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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-Q

(Mark One)

 

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the Quarterly Period ended September 30, 2014

 

Commission File No. 001-31446

 

CIMAREX ENERGY CO.

 

1700 Lincoln Street, Suite 3700

Denver, Colorado 80203

(303) 295-3995

 

Former Address

1700 Lincoln Street, Suite 1800

Denver, Colorado 80203

 

 

 

Incorporated in the

 

Employer Identification

State of Delaware

 

No. 45-0466694

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes   No 

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes   No 

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

 

 

 

 

Large accelerated filer 

Accelerated filer 

Non-accelerated filer 
(Do not check if a smaller
reporting company)

Smaller reporting company 

 

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

 

The number of shares of Cimarex Energy Co. common stock outstanding as of September 30, 2014 was 87,248,508.

 

 


 

CIMAREX ENERGY CO.

 

Table of Contents

 

 

 

 

 

Page

PART I — FINANCIAL INFORMATION 

 

 

 

Item 1 

Financial Statements

 

 

 

 

 

Condensed consolidated balance sheets (unaudited) as of September 30, 2014 and December 31, 2013

 

 

 

 

Consolidated statements of income and comprehensive income (unaudited) for the three and nine months ended September 30, 2014 and 2013

 

 

 

 

Condensed consolidated statements of cash flows (unaudited) for the  nine months ended September 30, 2014 and 2013

 

 

 

 

Notes to consolidated financial statements (unaudited)

 

 

 

Item 2 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

21 

 

 

 

Item 3 

Quantitative and Qualitative Disclosures about Market Risk

37 

 

 

 

Item 4 

Controls and Procedures

38 

 

 

 

PART II — OTHER INFORMATION 

 

 

 

Item 1 

Legal Proceedings

39 

 

 

 

Item 6 

Exhibits

39 

 

 

 

Signatures 

40 

 

 

 

 


 

GLOSSARY

 

Bbl/d—Barrels (of oil or natural gas liquids) per day

Bbls—Barrels (of oil or natural gas liquids)

Bcf—Billion cubic feet

Bcfe—Billion cubic feet equivalent

Btu—British thermal unit

MBbls—Thousand barrels

Mcf—Thousand cubic feet (of natural gas)

Mcfe—Thousand cubic feet equivalent

MMBbl/MMBbls—Million barrels

MMBtu—Million British Thermal Units

MMcf—Million cubic feet

MMcf/d—Million cubic feet per day

MMcfe—Million cubic feet equivalent

MMcfe/d—Million cubic feet equivalent per day

Net Acres—Gross acreage multiplied by working interest percentage

Net Production—Gross production multiplied by net revenue interest

NGL or NGLs—Natural gas liquids

Tcf—Trillion cubic feet

Tcfe—Trillion cubic feet equivalent

 

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

 

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

 

Throughout this Form 10-Q, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934.  These forward-looking statements include, among others, statements concerning our outlook with regard to timing and amount of future production of oil and gas, price realizations, amounts, nature and timing of capital expenditures for exploration and development, plans for funding operations and capital expenditures, drilling of wells, operating costs and other expenses, marketing of oil, gas, and NGLs and other statements of expectations, beliefs, future plans and strategies, anticipated events or trends, and similar expressions concerning matters that are not historical facts.  The forward-looking statements in this report are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by the statements.

 

These risks and uncertainties include, but are not limited to, fluctuations in the price we receive for our oil and gas production, reductions in the quantity of oil and gas sold due to decreased industry-wide demand and/or curtailments in production from specific properties or areas due to mechanical, transportation, marketing, weather or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated, and increased financing costs due to a significant increase in interest rates.  In addition, exploration and development opportunities that we pursue may not result in economic, productive oil and gas properties.  There are also numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures.  These and other risks and uncertainties affecting us are discussed in greater detail in this report and in our other filings with the Securities and Exchange Commission. 

 

 

3

 


 

PART I

 

ITEM 1 - Financial Statements

 

CIMAREX ENERGY CO.

Condensed Consolidated Balance Sheets

(Unaudited)

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

 

 

2014

 

2013

 

 

 

 

 

 

 

 

 

(in thousands, except share data)

Assets

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

563,657 

 

$

4,531 

Receivables, net

 

 

430,702 

 

 

367,754 

Oil and gas well equipment and supplies

 

 

93,012 

 

 

66,772 

Deferred income taxes

 

 

13,544 

 

 

16,854 

Derivative instruments

 

 

1,090 

 

 

4,268 

Prepaid expenses

 

 

6,603 

 

 

7,867 

Other current assets

 

 

1,929 

 

 

1,093 

Total current assets

 

 

1,110,537 

 

 

469,139 

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

 

 

 

 

 

 

Proved properties

 

 

13,842,214 

 

 

12,863,961 

Unproved properties and properties under development, not being amortized

 

 

865,058 

 

 

585,361 

 

 

 

14,707,272 

 

 

13,449,322 

Less — accumulated depreciation, depletion and amortization

 

 

(8,049,016)

 

 

(7,483,685)

Net oil and gas properties

 

 

6,658,256 

 

 

5,965,637 

Fixed assets, net

 

 

195,854 

 

 

146,918 

Goodwill

 

 

620,232 

 

 

620,232 

Other assets, net

 

 

59,215 

 

 

51,209 

 

 

$

8,644,094 

 

$

7,253,135 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable

 

$

123,388 

 

$

116,110 

Accrued liabilities

 

 

474,074 

 

 

412,495 

Derivative instruments

 

 

156 

 

 

389 

Revenue payable

 

 

218,025 

 

 

154,173 

Total current liabilities

 

 

815,643 

 

 

683,167 

Long-term debt

 

 

1,500,000 

 

 

924,000 

Deferred income taxes

 

 

1,710,662 

 

 

1,459,841 

Other liabilities

 

 

187,815 

 

 

163,919 

Total liabilities

 

 

4,214,120 

 

 

3,230,927 

Commitments and contingencies

 

 

 

 

 

 

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, 87,248,508 and 87,152,197 shares issued, respectively

 

 

872 

 

 

872 

Paid-in capital

 

 

1,988,257 

 

 

1,970,113 

Retained earnings

 

 

2,439,794 

 

 

2,050,034 

Accumulated other comprehensive income

 

 

1,051 

 

 

1,189 

 

 

 

4,429,974 

 

 

4,022,208 

 

 

$

8,644,094 

 

$

7,253,135 

 See accompanying notes to consolidated financial statements.

4

 


 

 

CIMAREX ENERGY CO.

Consolidated Statements of Income and Comprehensive Income

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months

 

For the Nine Months

 

 

Ended September 30,

 

Ended September 30,

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands, except per share data)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

Gas sales

 

$

176,539 

 

$

118,824 

 

$

519,139 

 

$

346,492 

Oil sales

 

 

348,276 

 

 

371,881 

 

 

1,028,229 

 

 

933,879 

NGL sales

 

 

111,701 

 

 

58,922 

 

 

297,128 

 

 

168,106 

Gas gathering and other

 

 

12,951 

 

 

11,380 

 

 

39,699 

 

 

32,951 

Gas marketing, net

 

 

273 

 

 

329 

 

 

1,430 

 

 

21 

 

 

 

649,740 

 

 

561,336 

 

 

1,885,625 

 

 

1,481,449 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

219,359 

 

 

159,182 

 

 

588,279 

 

 

442,851 

Asset retirement obligation

 

 

1,420 

 

 

1,797 

 

 

8,288 

 

 

7,080 

Production

 

 

89,084 

 

 

76,166 

 

 

250,310 

 

 

214,985 

Transportation, processing, and other operating

 

 

54,573 

 

 

25,838 

 

 

145,299 

 

 

66,494 

Gas gathering and other

 

 

8,588 

 

 

6,970 

 

 

27,413 

 

 

18,310 

Taxes other than income

 

 

33,510 

 

 

31,104 

 

 

99,454 

 

 

84,039 

General and administrative

 

 

20,240 

 

 

19,003 

 

 

57,523 

 

 

57,416 

Stock compensation

 

 

3,603 

 

 

3,347 

 

 

10,875 

 

 

10,459 

(Gain) loss on derivative instruments, net

 

 

(9,229)

 

 

10,824 

 

 

8,960 

 

 

(1,233)

Other operating, net

 

 

(181)

 

 

2,507 

 

 

34 

 

 

7,804 

 

 

 

420,967 

 

 

336,738 

 

 

1,196,435 

 

 

908,205 

Operating income

 

 

228,773 

 

 

224,598 

 

 

689,190 

 

 

573,244 

Other (income) and expense:

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

20,879 

 

 

13,954 

 

 

51,645 

 

 

41,272 

Capitalized interest

 

 

(10,005)

 

 

(7,286)

 

 

(25,870)

 

 

(23,868)

Other, net

 

 

(11,123)

 

 

(2,263)

 

 

(22,207)

 

 

(13,637)

Income before income tax

 

 

229,022 

 

 

220,193 

 

 

685,622 

 

 

569,477 

Income tax expense

 

 

84,707 

 

 

81,823 

 

 

254,210 

 

 

211,615 

Net income

 

$

144,315 

 

$

138,370 

 

$

431,412 

 

$

357,862 

Earnings per share to common stockholders:

 

 

 

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

 

 

 

 

 

Distributed

 

$

0.16 

 

$

0.14 

 

$

0.48 

 

$

0.42 

Undistributed

 

 

1.49 

 

 

1.45 

 

 

4.46 

 

 

3.70 

 

 

$

1.65 

 

$

1.59 

 

$

4.94 

 

$

4.12 

Diluted

 

 

 

 

 

 

 

 

 

 

 

 

Distributed

 

$

0.16 

 

$

0.14 

 

$

0.48 

 

$

0.42 

Undistributed

 

 

1.49 

 

 

1.45 

 

 

4.46 

 

 

3.70 

 

 

$

1.65 

 

$

1.59 

 

$

4.94 

 

$

4.12 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

144,315 

 

$

138,370 

 

$

431,412 

 

$

357,862 

Other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

(123)

 

 

302 

 

 

(139)

 

 

401 

Total comprehensive income

 

$

144,192 

 

$

138,672 

 

$

431,273 

 

$

358,263 

See accompanying notes to consolidated financial statements. 

5

 


 

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months

 

 

Ended September 30,

 

 

2014

 

2013

 

 

 

 

 

 

 

 

 

(in thousands)

Cash flows from operating activities:

 

 

 

 

 

 

Net income

 

$

431,412 

 

$

357,862 

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

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

588,279 

 

 

442,851 

Asset retirement obligation

 

 

8,288 

 

 

7,080 

Deferred income taxes

 

 

254,210 

 

 

211,615 

Stock compensation

 

 

10,875 

 

 

10,459 

(Gain) loss on derivative instruments

 

 

8,960 

 

 

(1,233)

Settlements on derivative instruments

 

 

(6,015)

 

 

(4,332)

Changes in non-current assets and liabilities

 

 

(1,873)

 

 

9,102 

Other, net

 

 

(2,384)

 

 

(685)

Changes in operating assets and liabilities:

 

 

 

 

 

 

Receivables, net

 

 

(63,091)

 

 

(88,131)

Other current assets

 

 

(26,110)

 

 

9,799 

Accounts payable and accrued liabilities

 

 

69,419 

 

 

(13,639)

Net cash provided by operating activities

 

 

1,271,970 

 

 

940,748 

Cash flows from investing activities:

 

 

 

 

 

 

Oil and gas expenditures

 

 

(1,630,929)

 

 

(1,165,555)

Sales of oil and gas assets

 

 

451,710 

 

 

37,707 

Sales of other assets

 

 

8,178 

 

 

31,252 

Other expenditures

 

 

(76,784)

 

 

(34,657)

Net cash used by investing activities

 

 

(1,247,825)

 

 

(1,131,253)

Cash flows from financing activities:

 

 

 

 

 

 

Net bank debt borrowings

 

 

(174,000)

 

 

150,000 

Proceeds from other long-term debt

 

 

750,000 

 

 

 —

Financing costs incurred

 

 

(11,616)

 

 

(100)

Dividends paid

 

 

(39,932)

 

 

(34,570)

Issuance of common stock and other

 

 

10,529 

 

 

10,168 

Net cash provided by financing activities

 

 

534,981 

 

 

125,498 

Net change in cash and cash equivalents

 

 

559,126 

 

 

(65,007)

Cash and cash equivalents at beginning of period

 

 

4,531 

 

 

69,538 

Cash and cash equivalents at end of period

 

$

563,657 

 

$

4,531 

 

See accompanying notes to consolidated financial statements.

 

 

6

 


 

Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2014

(Unaudited)

 

1.

Basis of Presentation

 

The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex”, “we”, or “us”) pursuant to rules and regulations of the Securities and Exchange Commission (SEC).  Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in Annual Reports on Form 10-K have been omitted.  Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our 2013 Annual Report on Form 10-K.

 

In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods and as of the dates shown.  We have evaluated subsequent events through the date of this filing.

 

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.  The primary components impacting this calculation are commodity prices, reserve quantities added and produced, overall exploration and development costs, depletion expense, and tax effects.  If the net capitalized cost of our oil and gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess would be charged to expense.  The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects.

 

At September 30, 2014, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.   However, a decline of 9% in the value of the ceiling limitation would have resulted in an impairment.  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 a full cost ceiling impairment related to our oil and gas properties in future quarters.

 

Oil, Gas and NGL sales

 

Oil, gas and NGL sales are based on the sales method by which revenue is recognized on actual volumes sold to purchasers.  There is a ready market for our products and sales occur soon after production.  The determination to record and separately disclose NGL volumes is based on the location at which both title contractually transfers from Cimarex to a buyer and the associated volumes can be physically quantified.  For those NGL volumes that we have recorded and disclosed separately, contractual title of the volumes has passed from Cimarex to a buyer at a point where the NGL volumes have been physically separated from the production stream.  Should title contractually transfer before NGL volumes can be physically separated and quantified (typically at the wellhead), we do not report separate NGL volumes and the value of the NGLs are included in the reported value of the disclosed gas volumes.

 

Under certain contracts, when NGLs are extracted from the gas stream, processors receive a portion of the sales value from both the residue gas and the NGLs as a processing fee and remit the contractual proceeds to us.  Prior to 2014,  revenue was recognized net of these processing fees for residue gas and NGLs sold under these contracts as allowed under EITF 00-10 Accounting for Shipping and Handling Fees and Costs.   Increasing NGL production combined with the impact of recent changes to these contracts has resulted in processing costs becoming more significant.  Accordingly, we have changed our policy to record these processing costs with operating costs as allowed under EITF 00-10.  Beginning in 2014, our realized prices for sales under these contracts reflect the value of 100% of the residue gas and NGLs yielded by processing, rather than the value associated with the contractual proceeds we received.  The related processing fees now are included in “transportation, processing and other operating costs.  The effect of this change in the current quarter and nine months ended was that total revenue was

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Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

$14.2 million and $38.2 million higher, respectively, with an offsetting increase in total transportation, processing and other operating costs.  There was no impact on operating income.  Financial statements for periods prior to 2014 have not been reclassified to reflect this change in accounting treatment as it was impracticable to do so.

 

Use of Estimates

 

Areas of significance requiring the use of management’s judgments relate to the estimation of proved oil and gas reserves, the use of proved reserves in calculating depletion, depreciation, and amortization (DD&A), estimates of future net revenues in computing ceiling test limitations and estimates of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill.  Estimates and judgments are also required in determining allowance for bad debt, impairments of undeveloped properties and other assets, purchase price allocation, valuation of deferred tax assets, fair value measurements, and contingencies.

 

Accounts Receivable, Accounts Payable, and Accrued Liabilities

 

The components of our accounts receivable, accounts payable, and accrued liabilities are shown below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(in thousands)

 

2014

 

2013

Receivables, net of allowance

 

 

 

 

 

 

Trade

 

$

95,243 

 

$

83,070 

Oil and gas sales

 

 

314,005 

 

 

265,050 

Gas gathering, processing, and marketing

 

 

21,265 

 

 

19,102 

Other

 

 

189 

 

 

532 

Receivables, net

 

$

430,702 

 

$

367,754 

 

 

 

 

 

 

 

Accounts payable

 

 

 

 

 

 

Trade

 

$

82,440 

 

$

80,918 

Gas gathering, processing, and marketing

 

 

40,948 

 

 

35,192 

Accounts payable

 

$

123,388 

 

$

116,110 

 

 

 

 

 

 

 

Accrued liabilities

 

 

 

 

 

 

Exploration and development

 

$

215,762 

 

$

173,298 

Taxes other than income

 

 

30,012 

 

 

27,509 

Other

 

 

228,300 

 

 

211,688 

Accrued liabilities

 

$

474,074 

 

$

412,495 

 

Recently Issued Accounting Standards

 

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606).  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 CodificationWe must comply with this ASU beginning in fiscal year 2017 and early adoption is not permitted.  Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach.  We are

8

 


 

Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

currently evaluating the impact of the provisions of Topic 606 and the effects of adoption cannot be determined at this time.

 

2.Derivative Instruments/Hedging

 

We periodically use derivative instruments to mitigate our exposure to a decline in commodity prices and the corresponding negative impact on cash flow available for reinvestment.  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.

 

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 hedging positions.

 

We have elected not to account for our derivatives as cash flow hedges.  Therefore, we recognize settlements and changes in the assets or liabilities relating to our open derivative contracts in earnings.  Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. 

 

The following tables summarize our outstanding derivative contracts as of September 30, 2014:

 

Oil Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Price

 

Fair Value

Period

 

Type

 

Volume/Day

 

Index (1)

 

Floor

 

Ceiling

 

(in thousands)

Oct 14 – Dec 14

 

Collars

 

12,000 Bbls

 

WTI

 

$

85.00 

 

$

103.47 

 

$

1,089 

(1)  WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

 

Gas Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Price

 

Fair Value

Period

 

Type

 

Volume/Day

 

Index (1)

 

Floor

 

Ceiling

 

(in thousands)

Oct 14 – Dec 14

 

Collars

 

80,000 MMBtu

 

PEPL

 

$

3.51 

 

$

4.57 

 

$

(81)

Oct 14 – Dec 14

 

Collars

 

60,000 MMBtu

 

Perm EP

 

$

3.62 

 

$

4.50 

 

$

(74)

(1)  PEPL refers to Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC.  Perm EP refers to El Paso Natural Gas Company, Permian Basin Index as quoted in Platt's Inside FERC.

 

Under a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor.  We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price.  No amounts are paid or received if the index price is between the floor and ceiling prices. 

 

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

The following table presents the net gains and (losses) from settlements and changes in fair value of our derivative contracts and the gains (losses) from settlements during the periods shown below.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) on derivative instruments, net

 

$

9,229 

 

$

(10,824)

 

$

(8,960)

 

$

1,233 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) from settlement of derivative instruments

 

$

(211)

 

$

(6,097)

 

$

(6,015)

 

$

(4,332)

 

Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs.  We estimate the fair value with internal risk-adjusted discounted cash flow calculations.  Cash flows are based on published forward commodity price curves for the underlying commodity as of the date of the estimate.  For collars, we estimate the option value of the contract floors and ceilings using an option pricing model, which takes into account market volatility, market prices, and contract terms.

 

The fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk and the fair value of instruments in a liability position includes a measure of our own non-performance risk.  These credit risks are based on current published credit default swap rates.

 

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price.

 

Our derivative instruments 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 policy is to not offset asset and liability positions in our accompanying balance sheets.

 

The following table presents the amounts and classifications of our derivative assets and liabilities as of September 30, 2014 and December 31, 2013, as well as the potential effect of netting arrangements on contracts with the same counterparty.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2014:

 

 

 

 

 

 

 

 

(in thousands)

 

Balance Sheet Location

 

Asset

 

Liability

Oil contracts

 

Current assets — Derivative instruments

 

$

1,089 

 

$

 —

Natural gas contracts

 

Current assets — Derivative instruments

 

 

 

 

 —

Natural gas contracts

 

Current liabilities — Derivative instruments

 

 

 —

 

 

156 

Total gross amounts presented in accompanying balance sheet

 

 

1,090 

 

 

156 

Less: gross amounts not offset in the accompanying balance sheet

 

 

(156)

 

 

(156)

Net amount:

 

 

 

$

934 

 

$

 —

 

 

 

 

 

 

 

 

 

December 31, 2013:

 

 

 

 

 

 

 

 

(in thousands)

 

Balance Sheet Location

 

Asset

 

Liability

Oil contracts

 

Current assets — Derivative instruments

 

$

1,805 

 

$

 —

Natural gas contracts

 

Current assets — Derivative instruments

 

 

2,463 

 

 

 —

Oil contracts

 

Current liabilities — Derivative instruments

 

 

 —

 

 

389 

Total gross amounts presented in accompanying balance sheet

 

 

4,268 

 

 

389 

Less: gross amounts not offset in the accompanying balance sheet

 

 

(389)

 

 

(389)

Net amount:

 

 

 

$

3,879 

 

$

 —

 

We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties.  We have mitigated our exposure to any single counterparty by contracting with a number of

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

financial institutions, each of which has a high credit rating and is a member of our bank credit facility.  Our member banks do not require us to post collateral for our hedge liability positions.  Because some of the member banks have discontinued hedging activities, in the future we may hedge with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

 

3.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.

 

The following tables provide fair value measurement information for certain assets and liabilities as of September 30, 2014 and December 31, 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2014:

 

Carrying

 

Fair

(in thousands)

 

Amount

 

Value

Financial Assets (Liabilities):

 

 

 

 

 

 

5.875% Notes due 2022

 

$

(750,000)

 

$

(810,000)

4.375% Notes due 2024

 

$

(750,000)

 

$

(755,775)

Derivative instruments — assets

 

$

1,090 

 

$

1,090 

Derivative instruments — liabilities

 

$

(156)

 

$

(156)

 

 

 

 

 

 

 

December 31, 2013:

 

Carrying

 

Fair

(in thousands)

 

Amount

 

Value

Financial Assets (Liabilities):

 

 

 

 

 

 

Bank debt

 

$

(174,000)

 

$

(174,000)

5.875% Notes due 2022

 

$

(750,000)

 

$

(799,988)

Derivative instruments — assets

 

$

4,268 

 

$

4,268 

Derivative instruments — liabilities

 

$

(389)

 

$

(389)

 

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 following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above.

 

Debt (Level 1)

 

The fair value of our bank debt at December 31, 2013 was estimated to approximate the carrying amount because the floating rate interest paid on such debt was set for periods of three months or less.

 

The fair value for our 4.375% and 5.875% fixed rate notes was based on their last traded value before period end.

 

Derivative Instruments (Level 2)

 

The fair value of our derivative instruments was estimated using internal discounted cash flow calculations.  Cash flows are based on the stated contract prices and current and published forward commodity price

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

curves, adjusted for volatility.  The cash flows are risk adjusted relative to non-performance for both our counterparties and our liability positions.  Please see Note 2 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.

 

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, 2014 and December 31, 2013, the allowance for doubtful accounts was $3.1 million and $6.0 million, respectively.

 

4.Capital Stock

 

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock.  At September 30, 2014, there were no shares of preferred stock outstanding.  A summary of our common stock activity for the nine months ended September 30, 2014 follows:

 

 

 

 

 

 

 

 

(in thousands)

 

 

Issued and outstanding as of December 31, 2013

 

87,152 

Issuance of restricted stock awards

 

160 

Common stock reacquired and retired

 

(117)

Restricted stock forfeited and retired

 

(132)

Option exercises, net of cancellations

 

185 

Issued and outstanding as of September 30, 2014

 

87,248 

 

Dividends

 

In September 2014, the Board of Directors declared a cash dividend of $0.16 per share.  The dividend is payable on December 1, 2014 to stockholders of record on November 14, 2014.  Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by the Board of Directors.

 

5.Stock-based Compensation

 

In May 2014, our 2014 Equity Incentive Plan (the 2014 Plan) was approved by stockholders and our previous plan was terminated at that time.  Outstanding awards under the previous plan were not impacted.  The primary purposes of the 2014 Plan are to increase the number of shares available in connection with awards, provide flexibility in the types of available awards and design of awards, modify certain individual award limits and revise the performance measures for qualified performance-based awards.  The 2014 Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, dividend equivalents and other stock-based awards.  A total of 6.6 million shares of common stock may be issued under the 2014 Plan, including shares available from the previous plan.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

 

We have recognized non-cash stock-based compensation cost as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

Restricted stock

 

$

5,825 

 

$

5,329 

 

$

18,255 

 

$

17,252 

Stock options

 

 

847 

 

 

940 

 

 

2,402 

 

 

2,355 

 

 

 

6,672 

 

 

6,269 

 

 

20,657 

 

 

19,607 

Less amounts capitalized to oil and gas properties

 

 

(3,069)

 

 

(2,922)

 

 

(9,782)

 

 

(9,148)

Compensation expense

 

$

3,603 

 

$

3,347 

 

$

10,875 

 

$

10,459 

 

Historical amounts may not be representative of future amounts as additional awards may be granted.

 

Restricted Stock and Units

 

The following tables provide information about restricted stock awards granted during the three and nine months ended September 30, 2014 and 2013.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

Three Months Ended

 

 

 

September 30, 2014

 

 

September 30, 2013

 

 

 

 

 

Weighted

 

 

 

 

Weighted

 

 

 

 

 

Average

 

 

 

 

Average

 

 

 

Number

 

Grant-Date

 

 

Number

 

Grant-Date

 

 

 

of Shares

 

Fair Value

 

 

of Shares

 

Fair Value

Performance stock awards

 

 

 —

 

$

 —

 

 

26,000 

 

$

56.85 

Service-based stock awards

 

 

146,750 

 

$

139.02 

 

 

228,200 

 

$

72.83 

Total restricted stock awards

 

 

146,750 

 

$

139.02 

 

 

254,200 

 

$

71.20 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

Nine Months Ended

 

 

 

September 30, 2014

 

 

September 30, 2013

 

 

 

 

 

Weighted

 

 

 

 

Weighted

 

 

 

 

 

Average

 

 

 

 

Average

 

 

 

Number

 

Grant-Date

 

 

Number

 

Grant-Date

 

 

 

of Shares

 

Fair Value

 

 

of Shares

 

Fair Value

Performance stock awards

 

 

 —

 

$

 —

 

 

26,000 

 

$

56.85 

Service-based stock awards

 

 

160,402 

 

$

138.02 

 

 

277,236 

 

$

72.49 

Total restricted stock awards

 

 

160,402 

 

$

138.02 

 

 

303,236 

 

$

71.15 

   

Performance awards have been granted to eligible executives and are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance.  After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award.  In accordance with Internal Revenue Code Section 162(m), certain of the amounts awarded may not be deductible for tax purposes.  Service-based stock awards granted to other eligible employees and non-employee directors have vesting schedules of three to five years.

 

Compensation cost for the performance stock awards is based on the grant-date fair value of the award utilizing a Monte Carlo simulation model.  Compensation cost for the service-based vesting restricted shares is

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

based upon the grant-date market value of the award.  Such costs are recognized ratably over the applicable vesting period.

 

The following table reflects the non-cash compensation cost related to our restricted stock:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

Performance stock awards

 

$

2,900 

 

$

2,710 

 

$

8,714 

 

$

7,963 

Service-based stock awards

 

 

2,925 

 

 

2,619 

 

 

9,541 

 

 

9,289 

 

 

 

5,825 

 

 

5,329 

 

 

18,255 

 

 

17,252 

Less amounts capitalized to oil and gas properties

 

 

(2,695)

 

 

(2,491)

 

 

(8,766)

 

 

(8,229)

Restricted stock compensation expense

 

$

3,130 

 

$

2,838 

 

$

9,489 

 

$

9,023 

 

Unrecognized compensation cost related to unvested restricted shares at September 30, 2014 was $64.1 million, which we expect to recognize over a weighted average period of approximately 2.3 years.

 

The following table provides information on restricted stock and unit activity as of September 30, 2014 and changes during the year.  A restricted unit held by an employee represents a right to an unrestricted share of common stock upon completion of defined vesting and holding periods.  A restricted unit held by a non-employee director represents an election to defer payment of director fees until the time specified by the director in his deferred compensation agreement.  The remaining outstanding restricted units shown below represent restricted units held by a non-employee director who has elected to defer payment of common stock represented by the units until termination of his service on the Board of Directors.

 

 

 

 

 

 

 

 

 

 

 

 

Restricted

 

Restricted

 

 

Stock

 

Units

Outstanding as of January 1, 2014

 

1,863,834 

 

8,838 

Vested

 

(287,047)

 

N/A

Converted to stock

 

N/A

 

 —

Granted

 

160,402 

 

 —

Canceled

 

(132,068)

 

 —

Outstanding as of September 30, 2014

 

1,605,121 

 

8,838 

Vested included in outstanding

 

N/A

 

8,838 

 

Stock Options

 

The following table provides information about stock options granted in 2014 and 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three and Nine

 

Three and Nine

 

 

Months Ended

 

Months Ended

 

 

September 30,

 

September 30,

 

 

2014

 

2013

Options

 

 

82,500 

 

 

144,400 

Weighted average grant-date fair value

 

$

41.69 

 

$

21.64 

Weighted average exercise price

 

$

139.02 

 

$

72.25 

 

Options that have been granted under the 2014 plan and previous plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years.  The exercise price for an option under the

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

2014 plan is the closing price of our common stock as reported by the New York Stock Exchange on the date of grant. The previous plans provided that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. 

 

Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period.  We estimate the fair value using the Black-Scholes option-pricing model.  Expected volatilities are based on the historical volatility of our common stock.  We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures.  We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.

 

Non-cash compensation cost related to our stock options is reflected in the following table:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

Stock option awards

 

$

847 

 

$

940 

 

$

2,402 

 

$

2,355 

Less amounts capitalized to oil and gas properties

 

 

(374)

 

 

(431)

 

 

(1,016)

 

 

(919)

Stock option compensation expense

 

$

473 

 

$

509 

 

$

1,386 

 

$

1,436 

 

As of September 30, 2014, there was $4.7 million of unrecognized compensation cost related to non-vested stock options.  We expect to recognize that cost pro rata over a weighted-average period of approximately 2.0 years.

 

Information about outstanding stock options is summarized below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted

 

Weighted

 

Aggregate

 

 

 

 

Average

 

Average

 

Intrinsic

 

 

 

 

Exercise

 

Remaining

 

Value

 

 

Options

 

Price

 

Term

 

(in thousands)

Outstanding as of January 1, 2014

 

531,016 

 

$

59.78 

 

 

 

 

 

 

Granted

 

82,500 

 

$

139.02 

 

 

 

 

 

 

Exercised

 

(185,258)

 

$

56.83 

 

 

 

 

 

 

Forfeited

 

(17,509)

 

$

71.39 

 

 

 

 

 

 

Outstanding as of September 30, 2014

 

410,749 

 

$

76.53 

 

5.2 

Years

 

$

22,092 

Exercisable as of September 30, 2014

 

204,926 

 

$

58.37 

 

4.3 

Years

 

$

14,306 

 

The following table provides information regarding the options exercised and the grant-date fair value of options vested:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine months ended

 

 

September 30,

(dollars in thousands)

 

2014

 

2013

Number of options exercised

 

 

185,258 

 

 

201,295 

Cash received from option exercises

 

$

10,529 

 

$

10,168 

Intrinsic value of options exercised

 

$

13,872 

 

$

6,811 

Grant-date fair value of options vested

 

$

4,419 

 

$

2,521 

 

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Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

The following table provides information on non-vested stock option activity as of September 30, 2014 and changes during the year:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted

 

Weighted

 

 

 

 

Average

 

Average

 

 

 

 

Grant-Date

 

Exercise

 

 

Options

 

Fair Value

 

Price

Non-vested as of January 1, 2014

 

343,014 

 

$

21.64 

 

$

63.81 

Granted

 

82,500 

 

$

41.69 

 

$

139.02 

Vested

 

(202,182)

 

$

21.86 

 

$

62.48 

Forfeited

 

(17,509)

 

$

23.34 

 

$

71.39 

Non-vested as of September 30, 2014

 

205,823 

 

$

29.32 

 

$

94.62 

 

 

 

6.Asset Retirement Obligations

 

We recognize 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 required to be accreted each period.  If the fair value of a recorded asset retirement obligation changes, 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 DD&A calculations.

 

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, 2014:

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

Asset retirement obligation at January 1, 2014

 

$

154,026 

Liabilities incurred

 

 

10,022 

Liability settlements and disposals

 

 

(22,675)

Accretion expense

 

 

5,669 

Revisions of estimated liabilities

 

 

23,286 

Asset retirement obligation at September 30, 2014

 

 

170,328 

Less current obligation

 

 

(16,387)

Long-term asset retirement obligation

 

$

153,941 

 

During the first nine months of 2014, the liability settlements and disposals included $11.1 million related to properties that were sold.  Also during this period we recognized revisions of estimated liabilities totaling $23.3 million, which were due to changes in abandonment cost and timing estimates.

 

 

16

 


 

Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

 

7.Long-Term Debt

 

Debt at September 30, 2014 and December 31, 2013 consisted of the following:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(in thousands)

 

2014

 

2013

Bank debt

 

$

 —

 

$

174,000 

5.875% Senior Notes due 2022

 

 

750,000 

 

 

750,000 

4.375% Senior Notes due 2024

 

 

750,000 

 

 

 —

Total long-term debt

 

$

1,500,000 

 

$

924,000 

 

Bank Debt

 

In May 2014, we amended our senior unsecured revolving credit facility (Credit Facility) to extend the maturity date two years to July 14, 2018 and lowered the margins applicable to loans and commitments.  The amendment also raised our borrowing base from $2.25 billion to $2.5 billion until the next regular annual redetermination date scheduled for April 15, 2015.  The borrowing base under the Credit Facility is determined at the discretion of the lenders based on the value of our proved reserves.  Our aggregate commitments remained unchanged at $1 billion. 

 

As of September 30, 2014, we had letters of credit outstanding under the Credit Facility of $2.5 million, leaving an unused borrowing availability of $997.5 million.

 

At our option, borrowings under the Credit Facility, as amended in May 2014, may bear interest at either (a) LIBOR plus 1.5-2.25%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.5-1.25%, based on our leverage ratio.

 

The Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0.  We also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and non-cash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5.  Other covenants could limit our ability to incur additional indebtedness, pay dividends, repurchase our common stock, or sell assets.  As of September 30, 2014, we were in compliance with all of the financial and non-financial covenants.

 

5.875% Notes due 2022

 

In April 2012, we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May and November.  The notes were sold to the public at par.  The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions.  We may redeem the notes in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and thereafter.

 

17

 


 

Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

4.375% Notes due 2024

 

In June 2014, we issued $750 million of 4.375% senior notes due June 1, 2024, with interest payable semiannually in June and December.  The notes were sold to the public at par.  The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. At any time prior to March 1, 2024, we may redeem all or a part of the notes at a defined make-whole redemption price calculated at the time of redemption.  At any time on or after March 1, 2024, we may redeem all or part of the notes at a price equal to 100% of the principal amount.

 

8.Income Taxes

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

(in thousands)

 

2014

 

2013

 

2014

 

2013

 

Current benefit

 

$

 —

 

$

 —

 

$

 —

 

$

 —

 

Deferred taxes

 

 

84,707 

 

 

81,823 

 

 

254,210 

 

 

211,615 

 

 

 

$

84,707 

 

$

81,823 

 

$

254,210 

 

$

211,615 

 

Combined Federal and State effective income tax rate

 

 

37.0 

%

 

37.2 

%

 

37.1 

%

 

37.2 

%

 

At December 31, 2013, we had a U.S. net tax operating loss carryforward of approximately $605.4 million, which would expire in tax years 2031 through 2033.  We believe that the carryforward will be utilized before it expires.  The amount of U.S. net tax operating loss carryforward that will be recorded to equity when utilized to reduce taxes payable is $56.4 million.  We also had an alternative minimum tax credit carryforward of approximately $4.1 million.

 

At September 30, 2014, 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 2011 through 2013 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 the 2010 through 2013 tax years.

 

Our provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and non-deductible expenses.

 

9.Supplemental Disclosure of Cash Flow Information

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Nine months ended

 

 

September 30,

 

September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

Cash paid during the period for:

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense (including capitalized amounts)

 

$

835 

 

$

1,932 

 

$

27,125 

 

$

27,158 

Interest capitalized

 

$

30 

 

$

394 

 

$

13,587 

 

$

15,706 

Income taxes

 

$

 —

 

$

 —

 

$

354 

 

$

205 

Cash received for income taxes

 

$

 —

 

$

213 

 

$

342 

 

$

450 

 

 

 

18

 


 

Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

10.Earnings per Share

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Nine months ended

 

 

September 30,

 

September 30,

(in thousands, except per share data)

 

2014

 

2013

 

2014

 

2013

Basic:

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

144,315 

 

$

138,370 

 

$

431,412 

 

$

357,862 

Participating securities’ share in earnings

 

 

(2,411)

 

 

(2,375)

 

 

(7,206)

 

 

(6,049)

Net income applicable to common stockholders

 

$

141,904 

 

$

135,995 

 

$

424,206 

 

$

351,813 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

144,315 

 

$

138,370 

 

$

431,412 

 

$

357,862 

Participating securities’ share in earnings

 

 

(2,407)

 

 

(2,371)

 

 

(7,194)

 

 

(6,041)

Net income applicable to common stockholders

 

$

141,908 

 

$

135,999 

 

$

424,218 

 

$

351,821 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shares:

 

 

 

 

 

 

 

 

 

 

 

 

Basic shares outstanding

 

 

85,643 

 

 

85,213 

 

 

85,643 

 

 

85,213 

Incremental shares from assumed exercise of stock options

 

 

136 

 

 

134 

 

 

145 

 

 

117 

Fully diluted common stock

 

 

85,779 

 

 

85,347 

 

 

85,788 

 

 

85,330 

Excluded (1)

 

 

83 

 

 

232 

 

 

87 

 

 

254 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings per share to common stockholders (2):

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

1.65 

 

$

1.59 

 

$

4.94 

 

$

4.12 

Diluted

 

$

1.65 

 

$

1.59 

 

$

4.94 

 

$

4.12 

(1)  Inclusion of certain outstanding stock options would have an anti-dilutive effect. 

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

 

11.Commitments and Contingencies

 

Commitments

 

We have commitments of $212.8 million to finish drilling and completing wells in progress at September 30, 2014.  We also have various commitments for drilling rigs.  The total minimum expenditure commitments under these agreements are $53.7 million.

 

In New Mexico and Texas, we are constructing gathering facilities and pipelines.  At September 30, 2014, we had commitments of $5.9 million relating to these construction projects.

 

At September 30, 2014, we had firm sales contracts to deliver approximately 45.2 Bcf of natural gas over the next 15 months.  If this gas is not delivered, our financial commitment would be approximately $166.6 million.  This commitment will fluctuate due to price volatility and actual volumes delivered.  However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these obligations.

19

 


 

Table of Contents

 

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2014

(Unaudited)

 

 

We have various other transportation and delivery commitments in the normal course of business, which approximate $1.2 million over the next two years.

 

We have various commitments for office space and equipment under operating lease arrangements totaling $126.0 million for the next five years and beyond.

 

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

 

Litigation

 

In the ordinary course of business, we have various litigation matters.  We assess the probability of estimable amounts related to litigation 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. 

 

H.B. Krug, et al versus H&P

 

In the H.B. Krug, et al. v. Helmerich & Payne, Inc. (H&P) case, on December 13, 2013 the Oklahoma Supreme Court reversed the Tulsa County District Court’s original judgment of $119.6 million and affirmed an alternative jury verdict for $3.65 million.  It also remanded the case back to the trial court for consideration of potential prejudgment interest, attorney’s fees and cost awards.  Accordingly, on December 31, 2013 we reduced the previously recognized litigation expense and the associated long-term liability by $142.8 million.

 

On April 1, 2014, Cimarex paid the Plaintiffs $15.8 million in satisfaction of the $3.65 million damages award, the post-judgment interest award and the payment in lieu of bond, all of which are now final and not appealable.  On June 24, 2014, the trial court ruled the Plaintiffs were not entitled to prejudgment interest but were entitled to attorney’s fees and costs, the amount of which will be determined at a subsequent hearing.  On July 31, 2014, the Plaintiffs appealed the trial court’s denial of prejudgment interest, which will be determined by the Oklahoma Supreme Court.  The outcome of these remaining issues cannot be determined, and our current estimates and assessments likely will change, as a result of these future legal proceedings.

 

 

 

12.Property Acquisitions and Sales

The following acquisitions and sales were made in the ordinary course of business.

During the first nine months of 2014, we made property acquisitions totaling $259.2 million, most of which were in our Cana-Woodford shale play in Western Oklahoma.  During the same period of 2013, we had property acquisitions of $6.2 million.

We sold interests in various non-core oil and gas properties for $447.5 million during the first nine months of 2014. Most of the proceeds were related to sales of producing gas wells in southwestern Kansas and undeveloped acreage in Reagan County, Texas.  In the first nine months of 2013, we sold interests in non-core oil and gas properties for $37.7 million. During the second quarter of 2013, we also sold a 50% interest in our Culberson County, Texas Triple Crown gas gathering and processing system for approximately $31 million.

 

 

20

 


 

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.

 

Our principal business objective is to profitably grow proved reserves and production for the long-term benefit of our stockholders through a diversified drilling portfolio.  Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development.  We occasionally consider property acquisitions and mergers to enhance our competitive position.

 

In order to achieve a consistent rate of growth and mitigate risk, we have historically maintained a portfolio of exploration and development projects targeting both oil and gas.  We seek geologic and geographic diversification by operating in multiple basins.  In recent years, we have shifted our capital expenditures to oil and liquids-rich gas projects because of strong oil prices relative to gas prices.  We deal with volatility in commodity prices by maintaining flexibility in our capital investment program.

 

Our operations are currently focused in two main areas:  the Permian Basin and the Mid-Continent region.  The Permian Basin region encompasses west Texas and southeast New Mexico.  The Mid-Continent region consists of Oklahoma and the Texas Panhandle. 

 

Growth is generally funded with cash flow provided by operating activities together with bank borrowings, sales of non-strategic assets and occasional public financing.  Conservative use of leverage and maintaining a strong balance sheet have long been part of our financial strategy.  We have a long track record of profitable growth.

 

Third quarter 2014 summary of operating and financial results: 

·

Total average daily production grew 31% to 942.4 MMcfe/d.

·

Oil production grew 10%, gas production was up by 35% and NGL volumes increased by 59%.

·

Oil, gas and NGL sales totaled $636.5 million, 16% higher than a year earlier.

·

Net income was $144.3 million ($1.65 per diluted share) versus $138.4 million ($1.59 per diluted share) a year ago.

·

Exploration and development expenditures for the quarter totaled $459.6 million.

·

Cash flow provided by operating activities during the first nine months of 2014 increased 35% to $1.272 billion compared to $940.7 million for the same period of 2013.

·

Total debt at September 30, 2014 was $1.5 billion.

 

Revenues

 

Almost all of our revenues are derived from the sales of oil, 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 we receive are determined by prevailing market conditions.  Regional and worldwide economic and geopolitical activity, weather and other factors influence market conditions, which often result in significant volatility in commodity prices.

 

Oil sales contributed 56% of our total production revenue for the first nine months of 2014. Gas sales accounted for 28% and NGL sales were 16%. A $1.00 per barrel change in our realized oil price would have resulted in an $11.3 million change in revenues. A $0.10 per Mcf change in our realized gas price would have resulted in an $11.2 million change in our gas revenues. A $1.00 per barrel change in NGL prices would have changed revenues by $8.2 million.

21

 


 

The following table presents our average realized commodity prices and major U.S. index prices.  Our average realized prices do not include settlements of commodity derivative contracts.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Nine months ended

 

 

September 30,

 

September 30,

 

 

2014

 

2013

 

2014

 

2013

Oil Prices:

 

 

 

 

 

 

 

 

 

 

 

 

Average realized sales price ($/Bbl)

 

$

87.27 

 

$

102.88 

 

$

90.87 

 

$

93.81 

Average WTI Midland price ($/Bbl)

 

$

86.93 

 

$

105.47 

 

$

91.64 

 

$

96.96 

Average WTI Cushing price ($/Bbl)

 

$

97.15 

 

$

105.81 

 

$

99.61 

 

$

98.14 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Prices:

 

 

 

 

 

 

 

 

 

 

 

 

Average realized sales price ($/Mcf)

 

$

4.10 

 

$

3.72 

 

$

4.62 

 

$

3.73 

Average Henry Hub price ($/Mcf)

 

$

4.07 

 

$

3.58 

 

$

4.57 

 

$

3.67 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Prices:

 

 

 

 

 

 

 

 

 

 

 

 

Average realized sales price ($/Bbl)

 

$

34.08 

 

$

28.63 

 

$

36.10 

 

$

28.57 

 

Approximately 80% of our oil production is in the Permian Basin, the sale of which is tied to the WTI Midland benchmark price.  Due to greater industry-wide production in the area, related oil prices have declined relative to WTI Cushing benchmark prices.  In the third quarter of 2014, the average Midland index price was $10.22 per barrel lower than the average Cushing index price.  In the third quarter of 2013, the average Midland price was only $0.34 per barrel lower than the average Cushing prices.  The average Midland index price was lower than the Cushing price for the first nine months of 2014 by $7.97 per barrel versus $1.18 lower for the same period of 2013.  The declines in the Midland benchmark prices resulted in our lower realized oil prices in 2014.

 

Prior to 2014, our average realized prices for gas and NGLs were net of certain processing fees.  Beginning in 2014, these fees are no longer included in realized prices.  The resulting positive impact on gas prices for the three and nine months ended September 30, 2014 was $0.07 per Mcf and $0.08 per Mcf, respectively.  The positive impact on NGL prices was $3.43 per Bbl and $3.60 per Bbl for the three and nine months ended September 30, 2014, respectively.  These positive impacts to prices were offset by increased transportation, processing and other operating costs.  (See Results of Operations below and Note 1, Basis of Presentation – Oil, Gas and NGL Sales, to the Consolidated Financial Statements in this report for additional information regarding these processing fees.)

 

The impact of changes in realized prices is discussed below under RESULTS OF OPERATIONS.

 

Production and other operating expenses

 

Costs associated with producing oil and gas are substantial.  Some of these costs vary with commodity prices, some trend with the type and volume of production and some are a function of the number of wells we own. 

 

Production expense generally consists of costs for labor, equipment, maintenance, salt water disposal, compression, power, treating and miscellaneous other items.  Production expense also includes well workover activity necessary to maintain production from existing wells.

 

Transportation, processing and other operating costs principally consists of expenditures to prepare and transport production from the wellhead to a specified sales point and gas processing costs.  These costs vary by region and will fluctuate with increases or decreases in production volumes and changes in fuel and compression costs.

 

Depreciation, depletion and amortization (DD&A) 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

22

 


 

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 DD&A rate.  In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, and reclassifications of properties from unproved to proved will impact depletion expense.

 

We use the full cost method of accounting for our oil and gas properties.  Accounting rules require us to perform a quarterly ceiling test calculation to test our oil and gas properties for possible impairment.  The primary components impacting this analysis are commodity prices, reserve quantities added and produced, overall exploration and development costs, depletion expense, and tax effects.  If the net capitalized cost of our oil and gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess would be expensed.  The ceiling limitation is equal to the sum of (a) the present value discounted at 10% of estimated future net cash flows from proved reserves, (b) the cost of properties not being amortized, (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and (d) all related tax effects.

 

At September 30, 2014, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.  However, a decline of 9% in the value of the ceiling limitation would have resulted in an impairment.  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 a full cost ceiling impairment related to our oil and gas properties in future quarters.  An impairment charge would have no effect on liquidity or our capital resources, but it could adversely affect our results of operations in the period incurred.

 

General and administrative (G&A) expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices and 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.

 

 Since 2009, we have chosen not to apply hedge accounting treatment to our derivative instruments.  As a result, any settlements on the contracts are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments.

 

 

RESULTS OF OPERATIONS

 

Three Months and Nine Months Ended September 30, 2014 vs. September 30, 2013

 

Net income for the third quarter of 2014 was $144.3 million ($1.65 per diluted share), up 4% from $138.4 million ($1.59 per diluted share) for the same period of 2013.  For the first nine months of 2014, net income of $431.4 million ($4.94 per diluted share) was 21% greater than net income of $357.9 million ($4.12 per diluted share) for the same period of 2013.  The increases in net income for the 2014 periods resulted from increased production volumes and higher realized prices for natural gas and NGLs, which were partially offset by higher operating expenses and income taxes compared to the 2013 periods.  These changes are discussed further in the analysis that follows.

23

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Percent

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Change

 

 

 

 

 

 

 

 

 

Production Revenue

 

 

 

 

 

 

Between

 

Price/Volume Change

(in thousands or as indicated)

2014

 

2013

 

2014 / 2013

 

Price

 

Volume

 

Total

For the Three Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

$

348,276 

 

$

371,881 

 

(6)

%

 

$

(62,300)

 

$

38,695 

 

$

(23,605)

Gas sales

 

176,539 

 

 

118,824 

 

49 

%

 

 

16,376 

 

 

41,339 

 

 

57,715 

NGL sales

 

111,701 

 

 

58,922 

 

90 

%

 

 

17,865 

 

 

34,914 

 

 

52,779 

 

$

636,516 

 

$

549,627 

 

16 

%

 

$

(28,059)

 

$

114,948 

 

$

86,889 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

$

1,028,229 

 

$

933,879 

 

10 

%

 

$

(33,269)

 

$

127,619 

 

$

94,350 

Gas sales

 

519,139 

 

 

346,492 

 

50 

%

 

 

100,023 

 

 

72,624 

 

 

172,647 

NGL sales

 

297,128 

 

 

168,106 

 

77 

%

 

 

61,979 

 

 

67,043 

 

 

129,022 

 

$

1,844,496 

 

$

1,448,477 

 

27 

%

 

$

128,733 

 

$

267,286 

 

$

396,019 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Percent

 

 

 

 

 

 

 

Percent

 

 

For the Three Months

 

Change

 

For the Nine Months

 

Change

 

 

Ended September 30,

 

Between

 

Ended September 30,

 

Between

 

 

2014

 

2013

 

2014 / 2013

 

2014

 

2013

 

2014 / 2013

Total oil volume — thousand barrels

 

 

3,991 

 

 

3,615 

 

10 

%

 

 

11,316 

 

 

9,955 

 

14 

%

Oil volume — barrels per day

 

 

43,376 

 

 

39,292 

 

10 

%

 

 

41,450 

 

 

36,464 

 

14 

%

Average oil price — per barrel

 

$

87.27 

 

$

102.88 

 

(15)

%

 

$

90.87 

 

$

93.81 

 

(3)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gas volume — MMcf

 

 

43,094 

 

 

31,908 

 

35 

%

 

 

112,385 

 

 

92,914 

 

21 

%

Gas volume — MMcf per day

 

 

468.4 

 

 

346.8 

 

35 

%

 

 

411.7 

 

 

340.3 

 

21 

%

Average gas price — per Mcf

 

$

4.10 

 

$

3.72 

 

10 

%

 

$

4.62 

 

$

3.73 

 

24 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total NGL volume — thousand barrels

 

 

3,278 

 

 

2,058 

 

59 

%

 

 

8,231 

 

 

5,883 

 

40 

%

NGL volume — barrels per day

 

 

35,627 

 

 

22,373 

 

59 

%

 

 

30,151 

 

 

21,550 

 

40 

%

Average NGL price — per barrel

 

$

34.08 

 

$

28.63 

 

19 

%

 

$

36.10 

 

$

28.57 

 

26 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total equivalent production volumes — MMcfe per day

 

 

942.4 

 

 

716.8 

 

31 

%

 

 

841.3 

 

 

688.4 

 

22 

%

 

24

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months

 

For the Nine Months

 

 

Ended September 30,

 

Ended September 30,

 

 

2014

 

2013

 

2014

 

2013

Oil (Bbls per day)

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

 

34,299 

 

 

31,993 

 

 

33,090 

 

 

29,343 

Mid-Continent

 

 

8,158 

 

 

5,801 

 

 

7,166 

 

 

5,944 

Other

 

 

919 

 

 

1,498 

 

 

1,194 

 

 

1,177 

 

 

 

43,376 

 

 

39,292 

 

 

41,450 

 

 

36,464 

Gas (MMcf per day)

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

 

126.6 

 

 

102.5 

 

 

117.6 

 

 

93.9 

Mid-Continent

 

 

333.3 

 

 

230.2 

 

 

284.9 

 

 

232.6 

Other

 

 

8.5 

 

 

14.1 

 

 

9.2 

 

 

13.8 

 

 

 

468.4 

 

 

346.8 

 

 

411.7 

 

 

340.3 

NGL (Bbls per day)

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

 

12,634 

 

 

9,575 

 

 

11,144 

 

 

7,643 

Mid-Continent

 

 

22,604 

 

 

12,090 

 

 

18,475 

 

 

13,129 

Other

 

 

389 

 

 

708 

 

 

532 

 

 

778 

 

 

 

35,627 

 

 

22,373 

 

 

30,151 

 

 

21,550 

Total Equivalent (MMcfe per day)

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

 

408.1 

 

 

352.0 

 

 

383.0 

 

 

315.9 

Mid-Continent

 

 

517.9 

 

 

337.6 

 

 

438.8 

 

 

347.0 

Other

 

 

16.4 

 

 

27.2 

 

 

19.5 

 

 

25.5 

 

 

 

942.4 

 

 

716.8 

 

 

841.3 

 

 

688.4 

 

Third quarter 2014 production revenue increased 16% to $636.5 million compared to $549.6 million for the same quarter of last year.  For the first nine months of 2014, revenue from our production totaled $1.844 billion, up 27% from $1.448 billion for the same period of 2013.  Increased production volumes together with higher realized prices for natural gas and NGLs resulted in the year-over-year improvements.

 

Third quarter 2014 aggregate production volumes averaged 942.4 MMcfe/d, up 31% from 716.8 MMcfe/d for the third quarter of 2013.  Average production volumes for the first nine months of 2014 were 841.3 MMcfe/d, up 22% from 688.4 MMcfe/d for the comparable 2013 period.  Ongoing development drilling and workover activity in our Mid-Continent and Permian Basin core areas drove production volume growth.

 

Oil production for the third quarter of 2014 averaged 43,376 Bbl/d, up 10% from 39,292 Bbl/d in 2013.  The growth in 2014 volume provided an additional $38.7 million of oil revenue. During the first nine months of 2014, our oil production averaged 41,450 Bbl/d, up from 36,464 Bbl/d in the 2013 period.  The 14% increase contributed $127.6 million of additional revenue during the first nine months of 2014Our Permian Basin and Mid-Continent regions contributed equally to the increases in 2014 production.

 

Third quarter 2014 gas production averaged 468.4 MMcf/d, compared to 346.8 MMcf/d in 2013.  The 35% year-over-year increase resulted in additional revenue of $41.3 million.  During the first nine months of 2014 our gas production averaged 411.7 MMcf/d, up 21% from the first nine months of 2013 average of 340.3 MMcf/d.  The increase in gas production accounted for $72.6 million of additional revenue for the first nine months of 2014.  Most of the increases in 2014 gas production came from the Cana-Woodford area of the Mid-Continent region.

 

Third quarter 2014 NGL production volumes averaged 35,627 Bbl/d and were 59% greater than 22,373 Bbl/d for 2013.   The increase contributed $34.9 million of additional revenue and accounted for approximately two-thirds of the overall 90% increase in quarter-over-quarter NGL revenue.  Approximately 80% of the volume increase resulted from our liquids-rich Cana-Woodford development program in the Mid-Continent region.

 

Our NGL production for the first nine months of 2014 averaged 30,151 Bbl/d, compared to 21,550 barrels per day in the 2013 period.  This 40% increase in production provided an additional $67.1 million of revenue and

25

 


 

accounted for about half of the aggregate year-over-year increase in NGL revenue.  Increased volumes from our liquids-rich Cana-Woodford development program accounted for approximately 60% of the increase with the remainder coming from the Permian Basin.

 

Realized oil prices during the third quarter of 2014 averaged $87.27 per barrel, a decrease of 15% from $102.88 per barrel received in the same period of 2013.  The lower third quarter 2014 price resulted in lower oil revenues of $62.3 million.  For the first nine months of 2014, our average realized oil price was $90.87 per barrel, which was 3% lower than the average price of $93.81 for the same period of 2013.  The decrease in price accounted for $33.3 million of lower oil revenue for the first nine months of 2014.  Approximately 80% of our oil production comes from the Permian Basin, which is tied to WTI Midland benchmark prices.  During 2014, the Midland benchmark prices have declined compared to those of 2013.  See Revenues above for a comparison of realized prices to average benchmark prices.

 

Our average realized gas price for the third quarter of 2014 improved by 10%  to $4.10 per Mcf, compared to $3.72 per Mcf in 2013.  The 2014 price increase provided additional revenue of $16.4 million.  Our average realized gas price of $4.62 per Mcf for the first nine months of 2014 was 24% higher than an average realized price of $3.73 for the same period of 2013 and increased gas revenues by $100.0 million.  As noted above under Revenues, beginning in 2014, our average realized price for gas no longer includes deductions for certain processing fees, thus positively impacting revenue by $2.9 million ($0.07 per Mcf) for the third quarter of 2014 and by $8.6 million ($0.08 per Mcf) for the first nine months of 2014.  These positive impacts to prices were offset by increased transportation, processing and other operating costs discussed below and in Note 1, Basis of Presentation – Oil, Gas and NGL Sales, to the Consolidated Financial Statements in this report.

 

Our third quarter 2014 realized NGL price averaged $34.08 per barrel, which was 19% higher than the average realized price of $28.63 per barrel in the 2013 period.  The higher price in the third quarter of 2014 accounted for additional revenues of $17.9 million.  In the first nine months of 2014, we received an average NGL price of $36.10 per barrel, which was 26% higher than the 2013 average realized price of $28.57 and resulted in $62.0 million of additional NGL revenue.  As noted above under Revenues, beginning in 2014, our realized price for NGLs no longer includes deductions for certain processing fees, thus positively impacting revenue by $11.2 million ($3.43 per barrel) for the third quarter of 2014 and by $29.7 million ($3.60 per barrel) for the first nine months of 2014.  These positive impacts to prices were offset by increased transportation, processing and other operating costs discussed below and in Note 1, Basis of Presentation – Oil, Gas and NGL Sales, to the Consolidated Financial Statements in this report.

 

We sometimes transport, process and market third-party gas that is associated with our equity gas.  The table below reflects our pre-tax operating margin (revenues less direct expenses) for third-party gas gathering and processing as well as the marketing margin (revenues less purchases) for marketing third-party gas.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months

 

For the Nine Months

 

 

Ended September 30,

 

Ended September 30,

 

 

2014

 

2013

 

2014

 

2013

Gas Gathering and Marketing (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Gas gathering and other revenues

 

$

12,951 

 

$

11,380 

 

$

39,699 

 

$

32,951 

Gas gathering and other costs

 

 

(8,588)

 

 

(6,970)

 

 

(27,413)

 

 

(18,310)

Gas gathering and other margin

 

$

4,363 

 

$

4,410 

 

$

12,286 

 

$

14,641 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas marketing revenues, net of related costs

 

$

273 

 

$

329 

 

$

1,430 

 

$

21 

 

Fluctuations in net margins from gas gathering and gas marketing activities are a function of increases and decreases in volumes, prices and costs associated with third-party gas.

 

In the third quarter of 2014, our total operating costs and expenses (not including gas gathering and marketing costs, or income tax expense) were $412.4 million, up 25% compared to $329.8 million in the same period of 2013.  For the first nine months of 2014, operating costs were $1.169 billion, an increase of 31% over $889.9 million for the same period of 2013.  Analyses of the year-over-year differences are discussed below.

 

26

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months

 

Variance

 

 

 

 

 

 

 

Ended September 30,

 

Between

 

Per Mcfe

 

2014

 

2013

 

2014 / 2013

 

2014

 

2013

Operating costs and expenses (in thousands, except per Mcfe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

$

219,359 

 

$

159,182 

 

$

60,177 

 

$

2.53 

 

$

2.41 

Asset retirement obligation

 

1,420 

 

 

1,797 

 

 

(377)

 

$

0.02 

 

$

0.03 

Production

 

89,084 

 

 

76,166 

 

 

12,918 

 

$

1.03 

 

$

1.16 

Transportation, processing and other operating

 

54,573 

 

 

25,838 

 

 

28,735 

 

$

0.63 

 

$

0.39 

Taxes other than income

 

33,510 

 

 

31,104 

 

 

2,406 

 

$

0.39 

 

$

0.47 

General and administrative

 

20,240 

 

 

19,003 

 

 

1,237 

 

$

0.23 

 

$

0.29 

Stock compensation

 

3,603 

 

 

3,347 

 

 

256 

 

$

0.04 

 

$

0.05 

(Gain) loss on derivative instruments, net

 

(9,229)

 

 

10,824 

 

 

(20,053)

 

 

N/A

 

 

N/A

Other operating, net

 

(181)

 

 

2,507 

 

 

(2,688)

 

 

N/A

 

 

N/A

 

$

412,379 

 

$

329,768 

 

$

82,611 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months

 

Variance

 

 

 

 

 

 

 

Ended September 30,

 

Between

 

Per Mcfe

 

2014

 

2013

 

2014 / 2013

 

2014

 

2013

Operating costs and expenses (in thousands, except per Mcfe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

$

588,279 

 

$

442,851 

 

$

145,428 

 

$

2.56 

 

$

2.36 

Asset retirement obligation

 

8,288 

 

 

7,080 

 

 

1,208 

 

$

0.04 

 

$

0.04 

Production

 

250,310 

 

 

214,985 

 

 

35,325 

 

$

1.09 

 

$

1.15 

Transportation, processing and other operating

 

145,299 

 

 

66,494 

 

 

78,805 

 

$

0.63 

 

$

0.35 

Taxes other than income

 

99,454 

 

 

84,039 

 

 

15,415 

 

$

0.43 

 

$

0.45 

General and administrative

 

57,523 

 

 

57,416 

 

 

107 

 

$

0.25 

 

$

0.31 

Stock compensation

 

10,875 

 

 

10,459 

 

 

416 

 

$

0.05 

 

$

0.06 

(Gain) loss on derivative instruments, net

 

8,960 

 

 

(1,233)

 

 

10,193 

 

 

N/A

 

 

N/A

Other operating, net

 

34 

 

 

7,804 

 

 

(7,770)

 

 

N/A

 

 

N/A

 

$

1,169,022 

 

$

889,895 

 

$

279,127 

 

 

 

 

 

 

 

 Our third quarter 2014 DD&A expense of $219.4 million was 38% higher than the same period of 2013 and accounted for 73% of the total quarter-over-quarter increase in costs and expenses.  On a unit of production basis, third-quarter 2014 DD&A increased by 5% to $2.53 per Mcfe.  During the first nine months of 2014,  DD&A expense increased 33% to $588.3 million and comprised 52% of the aggregate year-over-year increase in total costs and expenses.  DD&A per Mcfe for the first nine months of 2014 increased by $0.20 (8%) to $2.56 per Mcfe.

 

Increases in our 2014 year-over-year production volumes were responsible for about 81% of our third quarter increase in DD&A expense and approximately 63% of the increase for the first nine months.  The remainder of the period-over-period increases in DD&A were due to increases in our DD&A rates.  Our DD&A rates have increased primarily because the cost of adding new proved reserves has exceeded the net remaining book basis of proved reserves added in prior years. 

 

27

 


 

Production costs consist of lease operating expense and workover expense as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months

 

Variance

 

 

 

 

 

 

 

 

Ended September 30,

 

Between

 

Per Mcfe

(in thousands, except per Mcfe)

 

2014

 

2013

 

2014 / 2013

 

2014

 

2013

Lease operating expense

 

$

71,133 

 

$

60,364 

 

$

10,769 

 

$

0.82 

 

$

0.92 

Workover expense

 

 

17,951 

 

 

15,802 

 

 

2,149 

 

$

0.21 

 

$

0.24 

 

 

$

89,084 

 

$

76,166 

 

$

12,918 

 

$

1.03 

 

$

1.16 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months

 

Variance

 

 

 

 

 

 

 

 

Ended September 30,

 

Between

 

Per Mcfe

(in thousands, except per Mcfe)

 

2014

 

2013

 

2014 / 2013

 

2014

 

2013

Lease operating expense

 

$

204,379 

 

$

166,995 

 

$

37,384 

 

$

0.89 

 

$

0.89 

Workover expense

 

 

45,931 

 

 

47,990 

 

 

(2,059)

 

$

0.20 

 

$

0.26 

 

 

$

250,310 

 

$

214,985 

 

$

35,325 

 

$

1.09 

 

$

1.15 

 

Third quarter 2014 lease operating expense (LOE) of $71.1 million increased 18% compared to $60.4 million in 2013.  LOE for the first nine months of 2014 increased by 22% to $204.4 million compared to $167.0 for the same period of 2013.  As we continue to put new wells on production, we have experienced higher costs for salt water disposal, rental equipment, chemical treating, labor and electricity.  We have also experienced increased costs for site maintenance and road repairs.

 

Workover expense for the third quarter of 2014 was 14% higher than the same period of 2013.   During the first nine months of 2014, workover expense declined by 4% compared to 2013.  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 costs in the third quarter and first nine months of 2014 increased significantly compared to the same periods of 2013.  These costs will vary by product type and region.  Increases or decreases in sales and processing volumes, contractual fees, compression charges and fuel costs will have an impact on the overall costs.  During the 2014 periods, about half of the increases in period-over-period costs resulted from greater production volumes, higher contractual fees and increases in fuel costs.  The remaining increases relate to the inclusion of certain processing fees which in previous periods were treated as a reduction in realized sales prices for residue gas and NGLs.  These costs accounted for approximately $0.17 per Mcfe for each of the 2014 periods.  See Note 1, Basis of Presentation – Oil, Gas and NGL Sales, to the Consolidated Financial Statements of this report for additional information.

 

Taxes other than income are assessed by state and local taxing authorities on production, revenues or the value of properties.  Revenue based production/severance taxes are our largest component of these taxes.  During the third quarter and first nine months of 2014, these taxes increased by 8% and 18%, respectively, compared to the same periods of 2013.  The increases are primarily due to increased production/severance taxes on higher production volumes and higher realized gas and NGL prices.

 

General and administrative (G&A) costs were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months

 

Variance

 

For the Nine Months

 

Variance

 

 

Ended September 30,

 

Between

 

Ended September 30,

 

Between

(in thousands)

 

2014

 

2013

 

2014 / 2013

 

2014

 

2013

 

2014 / 2013

G&A capitalized to oil & gas properties

 

$

19,838 

 

$

19,836 

 

$

 

$

62,278 

 

$

57,530 

 

$

4,748 

G&A expense

 

 

20,240 

 

 

19,003 

 

 

1,237 

 

 

57,523 

 

 

57,416 

 

 

107 

 

 

$

40,078 

 

$

38,839 

 

$

1,239 

 

$

119,801 

 

$

114,946 

 

$

4,855 

G&A expense per Mcfe

 

$

0.23 

 

$

0.29 

 

$

(0.06)

 

$

0.25 

 

$

0.31 

 

$

(0.06)

 

Our aggregate G&A for the third quarter and first nine months of 2014 increased modestly compared to the same periods of 2013.  The increases resulted primarily from higher salaries and benefits related to additional employees.

28

 


 

 

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and stock option awards, net of amounts capitalized.  We have recognized non-cash stock-based compensation cost as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months

 

Variance

 

For the Nine Months

 

Variance

 

 

Ended September 30,

 

Between

 

Ended September 30,

 

Between

(in thousands)

 

2014

 

2013

 

2014 / 2013

 

2014

 

2013

 

2014 / 2013

Performance stock awards

 

$

2,900 

 

$

2,710 

 

$

190 

 

$

8,714 

 

$

7,963 

 

$

751 

Service-based stock awards

 

 

2,925 

 

 

2,619 

 

 

306 

 

 

9,541 

 

 

9,289 

 

 

252 

Restricted stock awards

 

 

5,825 

 

 

5,329 

 

 

496 

 

 

18,255 

 

 

17,252 

 

 

1,003 

Stock option awards

 

 

847 

 

 

940 

 

 

(93)

 

 

2,402 

 

 

2,355 

 

 

47 

Total stock compensation

 

 

6,672 

 

 

6,269 

 

 

403 

 

 

20,657 

 

 

19,607 

 

 

1,050 

Less amounts capitalized to oil & gas properties

 

 

(3,069)

 

 

(2,922)

 

 

(147)

 

 

(9,782)

 

 

(9,148)

 

 

(634)

Stock compensation

 

$

3,603 

 

$

3,347 

 

$

256 

 

$

10,875 

 

$

10,459 

 

$

416 

 

Expense associated with stock compensation will fluctuate based on the grant-date market value of the award and the number of awards granted.  See Note 5 to the Consolidated Financial Statements for further discussion regarding our stock-based compensation.

 

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity prices and the monthly settlement of the contracts.  See Note 2 to the Consolidated Financial Statements in this report for further details regarding our derivative instruments.

 

The following table summarizes the net (gains) and losses from settlements and changes in fair value of our derivative contracts.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months

 

For the Nine Months

 

 

Ended September 30,

 

Ended September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

(Gain) loss on derivative instruments, net:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas contracts

 

$

(2,377)

 

$

(376)

 

$

7,443 

 

$

(9,575)

Oil contracts

 

 

(6,852)

 

 

11,200 

 

 

1,517 

 

 

8,342 

(Gain) loss on derivative instruments, net

 

$

(9,229)

 

$

10,824 

 

$

8,960 

 

$

(1,233)

 

 

 

 

 

 

 

 

 

 

 

 

 

Settlement (gains) losses:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas contracts

 

$

 —

 

$

(1,189)

 

$

4,824 

 

$

(1,189)

Oil contracts

 

 

211 

 

 

7,286 

 

 

1,191 

 

 

5,521 

Settlement (gains) losses

 

$

211 

 

$

6,097 

 

$

6,015 

 

$

4,332 

 

The caption “Other operating, net includes costs and accruals related to various legal matters.  As the result of certain litigation settlements these expenses have decreased considerably in 2014 versus comparable periods of 2013.  See Note 11 to the Consolidated Financial Statements and Part II, Item 1, in this report for further information regarding legal proceedings.

 

29

 


 

Other (income) and expense 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months

 

Variance

 

For the Nine Months

 

Variance

 

 

Ended September 30,

 

Between

 

Ended September 30,

 

Between

(in thousands)

 

2014

 

2013

 

2014 / 2013

 

2014

 

2013

 

2014 / 2013

Interest expense

 

$

20,879 

 

$

13,954 

 

$

6,925 

 

$

51,645 

 

$

41,272 

 

$

10,373 

Capitalized interest

 

 

(10,005)

 

 

(7,286)

 

 

(2,719)

 

 

(25,870)

 

 

(23,868)

 

 

(2,002)

Other, net

 

 

(11,123)

 

 

(2,263)

 

 

(8,860)

 

 

(22,207)

 

 

(13,637)

 

 

(8,570)

 

 

$

(249)

 

$

4,405 

 

$

(4,654)

 

$

3,568 

 

$

3,767 

 

$

(199)

 

Interest expense includes interest on debt and amortization of financing costs.  Our third quarter 2014 interest expense increased 50% compared to the third quarter of 2013.   Interest expense for the first nine months of 2014 was 25% higher than the same period of 2013.  The year-over-year increases were primarily the result of having more debt.

 

We capitalize interest on non-producing leasehold costs, the costs of drilling and completing wells and constructing qualified assets.  Period-over-period costs will fluctuate based on the current rate of interest and the amount of costs on which interest is calculated.  Capitalized interest in the 2014 periods increased compared to the comparable 2013 periods due to higher amounts of qualifying capitalized expenditures in the 2014 periods.

 

Components of other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss on the sale or value of oil and gas well equipment and supplies, income and expense associated with other non-operating activities, miscellaneous asset sales and interest income.  Increases in other, net (income) for the third quarter and first nine months of 2014 versus 2013 resulted from net gains on the sale of certain fixed assets and higher gains on sales of oil and gas well equipment and supplies in the 2014 periods.

 

Income Tax Expense

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

(in thousands)

 

2014

 

2013

 

2014

 

2013

 

Current benefit

 

$

 —

 

$

 —

 

$

 —

 

$

 —

 

Deferred taxes

 

 

84,707 

 

 

81,823 

 

 

254,210 

 

 

211,615 

 

 

 

$

84,707 

 

$

81,823 

 

$

254,210 

 

$

211,615 

 

Combined Federal and State effective income tax rate

 

 

37.0 

%

 

37.2 

%

 

37.1 

%

 

37.2 

%

 

Our combined Federal and state effective tax rates differ from the statutory rate of 35% primarily due to state income taxes and non-deductible expenses.  See Note 8 to the Consolidated Financial Statements of this report for additional information regarding our income taxes.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Overview

 

Our liquidity is highly dependent on prices we receive for the oil, gas and NGLs we produce.  Prices received for production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth.  See RESULTS OF OPERATIONS above for a discussion of the impact realized prices had on our 2014 revenues.

 

Commodity prices are market driven and future prices will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors.  We deal with volatility in commodity prices by maintaining flexibility in our capital investment program.  In addition, we have periodically hedged a

30

 


 

portion of our oil and/or gas production to mitigate our potential exposure to price declines and the corresponding negative impact on cash flow available for investment.

 

Our 2014 exploration and development (E&D) capital expenditures are expected to total approximately $1.95 billion and overall capital expenditures are expected to approximate $2.9 billion.  Our capital expenditures are generally funded with cash flow provided by operating activities and long-term debt.  Sales of non-core assets 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 bank credit facility.

 

At September 30, 2014, our long-term debt totaled $1.5 billion and consisted of $750 million of 4.375% senior notes due in 2024 and $750 million of 5.875% senior notes due in 2022.  We had letters of credit outstanding under our bank credit facility of $2.5 million, leaving an unused borrowing availability of $997.5 million.

 

Our debt to total capitalization at September 30, 2014 was 25%.  The reconciliation of debt to total capitalization, which is a non-GAAP measure, is:  long-term debt of $1.5 billion divided by long-term debt of $1.5 billion plus stockholders’ equity of $4.4 billion.  Management believes that this non-GAAP measure is useful information as it is a common statistic used in the investment community to assist with the analysis of the financial condition of an entity.

 

We believe that our operating cash flow and other capital resources will be adequate to meet our needs for planned capital expenditures, working capital, debt servicing and dividend payments for the remainder of 2014 and beyond.

 

Analysis of Cash Flow Changes

 

Cash and cash equivalents on September 30, 2014 were $563.7 million, an increase of $559.1 million from $4.5 million at December 31, 2013.  During the nine months ended September 30, 2014, cash flow provided by operating activities exceeded net cash flow used in investing activities by $24.1 million.  In addition, net cash provided by financing activities was $535.0 million, primarily from a public debt offering in the second quarter of 2014.

 

For the first nine months of 2013, our net cash flow used for investing activities of $1.131 billion was $190.6 million greater than net cash flow provided by operating activities.  Net bank borrowings of $150.0 million plus proceeds from issuance of common stock from employee option exercises, less dividend payments, provided $125.6 million of net cash flow from financing activities to fund investing activities.  The remaining shortfall was made up from the use of cash and cash equivalents on hand of $65.0 million.

 

Cash flow provided by operating activities for the first nine months of 2014 was $1.272 billion compared to $940.7 million for the same period of 2013.  The $331.2 million (35%) increase was primarily a result of increased revenues from greater production volumes and higher realized prices for natural gas and NGLs, which were partially offset by increased operating expenses.

 

During the first nine months of 2014, net cash flow used for investing activities increased by ten percent to $1.248 billion, compared to $1.131 billion for 2013. The net increase of $116.5 million was due to a $507.5 million increase in investments in oil and gas properties and other assets which were largely offset by higher proceeds from sales of oil and gas properties and other assets of $391.0 million.  Most of the asset sales occurred in the third quarter of 2014.

Cash provided by financing activities during the first nine months of 2014 was $535.0 million, an increase of $409.5 million compared to $125.5 million for the same period of 2013.  The majority of the increase relates to our June 2014 issuance of $750 million of senior notes.  Proceeds from the debt offering were used to pay outstanding bank debt, financing costs associated with the debt offering and to fund investing activities.  Similar additional financing activities in both the 2014 and 2013 periods included dividend payments and proceeds from issuance of common stock from employee option exercises.

 

31

 


 

Reconciliation of Adjusted Cash Flow from Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine months ended

 

 

September 30,

(in thousands)

 

2014

 

2013

Net cash provided by operating activities

 

$

1,271,970 

 

$

940,748 

Change in operating assets and liabilities

 

 

19,782 

 

 

91,971 

Adjusted cash flow from operations

 

$

1,291,752 

 

$

1,032,719 

 

Management believes that the non-GAAP measure of adjusted cash flow from operations is useful information for investors.  It is accepted by the investment community as a means of measuring a company’s ability to fund its capital program without reflecting fluctuations caused by changes in current assets and liabilities (which are included in the GAAP measure of cash flow from operating activities).  It is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry.

 

Capital Expenditures

 

The following table sets forth certain historical information regarding our capitalized expenditures for our oil and gas acquisition, exploration and development activities, and property sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Nine months ended

 

 

September 30,

 

September 30,

(in thousands)

 

2014

 

2013

 

2014

 

2013

Acquisitions:

 

 

 

 

 

 

 

 

 

 

 

 

Proved (*)

 

$

 —

 

$

(246)

 

$

144,516 

 

$

677 

Unproved

 

 

 —

 

 

1,816 

 

 

114,732 

 

 

5,481 

 

 

 

 —

 

 

1,570 

 

 

259,248 

 

 

6,158 

Exploration and development:

 

 

 

 

 

 

 

 

 

 

 

 

Land and seismic

 

 

34,697 

 

 

59,035 

 

 

143,891 

 

 

127,064 

Exploration and development

 

 

424,861 

 

 

328,655 

 

 

1,280,036 

 

 

1,059,546 

 

 

 

459,558 

 

 

387,690 

 

 

1,423,927 

 

 

1,186,610 

Sales proceeds:

 

 

 

 

 

 

 

 

 

 

 

 

Proved (*)

 

 

(271,954)

 

 

1,212 

 

 

(272,177)

 

 

(36,667)

Unproved

 

 

(174,403)

 

 

 —

 

 

(175,303)

 

 

(1,041)

 

 

 

(446,357)

 

 

1,212 

 

 

(447,480)

 

 

(37,708)

 

 

$

13,201 

 

$

390,472 

 

$

1,235,695 

 

$

1,155,060 

(*)     The negative amount in third quarter 2013 proved acquisitions and the positive amount in third quarter 2013 proved sales proceeds reflect net purchase price adjustments related to second quarter 2013 activity.

 

Capital expenditures in the table above are presented on an accrual basis.  Oil and gas expenditures and sales in the Condensed Consolidated Statements of Cash Flows in this report reflect activities on a cash basis, when payments are made.

 

We expect our total 2014 E&D capital investment to approximate $1.95 billion, almost all of which is focused on oil and liquids-rich gas wells in the Permian Basin and Mid-Continent region.  E&D expenditures of $1.424 billion during the first three quarters of 2014 were $237.3 million (20%) higher than $1.187 billion of expenditures during the 2013 period.  Through September 30, 2014, approximately 72% of our 2014 expenditures were for Permian Basin projects with the majority of the remainder invested in projects in the Mid-Continent.

 

32

 


 

The following table reflects wells drilled and completed by region:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,

 

September 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Gross wells

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

 

36 

 

 

42 

 

 

117 

 

 

132 

 

Mid-Continent

 

 

30 

 

 

67 

 

 

106 

 

 

154 

 

Other

 

 

 —

 

 

 

 

 

 

 

 

 

 

66 

 

 

112 

 

 

225 

 

 

291 

 

Net wells

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

 

27 

 

 

28 

 

 

78 

 

 

87 

 

Mid-Continent

 

 

 

 

21 

 

 

43 

 

 

56 

 

Other

 

 

 —

 

 

 

 

 

 

 

 

 

 

36 

 

 

52 

 

 

122 

 

 

147 

 

% Gross wells completed as producers

 

 

98 

%

 

99 

%

 

99 

%

 

99 

%

 

As of September 30, 2014, we had 52 gross wells awaiting completion: 43 Permian Basin and 9 Mid-Continent.  We also had 22 operated rigs running:  18 in the Permian Basin and 4 in the Mid-Continent region.    We regularly review our E&D capital expenditures and will adjust our activity based on changes in commodity prices, service costs and drilling success.

 

 In the ordinary course of business we make property acquisitions and dispositions, primarily to enhance our competitive position.  During the first nine months of 2014, we made property acquisitions totaling $259.2 million mostly for producing and nonproducing properties located in the Cana-Woodford shale play.  During the same period of 2013, we had property acquisitions of $6.2 million.

 

In the first nine months of 2014, we sold various non-core properties for net proceeds of approximately $447.5 million.  Most of the proceeds were related to sales of producing gas wells in southwestern Kansas and undeveloped acreage in Reagan County, Texas. In the same period of 2013 we had non-core oil and gas property dispositions of $37.7 million and also sold fixed asset gas gathering and processing systems for $31 million.

 

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.  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.

 

Financial Condition

 

Future cash flows and the availability of financing are subject to a number of variables including success in finding and economically producing new reserves, production from existing wells and realized commodity prices.  To meet capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, bank borrowings, and access to capital markets.  When necessary, we use our bank credit facility to finance our working capital needs.

 

During the first nine months of 2014, our total assets increased by $1.4 billion to $8.6 billion, up from $7.3 billion at December 31, 2013.  Half of the increase resulted from a $692.6 million increase in our net oil and gas properties.  Most of the remaining increase relates to a $559.1 million increase in our cash and cash equivalents, primarily from third quarter asset sales.

 

Total liabilities at September 30, 2014 increased to $4.2 billion, up $983.2 million from $3.2 billion at year-end 2013Over half of the increase relates to additional debt of $576.0 million resulting from our senior notes offering completed in the second quarter of 2014.  Most of the remaining increase comes from a $250.8 million increase in deferred income taxes during 2014.

33

 


 

 

Stockholders’ equity totaled $4.4 billion at September 30, 2014, up $407.8 million from $4.0 billion at December 31, 2013.  The increase resulted mainly from net income of $431.4 million less dividends of $41.7 million.

 

Dividends

 

A quarterly cash dividend has been paid to stockholders every quarter since the third quarter of 2006.  In February 2014, the quarterly dividend was increased to $0.16 per share from $0.14 per share.  Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

 

Working Capital Analysis

 

Our working capital balance fluctuates primarily as a result of changes in our cash and cash equivalents, exploration and development activities, realized commodity prices, and changes related to our operating activities.  Working capital is also impacted by changes in our oil and gas well equipment and supplies, our current tax provision and changes in the fair value of our outstanding derivative instruments.

 

At September 30, 2014, we had working capital of $294.9 million, an increase of $508.9 million compared to a deficit of $214.0 million at December 31, 2013.

 

Working capital increases consisted of the following: 

·

Cash and cash equivalents increased by $559.1 million, primarily from third quarter asset sales.

·

Operations-related accounts receivable increased by $63.3 million.

·

Oil and gas well equipment and supplies increased by $26.2 million.

Increases in working capital were partially offset by the following:

·

Operations related accounts payable and accrued liabilities increased by $90.2 million.

·

Accrued liabilities related to our E&D expenditures increased by $42.5 million.

·

Deferred income tax assets decreased by $3.3 million.

·

The net fair value of our derivative instruments declined by $2.9 million.

 

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.  The collection of receivables during the periods presented has been timely. Historically, losses associated with uncollectible receivables have not been significant.

 

Long-term Debt

 

Long-term debt at September 30, 2014 and December 31, 2013 consisted of the following:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(in thousands)

 

2014

 

2013

Bank debt

 

$

 —

 

$

174,000 

5.875% Senior Notes due 2022

 

 

750,000 

 

 

750,000 

4.375% Senior Notes due 2024

 

 

750,000 

 

 

 —

Total long-term debt

 

$

1,500,000 

 

$

924,000 

 

34

 


 

Bank Debt

 

In May 2014, we amended our senior unsecured revolving credit facility (Credit Facility) to extend the maturity date two years to July 14, 2018 and lowered the margins applicable to loans and commitments.  The amendment also raised our borrowing base from $2.25 billion to $2.5 billion until the next regular annual redetermination date scheduled for April 15, 2015.  The borrowing base is determined at the discretion of the lenders based on the value of our proved reserves.  Our aggregate commitments remained unchanged at $1 billion.

 

As of September 30, 2014, we had letters of credit outstanding of $2.5 million, leaving an unused borrowing availability of $997.5 million.  During the first nine months of 2014 we had average daily bank debt outstanding of $177.2 million, compared to $147.4 million for the same period of 2013.  Our highest amount of bank borrowings outstanding during the first nine months of 2014 was $515.0 million, occurring in May.  During the same period of 2013, the highest amount of outstanding bank borrowings was $285.0 million, occurring in September.

 

At our option, borrowings under the Credit Facility, as amended, may bear interest at either (a) LIBOR plus 1.5-2.25%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.5-1.25%, based on our leverage ratio.

 

The Credit Facility has a number of financial and non-financial covenants of which we were in compliance with at September 30, 2014.  See Note 7 to the Consolidated Financial Statements in this report for further information.

 

5.875% Notes due 2022

 

In April 2012, we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May and November.  The notes were sold to the public at par.  The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions.  We may redeem the notes in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and thereafter.

 

4.375% Notes due 2024

 

In June 2014, we issued $750 million of 4.375% senior notes due June 1, 2024, with interest payable semiannually in June and December.  The notes were sold to the public at par.  The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. At any time prior to March 1, 2024, we may redeem all or a part of the notes at a defined make-whole redemption price calculated at the time of redemption.  At any time on or after March 1, 2024, we may redeem all or part of the notes at a price equal to 100% of the principal amount.

 

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, 2014, our material off-balance sheet arrangements included operating lease agreements, which are customary in the oil and gas industry and are included in the table below.

 

35

 


 

Contractual Obligations and Material Commitments

 

At September 30, 2014, 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 (1)

$

1,500,000 

 

$

 —

 

$

 —

 

$

 —

 

$

1,500,000 

 

Fixed-Rate interest payments (1)

 

680,352 

 

 

76,602 

 

 

153,750 

 

 

153,750 

 

 

296,250 

 

Operating leases

 

125,972 

 

 

12,857 

 

 

21,871 

 

 

20,818 

 

 

70,426 

 

Drilling commitments (2)

 

266,474 

 

 

245,119 

 

 

21,355 

 

 

 

 

 

Gathering facilities and pipelines (3)

 

5,876 

 

 

5,876 

 

 

 

 

 

 

 

Asset retirement obligation (4)

 

170,328 

 

 

16,387 

 

 

(4)

(4)

(4)

Other liabilities (5)

 

81,397 

 

 

20,141 

 

 

42,303 

 

 

 —

 

 

18,953 

 

Firm transportation

 

469 

 

 

386 

 

 

83 

 

 

 —

 

 

 —

 


(1)

See Item 3: Quantitative and Qualitative Disclosures About Market Risk for more information regarding fixed and variable rate debt.

(2)

We have drilling commitments of approximately $212.8 million consisting of obligations to finish drilling and completing wells in progress at September 30, 2014.  We also have various commitments for drilling rigs.  The total minimum expenditure commitments under these agreements are $53.7 million.

(3)

We have projects in New Mexico and Texas where we are constructing gathering facilities and pipelines.  At September 30, 2014, we had commitments of $5.9 million relating to this construction.

(4)

We have not included the long-term asset retirement obligations because we are not able to precisely predict the timing of these amounts.

(5)

Other liabilities include the estimated value of our commitment associated with our benefit obligations and other miscellaneous commitments.

 

At September 30, 2014, we had firm sales contracts to deliver approximately 45.2 Bcf of natural gas over the next 15 months.  In total, our financial exposure would be approximately $166.6 million should we not deliver this gas.  Our exposure will fluctuate with price volatility and actual volumes delivered.  However, we believe Cimarex has no financial exposure from these contracts based on our current proved reserves and production levels from which we can fulfill these obligations.

 

In the normal course of business we have various delivery commitments which are not material individually or in the aggregate.  All of the noted commitments were routine and were made in the normal course of our business.

 

Based on current commodity prices and anticipated levels of production, we believe that estimated net cash generated from operations and our other capital resources will be adequate to meet future liquidity needs.

 

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

 

We consider accounting policies related to oil and gas reserves, full cost accounting, goodwill, contingencies and asset retirement obligations to be critical policies and estimates.  These critical policies and estimates are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K.

 

Recent Accounting Developments

 

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606).  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

36

 


 

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 CodificationWe must comply with this ASU beginning in fiscal year 2017 and early adoption is not permitted.  Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach.    We are currently evaluating the impact of the provisions of Topic 606 and the effects of adoption cannot be determined at this time.

 

 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates.  The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

 

Price Fluctuations

 

Our major market risk is pricing applicable to our oil and gas 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.

 

We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production.

 

The following tables detail the financial derivative contracts we have in place as of September 30, 2014:

 

Oil Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Price

 

Fair Value

Period

 

Type

 

Volume/Day

 

Index (1)

 

Floor

 

Ceiling

 

(in thousands)

Oct 14 – Dec 14

 

Collars

 

12,000 Bbls

 

WTI

 

$

85.00 

 

$

103.47 

 

$

1,089 

(1)

WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

 

Gas Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Price

 

Fair Value

Period

 

Type

 

Volume/Day

 

Index (1)

 

Floor

 

Ceiling

 

(in thousands)

Oct 14 – Dec 14

 

Collars

 

80,000 MMBtu

 

PEPL

 

$

3.51 

 

$

4.57 

 

$

(81)

Oct 14 – Dec 14

 

Collars

 

60,000 MMBtu

 

Perm EP

 

$

3.62 

 

$

4.50 

 

$

(74)

(1)

PEPL refers to Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC.  Perm EP refers to El Paso Natural Gas Company, Permian Basin Index as quoted in Platt's Inside FERC.

 

While these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.  For the oil contracts listed above, a hypothetical $1.00 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives in 2014 of $1.1 million.  For the gas contracts listed above, a hypothetical $0.10 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives in 2014 of $1.3 million.

 

Counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations.  This is primarily because we have mitigated our exposure to any single counterparty by contracting with numerous counterparties and because our derivative contracts are held with “investment grade”

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counterparties that are a part of our credit facility.  See Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments.

 

Interest Rate Risk

 

 

At September 30, 2014, our long-term debt consisted of $750 million in 5.875% senior notes that will mature on May 1, 2022 and $750 million in 4.375% senior notes that will mature on June 1, 2024.    Because all of our long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal.   This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.  See Note 3 and Note 7 to the Consolidated Financial Statements in this report for additional information regarding 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, 2014.  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, 2014 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

 

In the H.B. Krug, et al. v. Helmerich & Payne, Inc. (H&P) case, on December 13, 2013 the Oklahoma Supreme Court reversed the Tulsa County District Court’s original judgment of $119.6 million and affirmed an alternative jury verdict for $3.65 million.  It also remanded the case back to the trial court for consideration of potential prejudgment interest, attorney’s fees and cost awards.  Accordingly, on December 31, 2013 we reduced the previously recognized litigation expense and the associated long-term liability by $142.8 million.  On April 1, 2014, Cimarex paid the Plaintiffs $15.8 million in satisfaction of the $3.65 million damages award, the post-judgment interest award and the payment in lieu of bond, all of which are now final and not appealable.  On June 24, 2014, the trial court ruled the Plaintiffs were not entitled to prejudgment interest but were entitled to attorney’s fees and costs, the amount of which will be determined at a subsequent hearing.  On July 31, 2014, the Plaintiffs appealed the trial court’s denial of prejudgment interest, which will be determined by the Oklahoma Supreme Court.  The outcome of these remaining issues cannot be determined, and our current estimates and assessments likely will change, as a result of these future legal proceedings.

 

Additional information regarding this and other litigation is included in Note 11 to the Consolidated Financial Statements included in Part I, Item 1 of this report.

 

ITEM 6.   EXHIBITS

 

 

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 Paul Korus, 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 Paul Korus, 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

 

39

 


 

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 5, 2014

 

 

 

 

 

 

CIMAREX ENERGY CO.

 

 

 

 

 

/s/ Paul Korus

 

Paul Korus

 

Senior Vice President and Chief Financial Officer

 

(Principal Financial Officer)

 

 

 

 

 

/s/ James H. Shonsey

 

James H. Shonsey

 

Vice President, Chief Accounting Officer and Controller

 

(Principal Accounting Officer)

 

40