in earnings (1)		(1,572		)		—				(5,478		)		—
Net income (loss) available to common stockholders		$	89,827			$	(10,673	)		$	314,155			$	(456,586	)
Diluted:
Net income (loss)		$	91,399			$	(10,673	)		$	319,633			$	(456,586	)
Participating securities’ share in earnings (1)		(1,572		)		—				(5,476		)		—
Net income (loss) available to common stockholders		$	89,827			$	(10,673	)		$	314,157			$	(456,586	)
Shares:
Basic shares outstanding		93,501				93,221				93,431				93,221
Dilutive effect of potential common shares (2)		30				—				34				—
Fully diluted common stock		93,531				93,221				93,465				93,221
Earnings (loss) per share to common stockholders (3):
Basic		$	0.96			$	(0.12	)		$	3.36			$	(4.90	)
Diluted		$	0.96			$	(0.12	)		$	3.36			$	(4.90	)

(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, 298.7 thousand and 302.9 thousand shares were excluded from the calculations for the three and nine months ended September 30, 2017 and 2.1 million and 2.1 million shares were excluded from the calculations for the three and nine months ended September 30, 2016 .

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

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CIMAREX ENERGY CO.

Notes to Condensed Consolidated Financial Statements

September 30, 2017

(Unaudited) 

9.	INCOME TAXES

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

		Three Months Ended September 30,								Nine Months Ended September 30,
Income Tax Expense (Benefit)   (in thousands):		2017				2016				2017				2016
Current tax benefit		$	—			$	(1,115	)		$	(6	)		$	(1,115	)
Deferred tax expense (benefit)		51,239				(3,944		)		188,168				(258,368		)
		$	51,239			$	(5,059	)		$	188,162			$	(259,483	)
Combined federal and state effective income tax rate		35.9		%		32.2		%		37.1		%		36.2		%

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 September 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 2014 through 2016 remain open to examination by the Internal Revenue Service of the United States.  We file tax returns with various state taxing authorities, which remain open to examination for tax years 2013 through 2016.

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

10.	COMMITMENTS AND CONTINGENCIES

Commitments

At September 30, 2017 , we had estimated commitments of approximately: (i) $181.2 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $24.6 million to finish gathering system construction in progress. 

At September 30, 2017 , we had firm sales contracts to deliver approximately 207.2  Bcf of natural gas over the next 7.3 years .  If we do not deliver this gas, our estimated financial commitment, calculated using the October 2017 index price, would be approximately $491.0 million .  The value of this commitment will fluctuate due to price volatility and actual volumes delivered.  However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next 8.6 years .  If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2017 , would be approximately $312.3 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 volumetric obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines.  If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2017 , would be approximately $13.7 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. 

At September 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 $37.6 million over the remaining terms of the agreements. These agreements were entered into to support our residue marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation.

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We have various future commitments for office space under operating lease arrangements totaling approximately $89.6 million at September 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 September 30,								Nine Months Ended September 30,
(in thousands)		2017				2016				2017				2016
Cash paid for:
Interest expense (net of capitalized amounts of $477, $286, $12,439, and $10,343, respectively)		$	109			$	527			$	28,881			$	30,204
Income taxes		$	—			$	—			$	3			$	13
Cash income tax refunds received		$	—			$	1,115			$	21			$	1,140

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Cimarex is an independent oil and gas exploration and production company.  Our operations are entirely located in the United States, mainly in Oklahoma, Texas, and New Mexico.  Currently our operations are focused in two main areas: the Permian Basin and the Mid-Continent 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 fluctuate significantly.  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 volatile and we expect this volatility to persist. For the first nine months of 2017, average NYMEX oil and gas prices were $49.46 per barrel and $3.17 per Mcf, respectively, representing an increase of 20% and 39% , respectively, from the NYMEX prices for the same period in 2016. 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 RESULTS OF OPERATIONS Revenues below for further information regarding our realized commodity prices.

See “ Risk Factors ” in Item 1A of our Annual Report on Form 10-K/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.

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

•	Production increased 16% to 1,121.1 MMcfe per day.

•	Oil volumes increased 23% to 55.6 MBbls per day, gas volumes increased 10% to 506.7 MMcf per day, and NGL volumes increased 20% to 46.8 MBbls per day.

•	Production revenues increased 57% to $1,334.6 million .

•	Cash flow provided by operating activities increased 71% to $755.8 million .

•	Net income was $319.6 million , or $3.36 per diluted share, for the first nine months of 2017 , as compared to a net loss of $456.6 million , or $(4.90) per diluted share, for the first nine months of 2016 .

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•	In response to improved commodity prices, we increased our exploration and development expenditures to $813.7 million for the first nine months of 2017 , as compared to $443.3 million for the first nine months of 2016 .

•	Total debt at both September 30, 2017 and 2016 consisted of $1.5 billion of senior notes.  During the second quarter 2017, we repaid our 5.875% $750 million notes due 2022 and issued 3.90% $750 million notes due 2027.  Our 4.375% $750 million notes are due 2024.

RESULTS OF OPERATIONS

Three and Nine Months Ended September 30, 2017 vs. Three and Nine Months Ended September 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. See QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for more information regarding the sensitivity of our revenues to price fluctuations.

Production volumes and realized prices increased during the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 and production volumes and realized oil and NGL prices increased during the three months ended September 30, 2017 as compared to the three months ended September 30, 2016 , while realized gas prices remained relatively constant between the two quarterly periods. These production and realized price increases caused our revenue to increase by $126.5 million , or 39% , during the three months ended September 30, 2017 as compared to the three months ended September 30, 2016 and by $484.7 million , or 57% , during the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 . For the three months ended September 30, 2017 , our total production revenue was comprised of 51% oil sales, 28% gas sales, and 21% NGL sales. For the nine months ended September 30, 2017 , our total production revenue was comprised of 52% oil sales, 29% gas sales, and 19% NGL sales. The following tables show our production revenue for the periods as well as the change in revenues due to changes in volumes and prices.  

		Three Months Ended								Change
Production Revenue		September 30,								Between		Price/Volume Change
(in thousands)		2017				2016				2017 / 2016		Price				Volume				Total
Oil sales		$	231,441			$	166,079			39%		$	20,026			$	45,336			$	65,362
Gas sales		125,707				109,278				15%		(475		)		16,904				16,429
NGL sales		95,191				50,464				89%		32,963				11,764				44,727
		$	452,339			$	325,821			39%		$	52,514			$	74,004			$	126,518
		Nine Months Ended								Change
Production Revenue		September 30,								Between		Price/Volume Change
(in thousands)		2017				2016				2017 / 2016		Price				Volume				Total
Oil sales		$	687,960			$	445,657			54%		$	139,638			$	102,665			$	242,303
Gas sales		390,126				268,501				45%		95,453				26,172				121,625
NGL sales		256,503				135,755				89%		94,174				26,574				120,748
		$	1,334,589			$	849,913			57%		$	329,265			$	155,411			$	484,676

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The table below presents our regional production volumes.

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2017			2016			2017			2016
Oil (Bbls per day)
Permian Basin		43,735			35,930			43,544			35,939
Mid-Continent		12,846			8,486			11,937			8,889
Other		106			116			115			192
		56,687			44,532			55,596			45,020
Gas (MMcf per day)
Permian Basin		217.9			178.4			212.9			177.7
Mid-Continent		296.8			266.7			292.4			281.3
Other		1.2			1.6			1.4			1.5
		515.9			446.7			506.7			460.5
NGL (Bbls per day)
Permian Basin		24,659			20,549			23,771			17,952
Mid-Continent		23,142			18,194			22,999			21,009
Other		39			43			36			41
		47,840			38,786			46,806			39,002
Total (MMcfe per day)
Permian Basin		628.2			517.2			616.8			501.1
Mid-Continent		512.7			426.8			502.1			460.7
Other		2.2			2.6			2.2			2.8
		1,143.1			946.6			1,121.1			964.6

Our total production increased by 196.5 MMcfe per day and 156.5 MMcfe per day during the three and nine months ended September 30, 2017, respectively, as compared to the three and nine months ended September 30, 2016. These increases are the result of increased drilling and completion activity during 2017 as compared to 2016. Accordingly, our capital expenditures have also increased significantly during the 2017 periods as compared to the 2016 periods. See LIQUIDITY AND CAPITAL RESOURCES Capital Expenditures below for more information on our capital expenditures.

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The table below presents our production volumes by commodity, our average realized commodity prices, and certain major U.S. index prices.  The sale of our Permian Basin oil production is typically tied to the WTI Midland benchmark price and the sale of our Mid-Continent oil production is typically tied to the WTI Cushing benchmark price.  Our realized prices do not include settlements of commodity derivative contracts.

		Three Months Ended								Change		Nine Months Ended								Change
		September 30,								Between		September 30,								Between
		2017				2016				2017 / 2016		2017				2016				2017 / 2016
Oil
Total volume — MBbls		5,215				4,097				27%		15,178				12,336				23%
Total volume — MBbls per day		56.7				44.5				27%		55.6				45.0				23%
Percentage of total production		30		%		28		%				30		%		28		%
Average realized price — per barrel		$	44.38			$	40.54			9%		$	45.33			$	36.13			25%
Average WTI Midland price — per barrel		$	47.44			$	44.64			6%		$	49.14			$	41.43			19%
Average WTI Cushing price — per barrel		$	48.20			$	44.94			7%		$	49.46			$	41.33			20%
Gas
Total volume — MMcf		47,467				41,096				16%		138,338				126,164				10%
Total volume — MMcf per day		515.9				446.7				16%		506.7				460.5				10%
Percentage of total production		45		%		47		%				45		%		48		%
Average realized price — per Mcf		$	2.65			$	2.66			—%		$	2.82			$	2.13			32%
Average Henry Hub price — per Mcf		$	2.99			$	2.81			6%		$	3.17			$	2.28			39%
NGL
Total volume — MBbls		4,401				3,568				23%		12,778				10,687				20%
Total volume — MBbls per day		47.8				38.8				23%		46.8				39.0				20%
Percentage of total production		25		%		25		%				25		%		24		%
Average realized price — per barrel		$	21.63			$	14.14			53%		$	20.07			$	12.70			58%
Total
Total production — MMcfe		105,166				87,088				21%		306,073				264,297				16%
Total production — MMcfe per day		1,143.1				946.6				21%		1,121.1				964.6				16%
Average realized price — per Mcfe		$	4.30			$	3.74			15%		$	4.36			$	3.22			35%

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 agreements and may earn a fee for such services.  The table below reflects income from third-party gas gathering and processing and our net marketing margin for marketing third-party gas. 

		Three Months Ended								Variance				Nine Months Ended								Variance
		September 30,								Between				September 30,								Between
Gas Gathering and Marketing   Revenues (in thousands) :		2017				2016				2017 / 2016				2017				2016				2017 / 2016
Gas gathering and other		$	11,056			$	9,824			$	1,232			$	32,416			$	25,276			$	7,140
Gas marketing, net of related costs		$	286			$	72			$	214			$	304			$	1			$	303

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.  Among other factors, some of these costs vary with commodity prices, some trend with the volume of production, others are a function of the number of wells we own, and some depend on the prices charged by service companies. 

Total operating costs and expenses for the three months ended September 30, 2017 were lower by 8% compared to the three months ended September 30, 2016 .  The primary reasons for the decrease are: (i) the $105.6 million ( $67.1 million , net of tax) ceiling test impairment recorded in the 2016 period partially offset by (ii) increased depreciation, depletion, and amortization, production expense, transportation, processing, and other operating costs, taxes other than income, and net losses on derivative instruments in 2017. 

		Three Months Ended								Variance
		September 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		$	—			$	105,593			$	(105,593	)		N/A				N/A
Depreciation, depletion, and amortization		111,396				90,277				21,119				$	1.06			$	1.04
Asset retirement obligation		1,497				2,033				(536		)		$	0.01			$	0.02
Production		65,410				52,976				12,434				$	0.62			$	0.61
Transportation, processing, and other operating		58,387				48,706				9,681				$	0.56			$	0.56
Gas gathering and other		8,856				7,905				951				$	0.08			$	0.09
Taxes other than income		24,314				15,974				8,340				$	0.23			$	0.18
General and administrative		21,039				20,118				921				$	0.20			$	0.23
Stock compensation		7,038				5,764				1,274				$	0.07			$	0.07
(Gain) loss on derivative instruments, net		16,109				(9,758		)		25,867				N/A				N/A
Other operating expense, net		95				179				(84		)		N/A				N/A
		$	314,141			$	339,767			$	(25,626	)

Total operating costs and expenses for the nine months ended September 30, 2017 were lower by 48% compared to the nine months ended September 30, 2016 .  The primary reasons for the decrease are: (i) the $757.7 million ( $481.4 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, taxes other than income, and depreciation, depletion, and amortization in 2017.

		Nine Months Ended								Variance
		September 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		$	—			$	757,670			$	(757,670	)		N/A				N/A
Depreciation, depletion, and amortization		315,096				302,999				12,097				$	1.03			$	1.15
Asset retirement obligation		4,077				6,081				(2,004		)		$	0.01			$	0.02
Production		190,409				180,891				9,518				$	0.62			$	0.68
Transportation, processing and other operating		172,034				139,585				32,449				$	0.56			$	0.53
Gas gathering and other		25,930				23,477				2,453				$	0.08			$	0.09
Taxes other than income		63,104				43,879				19,225				$	0.21			$	0.17
General and administrative		58,835				55,439				3,396				$	0.19			$	0.21
Stock compensation		19,619				18,782				837				$	0.06			$	0.07
(Gain) loss on derivative instruments, net		(50,261		)		23,050				(73,311		)		N/A				N/A
Other operating expense, net		977				293				684				N/A				N/A
		$	799,820			$	1,552,146			$	(752,326	)

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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 each quarter-end date during the nine months ended September 30, 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 nine months ended September 30, 2017 .  During the three and nine months ended September 30, 2016 , we recognized ceiling test impairments of $105.6 million ( $67.1 million , net of tax) and $757.7 million ( $481.4 million , net of tax), respectively.  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 September 30, 2017 ceiling calculation, based on the required trailing twelve-month average prices, were $3.00 per Mcf of gas and $49.81 per barrel of oil.  A decline of approximately 18% or more in the value of the ceiling limitation would have resulted in an impairment at September 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. 

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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:

		Three Months Ended								Variance
		September 30,								Between				Per Mcfe
DD&A Expense   (in thousands, except per Mcfe)		2017				2016				2017 / 2016				2017				2016
Depletion		$	99,633			$	78,396			$	21,237			$	0.95			$	0.90
Depreciation		11,763				11,881				(118		)		0.11				0.14
		$	111,396			$	90,277			$	21,119			$	1.06			$	1.04
		Nine Months Ended								Variance
		September 30,								Between				Per Mcfe
DD&A Expense   (in thousands, except per Mcfe)		2017				2016				2017 / 2016				2017				2016
Depletion		$	280,379			$	267,880			$	12,499			$	0.92			$	1.02
Depreciation		34,717				35,119				(402		)		0.11				0.13
		$	315,096			$	302,999			$	12,097			$	1.03			$	1.15

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
		September 30,								Between				Per Mcfe
Production Expense   (in thousands, except per Mcfe)		2017				2016				2017 / 2016				2017				2016
Lease operating expense		$	55,296			$	44,249			$	11,047			$	0.52			$	0.51
Workover expense		10,114				8,727				1,387				0.10				0.10
		$	65,410			$	52,976			$	12,434			$	0.62			$	0.61
		Nine Months Ended								Variance
		September 30,								Between				Per Mcfe
Production Expense   (in thousands, except per Mcfe)		2017				2016				2017 / 2016				2017				2016
Lease operating expense		$	156,644			$	146,895			$	9,749			$	0.51			$	0.55
Workover expense		33,765				33,996				(231		)		0.11				0.13
		$	190,409			$	180,891			$	9,518			$	0.62			$	0.68

Through efficiency gains and increasing production by 16% during the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, we reduced our per unit lease operating expense by 7% between these two periods. On an absolute basis, lease operating expense in the third quarter 2017 increased 25% , or $11.0 million , compared to the third quarter of 2016 .  The increase was primarily caused by: (i) increased equipment maintenance costs, (ii) increased saltwater disposal and equipment rental costs, both due to increased drilling activity, and (iii) increased labor costs due to more employees and salary increases. Lease operating expense for the nine months ended September 30, 2017 increased 7% , or $9.7 million , compared to the nine months ended September 30, 2016 .  The increase was primarily caused by: (i) increased labor costs due to more employees and salary and bonus increases, (ii) increased saltwater disposal costs due to increased drilling activity and various issues (e.g., capacity and down time) at third-party disposal wells, (iii) increased gas lift and fuel compression costs, and (iv) increased chemicals and treating costs.

Workover expense during the three and nine months ended September 30, 2017 increased 16% , or $1.4 million , and decreased 1% , or $0.2 million , respectively, compared to the three and nine months ended September 30, 2016 .  During the three and nine months ended September 30, 2017, we had an increased number of workover projects as well as costlier major well workover projects than during the three and nine months ended September 30, 2016, which increased expense. For the nine months

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ended September 30, 2017, this increase was somewhat offset by the receipt of partial insurance proceeds in the second quarter 2017 related to a flooding event in 2015 and the 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 nine months ended September 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 September 30, 2017 were 20% , or $9.7 million , higher than transportation, processing, and other operating costs in the three months ended September 30, 2016 .  This increase was primarily due to increased production volumes in the 2017 quarter as compared to the 2016 quarter. Transportation, processing, and other operating costs in the nine months ended September 30, 2017 were 23% , or $32.4 million , higher than transportation, processing, and other operating costs in the nine months ended September 30, 2016 .  This increase was primarily due to increased production volumes and transportation and processing rates in 2017 as compared to 2016 .

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 September 30, 2017 was 12% , or $1.0 million , higher than gas gathering and other in the three months ended September 30, 2016 .  Gas gathering and other in the nine months ended September 30, 2017 was 10% , or $2.5 million , higher than gas gathering and other in the nine months ended September 30, 2016 .  The increases from 2016 are primarily due to increases in product costs associated with processing third-party production. These increased product costs are offset by increases in associated revenue.

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 $8.3 million , or 52% , in the third quarter of 2017 as compared to the third quarter of 2016 .  Taxes other than income increased $19.2 million , or 44% , in the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 .  These increases are due to the increase in revenue seen between the comparable periods.  Taxes other than income was 5.4% and 4.9% of production revenues for the three months ended September 30, 2017 and 2016 , respectively, and was 4.7% and 5.2% of production revenues for the nine months ended September 30, 2017 and 2016 , respectively.  The percentage for the nine months ended September 30, 2017 has decreased from the comparative period due to the approval of reduced tax rates on several of our high-cost gas wells in the State of Texas and, as part of this process, approved severance tax refunds of $8.2 million.

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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 that are not directly associated with exploration, development, or production activities.  Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting.  The amount of expense capitalized varies and depends on whether the cost incurred can be directly identified with acquisition, exploration, and development activities. The amount capitalized ranged from 45% to 48% during the periods presented in the table below, which shows our G&A costs.

		Three Months Ended								Variance Between 2017 / 2016				Nine Months Ended								Variance Between 2017 / 2016
		September 30,												September 30,
General and Administrative Expense   (in thousands):		2017				2016								2017				2016
Gross G&A		$	39,885			$	36,752			$	3,133			$	112,516			$	106,208			$	6,308
Less amounts capitalized to oil and gas properties		(18,846		)		(16,634		)		(2,212		)		(53,681		)		(50,769		)		(2,912		)
G&A expense		$	21,039			$	20,118			$	921			$	58,835			$	55,439			$	3,396

G&A expense for the third quarter of 2017 was 5% , or $0.9 million , higher than for the third quarter of 2016 .  This increase is primarily due to increased salaries and wages, consulting, and charitable donations, partially offset by decreased employee bonus expense. G&A expense for the nine months ended September 30, 2017 was 6% , or $3.4 million , higher than for the nine months ended September 30, 2016 .  This increase was primarily caused by increased employee bonus expense, charitable donations, and consulting, partially offset by decreased severance expense. A voluntary Early Retirement Incentive Program, which included severance pay, was offered to certain employees during 2016.  

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				Nine Months Ended								Variance
		September 30,								Between				September 30,								Between
Stock Compensation Expense   (in thousands):		2017				2016				2017 / 2016				2017				2016				2017 / 2016
Restricted stock awards:
Performance stock awards		$	6,508			$	5,465			$	1,043			$	19,348			$	18,374			$	974
Service-based stock awards		5,317				4,624				693				14,449				13,540				909
		11,825				10,089				1,736				33,797				31,914				1,883
Stock option awards		698				571				127				1,943				1,974				(31		)
Total stock compensation cost		12,523				10,660				1,863				35,740				33,888				1,852
Less amounts capitalized to oil and gas properties		(5,485		)		(4,896		)		(589		)		(16,121		)		(15,106		)		(1,015		)
Stock compensation expense		$	7,038			$	5,764			$	1,274			$	19,619			$	18,782			$	837

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 increase in total stock compensation cost in the 2017 periods as compared to the 2016 periods is primarily due to awards granted either during or subsequent to the 2016 periods. These increases were partially offset by the following decreases: (i) awards vesting prior to or during the 2017 periods, (ii) reversals of previously recognized expense on 2017 forfeitures, and (iii) expense associated with the voluntary Early Retirement Incentive Program during 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

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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 the payment of 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 nine months ended September 30, 2016 by increasing net cash provided by operating activities by $11.5 million and increasing net cash used by financing activities by $11.5 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 nine months ended September 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 for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments.  Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments.  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								Variance Between 2017 / 2016				Nine Months Ended								Variance Between 2017 / 2016
		September 30,												September 30,
(Gain) Loss on Derivative Instruments, Net   (in thousands):		2017				2016								2017				2016
Change in fair value of derivative instruments, net		$	19,085			$	(8,967	)		$	28,052			$	(53,003	)		$	32,768			$	(85,771	)
Cash (receipts) payments on derivative instruments, net		(2,976		)		(791		)		(2,185		)		2,742				(9,718		)		12,460
(Gain) loss on derivative instruments, net		$	16,109			$	(9,758	)		$	25,867			$	(50,261	)		$	23,050			$	(73,311	)

 

Other (Income) and Expense  

		Three Months Ended								Variance				Nine Months Ended								Variance
		September 30,								Between				September 30,								Between
Other Income and Expense   (in thousands):		2017				2016				2017 / 2016				2017				2016				2017 / 2016
Interest expense		$	16,838			$	20,931			$	(4,093	)		$	57,985			$	62,560			$	(4,575	)
Capitalized interest		(5,373		)		(5,421		)		48				(17,456		)		(15,958		)		(1,498		)
Loss on early extinguishment of debt		—				—				—				28,169				—				28,169
Other, net		(4,563		)		(3,828		)		(735		)		(9,004		)		(7,489		)		(1,515		)
		$	6,902			$	11,682			$	(4,780	)		$	59,694			$	39,113			$	20,581

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 LIQUIDITY AND CAPITAL RESOURCES Long-term Debt below for further information regarding our debt. The decrease in interest expense in the 2017 periods as compared to the 2016 periods is primarily due to the completion of a tender offer and redemption of $750 million 5.875% senior notes and the issuance of $750 million 3.90% senior notes, which occurred during the second quarter of 2017. The $28.2 million loss on early extinguishment of debt incurred during 2017 was also associated with the debt tender offer and redemption. The loss was composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.  The original maturity date of the 5.875% notes was May 1, 2022.

We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing 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. There have been higher capitalized costs upon which to capitalize interest in the 2017 periods than in the 2016 periods due to our increased capitalized expenditures. See LIQUIDITY AND CAPITAL RESOURCES Capital Expenditures below for further information regarding our capital expenditures. The replacement of our 5.875% notes with 3.90% notes in the second quarter of 2017 has served to lower the amount of capitalized

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interest in the 2017 periods as compared to what the capitalized interest would have been had we not replaced the higher interest notes with lower interest notes.

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								Variance				Nine Months Ended								Variance
		September 30,								Between				September 30,								Between
Income Tax Expense (Benefit)   (in thousands):		2017				2016				2017 / 2016				2017				2016				2017 / 2016
Current tax benefit		$	—			$	(1,115	)		$	1,115			$	(6	)		$	(1,115	)		$	1,109
Deferred tax expense (benefit)		51,239				(3,944		)		55,183				188,168				(258,368		)		446,536
		$	51,239			$	(5,059	)		$	56,298			$	188,162			$	(259,483	)		$	447,645
Combined federal and state effective income tax rate		35.9		%		32.2		%						37.1		%		36.2		%

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 approximate $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 nine months ended September 30, 2017 and 2016 .

We periodically use derivative instruments to mitigate volatility in commodity prices.  At September 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 enter into derivative instruments with durations of five to six quarters covering up to 50% of our oil and natural gas production on a forward eight quarter basis.  See Note 3 to the Condensed Consolidated Financial Statements for information regarding our derivative instruments.

We believe our conservative use of leverage, strong balance sheet, and hedging activities will mitigate our exposure to lower prices.  Cash and cash equivalents at September 30, 2017 were $422.8 million .  At September 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 September 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. 

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Our debt to total capitalization ratio at September 30, 2017 was 38% , 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 September 30, 2017 , the ratio calculation is $1.5 billion ÷ ( $1.5 billion + $2.4 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. 

		Nine Months Ended September 30,
(in thousands)		2017				2016
Net cash provided by operating activities		$	755,805			$	440,788
Net cash used by investing activities		$	(924,635	)		$	(484,396	)
Net cash used by financing activities		$	(61,238	)		$	(37,078	)

Net cash provided by operating activities for the first nine months of 2017 was $755.8 million , up $315.0 million or 71% from $440.8 million for the first nine months of 2016 .  The $315.0 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 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 nine months of 2017 was $924.6 million , up $440.2 million or 91% from $484.4 million for the first nine 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 nine months of 2017 was $61.2 million , up $24.2 million or 65% from $37.1 million for the first nine months of 2016 .  Net cash used by financing activities for the first nine months of 2017 includes $772.9 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 $741.8 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 three quarters of 2017 , we paid an $0.08 per share dividend, totaling $22.7 million in dividends paid during the nine months ended September 30, 2017 .  We paid a $0.16 per share dividend in the first quarter of 2016 and an $0.08 per share dividend in each of the second and third quarters of 2016, totaling $30.2 million in dividends paid during the nine months ended September 30, 2016 . 

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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 September 30,								Nine Months Ended September 30,
(in thousands)		2017				2016				2017				2016
Acquisitions:
Proved		$	—			$	—			$	260			$	2,618
Unproved		438				3,200				4,263				11,546
		438				3,200				4,523				14,164
Exploration and development:
Land and seismic		12,872				16,974				123,359				45,610
Exploration and development		322,651				157,571				813,693				443,279
		335,523				174,545				937,052				488,889
Sales proceeds:
Proved		1,807				(376		)		(85		)		(12,605		)
Unproved		(780		)		(9,207		)		(8,051		)		(9,608		)
		1,027				(9,583		)		(8,136		)		(22,213		)
		$	336,988			$	168,162			$	933,439			$	480,840

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 $1.2 billion .  Approximately 61% 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. 

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 completed by region during the periods indicated.

		Three Months Ended September 30,						Nine Months Ended September 30,
		2017			2016			2017			2016
Gross wells
Permian Basin		29			17			65			37
Mid-Continent		48			25			133			61
		77			42			198			98
Net wells
Permian Basin		16			10			42			22
Mid-Continent		14			7			32			14
		30			17			74			36

As of September 30, 2017 , we had 22 gross ( 10 net) wells in the process of being drilled: 7 gross ( 4 net) in the Permian Basin and 15 gross ( 6 net) in the Mid-Continent region and there were 109 gross ( 23 net) wells waiting on completion: 35 gross

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( 13 net) in the Permian Basin and 74 gross ( 10 net) in the Mid-Continent region.  We also had 14 operated rigs running: eight 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.  See our Form 10-K/A for the year ended December 31, 2016 , Item 1.A. Risk Factors, for a description of risks related to current and potential future environmental and safety regulations and requirements that could adversely affect our operations and financial condition.

Long-term Debt

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

		September 30, 2017												December 31, 2016
(in thousands)		Principal				Unamortized Debt Issuance Costs and Discount  (1)				Long-term Debt, net				Principal				Unamortized Debt Issuance Costs				Long-term Debt, net
5.875% Senior Notes		$	—			$	—			$	—			$	750,000			$	(5,691	)		$	744,309
4.375% Senior Notes		750,000				(5,626		)		744,374				750,000				(6,370		)		743,630
3.90% Senior Notes		750,000				(7,865		)		742,135				—				—				—
Total long-term debt		$	1,500,000			$	(13,491	)		$	1,486,509			$	1,500,000			$	(12,061	)		$	1,487,939

(1)	At September 30, 2017 , the unamortized debt issuance costs and discount related to the 3.90% notes were $6.0 million and $1.8 million , respectively.  The 4.375% notes were issued at par.

Bank Debt

We have a senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020.  The Credit Facility has aggregate commitments of $1.0 billion , with an option for us to increase 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 September 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 September 30, 2017 , we were in compliance with all of the financial covenants.

At September 30, 2017 and December 31, 2016 , we had $3.6 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

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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 date of the 5.875% notes was May 1, 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 received $741.8 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs.  The notes bear an annual 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. 

In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and interest is payable semiannually on June 1 and December 1.

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 September 30, 2017 .  As of September 30, 2017 , 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.

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 September 30, 2017 , we had working capital of $301.5 million , a decrease of $145.4 million or 33% 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 $230.1 million .

•	Operations-related accounts payable and accrued liabilities increased by $90.5 million .

•	Accrued liabilities related to our E&D expenditures increased by $23.3 million .

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

•	Operations-related accounts receivable increased by $128.6 million .

•	Current derivative instruments increased by $50.5 million to a net asset.

•	Oil and gas well equipment and supplies increased by $21.2 million .

Cash on hand was used during the nine months ended September 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 August 2017 , an $0.08 per share dividend was declared, which is payable on or before December 1, 2017 to stockholders of record on November 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 September 30, 2017 , our material off-balance sheet arrangements consisted of operating lease agreements, which are included in the table below.

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Contractual Obligations and Material Commitments

At September 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		89,564				9,770				21,619				22,328				35,847
Unconditional purchase obligations (2)		39,773				9,117				9,653				8,730				12,273
Derivative liabilities		5,990				5,778				212				—				—
Asset retirement obligation (3)		157,247				12,612				—		(3)		—		(3)		—		(3)
Other long-term liabilities (4)		34,986				1,736				3,304				2,771				27,175
	$	2,352,592			$	102,782			$	158,913			$	157,954			$	1,788,308

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

(2)	Of the total Unconditional purchase obligations, $37.6 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 may include potential future cash payments if we fail to meet various performance obligations.  These are not reflected in the table above. 

At September 30, 2017 , we had estimated commitments of approximately: (i) $181.2 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $24.6 million to finish gathering system construction in progress. 

At September 30, 2017 , we had firm sales contracts to deliver approximately 207.2  Bcf of natural gas over the next 7.3 years .  If we do not deliver this gas, our estimated financial commitment, calculated using the October 2017 index price, would be approximately $491.0 million .  The value of this commitment will fluctuate due to price volatility and actual volumes delivered.  However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next 8.6 years .  If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2017 , would be approximately $312.3 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 volumetric obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines.  If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2017 , would be approximately $13.7 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.

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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 months ended September 30, 2017 , our total production revenue was comprised of 51% oil sales, 28% gas sales, and 21% NGL sales. For the nine months ended September 30, 2017 , our total production revenue was comprised of 52% oil sales, 29% gas sales, and 19% NGL sales. The following table shows how hypothetical changes in the realized prices we receive on our commodity sales would have impacted revenue for the periods indicated.

				Impact on Revenue
	Change in Realized Price			Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
				(in thousands)
Oil	± $1.00	per barrel		± $5,215		± $15,178
Gas	± $0.10	per Mcf		± $4,747		± $13,834
NGL	± $1.00	per barrel		± $4,401		± $12,778
				± $14,363		± $41,790

We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production.  At September 30, 2017 , we had oil and gas derivatives covering a portion of our 2017 and 2018 production, which were recorded as current and non-current assets and current and non-current liabilities.  At September 30, 2017 , our oil and gas derivatives had a gross asset fair value of $7.1 million and a gross liability fair value of $6.0 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.  The following table shows how hypothetical changes in the forward prices used to calculate the fair value of our derivatives would have impacted the fair value as of September 30, 2017 .

			Impact on Fair Value
	Change in Forward Price		September 30, 2017
			(in thousands)
Oil	-$1.00		$	4,063
Oil	+$1.00		$	(4,237	)
Gas	-$0.10		$	4,200
Gas	+$0.10		$	(4,038	)

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Interest Rate Risk

At September 30, 2017 , our long-term debt consisted of $750 million of 4.375% senior unsecured notes that will mature on June 1, 2024 and $750 million of 3.90% senior unsecured notes that will mature on May 15, 2027 .  Because all of our outstanding long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal.  See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt. 

ITEM 4.  CONTROLS AND PROCEDURES 

Evaluation of Disclosure Controls and Procedures

Cimarex 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 September 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 September 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II

 

ITEM 1.   LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS  

In addition to the other information set forth in this report, you should carefully consider the risks discussed in our Annual Report on Form 10-K/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.

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 (filed as Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q filed on August 9, 2017 and incorporated herein by reference).
31.1	Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
32.2	Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

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SIGNATURES

 

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

 

November 8, 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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